Corrosion in Petroleum Refining

APPENDIX U PETROLEUM REFINING

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APPENDIX U

PETROLEUM REFINING 1

GREGORY R. RUSCHAU, PH.D.

AND MOHAMMED

2

A. AL-ANEZI

SUMMARY AND ANALYSIS OF RESULTS Corrosion Control and Prevention Petroleum refining is an industry that is undergoing intense amounts of scrutiny in the United States from regulatory agencies and environmental groups. As a result, releases of pollutants caused by corrosion leaks are becoming a high-consequence event. The Clean Air Act of 1990 has forced refineries to implement a number of costly measures to reduce their impact on the environment, both in the types of products they produce and the manner in which they operate. The total cost of corrosion control in refineries is estimated at $3.692 billion. Of this total, maintenance-related expenses are estimated at $1.767 billion annually, vessel turnaround expenses account for $1.425 billion annually, and fouling costs are approximately $0.500 billion annually. The costs associated with corrosion control in refineries include both processing and water handling. Corrosion-related issues regarding processing include the handling of organic acids (broadly referred to as napthenic acid corrosion) and sulfur species, particularly at elevated temperatures, as well as water carried over in processing vessels and pipelines. Water handling includes concerns with corrosives such as H 2S, CO2, chlorides, and high levels of dissolved solids.

Opportunities for Improvement and Barriers to Progress As with oil production, the lifeblood of a refinery is the production system. Failure in any processing vessel, particularly the major feedstock lines, costs significantly more in lost production than the cost of prevention and maintenance. Unlike oil and gas production, refining margins are dictated on both ends by commodity prices since the input feedstock crude oil is purchased at the market price and the output product is sold at each individual commodity price. Because the economics of refining are wholly dependent on world market prices, the amount spent on corrosion control is dictated by current economic conditions in the industry. Since 1981, the number of operating refineries in the United States has dropped from 324 to 163. The industry has seen a trend toward refining more highly acidic oils (which can be refined at a higher margin) since the early 1990s, which increases potential corrosion problems, but may extend the economic life of some existing refineries.

Recommendations and Implementation Strategy The majority of pipelines and vessels in refineries are constructed of carbon steel. Opportunities for significant savings exist through the use of low-alloy steels and alloy-clad vessels, particularly as increasingly higher fractions of acidic crude are refined.

1 2

CC Technologies Laboratories, Inc., Dublin, Ohio. Saudi Arabian Oil Company (Saudi ARAMCO), Dhahran, Saudi Arabia.

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Appendix U – Petroleum Refining

Increasing regulation and pressure from environmental groups have essentially forced the refiners to implement defensive strategies. This is compounded by overseas market forces such as the Organization of Petroleum Exporting Countries (OPEC), which can control the price of feedstock crude oil, making long-term planning difficult. In a commodity price-driven industry that is struggling to compete in the world market, investment in more effective corrosion control strategies often takes a backseat to across-the-board cost-cutting measures.

Summary of Issues

Increase consciousness of corrosion costs and potential savings.

Change perception that nothing can be done about corrosion.

Advance design practices for better corrosion management. Change technical practices to realize corrosion cost-savings. Change policies and management practices to realize corrosion cost-savings. Advance life prediction and performance assessment methods.

Advance technology (research, development, and implementation).

Improve education and training for corrosion control.

Federal regulations such as the Clean Air Act of 1990 have increased operating costs due to stricter controls on releases. In addition, more acidic crude oil is being refined because of the higher net margins possible; a stronger approach to corrosion control will enable these more aggressive crudes to be safely refined in the United States, otherwise, the refining industry will continue to move overseas. A longer-term vision must be incorporated into facility design and maintenance to enable U.S. refiners to remain competitive. This includes the use of some exotic materials, such as ceramics, which can provide a longer service life in high-temperature operations. More efficient processing vessel design would reduce the carryover of corrosives from one process to the next. Improved water separation, CO2 stripping, etc. would help isolate the problem areas and would allow corrosion control efforts to be focused farther upstream. Fitness-for-service principles will need to be applied to vessel inspections rather than following existing protocol, which may be inadequate. Riskbased models would enable the maintenance staff to prioritize inspections. Management may have to shift its focus from ensuring compliance with existing regulations to a more active strategy to prevent releases. Zeroleak policies and programs would be implemented in plants to emphasize commitment to this strategy. Flexible life prediction models are needed that can show how a change in the feedstock crude affects all vessels downstream. Also needed are improved inspection and monitoring techniques for in-plant piping systems, both for aboveground and buried lines. Processes in refineries are largely computer-controlled, but corrosion control methods lag behind in technology. Computer-aided mitigation systems, perhaps integrated with existing process control modules, could be used to track the changing corrosivity of existing processes. Requiring contract services such as nondestructive inspection companies, maintenance painters, and corrosion control specialists to provide NACEcertified personnel or at least personnel who meet some minimum training/education requirements before they are allowed to work on-site would improve the level of knowledge in the industry.

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TABLE OF CONTENTS SECTOR DESCRIPTION.........................................................................................................................................U1 REFINING CAPACITY OF THE UNITED STATES..........................................................................................U1 Refined Products ..........................................................................................................................................U2 Types of Crude Oil.......................................................................................................................................U3 Elements of the Refining Operation.............................................................................................................U4 AREAS OF MAJOR CORROSION IMPACT.......................................................................................................U6 Water-Related Side Corrosion......................................................................................................................U6 Processing-Related Corrosion ......................................................................................................................U6 Naphthenic Acid Corrosion..........................................................................................................................U7 Sulfur............................................................................................................................................................U7 CORROSION CONTROL METHODS...................................................................................................................U8 Materials in Refinery Construction ..............................................................................................................U8 Carbon Steel...................................................................................................................................U9 Austenitic Stainless Steel...............................................................................................................U9 Ferritic and Martensitic Steels .....................................................................................................U10 Other Alloys.................................................................................................................................U10 CORROSION MANAGEMENT ............................................................................................................................U10 Economics of Refining...............................................................................................................................U10 Capital Expenditures ..................................................................................................................................U11 Operational Expenditures ...........................................................................................................................U12 Fouling .......................................................................................................................................................U13 Acidic Crude Oils.......................................................................................................................................U14 Failure Costs...............................................................................................................................................U15 CASE STUDY.........................................................................................................................................................U15 Corrosion-Related Failure in Refinery ....................................................................................................... U15 REFERENCES .........................................................................................................................................................U16

LIST OF FIGURES Figure 1.

Past and predicted future refining capacity in the United States.................................................... U1

Figure 2.

1996 Outputs from refineries by end-product usage ...................................................................... U3

Figure 3.

Flowchart diagram of a typical refining process ............................................................................U5

Figure 4.

Margins of U.S. refiners since 1977.............................................................................................U11

Figure 5.

Incremental costs for corrosion control of carbon steel distillation column ................................U14

Figure 6.

Stress corrosion cracking near a weld ..........................................................................................U15

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LIST OF TABLES Table 1.

U.S. daily average supply and disposition of crude oil and petroleum products, January 1997 ....U2

Table 2.

Typical approximate characteristics and properties and gasoline potential of various crudes ....... U4

Table 3.

Comparison of the relative costs of various alloys......................................................................... U9

Table 4.

Environmental costs at a refinery.................................................................................................U12

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SECTOR DESCRIPTION Petroleum is the single largest source of energy for the United States. When measured in British thermal units, the nation uses twice as much petroleum than either coal or natural gas, and four times more petroleum than nuclear power, hydroelectricity, and other renewable energy sources. On average, every citizen in the United States consumes 9.1 kg (20 lb) of petroleum per day. This primary dependence on petroleum for energy has been a reality for decades, with petroleum's share of the domestic energy mix peaking at 49 percent in 1977.

REFINING CAPACITY OF THE UNITED STATES U.S. refineries represent approximately 23 percent of world production. The United States has the largest refining capacity in the world, with 163 operating refineries, having declined from a high of 324 refineries in 1981 and 205 refineries in 1990.(1) Most refineries in the United States are concentrated on the west and gulf coasts, primarily due to access to major sea transportation and shipping routes. The majority of the oil distillation capacity is currently centered in large, integrated companies with multiple refining facilities. About 25 percent of all facilities are small operations producing fewer than 50,000 barrels per day, representing 5 percent of the total output of petroleum products annually. In 1970, U.S. refineries supplied just under 15 million barrels of refined product per day. In 1996, U.S. refiners supplied more than 18 million barrels per day of refined petroleum products. Total daily crude oil refining capacity by the end of 1999 was 16,511,871 barrels per day. U.S. refiners rely on both domestic and foreign producers for crude oil. Historical trends over the last 10 years indicate that imports of crude oil have been rising steadily. Future refining capacity in the United States is predicted to increase slightly and level off in the next 20 years, as shown in figure 1. The curve illustrates how the United States experienced a steep decline in refining capacity in the years following 1981. Between 1981 and 1989, the number of U.S. refineries fell from 324 to 204, representing a loss of 3 million barrels per day (MMBD) in operable capacity, and a concomitant increase in refining capacity utilization from 69 to 86 percent.

y a d r e p s l e r r a b f o s n o i l l i M

Figure 1.

Past and predicted future refining capacity in the United States. (2)

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Refined Products Table 1 shows the average daily throughput of U.S. refineries in 1997. (3) On an annual basis, this translates into a total of 5.7 billion barrels 3 of refined product. Approximately 90 percent of all crude oil entering a petroleum refinery is converted to fuel products, with the remaining 10 percent divided into non-fuel products such as asphalt, lubricants, and waxes and petrochemicals such as polymer feedstocks and industrial solvents. Gasoline production alone accounts for more than 46 percent of all production, as shown in figure 2. U.S. daily average supply and disposition of crude oil and petroleum products, January 1997.(3)

Table 1.

FIELD PRODUCTION (thousand barrels per day)

COMMODITY Crude Oil

6,402

NGLs and LRGs*

1,782

Pentanes Plus LPGs** Ethane/Ethylene

528 302 1,480

246 53 193

528

634 520 165 161

26 519 -28 11

267

Other Hydrocarbons/Oxy

UNACCOUNTED-FOR IMPORTS (thousand barrels per day) 7,492

Propane/Propylene N Butane/Butylene OTHER LIQUIDS

REFINERY PRODUCTION (thousand barrels per day)

740 247

77

Ounfinished Oils Mogas Blend. Comp.***

421 242

Avgas Blend. Comp.****

20

FINISHED PETRO PROD.

19

Finished Mogas Reformulated Oxygenated

19

15,075

1,285 7,288

2,217 134 4,937

Other Finished Avgas Jet Fuel

0

1,491

100

0 100

1,491

Kerosene

118

Distilate Fuel Oil ≤0.05 Sulfur >0.05

136 0 184

16

Naptha-Type Kerosene-Type

3

3,119

293

1,751 1,368

Sulfur

94 198

Residual Fuel Oil Naptha Petro Feed

801 180

211 106

Oth Oils Petro Feed

240

206

47

10

168

7

21

1

Special Napthas Lubricants Waxes

3

320

1 barrel = 158 L.

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Table 1. U.S. daily average supply and disposition of crude oil and petroleum products, January 1997 (continued).(3)

COMMODITY

FIELD PRODUCTION (thousand barrels per day)

REFINERY PRODUCTION (thousand barrels per day)

Petroleum Cake Asphalt & Road Oil

638 322

Still Gas

585

Misc. Products

UNACCOUNTED-FOR IMPORTS (thousand barrels per day) 2 26

41

TOTAL

8,470

15,603

9,763

*Natural Gas Liquids and Lead Replacement Gasolines **Liquefied Petroleum Gas ***Motor Vehicle Fuel ****Aviation Fuel

Other Fuels 13.7%

Other Products 14.8%

Gasoline 46.5%

Fuel Oils 25.0%

Figure 2. 1996 Outputs from refineries by end-product usage.

Types 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 percent carbon, 14 percent hydrogen, 1 to 3 percent sulfur, and less than 1 percent 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. Table 2 lists some typical properties for crude oil sources from around the world.

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Crude oils are also defined in terms of API (American Petroleum Institute) gravity number. The higher the API gravity number, 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. Crude oils 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 the West Texas crudes, which are always considered sour regardless of their H 2S content, and the Arabian high-sulfur crudes, which are not considered sour because their sulfur compounds are not highly reactive. For refining operations, the acidity of the crude oil is an important consideration for economic reasons. A number of organic acids may be present in crude oil feedstocks. The extra costs associated with handling high-acid crudes can be offset by a lower feedstock cost. Acidity is defined in terms of the total acid number (TAN), which is a measure of the number of milligrams of potassium hydroxide (KOH) needed to neutralize 1 g of sample. A TAN exceeding 1.5 to 1.8 mg KOH/g is considered corrosive; however, corrosion problems can occur in crudes with TAN numbers as low as 0.3 for several reasons, including velocity and the nature of the acidic species present.

Table 2. Typical approximate characteristics and properties and gasoline potential of various crudes. (4) API

PARRAFINS

AROMATICS

NAPTHENES

SULFUR

SOURCE

(%VOL)

(%VOL)

(%VOL)

(%WT)

37

9

54

0.2

36

28

60

63 60

19 15

18 25

2 2.1

34 28

22 23

40 35

35

12

53

2.3

30

2

60

52

14

34

1.5

24

18

50

-

-

-

0.4

40

-

-

46

22

32

1.9

32

33

55

50

16

34

0.4

37

31

50

Nigerian (light) Saudi (light) Saudi (heavy) Venezuela (heavy) Venezuela (light) USA Midcont. Sweet USA (W.Texas Sour) North Sea (Brent)

GRAVITY (APPROX.)

NAPH. YIELD

OCTANE

CRUDE

(% VOL)

NUMBER (TYPICAL)

Elements of the Refining Operation Petroleum refining begins with the desalting (dehydration) of feedstock followed by distillation, or fractionation, of crude oils into separate hydrocarbon groups. The resultant products are directly related to the characteristics of the crude oil 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 sector. These converted products are then subjected to various treatment and separation processes, such as extraction, hydrotreating, 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. An outline of the refining process is shown in figure 3.

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Figure 3. Flowchart diagram of a typical refining process.(5)

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 surfactants (demulsifiers) are added to the crude and heated so that salts and other impurities dissolve into the water or attach to the water, and are 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. After desalting, crude oil is continuously drawn from the top of the settling tanks and sent to the crude distillation (fractionating) tower. 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.

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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 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 is the process of mixing and combining hydrocarbon fractions, additives, and other components to produce finished products with specific performance properties. Other refinery operations include light-end 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.

AREAS OF MAJOR CORROSION IMPACT A refinery operation may have in excess of 3,000 processing vessels of varying size, shape, form, and function. In addition, a typical refinery has about 3,200 km (2,000 mi) of pipeline, much of which is inaccessible. Some of these pipelines are horizontal; some are vertical; some are up to 61 m (200 ft) high; and some are buried under cement, soil, mud, and water. The diameters range from 10 cm (4 in) up to 76 cm (30 in).

Water-Related Corrosion Crude oil desalting and distillation generates considerable wastewater. Typical wastewater flow from a desalter is approximately 8 L (2.1 gal) of water per barrel of oil processed. This water contains accelerative corrosive components such as H 2S, CO2, chlorides, and high levels of dissolved solids. The wastewater also contains a fraction of crude oil, which may be recovered during the water treatment process. In addition to generated wastewater, cooling water (either fresh water or saltwater) is used extensively in refining operations. The corrosivity of the cooling water varies greatly depending on the process, so it is difficult to describe typical cooling water problems; however, corrosivity is highly dependent upon the level and type of dissolved solids and gases in the cooling water, including chlorides, oxygen, dissolved gases, and microbes. Cooling water temperature can also affect corrosivity.

Processing-Related Corrosion The top section of a crude unit can be subjected to a multitude of corrosive species. Hydrochloric acid, formed from the hydrolysis of calcium and magnesium chlorides, is the principal strong acid responsible for corrosion in the crude unit top section. Carbon dioxide is released from crudes typically produced in CO 2-flooded fields and crudes that contain a high content of naphthenic acid. Low molecular fatty acids such as formic, acetic, propionic, and butanoic acids are released from crudes with a high content of naphthenic acid. Hydrogen sulfide, released from sour crudes, significantly increases corrosion of

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the crude unit top section. Sulfuric and sulfurous acids, formed by either oxidation of H2S or direct condensation of SO2 and SO3, also increase corrosion. Mitigation of this type of corrosion is performed by process changes, material upgrading, design changes, and injection of chemicals such as neutralizers and corrosion inhibitors. Process changes include any action to remove or at least reduce the amount of acid gas present and to prevent accumulation of water on the tower trays. Material upgrading includes lining of distillation tower tops with alloys resistant to hydrochloric acid. Design changes are used to prevent the accumulation of water. They include coalescers and water draws. The application of chemicals includes the injection of a neutralizer to increase the pH and a corrosion inhibitor. The presence of many weak acids, such as fatty acids and CO 2, can buffer the environment and require greater use of neutralizers. Excess neutralizers may cause plugging of trays and corrosion under the salt deposits. A dew-point probe is typically placed in a location at least 38 °C (100 °F) above the calculated dew-point temperature. The probe elements are then cooled internally by cold-air injection and the temperature at which the first liquid drop forms is determined for the actual conditions in the tower. The injection point and the amount of chemicals used depend on the knowledge of the temperature in the tower where condensation starts. With the number of corrosive species present, the calculated dew point may be much lower than the actual dew point.

Naphthenic Acid Corrosion High-temperature crude corrosivity of distillation units is a major concern of the refining industry. The presence of naphthenic acid and sulfur compounds considerably increases corrosion in the high temperature parts of the distillation units and, therefore, equipment failures have become a critical safety and reliability issue. Naphthenic acid is the generic name used for all of the organic acids present in crude oils. Most of these acids are believed to have the chemical formula R(CH 2)nCOOH, where R is a cyclopentane ring and n is typically greater than 12. In addition to R(CH2)nCOOH, a multitude of other acidic organic compounds are also present; however, not all of them have been analyzed to date. Isolated deep pits in partially passivated areas and/or impingement attack in essentially passivation-free areas are typical of naphthenic acid corrosion (NAC). Damage is in the form of unexpected high corrosion rates on alloys that would normally be expected to resist sulfidic corrosion. In many cases, even very highly alloyed materials (i.e., 12 Cr, AISI types 316 and 317) have been found to exhibit sensitivity to corrosion under these conditions. NAC is differentiated from sulfidic corrosion by the nature of the corrosion (pitting and impingement) and by its severe attack at high velocities in crude distillation units. Crude feedstock heaters, furnaces, transfer lines, feed and reflux sections of columns, atmospheric and vacuum columns, heat exchangers, and condensers are among the types of equipment subject to this type of corrosion.

Sulfur Other than carbon and hydrogen, sulfur is the most abundant element in petroleum. It may be present as elemental sulfur, hydrogen sulfide, mercaptans, sulfides, and polysulfides. Sulfur at a level of 0.2 percent and greater is known to be corrosive to carbon and low-alloy steels at temperatures from 230 °C (450 °F) to 455 °C (850 °F). At high temperatures, especially in furnaces and transfer lines, the presence of naphthenic acids may increase the severity of sulfidic corrosion. The presence of these organic acids may disrupt the sulfide film, thereby promoting sulfidic corrosion on alloys that would normally be expected to resist this form of attack (i.e., 12 Cr and higher alloys). In some cases, such as in side-cut piping, the sulfide film produced by H 2S is believed to offer some degree of protection from naphthenic acid corrosion. In general, the corrosion rate of all alloys in the distillation units increases with an increase in temperature. Naphthenic acid corrosion occurs primarily in high-velocity areas of crude distillation units in the 220 °C to 400 °C

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(430 °F to 750 °F) temperature range. No corrosion damage is usually found at temperatures greater than 400 °C (750 °F), probably due to the decomposition of naphthenic acids or protection from the coke formed at the metal surface. Velocity and, more importantly, wall shear stress are the main parameters affecting NAC. Fluid flow velocity lacks predictive capabilities. Data related to fluid flow parameters, such as wall shear stress and the Reynold’s Number, are more accurate because the density and viscosity of liquid and vapor in the pipe, the degree of vaporization in the pipe, and the pipe diameter are also taken into account. Corrosion rates are directly proportional to shear stress. Typically, the higher the acid content, the greater the sensitivity to velocity. When combined with high temperature and high velocity, even very low levels of naphthenic acid may result in very high corrosion rates.

CORROSION CONTROL METHODS High-temperature crude corrosion is a complex problem. There are at least three corrosion mechanisms: 1. 2. 3.

furnace tubes and transfer lines where corrosion is dependent on velocity and vaporization, and is accelerated by naphthenic acid, vacuum column where corrosion occurs at the condensing temperature, is independent of velocity, and increases with naphthenic acid concentration, and side-cut piping where corrosion is dependent on naphthenic acid content and is inhibited somewhat by sulfur compounds.

Mitigation of process corrosion includes blending, inhibition, materials upgrading, and process control. Blending may be used to reduce the naphthenic acid content of the feed, thereby reducing corrosion to an acceptable level. Blending of heavy and light crudes can change shear stress parameters and might also help reduce corrosion. Blending is also used to increase the level of sulfur content in the feed and inhibit, to some degree, naphthenic acid corrosion. Injection of corrosion inhibitors may provide protection for specific fractions that are known to be particularly severe. Monitoring needs to be adequate in this case to check on the effectiveness of the treatment. Process control changes may provide adequate corrosion control if there is the possibility of reducing charge rate and temperature. For long-term reliability, upgrading the construction materials is the best solution. Above 288 °C (550 °F), with very low naphthenic acid content, cladding with chromium (Cr) steels (5 to 12 percent Cr) is recommended for crudes of greater than 1 percent sulfur when no operating experience is available. When hydrogen sulfide is evolved, an alloy containing a minimum of 9 percent chromium is preferred. In contrast to high-temperature sulfidic corrosion, low-alloy steels containing up to 12 percent Cr do not seem to provide benefits over carbon steel in naphthenic acid service. Type 316 stainless steel [greater than 2.5 percent molybdenum (Mo)] or Type 317 stainless steel (greater than 3.5 percent Mo) is often recommended for cladding of vacuum and atmospheric columns.

Materials in Refinery Construction The selection of materials for refinery constructi on depends on the type of refinery, the type of crude oil handled, and the expected service life for each vessel. (6) As with all materials selection, the life-cycle cost must be considered in addition to purchase price. Table 3 lists some common alloys and their material costs relative to carbon steel.

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Table 3. Comparison of the relative costs of various alloys. (7) CONSTITUENTS ALLOY CLASS

EXAMPLE Ni

Carbon Steel

C10

Low-Alloy Steel

1-1/4Cr 1/2Mo

Cr

Mo

Fe

Al

V

0.5

balance

0.25

2.3

balance

1.0

4.6

-

Alloy 800H

32.5

21.0

20Cb-3

35.0

20.0

2.5

Alloy C2

54.0

15.5

16.0

Alloy C276

57.0

16.0

16.0

5.5

Alloy C4

54.0

16.0

15.5

3.0

Alloy 625

60.0

21.5

9.0

Alloy G

45.0

22.2

6.5

Alloy 600

76.0

15.0

Ni-Mo

Alloy B2

balance

1.0

Ni-Cu

Alloy 400

65.1

Nickel

Alloy 200

99.9

Co-Base

ULTIMET (R)

Ti-Base

Ti-6Al-4V

9.0

Cb

1.25 17.0

Ni-Cr-Fe

Cu

0.2

13.0

Ni-Cr-Mo

Ti

> 94

Type 316L Fe-Ni-Cr + Mo

Co

COST RATIO(9)

balance

3.5

3.8 6.0 3.7

19.5

6.3

2.0

6.4

8.0 28.0

2.0

1.0

11.6 32.0

-

26.0

5.0

3.0

54.0

27.2 90

6.0

4.0

-

Carbon Steel Carbon steel is by far the most common structural material in refineries due primarily to a combination of strength, availability, relatively low cost, and a resistance to fire. The low-alloy steels are specified for applications that require higher properties than can be obtained with carbon steels. The workhorse refinery alloys for elevated temperature service greater than 260 oC (500 oF) contain 0.5 to 9.0 percent chromium plus molybdenum. Normally, at least 5 percent chromium is required to resist oxidation at temperatures in excess of 430 oC (800 oF). Currently, most refineries use 9Cr-1 Mo tubes in coker heaters. For carbon steel and low-alloy steel, creep becomes a design consideration at about 430 oC (800 oF) and 480 oC (900 oF), respectively. These alloys are used for pressure vessels, piping, exchangers, and heater tubes.

Austenitic Stainless Steel The austenitic structure provides a combination of excellent corrosion, oxidation, and sulfidation resistance with high creep resistance, toughness, and strength at temperatures greater than 565 oC (1050 oF). They are, therefore, often used in refineries for heater tubes and heater tube supports, and in amine, fluid catalytic cracking (FCC), catalytic hydro-desulfurization (CHD) sulfur, and hydrogen plants. They are susceptible, however, to grain boundary chromium carbide precipitation “sensitization” when heated in the range of 540 oC (1000 oF) to 820 oC (1500 oF). Where “sensitization” is to be avoided, refineries prefer to use the stabilized grades of Type 347 (with Cb) or Type 321 (with Ti). The susceptibility of the austenitic stainless steels to stress corrosion cracking limits their use and requires special precautions during operation and at downtime. At downtime, the precautions taken to prevent stress corrosion cracking are either alkaline washing with a dilute soda ash and low-chloride water solutions and/or nitrogen blanketing. The austenitic stainless steels are used for corrosion resistance or resistance to

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high-temperature hydrogen or sulfide damage. Solid stainless steel vessels are rarely constructed. Strip-lined, stainless-clad, or lined vessels are found in hydrocracking and hydrotreating services. Austenitic stainless steels also find service as tubing in heat exchangers exposed to corrosive conditions.

Ferritic and Martensitic Steels Other chromium-iron stainless steels with little or no nickel form crystallographic structures different from austenitic. This stainless steel alloy contains less than 0.10 percent C, 11 to 13 percent Cr, balance Fe, and a ferritic structure. When the ferritic stainless alloys are modified, they may be hardened and become what is called "martensitic" by heat treatment. The ferritic and martensitic stainless steels are classified by the American Iron and Steel Institute (AISI) as the 400 series. The most common alloys from this series found in refineries are types 410, 410S, 405, and 430 stainless steels. A common stainless steel for trays and lining in crude service is Type 410 stainless steel.

Other Alloys The principal non-ferrous alloys in refinery processing equipment are the copper-based and copper-nickel alloys; however, the use of copper-based alloys in NH 3 or NH4 environments should be avoided. Although admiralty brass was the original saltwater condenser tube material, it was found to be susceptible to erosion-corrosion, particularly at tube ends. Aluminum brass, containing 2 percent aluminum, was found to be somewhat more resistant to erosion in saltwater. Inhibition with arsenic is necessary to prevent de-zincification, as in the case of admiralty brass. The stronger naval brass is often selected as the tube sheet material when admiralty brass tubes are used in condensers. Generally, a bronze is a tin alloy of copper, although the term has been widely used for other alloys, including some brasses. Cast brass or bronze alloys for valves and fittings are usually coppertin-zinc compositions, plus lead for machinability. Aluminum bronzes are often used as tube sheet and channel material for exchangers with admiralty brass or titanium tubes exposed to cooling water. The 70/30 copper-nickel alloy is used for exchanger tubes when better saltwater corrosion resistance than in aluminum brass is needed, or when high metal temperatures in water-cooled exchangers may cause de-zincification in brass. Monel is a nickel-copper alloy with 67 percent nickel and 30 percent copper. Monel has very good resistance to saltwater and, under non-oxidizing conditions, to acids such as hydrochloric and hydrofluoric acids. Monel has a better high-temperature resistance to cooling water than does 70/30 copper-nickel. Monel cladding and Monel trays are commonly specified at the top of crude towers to resist HCl vapor and where the temperature is below 205 oC (400 oF). Over 205 oC (400 oF), nickel-based alloys are attacked by H 2S. For high temperature strength and/or corrosion resistance, several nickel-based alloys are used for special applications such as expansion bellows in FCC process units (Alloy 625), stems in flue gas butterfly valves (Alloy X 750), and in springs exposed to high-temperature corrosives (Alloy X). Titanium has excellent resistance to seawater, and it is also used for tubing in crude tower overhead condensers. Overall, the use of titanium is extremely limited due to the high cost and the availability of suitable, more economic alternatives.

CORROSION MANAGEMENT Economics of Refining Although the individual components are quite complicated, the large-scale economics of refining operations can be defined in simple terms. Gross margin is the difference between the output of a refinery (refined products) and the cost of the feedstock (crude oil and other chemicals). The net margin is the gross margin minus the operating costs. Figure 4 illustrates the last 20 years of margins in the refinery industry.

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Figure 4.

Margins of U.S. refiners since 1977.(8)

Capital Expenditures The capital intensity of a process refers to the amount of capital needed to produce a unit of product. For U.S. refining operations, capital intensity is measured by the ratio of net property, plant, and equipment (i.e., the balance sheet value of productive long-term assets adjusted for depreciation) to refinery capacity (barrels per calendar day of crude distillation capacity). Adjusted for general inflation (via the implicit gross domestic product deflator), the refiners’ capital expenditures for U.S. refining doubled from 1989 to 1992. A surge in capital expenditures occurred in the late 1970s through the early 1980s. During this period, the major U.S. companies upgraded their refineries to process heavier, more sulfurous crude oil inputs into relatively greater proportions of lighter products, particularly gasoline. These investments were largely premised on wide price spreads between higher and lower quality crude oils and lighter and heavier refined products. The decline in the price spread between differing qualities of crude oils in the 1990s contributed to the overall deterioration in the gross margin evidenced in figure 4. The price decline between crude oils of differing qualities was especially adverse for refiners who invested heavily in refinery upgrades to yield higher proportions of light products. The refiners directed much of the surge in their refining investments in the late 1970s to the early 1980s toward increasing their capability to process heavier, more sulfurous crude oils. For example, the capacity for increased processing of heavy sour crude inputs, relative to basic crude distillation capacity, rose from 22 percent in 1974 to 30 percent in 1980 to 47 percent in 1993. Unlike the earlier surge in refinery investments, the upswing in capital expenditures in the 1990s appeared to be largely driven by increased expenditures for pollution abatement. (8) In particular, the Clean Air Act Amendments of 1990 required production of oxygenated gasolines by late 1992, lower sulfur diesel fuels by late 1993, and reformulated gasoline by January 1, 1995. The share of total U.S. refining capital expenditures for pollution abatement increased from slightly more than 10 percent shortly before the Clean Air Act Amendments of 1990 to more than 40 percent in recent years. Although pollution abatement requirements clearly reduced the rate of return to refining/marketing assets, these requirements appear to account for only a small part of the steep decline in the rate of return to U.S.

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refining/marketing operations in the 1990s. The increase in pollution abatement operating costs over this period was $0.07 per barrel of refined products sold, or 5 percent of the $1.52 per barrel decline in the net margin. The cost of extra capital expenditures for corrosion control can be included in the operational expenditures for refinery operations. If an operator chooses a corrosion-resistant alloy vessel for a refinery operation, then the extra annual cost of this vessel amortized over the life of the vessel is included in the operational expenditures. If an operator chooses carbon steel for the vessel, then the cost of corrosion control measures, such as anodes, chemical treatment, and monitoring, are the only measurable capital expenditures, but annual costs of upkeep will greatly increase operational expenditures. Economic justifications for such expenditures based on life-cycle costs continue to be part of corrosion control decisions for refinery operations.

Operational Expenditures The operating costs of refineries have steadily decreased in recent years due to technologica l advances and improvements in efficiency. The 1996 operating costs were an average of $5.51 per barrel (bbl). (9) It should be noted that direct costs for corrosion prevention and mitigation are extremely difficult to obtain, as these are kept very “close to the vest” by the refining industry. While the reasons for this are unclear, it can be assumed that the intense scrutiny that the entire petrochemical industry undergoes by environmental regulators and community watchdogs has created a situation in which refiners prefer not to divulge the magnitude of their corrosion problems. Thus, information for this sector has been gathered from a combination of some published surveys and government sources. One particular study(10) focused on operating costs at a single small refinery (53,000 barrels/day), concentrating on the costs related to environmental protection. This project quantified air emissions, water discharges, and other wastes generated at the facility. Moreover, it identified a range of options to reduce or prevent those releases, some of which appeared more cost-effective than those required by existing rules. At most refineries, operating costs are dominated by crude oil. Even small fluctuations in the price of crude oil can overshadow other operating costs of the refinery. As a result, it is customary at the refinery level to track "non-crude operating costs," excluding the cost of feedstock. The non-crude operating costs of this refinery are shown in table 4.

Table 4.

Environmental costs at a refinery. PERCENTAGE OF 1992 NON-CRUDE OPERATING COSTS

ENVIRONMENTAL COST CATEGORY

Waste Treatment Maintenance Product Requirements Depreciation Administration, Compliance Sulphur Recovery Waste Disposal Non-Recurring Costs

4.9 3.3 2.7 2.5 2.4 1.1 0.7 4.0

TOTAL

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21.6%


The analysis estimates that total environmentally related costs are 21.6 percent of total non-crude operating costs. This total focuses primarily on capital, operating, and maintenance costs, and excludes contingent liability costs. If these costs were added, the total could be higher. Remediation expenses are recorded as "non-recurring costs." At the outset of the project, prior to conducting the analysis, environmental personnel informally estimated environmentally related costs at only 3 percent of the total non-crude operating costs. The magnitude of this difference, as well as the magnitude of the costs, indicates the value of identifying and tracking environmental costs. Maintenance costs (40 percent of which can be attributed to corrosion control) were estimated in the study (10) to be 3.3 percent (rounded to 3 percent) of the non-crude operating costs (table 4). When scaling up to all processes, this figure becomes: 0.03 fraction maintenance costs / 0.216 fraction environmental operating costs = 13.9% of the total operating costs due to maintenance $5.51/bbl operating costs (9) x 13.9% = $0.76/bbl maintenance costs $0.76/bbl maintenance costs x 40% due to corrosion control = $0.31/bbl operating costs for corrosion control When multiplied by the annual refinery output in the United States (5.7 billion barrels in 1997), the total cost of corrosion is ($0.31 x 5.7 billion = ) $1.767 billion per year. Vessel turnarounds, during which a processing vessel is emptied, inspected, repaired (if necessary), and put back into service, are mandatory in most cases due to U. S. Department of Transportation (DOT) regulations, primarily due to suspected corrosion damage inside the vessels. The costs for these operations are capitalized rather than included in the maintenance budget. One refiner estimated the total cost of the turnarounds at one of their refineries (a 260,000-bbl per day plant). (4) For the 3,000 processing vessels in this refinery, the total cost of turnarounds (5-year intervals for each individual vessel) was $118 million. Therefore, turnaround costs per barrel are: ($118,000,000/yr x 1 turnaround/5 years) / (260,000 bbl/day x 365 days/yr) = $0.25/bbl $0.25/bbl x 5.7 billion bbl/yr = $1.425 billion/yr for turnaround costs It should be noted that the trend in this activity is to move toward risk-based inspections and longer intervals (10 to 20 years) between turnarounds, which would significantly reduce the cost of corrosion maintenance, but increase the risk factor dramatically. The validity of this strategy is yet to be determined since the number of incidents with vessels outside the standard 5-year window will, in the future, help to define the p roper risk assessment.

Fouling In addition to mitigation and maintenance costs, the component of lost production due to corrosion and related problems must be considered. Fouling is the leading cause of diminished efficiency and productivity in refineries. Fouling is a deposit buildup in refinery processes that impedes heat transfer and/or reduces throughput. The energy lost due to this inefficiency must be supplied by burning additional fuel or reducing feed. It is estimated that the cost penalty of fouling is in excess of $2 billion annually. (11) While most fouling is caused by the deposition of heavier hydrocarbon species coming directly from the crude oil, a small undetermined percentage is related to corrosion and scale deposits, either actively participating as loose corrosion products or by scale acting as a substrate for hydrocarbon deposition.

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It is not known exactly how much fouling is related to corrosion versus that related to deposits, which affect only production rates. In the Drinking Water and Sewer Systems sector of this report (Appendix K), 50 percent of the costs of fouling were corrosion-related. Applying this factor to the water handling half of the refining process, the fouling-related corrosion costs in the refining sector are estimated to be $2 billion total costs x (1/2 fluid volume on water handling portion of refining process x 50% corrosion-related fouling costs = $0.5 billion. The estimate of the total annual cost of corrosion in refining applications is therefore: $1.767 billion operational costs for corrosion $1.425 billion turnaround costs $0.500 billion fouling costs $3.692 billion total cost of corrosion

Acidic Crude Oils As was discussed earlier, the refiners’ willingness to accept the more corrosive, acidic crude oils has heavily influenced U.S. refinery operations due to the lower cost of the feedstock. It can be anticipated that the growth in expenditures for corrosion can be expected to increase at the rate of the acidity in the crude oil refined. Therefore, this cost is part of the incremental maintenance cost, but in the near future, this will become a significant expenditure. For a typical carbon steel distillation column running acidic crude oil, there are additional costs associated with corrosion coupons and probes for monitoring, nondestructive testing and analysis, and chemical treatment. It should be noted that these costs, shown below in figure 5, have a wide variance associated with them.

12

10 s 8 t n e c , l b 6 b / t s o C 4

LO W

HIGH

2

0 C o up o ns

Figure 5.

P ro b es

Inhib ito rs

NDE

TO TA L

Incremental costs for corrosion control of carbon steel distillation column. (12)

The total cost for chemical treatment and all associated costs in the column range from $0.01 per bbl to a high of $0.11 per bbl. The figure is dominated by the chemical cost of the inhibitors. One study estimated that the total inhibitor cost associated with refinery operations in the United States was $246 million in 1998. (13)

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Alternatively, a metallurgical upgrade in susceptible areas for a $120,000-bbl per day refinery is estimated to be $12 million to $20 million, which could be economically feasible if the refinery has a long-term commitment to processing acidic crudes. Based on a 20-year design life (typical for alloys), the incremental costs become $0.18 to $0.30 per bbl (higher than the costs for treatment with corrosion inhibitor, but comparable). The increased chance for success with the use of alloys relative to corrosion inhibitor treatments makes these options worth further study.

Failure Costs The costs associated with catastrophic failures are very difficult to quantify since they include the costs of equipment replacement, production loss, and sometimes lost lives and litigation. In addition to the direct costs, indirect costs in publicity and increased scrutiny cannot be quantified. Analyzing processing industry data for August 2000, (14) 9 incidents (fire, explosion, leak, or emergency shutdown) were reported at refineries in the United States out of a total of 52 total incidents during that month. The cause of each is still being investigated, but all of these incidents resulted in some loss of production and a significant economic impact.

CASE STUDY Corrosion-Related Failure in Refinery This example clearly illustrates the hazards associated with amine absorber pressure vessels used in refineries. On July 23, 1984, a refinery at Romeoville, Illinois, owned and operated by the Union Oil Company of California, experienced a disastrous explosion and fire.(10,15) An amine absorber pressure vessel ruptured and released large quantities of flammable gases and vapors. Seventeen lives were lost, 17 individuals were hospitalized, and more than $100 million in damages resulted. The National Bureau of Standards (NBS) conducted a detailed investigation, which included chemical analyses, fracture mechanics analyses, stress corrosion cracking (SCC) susceptibility tests, and hydrogen cracking susceptibility tests. Preliminary NBS test results indicated that the subject plate material (ASTM A516, Grade 70 carbon steel) of the amine absorber was susceptible to hydrogen-induced cracking. Furthermore, repair welds that were done in the field and that had not been stress relieved, were especially sensitive to amine-induced corrosion and cracking. Figure 6 is an example of SCC both parallel and perpendicular to the weld, but not in the weld. The propagation of the crack clearly distinguishes SCC and reflects the different stresses along the weld area.

Figure 6.

Stress corrosion cracking near a weld.

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REFERENCES 1.

Energy and Environmental Profile of the U.S. Petroleum Refining Industry, report by Energetics Inc. for

the U.S. Department of Energy, 1998. 2.

Petroleum Industry of the Future, www.oit.doe.gov/petroleum, October 2000.

3.

Petroleum Supply Annual 1999, Vol. 1, Energy Information Administration.

4.

Petroleum Refining Corrosion, www.hghouston.com/refining.html#top, October 2000.

5.

R.A. White, Materials Selection for Petroleum Refineries and Gathering Facilities , NACE, 1998.

6.

Refinery Materials of Construction, www.corrmet.ndirect.co.uk/steel.htm.

7.

C. Shawber and P. Manning, Haynes International, Personal Communication, August and September 2000.

8.

The Impact of Environmental Compliance Costs on U.S. Refining Profitability, Energy Information

Administration, October 1997. 9.

D. Ditz, J. Ranganathan, and R. Banks, Green Ledgers: Case Studies in Corporate Environmental Accounting, World Resources Institute, May 1995.

10.

Reduced Corrosion in Amine Gas Absorption Columns,

www.hydrocarbonprocessing.com/archive/archive_99-10/99-10_reduce-mogul.htm, October 2000. 11.

Petroleum Project Fact Sheet – Fouling Minimization, U.S. Department of Energy, Office of Industrial

Technologies, January 1999. 12.

J. Skippins, D. Johnson, and R. Davies, Corrosion Mitigation Program Improves Economics for Processing Naphthenic Crudes”, Oil & Gas Journal 98, 2000.

13.

Corrosion Inhibitors Market Analysis , Publications Resource Group Inc., 1999.

14.

Process Incidents, August 2000, www.saunalahti.fi/ility/PI0008.htm, October 2000.

15.

V. Novokshchenov, Proceedings of Fifth Middle East Corrosion Conference, Oct 28-30, 1991, Manama, Bahrain, pp. 209-223

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Corrosion in Petroleum Refining

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