Corrosion Principles

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CORROSION PRINCIPLES

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Table of Contents

Page No.

1.0 Introduction

1

2.0 References and Definitions 1

2.1 References 1

2.2 Definitions 1

3.0 Why Metals Corrode 2

3.1 Corrosion Defined 2

3.2 Metal Ores 2

3.3 Chemical Free Energy

2

4.0 Nature of Corrosion Reaction 3

4.1 Corrosion by Water 3

4.2 Voltage Source 3

4.3 Electrical Circuits 3

4.4 Polarization

4

5.0 Nature of Metals 6 5.1 Inhomogeneities in Metal Surfaces

6

6.0 Effect of Electrolyte Composition 7

6.1 Conductivity 7

6.2 Hydrogen Ion Concentration (pH) 7

6.3 Dissolved Gases 8

6.3.1 Oxygen 8

6.3.2 Carbon Dioxide 9

6.3.3 Hydrogen sulphide 9

6.4 Chloride Ions

10

7.0 Physical Variables 10 7.1 Temperature 10

7.2 Pressure 11

7.3 Velocity 11

7.3.1 Erosion/Velocity (API RP 14E)

11

8.0 Forms of Corrosion 12 8.1 Uniform Corrosion 12

8.2 Pitting Corrosion 12

8.3 Bimetallic Corrosion 14

8.4 Flow Enhanced Corrosion (Erosion Corrosion) 15

8.5 Cavitation Corrosion 15

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Table of Contents

Page No.

8.6 Intergranular Corrosion 15

8.7 Hydrogen Induced Failures 16

8.8 Sulphide Stress Cracking 16

8.9 Stress Corrosion Cracking 17

8.10 Corrosion Fatigue 18

8.11 Microbiologically Influenced Corrosion (MIC) 19

8.12 Oxygen Corrosion 19

8.13 Sweet Corrosion (CO2) 20

8.14 Sour Corrosion (H2S) 21

Attachments:

1. Free Energies of Metal Oxides 22

2. Galvanic Series in Sea Water 23

3. Galvanic Corrosion Material Selection Guide 24

4a. Corrosion Cell 29

4b. Zinc-Copper Corrosion Cell 29

5. Electromotive Force Series 30

6a. Polarization Curve 31

6b. Corrosion Rate of Steel vs. pH 31

7. Corrosion Rate of Steel vs. O2 32

8. H2S Service Induced Cracking of Steels 33

9. Qualitative Categorization of Coupon Corrosion Rates for Oil Production Systems

34

10. Corrosion Rate of Steel vs CO2 35

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1.0 INTRODUCTION

This document is intended to provide operations personnel with an overview of the upstream oil and gas industry corrosion principles. The reader is encouraged to read about the subjects covered in this overview in more detail as required.

2.0 REFERENCES AND DEFINITIONS

2.1 References Corrosion and Water Technology for Petroleum Producers, L. W. Jones, 1988

Corrosion Engineering, M. G. Fontana and N. D. Greene,1978

Recommendations for Preventing Hydrogen-Induced Cracking (HIC) in Upstream Operations, EPR EPR.23PS.89

Corrosion Basics - An Introduction, NACE 1984

Corrosion Control in Petroleum Production, TPC 5, NACE 1979

Biologically Induced Corrosion, NACE 1985

Preparation and Installation of Corrosion Coupons and Interpretation of Test Data in Oilfield Operations, NACE RP0775

Petroleum Engineering, “Treating and Monitoring 45,000 B/D Injection Water”, D. Wheeler, Burmah Oil and Gas Co., 1975

Society of Petroleum Engineers, SPE No. 4064, “Efficient Removal of Oxygen in a Water Flood by Vacuum Deaeration”, W. J. Frank, Humble Oil and Refining Co., 1972

2.1 Definitions ρm - fluid/gas mix density (lb/ft3)

C - empirical constant, where C = 100, per API RP 14E for carbon steels or, C = 160+ for corrosion resistant alloys

d - pipe ID (inches)

E - potential (volts)

HIC - Hydrogen Induced Cracking

HRC - Rockwell “C” Hardness number

I - current (amps)

medium - in this text, a medium is the fluid to which a component is exposed and with which it may react (plural: media)

MIC - Microbiologically Influenced Corrosion

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P - pressure

QG - gas flow rate (mmscfd)

QL - liquid flow rate (BPD)

S - specific gas gravity (Air = 1.0)

S.G. - specific gravity of the liquid mix relative to water

SOHIC - Stress Oriented Hydrogen Induced Cracking

SRB - Sulphate Reducing Bacteria

SSC - Sulphide Induced Cracking

SWC - Stepwise Cracking

T - temperature

Ve - erosional flow velocity (ft/sec)

VG - gas velocity (ft/sec)

VL - fluid velocity (ft/sec)

Z - gas compressibility factor

3.0 WHY METALS CORRODE

3.1 Corrosion Defined In its broadest sense, corrosion can be defined as the deterioration of a substance or its properties because of a reaction with its environment. Primarily in the oilfield, it is more specific to say the concern is with the destruction of metal by a chemical reaction with a given environment, caused by existence of an electrochemical mechanism. This overview specifically addresses metallic corrosion. Deterioration of non-metallic materials is beyond the scope of this document.

3.2 Metal Ores Most metals are found in nature as ores which are typically metallic oxides or sulphides. Metals are refined from ores by reduction, a forcing of the metal ions to give up their charges and become metallic atoms in a regular lattice array. For this to take place, energy in the form of heat or electricity must be supplied. It is the energy stored in the metal during the refining process that provides the driving force for corrosion.

3.3 Chemical Free Energy It can be shown by chemical thermodynamics that the driving force for any chemical reaction is the chemical free energy. For any spontaneously occurring reaction, the free energy change is negative. If the calculation shows the free energy to be positive, the reaction cannot take place without an external

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source of energy. Attachment 1 shows the calculated free energy change for the formation of a number of metal oxides. What these numbers mean is that, from a free energy standpoint, aluminium will tend to form its oxide very easily, iron almost as easily, copper only to minor extent, and gold only with an input of energy. Since steel (iron) is our basic structural metal and its free energy is so negative, we are continually faced with the tendency of the metal to return to its oxide. It should be noted that the magnitude of ∆G does not alone determine the rate at which a metal returns to its oxide.

4.0 NATURE OF CORROSION REACTIONS

4.1 Corrosion By Water Nearly all corrosion problems which occur in oilfield production operations are due to the presence of water. In order to corrode, the metal surface must be in contact with a water phase. For example, if a well produces at a high oil-to-water ratio, very little corrosion is likely to occur because the water is mixed with oil as an oil-external emulsion. On the other hand, in low oil-to-water ratio wells, corrosion occurs because free water contacts the metal surface. Corrosion in the presence of water depends on electrochemical processes. Electric current flows and there must be a driving force and a complete electrical circuit.

4.2 Voltage Source The source of voltage (driving force) in the corrosion process is the energy stored during the refining process. Due to the difference of free energy values of various metals, these voltages are different for each metal. Potential values are a function of both the metal and the chemical and physical characteristics of the water. Attachment 2, the Galvanic Series, is a practical table where common metals and alloys are arranged based on their respective potentials in sea water. Attachment 3 is a guide that shows the probable effect of coupling two dissimilar metals in sea water.

4.3 Electrical Circuits The electrical circuit of the corrosion process consists of an anode, cathode, electrolyte and metallic return path (see Attachment 4a). • The anode is that portion of the metal surface that is corroded. It is the

point at which metal dissolves, or goes into solution. When metal dissolves, the metal atom loses electrons and is oxidised. The reaction for iron is:

Fe → Fe++ + 2e- (1)

The iron ion goes into solution and two electrons are left behind in the metal.

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• The cathode is that portion of the metal surface where reduction takes

place and does not dissolve. The electrons left behind by the oxidation reaction at the anode travel through the metallic path to the cathodic surface where they are consumed by reaction with an oxidising agent that must be present in the electrolyte. This consumption of electrons is called a reduction reaction. Three typical reactions are:

2H+ + 2e- → H2 (Acidic Solutions) (2)

With oxygen present: O2 + 4H+ + 4e- → 2H2O (Acidic Solutions) (3)

OR

O2 + 2H2O + 4e- → 4OH- (Neutral or Alkaline Solutions) (4) H+ and O2 are examples of the oxidising agents referred to above.

• A metallic return path is necessary for the electrons generated at the anode to travel to the cathode where they are consumed. Electrical current flow is actually this passage of electrons through the metallic path. In corrosion terminology, the conventional or positive current is usually used to indicate the direction of current flow. Therefore, corrosion currents flow from the anode to the cathode in the electrolyte and from cathode to anode in the metallic circuit. Corrosion of the metal occurs where positive current leaves the metal to the electrolyte. (See Attachment 4a.)

• In order to support the reduction and oxidation reactions and to complete

the electrical circuit, both the anode and cathode must be covered by the same electrolyte. Electrolytes conduct electricity because they contain ions. In oil and gas production, the most commonly encountered electrolytes are water solutions of salts and acids.

4.4

Polarization Attachment 4a shows a typical corrosion cell on the surface of a metal. As was explained in the previous Section, an electrical circuit is formed between the cathode and anode, thus allowing a potential difference to be established between them. It is this shift in potential as the corrosion current flows that is termed polarization. The effects of polarization are also important in galvanic (bimetallic) corrosion, which is more fully discussed in Section 8.3. To illustrate this, consider the experimental copper-zinc cell shown in Attachment 4b. If the circuit is open and no current is flowing, then the electrodes each have a characteristic potential as shown in Attachment 5. Attachment 6a shows a plot of those potentials at zero current on a potential versus current graph. When a small amount of current is allowed to flow through the external circuit,

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the potential of the electrodes changes slightly, the copper electrode becomes more anodic, and the zinc electrode more cathodic (as shown in Attachment 6a). As more current is allowed to flow, the potentials continue to change (polarize) and the potential difference between the two decreases to a value limited primarily by the resistance of the electrolyte solution (Re). If polarization is not taking place, then there is no corrosion. The magnitude of strength of a corrosion cell is determined by the difference in electrical potential between the anode and the cathode. This voltage difference is greatly influenced by the level of polarisation which may be achieved in the corrosion circuit. Several factors may reduce the polarisability of the corrosion circuit, such as: • a film of corrosion product on the metal

• build-up of a hydrogen gas layer

• presence of corrosion inhibitors

• presence of sulphate reducing bacteria

• increased pressure

• increased temperature

• increased electrolyte turbulence or velocity

• low resistivity of the electrolyte The result of a reduction in polarisability is a decrease in polarization. The passage of an impressed direct current will also have an effect on the level of polarization. The corrosion rate may rise or fall, depending upon the direction of the current.

In the absence of oxygen, hydrogen deposited on cathodes as the result of cell action (refer back to Attachment 4a) tends to remain as a polarizing film that resists additional hydrogen ions. The additional ions must seek points of entry more remote from the anode until the voltage (V) equals the current (I) times the resistance (R) according to Ohm’s law. Resistance is due to the metallic path, the electrolyte path and the polarization of the anode and the cathode. This relationship for multiple cell action is described by Kirchoff’s second law as: ∑ emf = ∑ IR (5)

OR

Ec - Ea = IRe + IRm (6) Where: Re = resistance of electrolyte

Rm = resistance of metal

Ec = effective polarized potential of the cathode

Ea = effective polarized potential of the anode

I = current flowing in circuit

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Corrosion will continue, but the rate will only change if the polarisability is altered hence producing a change in polarisation. This occurs when hydrogen is removed from the cathode. Once an E = IR steady state is reached, further cell action depends upon the rate of hydrogen removal from the cathode. That rate is largely controlled by the rate at which oxygen reaches the cathode. In oilfield operations, hydrogen removal from the cathode is usually accomplished by one of the mechanisms discussed in paragraph 4.3 above.

5.0 NATURE OF METALS

5.1 Inhomogeneities in Metal Surfaces Metal atoms do not necessarily dissolve at a single point on a metal surface, nor are cathode areas restricted to one area on the surface. The reason certain areas of the metal surface act as anodes centers on the inhomogeneities in the metal surface, in the electrolyte or both. Potential differences on the metal surface are a natural result and are a primary cause of the initiation of localized corrosion cells. The type of corrosion that occurs usually gives a clue as to the major cause. Commercial metals are not homogeneous but contain inclusions, precipitates and several different phases. Steel is an alloy of iron and carbon. Where pure iron is a relatively weak, ductile material, the alloy, steel, is a much stronger material. As a result of combining part of the iron with carbon, the resultant metal contains dissolved carbon and precipitated iron carbide (Fe3C). The iron carbide that has a lower tendency to corrode than pure iron is distributed within the iron as tiny microscopic islands. The Fe3C and pure iron are in electrical contact so when the steel is placed in an electrolyte, an electrical circuit is completed and current flows through thousands of microcells on the steel surface. The locations of the anodic and cathodic areas of the microcells may change as corrosion products accumulate shifting the anodic areas. In solid solution alloys, such as 304 or 316 stainless steel, or Monel 400, there may be potential differences arising from concentration differences from point to point. This concentration difference can be evident when metals are formed or reformed such as in castings or weldment of metals. Here is where an area relationship can be very harmful. If the anode is small compared to a large cathode, the corrosion may occur at a rapid rate due to the high current density on the anode. Local heating, such as welding, can result in changes of the nature of phases and their compositions or changes in grain size and grain boundaries creating differences in potentials. Intergranular attack may be accelerated by the potential differences between the grains and grain boundaries. Stress such as that applied during cold working or cold forming of the metal can set up potential differences along the surface of the metal. The stressed areas will be anodic to the unstressed areas. Scratches or abrasions on the metal surface will act in the same manner.

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6.0 EFFECT OF ELECTROLYTE COMPOSITION There are two aspects to the effects of electrolyte composition on the corrosion circuit. The first is the conductivity of the electrolyte and the effect of electrolyte on the base corrosion potential of the system. The second has to do with the presence or absence of oxidizing agents which are necessary for the cathodic portion of the corrosion cell. The anodic reaction cannot occur in the absence of a corresponding reaction at the cathode, regardless of the conductivity of the cathode.

6.1 Conductivity The electrical resistance of typical electrolytes is usually much higher than that of metal, therefore the resistance of the electrolyte will normally predominate in the corrosion cell reaction. The more conductive the electrolyte, the easier current can flow and the faster corrosion will occur. The amount of metal that dissolves is directly proportional to the amount of current flow between anode and cathode. For iron, one amp of current flowing for one year will result in the loss of 20 pounds (9.1 kg) of metal. It is important to remember that other factors will also have an impact on the corrosivity of the electrolyte, the conductivity only determining the ease at which corrosion currents are able to flow from anode to cathode.

6.2 Hydrogen Ion Concentration (pH) The pH of water is the negative logarithm of the hydrogen ion concentration: pH = -log (H+) (7) The greater the concentration of hydrogen ions, the more acid the solution and the lower the pH value. Hydrogen ions (H+) make a solution acidic and, therefore, force the pH towards zero. Hydroxyl ions (OH-) make a solution basic or alkaline and force the pH towards 14. The following lists the pH ranges for acidic, neutral, and alkaline conditions: The corrosion rate of steel usually increases as the pH of the water decreases,

pH Range Classification

< 7.0 Acidic

7.0 Neutral

> 7.0 Basic or Alkaline

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although extremely high pH solutions can also be corrosive (see Attachment 6b). The actual variation of corrosion rate with pH is dependent on the composition of the electrolyte. Since pH is a negative logarithmic function, a 10-fold reduction or increase in the hydrogen ion concentration is required to effect a pH change of one.

6.3 Dissolved Gases Oxygen, carbon dioxide, or hydrogen sulphide gases, when dissolved in water, increase its corrosivity. Dissolved gases are the primary cause of most corrosion problems in oil and gas production. The following paragraphs discuss each gas independently, but it is important to note that corrosion rates are also greatly influenced by physical variables such as temperature, pressure and velocity. Similarly, the Figures referred in these paragraphs are for specific conditions and are only intended to reflect the relative corrosion tendencies of each.

6.3.1 Oxygen Dissolved oxygen can cause severe corrosion at very low concentrations (less than 100 ppb or 0.1 ppm) and if either or both CO2 and/or H2S are present, it further increases their corrosivity. Attachment 7 is a composite graph from results of three different studies showing corrosion rates as a function of oxygen concentration: The solubility of oxygen in water is a function of pressure, temperature, and chloride content. Although it is not usually present in produced water, it is often introduced into oilfield water handling systems through failures to maintain oxygen free gas blankets on water handling vessels, vacuums created by positive displacement pumps or separator dump valves and/or exposure to the atmosphere. Water from lakes, streams, fresh water aquifers, rain or oceans usually will be oxygen saturated. Oxygen is more soluble at high pressures and lower temperatures and is less soluble in salt water than in fresh water. Oxygen accelerates corrosion under most circumstances because it is a strong and rapid oxidising agent in cathodic reactions. It will easily combine with electrons at the cathode and allow the corrosion reactions to proceed at a rate limited by the rate at which oxygen can diffuse to the cathode as discussed in Section 4.3: O2 + 4H+ + 4e- → 2H2O (Acidic Solutions) (3)

OR

O2 + 2H2O + 4e- → 4OH- (Neutral or Alkaline Solutions) (4)

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6.3.2 Carbon Dioxide When carbon dioxide dissolves in water, it forms carbonic acid, decreases the pH of the water, and increases its corrosivity. Corrosion in the presence of dissolved CO2 is referred to as sweet corrosion. There are numerous intermediate reactions which may be summarised as: CO2 + H2O → H2CO3 (Carbonic acid) (8) Fe + H2CO3 → FeCO3 + H2 (Iron Carbonate) (9) Factors governing the solubility of carbon dioxide are pressure, temperature, and composition of the water. Increased pressure, reduced temperature, or reduced water salinity each increase CO2 solubility which lowers pH. Many dissolved minerals buffer the water, thus minimising the effects of the above changes on pH reduction. Partial pressure of carbon dioxide can be used as a yardstick to predict the corrosiveness of a system. The partial pressure of carbon dioxide can be determined by the formula: CO2 partial pressure (psia pp) = Total pressure of gas (psia) x Mole fraction of CO2 in gas (10) In general, field experience indicates that, in the presence of an electrolyte, a partial pressure above about 30 psia may cause severe corrosion rates; between 7 psia and 30 psia may cause high corrosion rates and, less than 7 psia can still cause low to moderate corrosion rates.

6.3.3 Hydrogen Sulphide Hydrogen sulphide is soluble in water at pressures and temperatures common in oilfield operations and, when dissolved, behaves as a weak acid and usually causes pitting. Attack due to the presence of dissolved hydrogen sulphides is referred to as sour corrosion. The general corrosion reaction of steel is: H2O H2S + Fe → FeS + H2 (11) The iron sulphide produced generally adheres to the surface as a black scale and is cathodic to the steel that, in the presence of water, causes local severe corrosion in the form of deep pitting. However, in some instances, a thin iron sulphide scale may be relatively impermeable and actually slow down the corrosion reaction if erosion or some other mechanism does not remove the

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scale. Hydrogen sulphide can be generated by sulphate reducing bacteria (SRB). These bacteria contribute to corrosion by their ability to flourish in the absence of oxygen and their ability to change sulphate ions into hydrogen sulphide. The anaerobic conditions under a colony constitute a differential aeration cell with the bulk of the electrolyte, whereas their ability to produce hydrogen sulphide can cause severe localized corrosion. Refer to Section 8.11. Under certain pressure conditions, the hydrogen produced by the corrosion reaction can diffuse into the metallic lattice to cause embrittlement and subsequent cracking of susceptible metals. Refer to Section 8.7 and Attachment 8 for further discussion of this phenomenon.

6.4 Chloride Ions The most common electrolyte in oil production is water, and one of the most common ions in solution is the chloride ion. The chloride ion and its concentration has a major effect on the corrosion reactions as noted below: • An increase in concentration of chlorides increases the conductivity of the

solution and, therefore, allows corrosion currents to occur more rapidly.

• Chloride anions (negatively charged ions) tend to react very easily with cations (e.g. Fe+2) going into solution at the corrosion cell anode. These reactions, therefore, reduce polarization by allowing more cations to come into solution that increases the conductivity of the electrolyte.

• Although not a weight loss type corrosion, increased concentration of chloride ions increases the susceptibility of austenitic stainless steels to pit and crack. See Section 8.9 and also refer to the CIMS Metallurgy and Metallic Material Selection Guidelines.

7.0 PHYSICAL VARIABLES The variables of temperature, pressure, and velocity need to be accounted for when designing and implementing a corrosion control program. Correct application inhibitors and cathodic protection as corrosion control methods are very dependent on these variables. Temperature and pressure are interrelated, and the corrosivity of a system is further influenced by velocity.

7.1 Temperature Like most chemical reactions, corrosion rates generally increase with temperature. For example, in a system open to the atmosphere, the corrosion rate generally increases with increasing temperature until the concentration of dissolved gases decreases. In a closed system, this is not necessarily the case. In addition, many metallic alloys have minimum temperature limitations to

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prevent H2S service related cracking or other toughness problems.

7.2 Pressure Pressure also affects the rates of corrosion reactions. More gas goes into solution as the pressure increases, which may, depending on the dissolved gas, increase the corrosivity of the solution. The partial pressure of CO2 or H2S in a system is calculated as follows (refer to Section 6.3.2): partial pressure (psia pp) = Total absolute pressure (psia) x mol % CO2 or H2S (12)

7.3 Velocity Velocity has a significant effect on corrosion rates. Stagnant or low velocity fluids usually give low general corrosion rates, but pitting rates may be high. Corrosion rates generally increase with increasing velocity due to the depolarising effect on the cathode. High velocities and the presence of suspended solids or gas bubbles can lead to erosion corrosion, impingement, or cavitation. On the other extreme, oil, gas, or multi-phase pipelines operating at low velocities can result in corrosion along the bottom of a pipeline. The low flow condition is referred to as stratified or laminar flow which can be modelled using commercially available computer programs.

7.3.1 Erosion/Velocity (API RP 14E) Any fluid, gas, or multiphase pipeline or piping system should be operated below its calculated erosional velocity to prevent flow enhanced corrosion (erosion corrosion). API RP 14E, “Design and Installation of Offshore Production Platform Piping Systems,” provides the following equation to calculate the erosional velocity limit for any oil or gas piping:

Ve = C

m( )ρ12

(13)

where: Ve = erosional flow velocity (ft/sec) ρm = fluid/gas mix density (lb/ft3)

C = empirical constant, where C = 100, per API RP 14E for carbon steels or, C = 160+ for corrosion resistant alloys To calculate the density of two phase flow systems use:

ρm = ( )( ) ( )

( )12 409 27

198 7, . . .

.S G P SRP

P ZRT+

+ (14)

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where: S.G. = specific gravity of the liquid mix relative to water. S = specific gas gravity (Air = 1.0) R = gas/liquid ratio, ft3/bbl T = operating temperature, oR (same as oF + 460) Z = gas compressibility factor P = absolute pressure, psia (psig + 14.7) The actual velocity for oil or water piping/pipeline systems is:

VL = 0 012 2. Qd

L (15)

where: VL = fluid velocity (ft/sec) QL = liquid flow rate (BPD) d = pipe ID (inches) The actual velocity of gas piping/pipeline systems is:

VG = 60 2Q TZ

d PG (16)

where: QG = gas flow rate (mmscfd) VG = gas velocity (ft/sec) T = operating temperature Z = gas compressibility factor P = pressure (psig)

8.0 FORMS OF CORROSION

8.1 Uniform Corrosion Uniform corrosion is a weight loss corrosion where the area of metal loss is spread over a relatively large area so that the surface is attacked uniformly. This type of corrosion can be common in atmospheric corrosion of industrial or marine locations. Strong uninhibited acids will uniformly corrode steel very rapidly. In general, however, uniform corrosion occurs gradually thus failures take longer to occur. Uniform corrosion can be addressed in original design criteria by adding a corrosion allowance to design metal thickness. It is very important to recognize that this is not a corrosion control measure. The extra metal thickness simply allows more time for detection and mitigation before equipment capability or operations safety is jeopardized. Refer to Attachment 9 which lists the relative severity of average (uniform) corrosion rates.

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8.2 Pitting Corrosion Pitting is the most common cause of corrosion failures occurring in oil and gas industry production equipment. It occurs when the metal undergoing corrosion suffers metal loss at localized areas rather than over a large area or the entire surface area. The entire driving force of the corrosion reaction is concentrated at these localized areas. The corrosion rate at these areas will be many times greater than the average corrosion rate over the entire surface. Pitting is much more dangerous than uniform corrosion because the pitted area can become penetrated in a short time. Refer to Attachment 9 which lists the relative severity of corrosion pitting rates.

8.2.1 There are many causes of pitting in metals and alloys but, generally, they are caused by localized differences in the metal or in the electrolyte. Localized differences in electrolyte composition are referred to as concentration cells as discussed below: • Crevices promote formation of concentration cells. In oxygenated systems,

oxygen in the crevice may be consumed more rapidly than fresh oxygen can diffuse into the crevice. This difference in oxygen concentration at crevices and open areas creates a potential difference and results in corrosion of metal in oxygen-deficient areas. In addition, the pH in a crevice decreases compared to the bulk solution which may result in a more acidic environment thus accelerating corrosion. This is particularly the case with 300 (austenitic) and 400 (martensitic) series stainless steels.

• When metal surfaces are uniform and the electrolyte contains varying amounts of dissolved oxygen, oxygen concentration cells occur. An example is a bare or poorly coated pipeline buried under a paved or compacted road. Under the road, the soil is not well aerated, but on either side of the road the soil is well aerated. Locally, severe attack can occur on the pipe at the edge of the road in the transitions from the compacted nonaerated soil to the loose, aerated soil.

• The deposition of a solid on a metal surface can cause increased corrosion under the deposit due to differential oxygen concentration. In addition, sulphate reducing bacteria may thrive under these deposits magnifying the corrosion process by creating hydrogen sulphide.

8.2.2 A common cause of pitting in carbon steel is the formation of local cells due to

the partial breakdown or destruction of protective scales. When a corroding metal becomes covered with a corrosion product that is dense, impermeable and adherent, the product protects the metal from its environment. Localized removal of this protective scale may precipitate the onset of preferential corrosion of the exposed metal surfaces. If the scale is a conducting scale (e.g. FeS), then damage to it could result in intense attack of the area that lost its protective scale layer. This is the classic pit scenario. In the case of detachment of a conducting scale, or removal of a non-conduction scale (e.g. calcium carbonate), then there should be little attack at the damage scale area, although the attack may be greater beneath a detached scale.

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8.2.3 Stainless steels are the most susceptible ferrous alloys to pitting, primarily because of the very properties that make them stainless. Stainless steels derive their corrosion resistance from the formation of a thin iron chromium oxide film and the ability to maintain that film. If the film becomes destroyed at local areas, those areas become anodic and pitting results.

8.3 Bimetallic Corrosion When two dissimilar metals are placed in electrical contact in electrolyte containing an oxidizing agent, the more reactive one will corrode and the other may either not corrode at all, or will corrode at reduced rate, depending upon the extent of polarization of the cathode (see Attachments 3 and 4). This coupling of dissimilar metals is referred to as a bimetallic couple or a galvanic cell. It can be destructive, accelerating the corrosion rate of the more reactive of the two metals.

8.3.1 The galvanic cell is used in a practical way in cathodic protection. When steel is connected to a more reactive metal, such as magnesium, the steel is the cathode and is protected; and the magnesium is the anode and corrodes.

8.3.2 The area principle implies that in galvanic corrosion, the cathode to anode ratio is of great significance in a galvanic cell with a large anode and a small cathode, corrosion is spread over a large area and very little corrosion damage will occur. However, in a cell with a small anode and a large cathode, corrosion is concentrated at the anode and severe corrosion damage will occur. Refer to Attachment 3.

8.3.3 It is important to know that coupling dissimilar metals together in a neutral pH, nonaerated fluid may not cause corrosion. The fluid has to be corrosive to at least one member of the dissimilar metal couple for bimetallic corrosion to occur.

8.3.4 Weld line corrosion in piping/pipelines and ring worm corrosion in downhole tubing are types of galvanic cells that are caused by the manufacturing process of the steel as discussed below: • When a metal is welded, the welding process results in localised heat,

creating a microstructure near the weld which differs from the microstructure of the parent metal. This difference in microstructure can create a potential difference and set up a corrosion cell. A similar problem can result from an improper choice of welding rods. In this case, the potential differences are due to the differences in the composition of the weld and parent metals.

• Ring worm corrosion is due to the upsetting process in the manufacture of

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downhole tubing and usually occurs as sweet corrosion (See Section 8.13). The heat required in upsetting causes the transition zone in the heated end, or upset, to have a different grain structure from the rest of the pipe body. A transition zone in grain structure near the upset runout, typically within 18” of the pin end, can cause a potential difference and set up a local corrosion cell. Fully normalizing the tubing after the upset process will return uniformity to the grain structure which will eliminate this corrosion potential.

8.4 Flow Enhanced Corrosion (Erosion Corrosion) Most metals depend on the formation and maintenance of a protective scale for corrosion resistance. Removal of this scale at local areas can lead to accelerated attack. High velocity flow or turbulence can erode away the protective scale to expose fresh metal to corrosive attack. The combination of the erosion of the scale and corrosion of the underlying metal is termed flow enhanced corrosion (erosion corrosion). Carbon steel piping systems and downhole tubing must be designed to maintain velocities below the API RP 14E critical velocity discussed in Section 7.3.1.

8.4.1 A phenomenon similar to erosion-corrosion, but more localized, is know as impingement. This occurs when a stream impinges upon a metal surface and breaks down protective films at very small areas. The resulting attack is characteristically in the form of pits elongated and undercut on the downstream end. Impingement often results from turbulence surrounding small particles adhering to a metal surface.

8.5 Cavitation Corrosion Although corrosion normally plays a minor role in the rate of cavitation damage, it is important to recognize its effect. Cavitation is the formation and collapse of vapour bubbles in fluids because of rapid changes in pressure. It can occur whenever the absolute pressure at a point in the liquid stream is reduced to the vapor pressure of the fluid so that bubbles form, and this is followed by a rapid rise in pressure resulting in bubble collapse. Cavitation damage is the wearing away of metal from repeated impact blows from collapse of bubbles within a fluid, such as that caused when a pump’s suction is starved.

8.6 Intergranular Corrosion Intergranular corrosion is preferential attack of a metal’s grain boundaries. Intergranular corrosion can occur in the absence of stress. It is caused by precipitation of impurities at grain boundaries, or changes in the alloying elements at the grain boundary areas. For example, depletion of chromium in the grain boundary of stainless steel can be lead to intergranular corrosion.

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Proper heat treatment or control of chemistry of the steel can reduce the susceptible grain boundary constituent and render the alloy more resistant to intergranular attack.

8.7 Hydrogen Induced Failures Hydrogen atoms may be produced on a metal surface in an aqueous environment by a corrosion reaction, cathodic protection, electroplating or acid pickling. Some of the hydrogen atoms combine to form gaseous molecular hydrogen (H2) on the metal surface and are released to the environment. A portion of the atoms are absorbed by the metal and this entry of hydrogen atoms into the metal may have some very undesirable effects. Hydrogen-induced cracking (HIC) and hydrogen embrittlement are two types of phenomena that can occur.

8.7.1 Hydrogen entry into low strength steel can result in HIC if there is a microscopic defect in the steel such as a lamination or inclusion. HIC is typically manifested as blisters, stepwise cracking (SWC), and/or stress oriented HIC (SOHIC). A lamination or void in the steel provides a place for hydrogen atoms to combine, form hydrogen gas, and result in sufficient pressure to cause blistering. Blisters are visible on a surface when the voids responsible for the HIC are near the surface. SWC is initiated at inclusions on different planes through the metal wall. The initial crack propagation occurs along the axis of the inclusion and then interconnects with cracks on other planes to form the SWC. The term SOHIC is used to indicate that the characteristics of HIC have been influenced by applied or residual stresses, usually from welding. These stresses will cause cracks to initiate and propagate perpendicular to existing HIC. This can result in cracks that eventually propagate through the steel wall (see Attachment 8). Solutions to HIC include controlling the metal chemistry to minimise the affects of inclusions or laminations, and controlling corrosion with coating or inhibitors to minimise the generation of hydrogen.

8.7.2 Hydrogen entry into high strength steels or steels with a hardness above 22 HRC can result in hydrogen embrittlement. A material can fail in a brittle manner at stresses well below its nominal yield strength. Hydrogen embrittlement is normally limited to high strength materials due to the fact that these materials reach tensile strengths high enough to initiate the failure mechanism. It is often very difficult to distinguish between failures caused by hydrogen embrittlement or stress corrosion cracking. The susceptibility to hydrogen embrittlement increases with increasing strength and hardness. Even though a steel contains hydrogen, no permanent damage occurs unless sufficient stress is applied to cause the steel to crack. Therefore, in many cases, the hydrogen can be baked out by heat treatments, restoring the original properties of the metal.

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8.8 Sulphide Stress Cracking (SSC)

Sulphide stress cracking is a spontaneous brittle failure that occurs in steels and high strength alloys when exposed to moist hydrogen sulphide. This phenomenon is also referred to as sulphide cracking, sulphide corrosion cracking, and sulphide stress corrosion cracking. All the names refer to the same corrosion phenomenon, hydrogen embrittlement (see Section 8.7.2), which requires that hydrogen sulphide be present, water (even in minute quantities) a high strength material, and tensile stress (either applied or residual). Sulphide stress cracking (SSC) may occur very rapidly after exposure to a sour environment, or it may take place after considerable time has passed. Refer to NACE MR0175 (latest revision) for guidelines on selecting materials resistant to SSC. Also, refer to Attachment 8. Materials are susceptible to SSC when the following conditions are met : • Plain carbon steels with maximum yield strengths above 90,000 psi and

hardness above HRC22 are susceptible to sulphide stress cracking at temperatures below 190oF (88oC). The higher the steel strength, the shorter the time to failure. A hardness of HRC22 is not an absolute value; alloying with other materials can cause failures below this level, and for certain heat treatments, the permissible hardness level can be increased.

• The time to failure decreases as the stress level increases. The stresses can be applied or residual.

• The time to failure decreases as the hydrogen sulphide concentration increases. Failure can occur at H2S partial pressures as low as 0.05 psia pp, and even lower if the steel hardness greatly exceeds HRC22.

• Cracking tendency increases as the pH decreases. The tendency to failure can be drastically reduced if the pH of a solution is maintained above 9.0. This is why high pH drilling fluids are used to drill sour wells.

• Cracking susceptibility decreased rapidly above a temperature of 150oF (65oC).

8.9 Stress Corrosion Cracking (SCC) Stress corrosion cracking is caused by the synergistic action of a corrosive medium and applied tensile stress; that is, the combined effect of the two is greater than the sum of the single effects. In absence of the corrodent, the alloy could easily support the stress. The stress is always a tensile stress and can be either applied or residual. When a metal suffers stress corrosion cracking, metal loss from corrosion is generally very low, although most likely, pits will occur and the cracks will develop in the base of the pits. All alloys are subject to stress corrosion cracking. Stress corrosion cracking results from exposure of a particular alloy to a particular corrosive medium. No one corrosive medium causes stress corrosion in all alloys, and most alloys are subject to attack in only a few specific corrosive media. Because stress corrosion cracking tendency increases with increasing stress, one approach to prevent failure is to minimise stress. In some cases, shot peening to induce

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compressive stresses is used to reduce stress corrosion cracking tendencies. Increasing solution concentration increases stress corrosion cracking tendencies and, therefore, in environments with no electrolyte (i.e., dry gases), stress cracking will not occur.

8.9.1 The most common corrosive which cause stress corrosion cracking in carbon and low alloy steels are sodium hydroxide and nitrate solutions. Chemical inhibition and proper stress relieving are widely used to control cracking in these environments.

8.9.2 Stress Corrosion Cracking (SCC) of high strength steels occurs in salt solutions, moist atmospheres, and even in tap water if the steel is ultra high strength steel. Cracking tendency increases with the strength of the steel. Experience or testing is necessary to determine the corrosive and conditions which will cause cracking of high strength steels.

8.9.3 The hardenable stainless steels, which include martensitic stainless steel and precipitation hardening stainless steels, when treated to high hardness levels have tendencies to stress corrosion crack. To reduce this tendency, the strength of the steels can be reduced by heat treating the alloys.

8.9.4 Austenitic stainless steels are susceptible to both transgranular and intergranular cracking. These steels are most susceptible in electrolytes containing chloride ions. Therefore, austenitic stainless steels are not recommended for use in chloride containing environments at temperatures above about 150oF (65oC). Hot caustic solutions are also a source of cracking for austenitic stainless steels; however, these steels will resist attack by caustic at low temperatures and concentrations. Refer to CIMS-MS-1.0, Metallurgy and Metallic Material Selection Guidelines.

8.10 Corrosion Fatigue When metals are repeatedly stressed in a cyclic manner, they will fail in a brittle manner at stresses far below the yield or tensile strength of the material. There exists a limiting stress below which steel may be cyclically stressed indefinitely without failure. This stress is called the endurance limit and is always lower than the yield and tensile strengths. The fatigue life of metal is substantially reduced when the metal is cyclically stressed in a corrosive environment. The simultaneous occurrence of cyclic stress and corrosion is called corrosion fatigue, and the steel no longer exhibits an endurance limit.

8.10.1 In corrosion fatigue, the corrosivity of the environment is extremely important. The presence of dissolved gases especially oxygen carbon dioxide or

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The presence of dissolved gases, especially oxygen, carbon dioxide or hydrogen sulphide, results in a pronounced reduction in fatigue life. Pitting or localized attack is most damaging to fatigue life, but even slight general corrosion will substantially reduce time to failure.

8.10.2 The corrosion fatigue performance of carbon and low alloy steels is independent of strength. Therefore, heat treating and alloying are used to increase corrosion resistance rather than enhance physical properties of the metal to increase fatigue life.

8.10.3 Surface conditions and stress history have a large bearing on fatigue life. Notches imposed in manufacturing or installation can decrease fatigue life. Also, the time available for corrosion damage to occur is extremely important in the corrosion fatigue behaviour of materials. Cycle frequency must also be considered as a major variable in corrosion fatigue performance.

8.11 Microbiologically Influenced Corrosion (MIC) Microbiologically influenced corrosion is pitting type corrosion. Microorganisms can exert considerable influence on the corrosion rate. The type of bacteria most commonly associated with corrosion in oilfield operations is the sulphate reducing bacteria (SRB). The metabolic process of the SRB reduces sulphates to sulphides and consume large quantities of hydrogen in the process to produce H2S. The polarization film in the cathode areas provide the hydrogen; therefore, the SRB act as strong depolarizes which causes accelerated corrosion rates. Bacteria can be controlled with bactericides. The following describes the SRB depolarization process: SO4

-2 + 8H+ → (SRB) → S-2 + 4H2O (Depolarization) (17)

In addition to the depolarizing effect, the production of hydrogen sulphide (H2S) will accelerate the corrosion process as shown below: Fe+2 + S-2 → FeS (Corrosion product) (18) or simplified H2O H2S + Fe → FeS + 2H (11)

In the presence of an oxidizing agent, the iron sulphide (FeS) deposited is

cathodic to the steel and a galvanic cell can be set up. This may result in pitting of areas where the iron sulphide film has bee partially detached from the surface of the steel. An iron sulphide film that is adherent and undamaged can actually provide protection to the steel.

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8.12 Oxygen Corrosion

8.12.1 Water produced with oil seldom contains dissolved oxygen; however, oxygen corrosion can be found in downhole and surface facility equipment. It is usually caused by careless operating techniques, faulty equipment or by oxygen rich wash water used for desalting. The presence of CO2 or H2S drastically increases the rate of oxygen corrosion. Attachment 7 shows the relation of dissolved oxygen content to the corrosion rate of steel in brine. Note that oxygen can be highly corrosive above 20 parts per billion. As discussed in Section 6.3.1, the cathodic corrosion reaction of steel in an oxygen environment is as follows: O2 + 2H2O + 4e- → 4OH- (Acidic Solutions) (3)

OR

O2 + 4H+ + 4e- → 2H2O (Neutral or Alkaline Solutions) (4)

8.12.2 Oxygen corrosion is generally an external problem in primary production equipment. In areas of high relative humidity, such as offshore structures, serious atmospheric pitting and overall corrosion can occur. The presence of accumulated solids can absorb water from the air, thus increasing the rate of corrosion by keeping the surface wet.

8.12.3 Oxygen in oilfield brine or flood water is a major cause of corrosion in waterflood injection equipment. Rapid perforation of the metal, obstruction of flow, and formation plugging by the corrosion products can occur. Oxygen can also cause injection well plugging if the injected water contains dissolved iron or manganese that react with the oxygen to form insoluble compounds.

8.12.4 Corrosion of offshore structures is divided into four areas of attack and is due to oxygen corrosion in each zone. The mud zone, that portion below the mud line, may suffer the least attack because of the high resistivity of the mud and little dissolved oxygen. This, of course, will not be the case where microbiologically assisted corrosion can take place. The submerged zone is always covered by water and the corrosion tends to be uniform, generally shallow pits. The splash zone, that area which is alternatively wetted by wave action, tends to be the most corrosive zone. The atmospheric zone may appear dry but, especially near the water surface and on the underside of members, the humidity is always close to 100% so the surfaces remain moist.

8.13 Sweet Corrosion Sweet corrosion results from the presence of water containing dissolved carbon dioxide. Dissolved carbon dioxide (CO2) in water decreases the pH of the water and increases its corrosivity. Refer to Attachment 10. The following shows

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how carbon dioxide results in the corrosion of steel: CO2 + H2O → H2CO3 (Carbonic Acid)

Fe + H2CO3 →FeCO3 + H2 (Iron Carbonate) It should be noted that the corrosion rates experienced in reality are higher than indicated by these summary reactions.

8.13.1 Corrosion in the tubing of gas condensate wells usually takes the form of deep pits with steep, undercut sides. This is sometimes referred to as “mesa” corrosion due to the shape of the pitting profile, i.e. areas of unattacked metal adjacent to pitted areas. The pits may penetrate the wall completely in a relatively short period of time. This pitting is caused when the carbon dioxide dissolves in water droplets that condense on the tubing wall. The tubing below the point of condensation may relatively corrosion free.

8.13.2 The most serious sweet oil corrosion problem can usually be found in gas lift wells. They are usually high water producers, and corrosion can be accelerated if the injected gas lift gas contains carbon dioxide and/or small amounts of oxygen.

8.14 Sour Corrosion Corrosion caused by hydrogen sulphide dissolved in water is referred to as sour corrosion. Refer to Section 8.11.

8.14.1 In oil well tubing, hydrogen sulphide can cause the development of scattered pits with cone shape sides leading to a rounded bottom. Black iron sulphide (FeS) scale will usually be present. The cathodic nature of the iron sulphide scale results in the pitting of the underlying steel.

8.14.2 Equipment in high-pressure sour gas wells may fail due to sulphide stress cracking, hydrogen embrittlement, or hydrogen induced cracking. Severe pitting corrosion can also occur in sour gas wells.

8.14.3 Corrosion on the interior of oil or sour water storage tank roofs (fixed roof design tanks) begins when condensed water droplets are saturated with hydrogen sulphide. The extensive pitting which results can perforate the tank deck. The interior bottoms of oil storage tanks are also subject to attack because of the layer of water which usually forms at the bottom under the oil. Additionally, corrosion scale falling from the top to the bottom of the tanks may cause corrosion concentration cells. Corrosion of the shell of oil tanks is normally negligible. However, sour saltwater tanks will be subject to roof, wall, and floor internal corrosion.

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ATTACHMENT 1 (Section 3.3)

FREE ENERGIES (KINETICS) OF FORMATION OF METAL OXIDES

Symbol Metal Oxide Calories/Mole (∆G)

Al2O3

Aluminium Oxide

-376,700

Fe2O3

Ferric Oxide

-177,100

MgO

Magnesium Oxide

-136,130

ZnO

Zinc Oxide

-76,080

CuO

Cupric Oxide

-30,400

Ag2O

Silver Oxide

+2,600

Au2O3

Auric (Gold) Oxide

+18,810

Notes:

1. For example, aluminum will tend to form its oxide very easily, iron almost as easily, copper only to a minor extent, and gold only with an input of energy.

2. The magnitude of ∆G does not alone determine the rate at which a metal returns to its oxide.

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GALVANIC SERIES IN SEAWATER

VOLTS: SATURATED CALOMEL HALF-CELL REFERENCE ELECTRODE +0.2 +0.1 0.0 -0.1 -0.2 -0.3 -0.4 -0.5 -0.6 -0.7 -0.8 -0.9 -1.0 -1.1 - 1.2 -1.3 -1.4 -1.5 -1.6 -1.7

Alloys are listed in the order of the potential they exhibit in flowing sea water. Certain alloys indicated by the symbol: in low-velocity or poorly aerated water, and at shielded areas may become active and exhibit a potential near -0.5 volts.

ZincBerylliumAluminium Alloys

Cadmium

Mild Steel. Cast IronLow Alloy Steel

Austenitic Nickel Cast IronAluminium Bronze

Naval Brass, Yellow Brass, Red Brass

Tin

CopperPb-Sn Solder (50/50)

Admiralty Brass, Aluminium Brass

Tin Bronzes (G & M)

Stainless Steel - Type 410, 416Nickel Silver90-10 Copper-Nickel80-20 Copper-Nickel

Stainless Steel - Type 430

Lead70-30 Copper - Nickel

Nickel - Aluminium BronzeNickel - Chromium Alloy 600

Silver Brazed AlloysNickel 200

SilverStainless Steel - Types 302, 304, 321, 347

Nickel - Copper Alloys 400, K-500Stainless Steel - Types 316,

Alloy "20" Stainless Steels, cast and wrought

Nickel-Iron-Chromium Alloy 825Ni-Cr-Mo-Cu-Si Alloy B

TitaniumNi-Cr-Mo Alloy C

PlatinumGraphite

Magnesium

Manganese Bronze

Silicon Bronze

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ATTACHMENT 3 (Page 1 of 5) (Section 4.2 and 8.3.3)

CORROSION OF GALVANIC COUPLES IN SEA WATER AT 40- 80ºF (4-27ºC)

METAL CONSIDERED COUPLED Note: These Numbers correspond with the numbers and alloy designations listed in the left column.WITH 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32

S

1 Magnesium Alloys EL x xS x

2 Zinc E x x xLS x

3 Beryllium E x x xL x x xS x

4 Aluminum Alloys E x xL x x x x x x x x x xS x x x

5 Cadmium E x xLS x

6 Mild Steel, Wrought Iron E xLS x x

7 Cast Iron, Flake or Ductile E x xL x x x x x x x x x x x x x x x x x

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S x

8 Low Alloy High Strength Steel E x x xL xS x x x

9 Austenitic Cast Iron, Types 1 & 2 E x x x x xL x

10 Naval Br (CA464), Yel. Br (CA268), S x x Al Br (CA687), Red Br(CA230), E x x x x x x x x x x x x x x x x Adm'ty Br (CA443), Mn Bronze L x x x x x x x x x x x x x x x

S x x x x x

11 Tin E x x x x x x x x x x x x x x x x xL x x x x x x x x x x x x x x x xS x x x

12 Copper (CA102, 110), E x x x x x x x x x x x x x x xSi Bronze (CA655) L x x x x x x x x x x x x x

S x x x x x x x x x x

13 Lead -Tin Solder E x x x x x x x x x x xL x x x x x x x x x x xS x x x x x x x x x x x x x x x x

14 Tin-Bronze (G&M) E x x x x x x x x x x xL x x x x x x x x x x

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S

15 Stainless Steel, 12-14% Cr E(AISI Types 410,416) L

S x x x x x x x x x

16 Nickel Silver (CA 732, 735, 745, E x x x x x x x x x x x x x752, 764, 770, 794) L x x x x x

S x x x x x x x x x

17 90/10 Copper-Nickel (CA706) E x x x x x x x x x xL x x x xS x x x x x x x x x

18 80/20 Copper-Nickel (CA710) E x x x x x x x x x xL x x x xS

19 Stainless Steel, 16-18% Cr E(AISI Type 430) L

S x x x x x x x x x

20 Lead E x x x x x x x x x x x xL x x x x x x x x xS x x x x x x x

21 70/30 Copper-Nickel E x x x x x x x x x x x(CA715) L x x x

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S x x x x x x x

22 Nickel-Aluminium-Bronze E x x x x x x x x x x x x xL x x x x xS x x x x x x x x x x x

23 Nickel Alloy 600 E x x x x x x x x x x x x x x x xL x x x x x x xS x x x x x x x x x x x x x x x x x x

24 Silver Braze Alloys E x x x x x x x x x x x x x x x xL x x x x x x x x x x x xS x x x x x x x x x

25 Nickel E x x x x x x x x x x x x x x x x x xL x x x x x x x xS x x x x x x x x x x x x x x

26 Silver E x x x x x x x x x x x x xL x x x x

27 Stainless Steel, 18 Cr, 8 Ni S x x(AISI Types 302, 304, 321, 347) E x

L xS x x x x x x

28 Nickel Alloys 400 E x x x x x x x x x x x x x x xand K-500 L x x x x x

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S x x x x x x x x x x x x

29 Stainless Steel, 18 Cr, 12 Ni-Mo E x x x x x x x x x x x x x x x x(AISI Types 316, 317) L x x x x x x x

S x x x x x x x

30 Stainless Alloy 20, E x x x x x x x x x x x x x x x xNickel Alloy 825 L x x x x x x

S x x x x x x x

31 Titanium, Nickel Alloys C, E x x x x x x x x x x x x x x x x x x x xC-276, 625 L x x x x x x x

S x x x

32 Graphite, Graphitized Cast Iron E x xL x x

KEY:

● UNFAVORABLE - Normal deterioration of either material may be increased moderately or severely. x UNCERTAIN - Direction and/or magnitude of effect on normal behavior may vary, depending on circumstances.

COMPATIBLE - Deterioration of either material is normally within tolerable limits. S - Exposed are of the metal under consideration is small compared with the area of the metal with which it is coupled. E - Exposed are of the metal under consideration is approximately equal to the area of the metal with which it is coupled. L - Exposed are of the metal under consideration is large compared with the area of the metal with which it is coupled. Source: Galvanic Corrosion Indicator, International Nickel Co. and NACE Corrosion Engineer's Reference Book, 1983 Edition.

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ATTACHMENT 4 (Sections 4.3 and 4.4)

4a : Corrosion Cell (Section 4.3)

Electrolyte

Conventional Current Flow

Fe++ H+ OH-

e- e- Electrons e- Anode (Corrosion area) Flow Cathode

4b : Zinc-Copper Corrosion Cell (Section 4.4)

Zn Cu Electrolyte Anode Cathode

V

A

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ELECTROMOTIVE FORCE SERIES

Symbol

Metal Standard Reduction

Potential Volts at 25oC (vs Normal Hydrogen Electrode)

K Potassium -2.92 Greatest Tendency

Ca Calcium -2.87 to

Na Sodium -2.71 Corrode

Mg Magnesium -2.34

Be Beryllium -1.70

Al Aluminium -1.67

Mn Manganese -1.05

Zn Zinc -0.762

Cr Chromium -0.71

Fe Iron -0.44

Cd Cadmium -0.402

In Indium -0.346

Co Cobalt -0.277

Ni Nickel -0.250

Sn Tin -0.136

Pb Lead -0.126

H Hydrogen 0.00

Cu Copper 0.345

Hg Mercury 0.799

Ag Silver 0.800 Least Tendency

Pt Platinum 1.20 to

Au Gold 1.42 Corrode

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6a : Polarisation Curve (Section 4.4)

Potential Cu E corr I Re corr Re = Electrolyte Resistance Zn Current corr

6b : Corrosion Rate of Steel vs pH (Section 6.2)

Corrosion Rate 4 6 9 14 pH

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ATTACHMENT 7 (Sections 6.3.1 and 8.12)

Relation of Dissolved Oxygen to the General Corrosion Rate of Steel

Corrosion Rate (mpy) 30 25 20 15 10 5 Note change of scale O 0 20 50 75 125 1000 3000 4500 6000 8000 Oxygen Concentration (ppb) Burma Oil Exxon Data O&G Consultant

Note: Variation in values are due to differences in CO2/H2S content and accuracy of O2 measurement.

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ATTACHMENT 8 (Sections 6.3.3, 8.7.1 and 8.8)

H2S Service Induced Cracking of Plate Steel and Welds

Vessel ID in Sour Environment

Plate Steel Weld Heat Affected Zone (HAZ)

LEGEND: SOHIC - Stress Oriented Hydrogen Induced Cracking SSC - Sulfide Stress Cracking SWC - Stepwise Cracking

Laminations or Inclusions

SSC

Blistering

SWC

SOHIC

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QUALITATIVE CATEGORIZATION OF COUPON CORROSION RATES FOR OIL PRODUCTION SYSTEMS

Average Corrosion Rates

Pitting Rate

US Customary (mpy(1))

Metric (SI) (µm/a(2))

US Customary (mpy)

Metric (SI) (µm/a)

Low <1.0 <25 <5 <127

Moderate 1.0-4.9 25-126 5-7.9 127-201

High 5.0-10 127-254 8-15 202-381

Severe >10 >254 >15 >381

(1) mpy = mils per year (2) µm/a = micrometer per annum Note: This information is from NACE RP0775.

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CO2 General Corrosion Rate of Steel Corrosion Rate (mpy) 1000 150oF (65oC) 100 10 7 4 1 10 100 1000

CO2 Partial Pressure (psia)

77oF (25oC)

Non-Flowing 77oF (25oC)

Flowing

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Note: Graph is from a compilation of NACE data and is intended to show only the relationship of CO2 partial pressure to corrosion rate in flowing and non- flowing conditions. Do not use this figure to predict CO2 corrosion rates.

Documents

Corrosion Principles