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Prediction of Corrosion Rate and Its Affecting Factors on Surface Casing

Abstract

Corrosion is a physicochemical phenomenon affected by multiple factors. The effect of these factors on corrosion depends on their concentrations and interactions with each other. It is not possible to establish a direct one to one relationship between the values of a single parameter and the corrosion rate while neglecting other parameters. This requires calculation that considers interactions of different parameters with each other as well as their effect on the corrosion rate. As the impact of each parameter value on corrosion rate, considering value of other parameters, cannot be expressed with a simple equation, it is not possible to accurately and confidently generalize the effects of change in each parameter on the corrosion rate over an entire domain.

Surface casing of the wells can cause serious hazards and possible blowout as a result of early corrosion. In different areas in the world, surface casing collapses as a result of downhole corrosion, casing cracking, and rupture under high-pressure-corrosion. Surface casings or conductor pipes cannot be excavated deep for repair because of safety concerns. Corrosion problems of the surface casing result from non-fined manufactured joints, presence of salt water in some formation beds, and the cement section that isolates formation from the casing. In the shallow part of the casing, corrosion can result from either local or areal electrochemical reaction.

Keywords:

CO2 Corrosion, Surface Casing, Corrosion Rate, NORSOK M-506.

III

List of Symbols

A - the cross sectional area in m2

B(index) - the constant used in viscosity calculations

C(index) - the concentration of component

CRT - the corrosion rate at temperature T in mm/year

D - the pipe diameter in mm

FH2O - the water mass flow in humidity calculations

Ftot - the total mass flow in humidity calculations

K(index) - the equilibrium constant used in pH calculations

KSP - the equilibrium constant of iron carbonate

KT - the constant for the temperature T used in corrosion rate calculations

LTR - Linear Polarization Resistance

OCTG - Oil Country Tubular Goods

P - the total system pressure in bar

QG - the volumetric flow of gas in MSm3/d

QL - the volumetric flow of liquid (i.e. liquid hydrocarbons and water) in Sm3/d

R - μw/μo

Re - the Reynolds number

S - the wall shear stress in Pa

T - the temperature given in Kelvin.

Tc - the temperature given in °C

Tf - the temperature given in °F

Tstd - the temperature given in Kelvin at standard conditions (60 °F/15.55 °C)

Z - the compressibility of the gas

a - the fugacity coefficient

f - the friction factor

fCO2 - the fugacity of CO2 in bar

f(pH)T - the the pH factor at temperature T

k - the pipe roughness in m

I - the ionic strength given in molar

pCO2 - the CO2 partial pressure in bar

pH2O - the H2O vapour pressure in bar

T - the 20 °C, 40 °C, 60 °C, 80 °C, 90 °C, 120 °C or 150 °C

uGS - the superficial velocities of gas in m/s

uLS - the superficial velocities of liquid in m/s

um - the mixed velocity (m/s)

λ - the liquid fraction

μo - the viscosity of oil in Ns/m2

μG - the viscosity of gas in Ns/m2

μL - the viscosity of liquid in Ns/m2

μm - the mixed viscosity in Ns/m2

μrelmax - the maximum relative viscosity (relative to the oil)

μw - the viscosity of water in Ns/m2

ρG - the gas density in kg/m3

ρL - the liquid density in kg/m3

ρm - the mixed density in kg/m3

ρo - the oil density in kg/m3

ρw - the water density kg/m3

φ - the watercut

φc - the watercut at inversion point

III

Prediction of Corrosion Rate and Its Affecting Factors Introduction

1. Introduction

Corrosion is defined as the chemical degradation of metals by reaction with the environment. The destruction of metals by corrosion occurs either by direct chemical attack at elevated temperatures in a dry environment or by electrochemical processes at low temperature in a water-wet or moist environment.

Corrosion is the main threat to the petroleum industry. Its enormous impact is shown in Table 1.1. The values in the table may be assumed as average ones, because they vary regarding to the country and region e.g. in Western Europe corrosion-related failures come to ca. 25%, in the Gulf of Mexico and Poland about 50%, while in India they reach 80% (1)

Table 1.1 Failures in Oil and Gas Industry (2)

Type of failure

Number of Cases [%]

Corrosion (all types)

33

Fatigue

18

Mechanical damage/overload

14

Brittle fracture

9

Fabrication defects (excluding welding defects)

9

Welding defects

7

Others

10

The surface casing of wells located varies from a few hundred feet to as much as 5000 ft is prone to external corrosion attack at the splash zone around the wellhead region. The principal functions of the surface casing string are to: hold back unconsolidated shallow formations that can slough into the hole and cause problems, isolate the freshwater-bearing formations and prevent their contamination by fluids from deeper formations and to serve as a base on which to set the blowout preventers. It is generally set in competent rocks, such as hard limestone or dolomite, so that it can hold any pressure that may be encountered between the surface casing seat and the next casing seat.

The effect of corrosion in surface casing ultimately results in loss of load bearing capacity of the wellhead when the severity is very high. At rig based well reentry, collapse of the surface casing had occurred under the weight of the Blow Out Preventer (BOP) during its installation.

Historical records, field investigation and lab results from a previous study (SPE Paper 100432 and 108698) indicate the near surface casing corrosion is a result of cyclic or consistent moisture ingress of oxygenated water with the annulus between the Surface Casing and Conductor Casing. Elevated well operating temperatures in conjunction with an extremely corrosive environment caused by the salts that leach from the cement create a very aggressive corrosion environment.

Corrosion of Surface casing itself can be distinguished based on its environment conditions ( 1.1)

1. Corrosion due to atmospheric condition (Zone I)

2. Corrosion due to corrosive water (Zone II)

3. Corrosion due to cementing (Zone III)

4. Internal Corrosion

Prediction of Corrosion Rate and Its Affecting Factors Types of Casing Corrosion

2. Types of Casing Corrosion

Casing is made by steel consists of alloy of pure iron and small amounts of carbon present as Fe3C with trace amounts of other elements such as Manganese, Molybdenum, Chromium, Nickel, Copper with particular purposes.

In the most steel corrosion problems, the important differences in reaction potentials are not those between dissimilar metals but those which exist between separate areas interspersed over all the surface of a single metal. These potential differences result from local chemical or physical differences within or on the metal, such variations in grain structure, stresses and scale, inclusions in the metal, grain boundaries, scratches or other surface conditions.

Corrosion of surface casing is initiated by a wide variety of mechanisms. They can be grouped into three categories: electrochemical corrosion, chemical corrosion, and mechanical assisted corrosion (3).

2.1 Electrochemical Corrosion

Corrosion of casing is mostly electrochemical reaction composed of two half cell reactions, an anodic reaction and a cathodic reaction. The anodic reaction releases electrons, while the cathodic reaction consumes electrons (2.1 and 2.2). There are three common cathodic reactions, oxygen reduction (fast), hydrogen evolution from neutral water (slow), and hydrogen evolution from acid (fast).

The corrosion cell can be represented as follows:

* Anodic reaction:

Fe → Fe2+ + 2e-

* Cathodic reactions:

O2 + 4 H+ + 4e- → 2H2O (oxygen reduction in acidic solution)

1/2 O2 + H2O + 2e- → 2OH- (oxygen reduction in neutral or basic solution)

2H+ + 2e- → H2 (hydrogen evolution from acidic solution)

2H2O + 2e- → H2 + 2OH- (hydrogen evolution from neutral water)

Electrochemical corrosion occurs above all on the outer casing wall. This type of corrosion can be subdivided into the following three sub-groups.

2.1.1 Galvanic Corrosion

Galvanic corrosion is the most widespread type of corrosion and comes into being when two different metals or alloys develop a potential difference between them in a conducting electrolyte ( 2.3). The metal with the lower positive electrochemical potential acts as an anode and corrodes metal ions away to balance the electron flow. The second metal with higher positive electrochemical potential acts as a cathode and is protected from corrosion. If there were no electrical contact, both metals would be uniformly attacked by the corrosion. The severity of galvanic corrosion depends primarily upon the difference in potentials (the ranking of metal in galvanic series), their surface areas and environment (conductivity of the corrosive medium).

2.1.2 Crevice Corrosion

This is an example of localized attack in the shielded areas of metal assemblies, shielded areas of metal assemblies. Crevice corrosion is caused by concentration differences of a corrodant over a metal surface. Electrochemical potential differences result in selective crevice or pitting corrosion attack. This kind of corrosion occurs at casing in poorly cemented sections as well as at drillpipe joints, tubing and casing collars ( 2.4).

2.1.3 Pitting Corrosion

Pitting corrosion is similar to crevice corrosion and indicates a localized attack ( 2.5). Pitts are caused by a scratch, defect or impurity in casing. Pitting is one of the most dangerous forms of corrosion, because the metal loss can be rapid (even several mm per year) and often results in fast penetration. This type of corrosion is strongly affected by temperature.

2.2 Chemical Corrosion

Chemical corrosion occurs mainly on the inner casing wall. It is governed by the chemical reactions that can not generate the electrical current. Characteristic chemical attacks are primary encouraged by carbon dioxide, hydrogen sulphide and organic or inorganic acids.

2.2.1 CO2 Corrosion

CO2 corrosion or Sweet corrosion results from the presence of water containing dissolved carbon dioxide. Dissolved carbon dioxide in water decreases the pH of the water and increases its corrosivity. The following shows how CO2 results in the corrosion of steel:

CO2 (g) + H2O (l) → H2CO3 (aq) (Carbonic Acid)

Fe (s) + H2CO3 (aq) → FeCO3 (aq) + H2 (g) (Iron Carbonate)

CO2 Corrosion in surface casing 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 casing wall ( 2.6).

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.

2.2.2 H2S Corrosion

H2S Corrosion or sour corrosion is caused by hydrogen sulphide dissolved in water, which reacts with metal. Hydrogen ions are produced, which results in a more acidic environment, and low pH accelerates corrosion (especially in deep wells, where pH is further reduced by the pressure). Additionally iron sulphide is created, which at higher temperatures is cathodic to iron and leads to galvanic corrosion. Below is the chemical reaction to describe reaction between iron and H2S.

Fe (s) + H2S (g) →FeS (s) +2H

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.

2.2.3 Strong Acids Corrosion

Strong Acids Corrosion results from acids, which are pumped into the wells. They are mostly used to stimulate production like HCl in limestone formations or hydrofluoric acid for sandstones reservoir. Furthermore, dissolved oxygen stimulates corrosion in the presence of H2S and CO2.

2.3 Mechanical Assisted Corrosion

The surface casing is considered to have low load level. Since the setting depth of surface casing is low, its main load is produced by BOP during the drilling phase and by other casing string strings hanging on it during production. However the Stresses in surface casing can increase corrosion especially on the casing joints and collars. This type of corrosion can be divided into several groups

2.3.1 Corrosion Fatigue

When surface casing is repeatedly stressed in a cyclic manner, it will fail in a brittle manner at stresses far below the yield or tensile strength of the material ( 2.8). 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 casing is substantially reduced when the casing 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.

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

2.3.2 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, which requires that hydrogen sulphide be present, water (even in small 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.

2.3.3 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 corrodant, the alloy could easily support the stress. The stress is always a tensile stress and can be either applied or residual. When a casing 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.

Stress Corrosion Cracking (SCC) of high strength casing 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 ( 2.6).

It has to be added that the pure hydrocarbons are not corrosive themselves, so the corrosion is always initiated by other factors (most important are mentioned above). The market shares of individual corrosion mechanisms are presented in Table 2.1, however naturally they may occur simultaneously.

Table 2.1 Causes of corrosion-related failure within the oil and gas industry (2)

Cause of failure

Total failure [%]

CO2 related

28

H2S related

18

Preferential weld

18

Pitting

12

Erosion corrosion

9

Galvanic

6

Crevice

3

Impingement

3

Stress corrosion

3

45

Prediction of Corrosion Rate and Its Affecting Factors Corrosion Aspects of OCTG Materials

3. Corrosion Aspects of OCTG Materials

3.1 Introduction of OCTG Materials

In recent years, oil and gas wells have been developed in increasingly severe corrosion environment characterized by high temperature, high partial pressure of CO2 and high concentration of Chloride ions, and in some cases, also containing H2S. For this reason, the prevention of corrosion in Oil Country Tubular Goods (OCTG) has become important task. OCTG includes three types of seamless tubes, delivered in quenched and tempered condition:

* Drillpipe - heavy seamless tubes that rotate the drill bit and circulate the drilling fluid. Joint of pipe 30 ft (9m) long are coupled together with tool joints.

* Casing pipe is used to line the hole.

* Tubing - a pipe through which the oil and gas is produced from the wellbore. Tubing joints are generally around 30 ft (9m) long with thread connection on each end.

The corrosion aspects of OCTG materials depend on their material contents such as Carbon, Chromium, Manganese, Nickel, Molybdenum and Copper. The tables below (Table 3.1 and 3.2) show the chemical compositions for OCTG grades of low alloy grades and stainless steel.

Traditionally the grades used for OCTG applications were Carbon Manganese steels (up to the 55 ksi strength level) or Mo containing up to 0.4% Mo. Nowadays, wells with contaminants causing corrosive attack have strong demand for higher strength materials resistant to Hydrogen Embrittlement and Sulphide Stress Cracking (SCC).

Highly tempered martensite has been identified as the structure which most resistant to SCC at higher strength level, and 0.75% Mo has been found to be the Mo concentration to obtain the optimum combination of yield strength and resistance to SCC (10). This is reflected in the list of Mo containing low alloy API standard grades (Table 3.1). For the 75 ksi strength level 0.4% Mo is sufficient, while each of the higher strength grades up to 125 ksi show the optimum Mo level of 0.75 or 0.80% and for higher strength up to 140 ksi (yield strength 965-1171 MPa) precipitated has been introduced as an additional strengthening mechanism by the addition of Niobium (Columbium).

Table 3.1 Chemical Composition and Strength Properties of Common Alloy OCTG Steels (9)

Yield strength

API Grade

% Alloy content

Tensile Strength

(ksi)

Code

C

Mn

Ni

Cr

Mo

Cu

min (N/mm2)

40

H40

0.5

1.5

410

55

K55

0.5

1.5

655

75

C75-1

0.5

1.7

0.5

0.5

0.4

0.5

665

90

C90-1

0.35

1.9

0.9

1.2

0.75

690

95

T95-1

0.35

1.2

0.9

1.5

0.85

724

125

Q125

0.35

1

0.9

1.2

0.75

930

140

0.3

1

1.6

1.1

0.05

1034

Table 3.2 Chemical Composition and Strength Properties of OCTG Stainless Steels (9)

Yield strength

API Grade

% Alloy content

Tensile Strength

(ksi)

Code

C

Mn

Ni

Cr

Mo

Cu

min (N/mm2)

9% Chromium

75

C75-9Cr

0.15

0.6

0.5

9

1

0.25

655

13% Chromium

80

L80-13Cr

0.22

16

0.5

13

0.25

655

95/110

0.04

0.6

4

13

1.5

95/111

0.04

0.6

5

13

2.5

For service in oil and gas fields with more aggressive corrosion environments stainless API grades are standardized with 9% Cr, 1% Mo and 13% Cr (without Mo). For high temperature environments with CO2 and H2S, the non API specialized grades shown in table 3.2 with improved corrosion and SCC resistance have been developed (11). The reduced Carbon content increases Cr in solid solution, which effectively improves the corrosion resistance. Ni and Mo secure both hot workability and corrosion resistance. In particular the addition of Mo improves the pitting corrosion resistance, thereby eliminating initiation sites for SCC.

3.2 Influence of Microstructure and Chemical Composition of Steel in Corrosion Behavior

Steel is an alloy of iron (Fe) and carbon (C). Carbon is fairly soluble in liquid iron at steel making temperatures, however, it is practically insoluble in solid iron (0.02% at 7230C), and trace at room temperature. Pure iron is soft and malleable; small amounts carbon and manganese are added to give steel its strength and toughness.

Most of the carbon is oxidized during steelmaking. The residual carbon and post-fabrication heat treatment determines the microstructure, therefore strength and hardness of steels. Carbon steels are then identified by their carbon contents, i.e., low-carbon or mild steel, medium carbon (0.2- 0.4 % C), high-carbon (up to 1% C) steels, and cast irons (>2 % C).

In a corrosive environment, either grains or the grain boundaries having different composition can become anodic or cathodic, thus forming the corrosion cells. Hydrogen evolution reaction can take place on iron carbide, and spheroidized carbon in steels, and graphite in cast irons, in acidic solutions with relative ease; areas denuded in carbon become anodic and corrode preferentially. Therefore, post-weld heat treatment of steels is critical in order to prevent corrosion of the heat affected zone (HAZ), sensitization and intergranular corrosion in stainless steels

The final microstructure of carbon and low alloy carbon steel OCTG is determined by its chemical composition and the thermomechanical treatments used during the production processes. Although the design criteria are mainly focused on properties such as mechanical resistance, toughness, and weld ability, the corrosion resistance is also affected. The microstructure is considered to have an important effect on how firmly the corrosion scale sticks to the surface. The adherence of the corrosion product film, and hence its protectiveness, has often been related to the presence of iron carbide and its morphology (laminar, globular, etc.). The idea is that the carbide phase can strengthen the film and can anchor it to the steel substrate, and then the size and distribution of these carbides become very important.

Table 3.3 shows the typical corrosion characteristics of different types of steel. The table indicates that metals which have similar chemical composition will have different behavior in corrosion depend on their microstructures.

Table 3.3 Typical Corrosion Characteristics of Different Types of Steel. (12)

Item

Martensitic

Ferritic

Austenitic

Duplex

Corrosion resistance to General Corrosion

Fair

Excellent

Excellent

Excellent

Corrosion resistance to SSC

Poor

Poor

Excellent

Fair

Corrosion resistance to SCC

Excellent

Excellent

Poor

Fair

Strength

High

Low

Low

High

Weldability

Fair

Fair

Excellent

Fair

In order to prevent possible stress corrosion cracking in sour gas and oil wells containing CO2 and H2S with specific partial pressure, it is necessary to use specially manufactured tubing and casing. 3.1 below is a concept for material selection according to CO2 and H2S partial Pressure.

Prediction of Corrosion Rate and Its Affecting Factors Corrosion of Surface Casing and Affecting Factors

4. Corrosion of Surface Casing and Elements Affecting of Corrosion Rate

4.1 Corrosion due to Atmospheric Corrosion

Atmospheres are often classified as being rural, industrial or marine in nature. Two decidedly rural environments can differ widely in average yearly temperature and rainfall patterns, mean temperature, and perhaps acid rain, can make extrapolations from past behavior less reliable.

The corrosion of casing steel in the atmosphere and in many aqueous environments is best understood from a film formation and brake down standpoint. It is an inescapable fact that iron in the presence of oxygen and water is thermodynamically unstable with respect to its oxides. Because atmospheric corrosion is an electrolytic process, the presence of an electrolyte is required. This should not be taken to mean that the steel surface must be awash in water; a very thin adsorbed film of water is all that is required.

During the actual exposure, the metal spends some portion of the time awash with water because of rain or splashing and a portion of the time covered with a thin adsorbed water film. The portion of time spent covered with the thin water film depends quite strongly on relative humidity at the exposure site. This fact has led many corrosion scientists to investigate the influence of the time of wetness on the corrosion rate.

Rusting of iron depends on relative humidity and time of exposure in atmosphere containing 0.01% SO2. The increase in corrosion rate produced by the addition of SO2 is substantial. Oxides of nitrogen in the atmosphere would also exhibit an accelerating effect on the corrosion of steel. Indeed, any gaseous atmospheric constituent capable of strong electrolytic activity should be suspected as being capable of increasing the corrosion rate of steel.

Because carbon steels are not very highly alloyed, it is not surprising that most grades do not exhibit large differences in atmospheric-corrosion rate. Nevertheless, alloying can make changes in the atmospheric-corrosion rate of carbon steel. The elements generally found to be most beneficial in this regard are copper, nickel, silicon, chromium and phosphorus. Of these, the most striking example is that of copper, increases from 0.01-0.05%, decrease the corrosion rate by a factor of two to three.

4.2 Corrosion due to Water Environment

Carbon steel casing is often submerged in water to some extent during service. This exposure can be under conditions varying temperature, flow rate, pH, and other factors, all of which can alter the rate of corrosion. The relative acidity of the solution is probably the most important factor to be considered. At low pH the evolution of hydrogen tends to eliminate the possibility of protective film formation so that steel continues to corrode but in alkaline solutions, the formation of protective films greatly reduces the corrosion rate. The greater alkalinity, the slower the rate of attack becomes. In neutral solutions, other factors such as aeration became determining so that generalization becomes more difficult.

The corrosion of steels in aerated seawater is about the same overall as in aerated fresh water, but this is somewhat misleading because the improved electrical conductivity of seawater can lead to increased pitting. The concentration cells can operate over long distance, and this leads to a more nonuniform attack than in fresh water. Alternate cycling through immersion and exposure to air produces more pitting attack than continuous immersion. The effect of various alloying addition and exposure conditions on the corrosion behavior is shown in Table 4.1.

Table 4.1 Comparison of results under different type of exposure (13)

Effects of

alloy selection,

chemical

composition and alloy

additions

Sea air

Freshwater

Alternately wet with

Seawater or

Spray and dry

Continuously wet with

seawater

Ferrous alloys

Pockmarked

Vermiform on cleaned

bars

Pitting,

particularly on

bars with scale

Pitting,

particularly on

bars with scale

Wrought iron

versus carbon

steel

Steel superior

to wrought and ingot irons

Iron and steel equal in low-moor areas

Low-moor iron superior

to carbon steel

Low-moor iron

superior

to carbon steel

Sulfur and

phosphorus

content

Best results

when S and P are low

Best results

when S and P are low

Best results

when S and P are low

Apparently little

influence

Addition

of copper

Beneficial: Effect increasing with copper content

Beneficial:

0.635% Cu

almost as

good as

2.185% Cu

Beneficial:

0.635% and

2.185% Cu

much the same

0.635%

Cu slightly

beneficial: 2.185% Cu

Addition

of nickel

3.75% Ni

Superior even

to 2% Cu; 36%

Ni almost

Perfect after

15-year exposure

3.75%Ni

Superior even to

2%Cu; 36%Ni excellent

resistance

3.75%Ni

beneficial usually more so than Cu:

36%Ni the best metal in the set

3.75%

Ni slightly

beneficial and

slightly superior to Cu: 36% Ni the best metal in the set

Addition

of 13.5% Cr

Excellent resistance to

corrosion: cold

blast metal

perfect after

15-year

exposure: equal to 36%

Ni steel

Excellent

resistance to

corrosion: equal to 36% Ni steel

Subject

to severe

localized

corrosion that

virtually destroys

the metal

Subject

to severe

localized corrosion

that virtually

destroys

the metal

Behavior of

cast irons

Excellent resistance to

corrosion: cold blast metal

superior to hot:

no graphitic

corrosion

Undergoes

graphitic

corrosion

Undergoes

graphitic

corrosion

Undergoes graphitic

corrosion

Interestingly, the corrosion rates of specimens completely immersed in seawater do not appear to depend on the geographical location of the test site; therefore, by inference, the mean temperature does not appear to play an important role.

This constancy of the corrosion rate in seawater has been attributed to the more rapid fouling of the exposed steel by marine organisms, such as barnacles and algae, in warmer seas. It is further speculated that this fouling offsets that increases expected from the temperature rise.

4.3 Corrosion due to Cement Environment

4.3.1 Cement as an Environment for Casing Steel and the Role of Alkalinity

Cementing is one of the fundamental techniques in oil and gas well design approach. It serves its purpose as a protective material in preventing the casing from corrosion. Environment formation characteristics such as mineral content, microorganisms, acidity lead to steel corrosion and this could be prevented by cementing.

Cementing is one method to surround the steel with an alkaline environment having a pH value within the range 9.5 to 13. Hydrated cement provides such an environment, the normal pH value being 12.5, at which steel is protected in the absence of aggressive anions. At this pH value a passive film forms on the steel that reduces the rate of corrosion to a very low and harmless value (Fig 4.1). Thus, cement cover provides chemical as well as physical protection to the steel. However, circumstances do arise in which corrosion of reinforcement occurs. Since rust has a larger volume than the steel from which it is formed, the result can be cracking, rust-staining, or even spalling of the cement cover. Such occurrences usually arise from loss of alkalinity in the immediate vicinity of the steel or from the presence of excessive quantities of aggressive anions in the cement (normally chloride), or from a combination of both of these factors.

4.3.2 Loss of Alkalinity by Carbonation

Alkalinity can be lost as a result of:

* Reaction with acidic gases (such as carbon dioxide) in the atmosphere. The effects of sulphur dioxide are also included in the term “carbonation”.

* Leaching by water from the surface.

In practice both of these factors contribute to the reduction of alkalinity in the cement. Cement is permeable and allows the slow ingress of the atmosphere; the acidic gases react with the alkalis (usually calcium, sodium and potassium hydroxides), neutralizing them by forming carbonates and sulphates, and at the same time reducing the pH value. If the carbonated front penetrates sufficiently deeply into the cement to intersect with the cement reinforcement interface, protection is lost and, since both oxygen and moisture are available, the steel is likely to corrode. The extent of the advance of the carbonation front depends, to a considerable extent, on the porosity and permeability of the cement and on the conditions of the exposure.

4.3.3 The Effect of Chloride in The Cement

The passivity provided by the alkaline conditions can also be destroyed by the presence of chloride ions, even though a high level of alkalinity remains in the cement. The chloride ion can locally de-passivity the metal and promote active metal dissolution. Chlorides react with the calcium aluminates and calcium aluminoferrites in the cement to form insoluble calcium chloroaluminates and calcium chloroferrites in which the chloride is bound in non-active form; however, the reaction is never complete and some active soluble chloride always remains in equilibrium in the aqueous phase in the cement. It is this chloride in solution that is free to promote corrosion of the steel. At low levels of chloride in the aqueous phase, the rate of corrosion is very small, but higher concentration increases the risks of corrosion. Thus the amount of chloride in the cement and, in turn, the amount of free chloride in the aqueous phase (which is partly a function of cement content and also of the cement type) will influence the risk of corrosion. While the cement remains in an uncarbonated state the level of free chloride in the aqueous phase remains low (perhaps 10% of the total Cl). However, the influence of severe carbonation is to break down the hydrated cement phases and, in the case of chloroaluminates, the effect is to release chloride. Thus more free chloride is available in carbonated cement than in uncarbonated materials.

4.4 Elements Affecting of Corrosion Rate

4.4.1 Water Chemistry

Water chemistry is probably the most influential parameter affecting corrosion. The situation can vary from being very simple with only a few carbonic species present, as in the case with condensed water in gas pipelines, to being very complex with numerous species found for example in formation water emerging together with crude oil. In some cases the concentration of dissolved salts can be very high (> 10 wt %) making the solution non-ideal. Table 4.2 contains an overview over dissolved species can be found in formation water.

Table 4.2 Dissolved Species that can be found in Formation Water (13)

Specie

Description

CO2

Dissolved carbon dioxide

H2CO3

Carbonic acid

HCO3-

Bicarbonate ion

CO3-

Carbonate ion

H+

Hydrogen ion

OH-

Hydroxide ion

Fe2+

Iron ion

CH3COOH (HAc)

Acetic acid

H2S

Dissolved hydrogen sulphide

S-

Sulphide ion

SO4-

Sulphate ion

Cl-

Chloride ion

Na+

Sodium ion

K+

Potassium ion

Ca2+

Calcium ion

Mg2+

Magnesium ion

Ba2+

Barium ion

CH3COO- (Ac-)

Acetate ion

HSO4-

Bisulphate ion

O2

Dissolved Oxygen

Understanding the brine chemistry is important to be able to predict corrosion rate since pH is one of the most important parameters when calculating the corrosion rate. pH depends strongly on the water chemistry.

4.4.2 The Effect of pH

Experience has shown that pH has a strong influence on the corrosion rate. Typical pH in pure water is about 4, while pH in buffered brines normally is in the range 5 - 7. At pH 4 (and lower) direct reduction of H+ ions is important particular at lower partial pressure of CO2 and the pH has a direct affect on the corrosion rate. However, the most important effect of pH is indirect and relates to how pH affects conditions for formation of iron carbonate films. High pH results in a decreased solubility of iron carbonate and lead to an increased precipitation rate and higher scaling tendency; reflected by a rapid decrease of the corrosion rate with time.

When calculating corrosion rates, it is of vital importance to have as accurate as possible pH value for the actual exposure condition either from:

* Direct measured values (easy in lab, difficult in the field)

* pH calculation tool in addition to reliable water chemistry analysis

4.4.3 The effect of CO2 Partial Pressure

In case of film-free CO2 corrosion, an increase in partial CO2 pressure (PCO2) typically leads to an increase in the corrosion rate. The commonly accepted theory is that with PCO2 the concentration of H2CO3 increases and accelerates the cathodic reaction, and ultimately the corrosion rate. At a constant pH, higher PCO2 leads to an increase in CO32- concentration and a higher supersaturation, which accelerates precipitation and film formation.

4.4.4 The effect of HAc

Since acetic acid HAc is a stronger acid than carbonic acid (H2CO3), it is the main source of hydrogen ions when the two acid concentrations are similar. The effect of HAc is particularly pronounced at higher temperatures where the presence of HAc can increase the corrosion rate dramatically.

4.4.5 The effect of Temperature

Temperature accelerates all the processes involved in corrosion. One would expect that the corrosion rate steadily increases with temperature. This is the case at low pH when precipitation of iron carbonate or other protective films does not occur. The situation changes markedly when solubility of iron carbonate (or other salt) is exceeded, typically at high pH. In that case, increased temperature accelerates rapidly the kinetics of precipitation and protective film formation, decreasing the corrosion rate. The peak in the corrosion rate is usually seen between 60 and 800C depending on water chemistry and flow conditions; see 4.2 as an example.

Prediction of Corrosion Rate and Its Affecting Factors Corrosion Model and Calculation of Corrosion Rate

5. Corrosion Model and Calculation of Corrosion rate

5.1 Introduction of Corrosion Model

Corrosion of carbon steel alloys has been, and remains, a major cause of corrosion damage in oil and gas field operations. The industry relies heavily on the extensive use of these materials, and thus there is a desire to predict the corrosivity of CO2-H2S containing hydrocarbons when designing wellbore, production equipment and transportation facilities.

A true industry standard approach to predict CO2-H2S corrosion does not exist although there are aspects of commonality between the approaches/models offered by the industry and the research organizations. The Shell equation or nomogram was developed as an engineering tool. It presents, in a simple form, the relationship between potential corrosivity of aqueous media for a given level of dissolved CO2-H2S, defined by its partial pressure, at any given temperature.

The NORSOK M-506 model is an empirical model mainly base don laboratory data at low temperature and a combination of lab and field data at temperatures above 1000C. The NORSOK model takes larger account for the effect of protective corrosion films and therefore predicts lower corrosion rates at high temperature and high pH than other models. The model does not take any effect of oil wetting. The model has been developed by Statoil, Hydro Oil & Energy and Saga Petroleum, and has been issued as a NORSOK standard for the Norwegian Oil industry. The spreadsheet with the model is openly available on its website.

5.2 Corrosion Model based on NORSOK M-506 rev.2

The model is an empirical corrosion rate model for carbon steel in water containing CO2-H2S with particular ratio at different temperatures, pHs, CO2-H2S fugacities and wall shear stresses. It is based on flow-loop experiments at temperatures from 5°C to 150°C. A large amount of data at various temperatures, CO2-H2S fugacities, pHs and wall shear stresses are used.

The following general equation of the CO2-H2S corrosion rate for carbon steel at each of the temperatures (T);

* 20°C, 40°C, 60°C, 80°C, 90°C, 120°C and 150°C is used:

CRT = KT x fCO2 0.62 x (S/19) 0.146 + 0.0324 log (fCO2) x f(pH)T (mm/year) (5.1)

* The following equation is used at temperature 15°C:

CRT = KT x fCO2 0.36 x (S/19) 0.146 + 0.0324 log (fCO2) x f(pH)T (mm/year) (5.2)

* The following equation is used at temperature 5°C:

CRT = KT x fCO2 0.36 x f(pH)T (mm/year) (5.3)

The corrosion rate between temperatures where a constant Kt has been generated is found by a linear extrapolation between the calculated corrosion rate at the temperature above and below the desired temperature. The constant KT is given in the table below

Table 5.1 Constant KT

Temperature

KT

°C

5

0.42

15

1.59

20

4.762

40

9

60

11

80

10

90

6

120

8

150

5

When the pH in the water increases the corrosion rate will decrease due to the reduction of the H+- ions in the water. In addition to this protective corrosion films may be formed on the steel surface and reduce the corrosion rate even more. It has not been distinguished between these two effects on the general corrosion rate in this study. The effect of pH is included in equation (5.4):

* CRT = KT x fCO2 0.6 x f(S) x f(pH)T (mm/year) (5.4)

Where f(pH)T is the effect of pH on the corrosion rate for each temperature T. The effect of pH was found by plotting measured corrosion rate divided by the product of KT, fCO20.6 and f(S). The effect of pH on corrosion rate at various temperatures is described by the functions in Table 5.2. The effect of pH on corrosion rate is different for all the temperatures.

The effect of pH is given in Table 5.2.

Table 5.2 pH Function

Temperature

pH

f(pH)

°C

5

3,5 < pH < 4,6

f(pH) = 2,0676 - (0,2309 x pH)

5

4,6 < pH < 6,5

f(pH) = 4,342 - (1,051 x pH) + (0,0708 x pH2)

15

3,5 < pH < 4,6

f(pH) = 2,0676 - (0,2309 x pH)

15

4,6 < pH < 6,5

f(pH) = 4,986 - (1,191 x pH) + (0,0708 x pH2)

20

3,5 < pH < 4,6

f(pH) = 2,0676 - (0,2309 x pH)

20

4,6 < pH < 6,5

f(pH) = 5,1885 - (1,2353 x pH) + (0,0708 x pH2)

40

3,5 < pH < 4,6

f(pH) = 2,0676 - (0,2309 x pH)

40

4,6 < pH < 6,5

f(pH) = 5,1885 - (1,2353 x pH) + (0,0708 x pH2)

60

3,5 < pH < 4,6

f(pH) = 1,836 - (0,1818 x pH)

60

4,6 < pH < 6,5

f(pH) = 15,444 - (6,1291 x pH) + (0,8204 x pH2) - (0,0371 x pH3)

80

3,5 < pH < 4,6

f(pH) = 2,6727 - (0,3636 x pH)

80

4,6 < pH < 6,5

f(pH) = 331,68 x e(-1,2618 x pH)

90

3,5< pH < 4,57

f(pH) = 3,1355 - (0,4673 x pH)

90

4,57< pH < 5,62

f(pH) = 21254 x e(-2,1811 x pH)

90

5,62 < pH < 6,5

f(pH) = 0,4014 - (0,0538 x pH)

120

3,5 < pH < 4,3

f(pH) = 1,5375 - (0,125 x pH)

120

4,3 < pH < 5

f(pH) = 5,9757 - (1,157 x pH)

120

5 < pH < 6,5

f(pH) = 0,546125 - (0,071225 x pH)

150

3,5 < pH < 3,8

f(pH) = 1

150

3,8 < pH < 5

f(pH) = 17,634 - (7,0945 x pH) + (0,715 x pH2)

150

5 < pH < 6,5

f(pH) = 0,03

The corrosion rates at temperatures between 20 and 400C, 40 and 600C, 60 and 800C and so on should be calculated by linear interpolation between the corrosion rates calculated with equation (5.4) at these temperatures. The pH has a significant effect on the corrosion rate for all the temperatures. One interesting observation is that the maximum corrosion rates vary between 40 and 90°C depending on the pH.

To predict the pH in the condensed water or formation water, the parameters given in Table 5.3 are needed.

Table 5.3 Input Parameters for pH Calculation

Parameter

Unit

Range

Default values

Comments

Temperature

°C

5 to 150

°F

41 to 302

Total pressure

bar

1 to 1000

psi

14,5 to 14500

Total mass flow

kmole/h

10 to 106

Only relevant when CO2

is given in kmole/h

CO2 fugacity

bar

0 to 10

The CO2 partial pressure shall be lower than the

psi

0 to 145

total pressure.The allowed ranges of mole% and

mole%

variable

kmole/h CO2

are dependent on the total pressure.

kmole/h

variable

Bicarbonate (HCO3-)

mg/l

0 to 20000

0

Default values

for formation water.

mM

0 to 327

Ionic strength/salinity

g/l

0 to 175

50

Default values

for formation water.

M

0 to 3

The routine for calculation of pH is based on the following chemical reactions and equilibrium constants:

The system has to be electro-neutral, which can be described by the following equation:

(5.5)

It is assumed that bicarbonate is added as sodium bicarbonate (NaHCO3). It is also assumed that no other salts than sodium bicarbonate and sodium chloride (NaCl) are present in the solution. These salts will dissolve as follows:

Based on these assumptions, the amount of sodium bicarbonate equals the difference in the concentrations of sodium and chloride as shown below. The mass balance for bicarbonate will therefore be as follows:

(5.6)

C0, Bicarb equals the initial amount of sodium bicarbonate.

By combining the equations for the equilibrium constants with the required electro-neutrality and the mass balance for bicarbonate one gets the following expression for the concentration of the hydrogen cation:

(5.7)

This equation is solved by using the Newton's method.

The pH in a condensed water system saturated with iron carbonate can also be calculated. Based on a similar deduction as above, the equation becomes:

(5.8)

Where

(5.9)

Gases are not ideal at high pressures. To compensate for this, the partial pressure of a gas is multiplied by a fugacity constant. The real CO2 pressure can then be expressed as:

(5.10)

The CO2 partial pressure is found by one of the following expressions

(5.11)

The fugacity coefficient is given as

(5.12)

45

Prediction of Corrosion Rate and Its Affecting Factors Discussions of Results

6. Corrosion Rate Results and Discussions

Using Equations in sub-chapter 5.2, the charts of corrosion rate with several parameters on basis of given temperature, pH, CO2 partial pressure and shear stress have been generated with several assumptions as describe below:

* The model is valid for temperature 5 - 150 °C, pH 3.5 - 6.5,

* CO2 partial pressure 0.1 - 10 bar and shear stress 1 - 150 Pa.

* The model is not applicable when the H2S partial pressure is higher than 0.5 bar,

* or when the ratio between the partial pressure of CO2 and H2S is less than 20.

* The model can lead to underproduction of the corrosion rate when the total content of organic acids exceeds 100 ppm and the CO2 partial pressure is less than 0.5 bar.

6.1 Effect of Temperature

Corrosion rates as a function of temperature with specific amount of CO2 (in % mole) are shown in 6.1 to 6.12. The corrosion rates starts instantaneously still at low temperature due to continuous dissolution of Fe2+ ion in the solution. As the temperature increases corrosion rate increases due to the formation of porous iron carbonate films, results in the initiation of cracks and spallation of the oxide layers formed on the metal surface. The chloride ion easily ingress through the surface and significantly increases the corrosion at the temperature range of 40-80oC.

Further increase in temperature the corrosion rate decreases significantly due to the formation of denser, adherent and homogeneous layer of iron carbonate, which is, protects the metal to further corrosion. As the partial pressure of CO2 in the solution increases the formation of weak carbonic acid (H2CO3) favors, which increases the corrosion rate. However at higher temperature the bicarbonate ions (HCO3-) formed on the surface gives more carbonate ions (CO32-) results in formation of more insoluble iron carbonate which increases the solution pH and corrosion rate decreases significantly as shown in 6.1-6.12 at 120oC. In many literatures, it has been reported that Fe2CO3 precipitation is temperature dependent and for its precipitation super saturation with the Fe2+ ion is required which is 5-10 times higher than the thermodynamically calculated values of solubility. (16)

6.2 Effect of pH

The effect of various pH on Corrosion rates are shown in 6.1, 6.4, 6.7. Lower Corrosion rates are obtained at the higher pH, the corrosion rate does not change much with pH higher than 6.5, even if some ferrous carbonate precipitation occurs, reflecting the fact that a relatively porous, detached and unprotective layer is formed. There are other indirect effects of pH, and by almost all accounts, higher pH leads to a reduction of the corrosion rate, making the “pH stabilization” (meaning: pH increase) technique an attractive way of managing CO2 corrosion.

6.2,5,8,10,11,12 are described Corrosion rate at pH 4-4.4 at specific temperature (90-120oC) with various mole of CO2, CO2 partial pressure and shear stresses have constant corrosion rates compare to other corrosion rates with different pHs at similar temperature. The reason of this phenomenon is the acceleration of increasing formation of weak carbonic acid (H2CO3) during temperature 90-120oC which causes increasing corrosion rate has equal acceleration with the formation of iron carbonate which is formed on the surface of steel and create the passivity behavior.

6.3 Effect of Partial Pressure

An increase in partial CO2 pressure (PCO2) typically leads to an increase in the corrosion rate. The commonly accepted theory is that with PCO2 the concentration of H2CO3 increases and accelerates the cathodic reaction, and ultimately the corrosion rate ( 6.2,3,4,5,6,8,9). However, when other conditions are favorable for formation of ferrous carbonate layers, increased PCO2 can have a beneficial effect. At a constant pH, higher PCO2 leads to an increase in CO32- concentration and a higher supersaturation, which accelerates precipitation and protective layer formation.

With CO2 = 30% mole

6.4 Effect of Partial Pressure

The effect of wall shear stress may have two different effects on the corrosion rate:

* The general corrosion rate may increase with 10-30% as shown in Fig 6.10-12

* Local mesa attack may occur at high values of wall shear stress which can give corrosion rates which is 10-100 times higher than expected if the corrosion attach was general corrosion.

Prediction of Corrosion Rate and Its Affecting Factors An Experimental Approach to Investigate Long Term Corrosion

7. An Experimental approach to Investigate Long Term Corrosion

7.1 Introduction of LPR method

The LPR technique has become a well-established method of determining the instantaneous corrosion rate measurement of steel in cement structures. The technique is rapid and non-intrusive, requiring only localized damage to the cement cover to enable an electrical connection to be made to the steel or directly from steel to steel. Due to the widespread corrosion of steel in cement structures there has been a concerted demand for the development of non-destructive techniques to enable accurate assessment of the condition of steel. LPR monitoring has been developed to address this need. The technique is rapid and non-intrusive, requiring only a connection to the steel. The data provides a valuable insight into the instantaneous corrosion rate of the steel, giving more detailed information than a simple potential survey. The LPR data enables a more detailed assessment of the structural condition and is a major tool in deciding upon the optimum remedial strategy to be adopted. It is thus imperative that the LPR measurements obtained are accurate.

In LPR measurements the steel is perturbed by a small amount from its equilibrium potential. This can be accomplished potentiostatically by changing the potential of the steel by a fixed amount, ΔE, and monitoring the current decay, ΔI, after a fixed time. Alternatively it can be done galvanostatically by applying a small fixed current, ΔI, to the steel and monitoring the potential change, ΔE, after a fixed time period. In each case the conditions are selected such that the change in potential, ΔE, falls within the linear Stern-Geary range of 10-30 mV. The polarization resistance, Rp, of the steel is then calculated from the equation.

(7.1)

From which the corrosion rate, Icorr, can then be calculated

(7.2)

where, B is the Stern-Geary constant. A value of 25 mV has been adopted for active steel and 50 mV for passive steel. In order to determine the corrosion current density, icorr, the surface area, A, of steel that has been polarized needs to be accurately known:

(7.3)

The present residual strength and, by extrapolation, the remaining service life of the structure can be estimated. In a conventional LPR test the perturbation is applied from an auxiliary electrode on the cement surface. The surface area of steel assumed to be polarized is that lying directly beneath the auxiliary electrode. However, there is considerable evidence to suggest that the current flowing from the auxiliary electrode is unconfined and can spread laterally over an unknown, larger area of steel This can lead to inaccurate knowledge of the surface area of steel polarized and result in an error in the calculation of the corrosion current density, which, in turn, will produce an inaccurate estimate of the condition of the structure being investigated.

In order to overcome the problem of confining the current to a predetermined area, the use of a second auxiliary guard ring electrode surrounding the inner auxiliary electrode has been developed. The principle of this device is that the outer guard ring electrode maintains a confinement current during the LPR measurement. This confinement current prevents the perturbation current from the main inner auxiliary electrode spreading beyond a known area. In order to select an appropriate level for the confinement current two sensor electrodes are placed between the inner and outer auxiliary electrodes. The potential difference between these sensor electrodes is monitored and a confinement current selected to maintain this potential difference throughout the LPR measurement.

The performance of the guard ring has been shown to be an improvement upon that of a single unconfined auxiliary electrode, giving a more accurate value for the corrosion rate of the steel being monitored. At present the established method of guard ring LPR measurements uses galvanostatic control. This method relies upon the potential response, ΔE, to the selected perturbation, ΔI, falling within the linear region of the Stern-Geary plot. The use of a potentiostatic device would enable the potential shift itself to be selected, ensuring the measurement falls within this linear region and hence, would not risk the inaccuracies incurred by applying too large a galvanostatic perturbation.

7.2 Experimental Procedure

Using the concept and principle of LPR, an experiment for monitoring and measurement corrosion of Surface casing can be developed.

Casing steel is isolated with cement and flooded with water at certain level of high and CO2 is injected into water at certain level. The experiment can be done with several variables such as Temperature, CO2 composition in the water and salt contain ( 7.3).

After certain period, corrosion on surface casing shall be monitored and measured using LPR tool. The both electrodes (reference and working electrode) can be placed inside of the casing or the reference electrode can be also placed on the cement surface as well.

The result which is given by digital control system has to be calculated using equation 7-1-3 and compared by corrosion current table to determine condition of the steel.

The following broad criteria for corrosion have been developed from field and laboratory investigations with the sensor controlled guard ring device given in Table 7.1

Table 7.1 Corrosion current vs. condition of the steel (18)

Corrosion current (Icorr)

Condition of the steel

Icorr < 0.1 μA/cm2

Passive condition

Icorr 0.1 - 0.5 μA/cm2

Low to moderate corrosion (17.1 μm/year)

Icorr 0.5 - 1.0 μA/cm2

Moderate to high corrosion (34 μm/year)

Icorr > 1.0 μA/cm2

High corrosion rate (345 μm/year)

The device without sensor control has the following recommended interpretation

Icorr < 0.2 μA/cm2

No corrosion expected

Icorr 0.2 - 1.0 μA/cm2

Corrosion possible in 10 -15 years

Icorr 1.0 - 10 μA/cm2

Corrosion expected in 2-10 years

Icorr > 10 μA/cm2

Corrosion expected in 2 years or less

45

Prediction of Corrosion Rate and Its Affecting Factors Conclusions

8. Conclusions

1. The Norsok M-506 model was used for this study allowed clear calculations of trends for the general corrosion rate for the carbon steel. The temperature range 5-1500C was particularly covered. The parameters of main importance were (in order of importance): the pH, the fugacity of CO2, temperature and the mean wall shear stress with several assumptions as describe below:

* The model is valid for temperature 5 - 150 °C, pH 3.5 - 6.5,

* CO2 partial pressure 0.1 - 10 bar and shear stress 1 - 150 Pa.

* The model is not applicable when the H2S partial pressure is higher than 0.5 bar,

* or when the ratio between the partial pressure of CO2 and H2S is less than 20.

* The model can lead to underproduction of the corrosion rate when the total content of organic acids exceeds 100 ppm and the CO2 partial pressure is less than 0.5 bar.

2. As the temperature increases corrosion rate increases due to the formation of porous iron carbonate films, results in the initiation of cracks and spallation of the oxide layers formed on the metal surface.

3. An increase in partial CO2 pressure (PCO2) typically leads to an increase in the corrosion rate.

4. The wall shear stress may have two different effects on the corrosion rate:

* The general corrosion rate may increase with 10-30% dependent on the wall shear stress and fugacity of CO2.

* Mesa attacks may occur at high values of shear stress.

5. Casing Steel which is isolated with cement will start to corrode when the cement loss alkalinity during its life time and cracking.

6. Linear Polarization Resistance method can be used to monitor and determine corrosion on surface casing

Prediction of Corrosion Rate and Its Affecting Factors References

References:

1. Samant, A.; Corrosion Problems in Oil Industry Need More Attention, Technical paper from Oil and Natural Gas Corporation Limited, February 2003

2. Keranl, M., Harrop, D.; The Impact of Corrosion on the Oil and Gas Industry, SPE, Production and Facilities, August 1996

3. Tomasz Szary.; The Finite Element Method Analysis for Assessing the Remaining Strength of Corroded Oil Field Casing and Tubing, Dissertation paper from Freiberg University, September 2006.

4. Mok Chek Min.; An Introduction to Corrosion, CMM NDT Services, 2008

5. http://octane.nmt.edu/waterquality/corrosion/corrosion.htm

6. http://www.materialsinspectionassociates.com/CO2.php

7. http://corrosion.ksc.nasa.gov/faticor.htm

8. Scoppio, L.; Assessment of Corrosion and Environmental Cracking of Metallic Materials in HPHTCs/K Formate Brines. 3rd Annual ChemiMetallurgyTM Technical Symposium, November 2007

9. http://www.imoa.info/moly_uses/moly_grade_alloy_steels_irons/oil_country_tubular_goods.html

10. J.A. Straatmann, A.P. Grobner. Molybdenum containing steels for Gas and Oil Industry Applications. Climax Molybdenum Company, 1978.

11. Dishimaru et al. in JFE Technical Report No.2, (Mar 2004)

12. Hashizume, Shuji. Materials selection in Oil and Gas Production. Tenaris NKKTubes, January 2008

13. http://www.sumitomo-tubulars.com/materials/index.htm

14. Technical Memorandum Gemite Products Inc, Corrosion of Steel in Concrete due to Carbonation. 22 April 2005

15. George V.Chilingar, Ryan Mourhatch, Ghazi Al-Qahtani. The Fundamentals of Corrosion and Scaling. Gulf Publishing Company. 2008

16. A. Turnbull, D. Coleman, A. J. Griffiths, P. E. Francis and L. Orkney, “Effectiveness of Corrosion Inhibitors in Retarding the Rate of Propagation of Localized Corrosion”, Corrosion, Vol. 59, No. 3, 2003, pp. 250-257.

17. http://www.cosasco.com/

18. Ha-Won Song, Velu Saraswathy, Corrosion Monitoring of Reinforced Concrete Structures - A Review, International Journal of Electrochemical science, 2007.

Appendix

A.1 Input parameters

A.1.1 Basic input parameters

The basic input parameters for the CO2 corrosion model for carbon steel are given in Table A.1.1. The allowed units and ranges are also given

Table A.1.1 Basic Input Parameters

Parameter

Units

Range

Comments

Temperature

°C

5 to 150

°F

68 to 302

Total mass flow

kmole/h

10-3 to 106

Only relevant when CO2 is given in kmole/h.

CO2 fugacity in the gas phase

bar

0,1 to 10

The CO2 partial pressure shall be

psi

1,45 to

145

< the total pressure.

mole%

variable

The allowed ranges of mole% and kmole/h CO2 are dependent on the

kmole/h

variable

total pressure.

Wall shear stress

Pa

Can be calculated by use of other input parameters

pH

3,5 to 6,5

Can be calculated by use of other input parameters

A.1.2 Input parameters for wall shear stress calculations

Wall shear stress is one of the parameters needed for calculation of corrosion rate. In the model, the mean wall shear stress in straight pipe sections is used.

Obstacles and other geometrical changes in the flow will give rise to higher shear stresses than calculated by this program. Further, different flow regimes and geometrical obstacles may generate shear stress fluctuations where the shear stress peaks may be considerably higher than the average shear stress.

High shear stress may cause mesa attacks, with corrosion rates significantly higher than what is estimated by this computer program.

It is not the objective of this computer program to cover all such eventualities, and the user of the program shall evaluate the flow effect in each system/part of a system based on expertise and available experience and documentation.

The mean wall shear on the wall at medium to high superficial velocities of one or both of the liquid and gas velocities

where the friction factor, f, can be expressed as:

Mixture density, velocity and viscosity is expressed as:

To calculate the wall shear stress, the input parameters given in Table A.1.2, are as a minimum required

Table A.1.2 Input parameters for simplified calculation of wall shear stress

Parameter

Units

Range

Comments

Temperature

°C

5 to 150

°F

41 to 302

Total pressure

bar

1 to 1000

psi

14,5 to 14500

Superficial liquid velocity/

m/s

0 to 20

Requirement: turbulent flow, i.e.

Liquid flow

Sm³/d

(depends on internal pipe diameter)

Re > 2300

Superficial gas velocity/

m/s

0 to 40

Requirement: turbulent flow, i.e.

Gas flow

MSm³/d

(depends on internal pipe diameter)

Re > 2300

Watercut, φ

%

0 to 100

Internal pipe diameter

mm

All diameters

Requirement: turbulent flow, i.e. Re > 2300

For more accurate wall shear stress calculations, the input parameters given in Table A.1.3 should also be used.

Table A.1.3 Input parameters for accurate calculation of wall shear stress

Parameter

Units

Range

Default value

Roughness

μm

0 to 100

50

Compressibility

0,8 to 1

0,9

Specific gravity of gas relative to air

0,5 to 1

0,8

Water density, ρw

kg/m³

995 to 1050

1024

Oil density, ρo

kg/m³

600 to 1100

850

Gas density, ρw

kg/m³

1 to 1700

calculated

Water viscosity, μw

cp

0,17 to 1,1

calculated

N s/m²

0,00017 to 0,0011

Oil viscosity, μo

cp

0,2 to 200

1,1

N s/m²

0,0002 to 0,2

Gas viscosity, μG

cp

0,02 to 0,06

0,03

N s/m²

0,00002 to 0,00006

Watercut at inversion point, φc

0,3 to 0,9

0,5

Maximum relative liquid viscosity, μrelmax

1 to 100

7,06

A.2 Interface of Model

A.3 Comparison corrosion rate using another experiment (Parametric Study of CO2/H2S Corrosion of Carbon Steel Used for Pipeline Application, G. S. DAS & A. S. KHANNA, Corrosion Science & Engineering Indian Institute of Technology Bombay, 2004)

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Exams can be one of the most stressful experiences you’ll ever have! Revision is key, and we’re here to help. With custom created revision notes and exam answers, you’ll never feel underprepared again.