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Chapter 7: Corrosion Chapter 7: Corrosion Oil Field Chemicals Training Manual 7-2 Property of Nalco Energy Services Confidential & Proprietary – DO NOT DUPLICATE 7.1 Problem Corrosion is possibly the most important and costly cause of problems encountered in oil production systems. Corrosion requires special consideration during the design and fabrication of production equipment and the operation of the process. Corrosion detection, monitoring, and control are paramount considerations when seeking maximum equipment life, minimum cost, and maximum safety. Corrosion can occur anywhere in the production system — from well bottom to final transfer of produced gas or oil to the refinery. To control corrosion, you need to understand the nature and mechanisms by which it occurs. 7.2 Theory Corrosion is the deterioration of a substance, usually a metal, due to a reaction with its environment, so “Why do metals corrode?” Metals do not normally exist in nature as pure substances. They occur combined with other elements as ores. Most ores are oxides where the metal element is combined with oxygen. For example, the most common form of iron ore is hematite, which is essentially a mixture of iron oxides of the type Fe2O3. Hematite looks like rust and is in fact one component of rust. Iron ore is converted to steel by the addition of energy. This same energy is expended when the steel reconverts back to rust as it corrodes. This principle applies to most corrosion processes. The refining and corrosion cycle is a process whereby energy is added during refining the ore to pure metal and expended as the metal corrodes back to its original ore. This energy is the driving force for corrosion. All of the corrosion problems that occur in oil and gas production systems are due to the presence of water, in either large amounts or just traces. This corrosion process is known as the “wet corrosion process” and is electrochemical in nature. 7.2.1 Corrosion Mechanisms As stated above, wet corrosion is an electrochemical process. As corrosion occurs, an electrical current passes through the corroding metal. For current to flow, there has to be a voltage source and a completed electrical circuit. Chapter 7: Corrosion Oil Field Chemicals Training Manual 7-3 Property of Nalco Energy Services Confidential & Proprietary – DO NOT DUPLICATE 7.2.1.1 Voltage Source The source of voltage is the energy stored during the original metal refining process. Different metals require different amounts of energy when being refined. This in turn gives them differing tendencies to corrode. This energy can be measured and is shown in the Galvanic or Electrochemical series, which is a progressive comparison of the electromotive force (EMF) of each metal when immersed in water. The electromotive force is the voltage required to lose or gain electrons (or to be oxidized/reduced). Potential values of EMF are a function of both the metal and the chemical and physical characteristics of the water. Absolute values also depend upon temperature, velocity, and other factors, but for most purposes, it is sufficient to compare voltages in water under similar conditions. This principle is shown in the following short table of metal potential comparisons. Metal Volts* Magnesuim (Mg) -2.37 Aluminum (Al) -1.66 Zinc (Zn) -0.76 Iron (Fe) -0.44 Copper (Ca) +0.34 to +0.52 Most Energy Required for Refining Silver (Ag) +0.80 Most Eager to Corrode Least Energy Required for Refining Gold (Au) +1.50 to +1.68 Least Eager to Corrode * With respect to NHE (normal hydrogen electrode) 7.2.1.2 The Electrical Circuit In addition to a voltage source, there also needs to be a completed electrical circuit consisting of an anode, a cathode, and an electrolyte. The Anode The anode is the part of the metal surface that corrodes — that is, the metal dissolves in the electrolyte. The reaction for iron would be: Fe Iron Atom Fe++ Iron Ion + 2e- Electrons This loss of electrons is called oxidation. The iron ion goes into solution, and the two electrons are left behind in the metal. Chapter 7: Corrosion Oil Field Chemicals Training Manual 7-4 Property of Nalco Energy Services Confidential & Proprietary – DO NOT DUPLICATE The Cathode The cathode is that portion of the metal surface that does not dissolve. It is the site where chemical reactions that absorb the electrons generated at the anode. The electrons generated as the iron dissolves at the anode and travel through the metal to the cathodic surface area. There are two primary reactions possible at the cathode, the “hydrogen evolution reaction” and the “oxygen absorption reaction.” Other reactions are possible but are encountered less often. In the hydrogen evolution reaction, the electrons combine on the surface of the metals with hydrogen ions in the electrolyte to form hydrogen molecules, which escape as gas bubbles. This consumption of electrons is called a reduction reaction. It should be noted that some hydrogen atoms are left uncoupled and diffuse into the metal, which causes embrittlement or blistering. (See 11.2.4.2.) The reaction would typically be: 2H+ Hydrogen Ions + 2e- Electrons H2 Hydrogen Gas Hydrogen ions exist to a small extent in water and are plentiful in acidic environments. Hence, this reaction is favored in acid solution and oxygen-free environments. The complete corrosion cell is represented by: Fe Fe2+ + 2e- Anodic Reaction 2H+ + 2e- H2 Cathodic Reaction This becomes overall: Fe Iron Ion + 2H+ Hydrogen Ion Fe2 Iron + H2 Hydrogen Gas Iron metal goes into solution (corrodes), hydrogen gas is generated. In the oxygen absorption reaction, the electrons at the cathode combine with oxygen and water to form hydroxyl ions. Chapter 7: Corrosion Oil Field Chemicals Training Manual 7-5 Property of Nalco Energy Services Confidential & Proprietary – DO NOT DUPLICATE The reactions would typically be: O2 Oxygen Atom + 2H2O Water + 4e- Electrons 4OH- Hydroxyl Ions This reaction added to: 2Fe 2Fe2+ + 4e- becomes overall: 2Fe Iron Atom + O2 Oxygen + 2H2O Water 2Fe2+ Iron Ion + 4OH- Hydroxyl Ions 2Fe(OH)2 Ferrous Hydroxide The iron ion and hydroxyl ions combine to form ferrous hydroxide, which is rapidly oxidized to ferric hydroxide. 4Fe(OH)2 + O2 + 2H2O 4Fe(OH)3 During rusting in the atmosphere, ferric hydroxide dehydrates to form red brown iron rust Fe2O3. 4Fe(OH)3 2Fe2O3 + 6H2O The oxygen absorption reaction occurs in fresh water, seawater, salt solutions, and alkaline or basic media, which are fully oxygenated. Since oxygen is not naturally present in oil and gas production, the hydrogen evolution reaction is most commonly encountered. If oxygen is allowed to leak into the production system, then the oxygen absorption reaction will take place. For corrosion to occur, there must be a formation of ions and release of electrons at an anodic surface where oxidation or corrosion of the metal occurs. There also must be a simultaneous acceptance at the cathodic surface of the electrons that were generated at the anode. The anodic and cathodic reactions occur at equivalent rates. Electrons flow from the anode to the cathode through the metal. Convention says that the electrical current flows in the opposite direction to the electron flow. Thus, the electrical current flows from cathode to anode within the metal. The metal betweenanode and cathode is an electrical conductor. Chapter 7: Corrosion Oil Field Chemicals Training Manual 7-6 Property of Nalco Energy Services Confidential & Proprietary – DO NOT DUPLICATE The Electrolyte The above reactions will only occur if the metal surface is covered by an electrically conductive solution. This solution is called an electrolyte. Water is an electrolyte whose electrical conductivity increases as the amount of dissolved salts or ions increase. The electrolyte conducts current from the anode to the cathode. The current then flows to the anode through the metal, thus completing the circuit. The combination of anode, cathode, and electrolyte is called a corrosion cell. Fe+2 Fe+2 2e-2e - 2H+ 2H+ H2 H2 Anode Cathode Electrolyte Figure 1. Figure 1 illustrates a typical corrosion cell. Metal atoms do not necessarily dissolve at a single point on the metal surface and cathodic areas are not restricted to one area on the metal surface. These processes may be limited to localized areas resulting in localized corrosion known as “pitting.” If the reactions occur randomly over the surface of the metal the result is general corrosion. The reason why some areas act as anodes and some as cathodes is not fully understood. In most cases it is assumed that it is due to inhomogeneities on the metal surface, or in the electrolyte or a combination of both. Chapter 7: Corrosion Oil Field Chemicals Training Manual 7-7 Property of Nalco Energy Services Confidential & Proprietary – DO NOT DUPLICATE 7.2.2 The Corrosion of Steel Most metals are not homogeneous; they contain inclusions, precipitates, and different phases. When such a metal is placed in an electrolyte, potential differences exist between these different areas, resulting in corrosion cells on the metal surfaces. For example, steel, the most widely used metal in the oil and gas production processes, is not a pure substance but is composed essentially of an alloy of iron and a number of trace elements such as carbon. Pure iron is a relatively weak, ductile metal. If it is alloyed with small amounts of carbon (0.2% to 1.0%), a much stronger metal is formed. The product of the iron and carbon is pure iron (Fe□) and iron carbide (Fe3C). Iron carbide is distributed within the steel as microscopic grains. These iron carbide grains, which appear as islands on the metal surface, have a lower tendency to corrode than the pure iron. The iron carbide and pure iron are in intimate contact, which allows electron flow between them. When the steel is placed in an electrolyte, the electrical circuit is completed, and current flows between the millions of micro cells on the metal surface. The iron acts as the anode and corrodes, while the iron carbide acts as the cathode. ANODE CATHODE Fe3C Fe Fe2+ Fe2+ e- H+ H+ H2 H2 H2 H2 H2 Figure 2. This is illustrated in Figure 2, where iron goes into solution at the pure iron anode and the electrons that are left behind migrate to the iron carbide cathode. As corrosion products accumulate, the potential distribution on the metal surface may change, shifting the anodic areas. Chapter 7: Corrosion Oil Field Chemicals Training Manual 7-8 Property of Nalco Energy Services Confidential & Proprietary – DO NOT DUPLICATE Other inhomogeneities in metals can be responsible for corrosion cells. Intergranular attack is caused and accelerated by potential differences between the grain and grain boundaries. Casting and welding can cause concentration differences in metal compositions from point to point, which gives a rise to potential differences between areas. - + -+ - +- + -+ - + METAL Figure 3. Metal inhomogeneities cause potential differences on metal surfaces. These differences are one of the primary causes of corrosion. Figure 3 illustrates this principle. Any metal surface is a composite of electrodes electrically short-circuited through the body of the metal itself. So long as the metal remains completely free of water, localized current does not flow and corrosion will not occur. Chapter 7: Corrosion Oil Field Chemicals Training Manual 7-9 Property of Nalco Energy Services Confidential & Proprietary – DO NOT DUPLICATE 7.2.3 Polarization As noted earlier, hydroxyl ions (OH-), hydrogen gas (H2), or both are produced at the cathode as a result of the corrosion reactions. If these chemical reaction products remain at the cathode, they stifle the cathodic reaction. Consequently, the anodic reaction also slows down since it cannot proceed at a higher rate than electrons can be consumed at the cathodic surfaces. Cathodic polarization acts as a barrier to current flow, so the rate of corrosion attack is decreased or stopped completely. This is illustrated in Figure 4. Fe2+ Fe2+ Fe2+ Fe2+ Fe2+ Fe2+ Fe2+ Fe2+ e-e- e- H+ H+ H+ H2 H2 H2 Gas Bubbles H2O H2O O2O2 OH- OH- OH- e-e- e- Fe FeFe Fe Fe Fe Fe Fe Fe Fe Fe (a.) (b.) Figure 4: (a) Polarization of the cathodic area at lower pH values by hydrogen molecules. (b) Polarization of the cathodic area by an alkaline film highly concentrated in hydroxyl ions. Chapter 7: Corrosion Oil Field Chemicals Training Manual 7-10 Property of Nalco Energy Services Confidential & Proprietary – DO NOT DUPLICATE 7.2.4 Factors Influencing Corrosion Mechanisms Corrosion principles have been generally discussed using steel as an example. Corrosion mechanisms can be greatly influenced by many factors such as: Electrolyte composition — conductivity, pH, salts Dissolved gases — oxygen, carbon dioxide, hydrogen sulfide Physical effects — temperature, pressure, velocity 7.2.4.1 Electrolyte Composition Conductivity The electrolyte completes the electrical circuit. The more conductive the electrolyte, the easier the current can flow and thus the faster is the corrosion rate. The amount of metal that dissolves is directly proportional to the flow of current. For example, one ampere of current flowing for one year allows approximately 9 kg (19.8 lb.) of iron to dissolve. Distilled water is not very conductive, whereas by contrast seawater is quite conductive and can be very corrosive. Here, we are considering conductivity alone. The presence of dissolved gases and the pH may make even distilled water corrosive, whereas a saline water containing no dissolved gas and at alkaline pH may be almost noncorrosive. Most formation waters produced with oil and gas contain high levels of salts and are very conductive. If all other conditions remain constant, the more conductive the electrolyte the less corrosion current is at a given electromotive force. Chapter 7: Corrosion Oil Field Chemicals Training Manual 7-11 Property of Nalco Energy Services Confidential & Proprietary – DO NOT DUPLICATE pH pH is a means for measuring the alkalinity/acidity of water. The pH range is expressed as a scale from 0 to 14 and is the negative logarithm of the hydrogen ion concentration. pH = - Log [H+] A pH value of 7 is neutral, below pH 7 the water is acidic while above pH 7 the water is alkaline. 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 ACIDIC NEUTRAL ALKALINE Since pH is a logarithmic function there is a ten-fold difference in concentration between each pH level. For example, at pH 5 the concentration of hydrogen ions is ten times that at pH 6. At pH 3, the concentration of hydrogen ions is one thousand times that at pH 6. On exposure of the metalto water, the localized cells function and corrosion commences. The variations of corrosion rate with pH depend upon the metal and the composition of the electrolyte. pH C or ro si on R at e pH C or ro si on R at e 14 14 (c.) (d .) pH C or ro si on R at e pH C or ro si on R at e 14 14 (a .) (b .) 0 0 0 0 Figure 5: (a) Nobel metals (i.e., gold, silver, platinum) (b) Metals with amphoteric oxides (i.e., zinc, aluminum and lead) (c) Acid soluble metals (i.e., magnesium) (d) Iron Figure 5 shows how the corrosion rate of various metals changes with increasing pH. Chapter 7: Corrosion Oil Field Chemicals Training Manual 7-12 Property of Nalco Energy Services Confidential & Proprietary – DO NOT DUPLICATE The noble metals (gold, silver, platinum, etc.) are relatively unaffected by the pH of water, while aluminum, zinc and lead exhibit what is known as “amphoteric characteristics.” In this case, the metal forms a protective hydroxide coating at neutral pH. When the pH is acidic or alkaline the protective hydroxide dissolves and the metal corrodes. Metals such as magnesium form protective hydroxide films which dissolve under acidic conditions. The corrosion rate of iron increases as the pH of the water decreases below pH 4. Between pH 4 and pH 12 a protective hydroxide film provides protection. This protective film dissolves below pH 4. At extremely high pHs iron is again attacked, by phenomena known as “caustic cracking.” 7.2.4.2 Dissolved Gases Dissolved oxygen, carbon dioxide and hydrogen sulfide considerably increase the corrosivity of water. In fact, most corrosion in oilfield processes is due to dissolved gases. If it were possible to exclude these gases pH would be maintained at 7.0 or higher and corrosion in the oil and gas production systems would be greatly reduced. Oxygen Of the three gases mentioned above, oxygen has the greatest potential for corrosion. Dissolved oxygen at very low levels can cause corrosion. Combination with either or both the other two gases (H2S or CO2) drastically increases their corrosivity. Oxygen accelerates corrosion in two ways: As a depolarizer. This means oxygen combines with electrons preventing the formation of a hydrogen protective blanket. The energy taken to evolve hydrogen gas at the cathode is a major bottleneck in the corrosion reaction causing it to slow down or stop completely. When oxygen is present, the corrosion rate is limited primarily by the rate at which oxygen can diffuse to the cathode. As an oxidizer. The oxidation of ferrous ions (Fe++) to ferric ions (Fe+++) increases the corrosion rate at pH above 4. This is because ferric hydroxide is insoluble and precipitates from solution. The corrosion rate increases as more ferrous ions are supplied from the metal to maintain the equilibrium in the solution. If the ferrous ions are rapidly oxidized to ferric away from the metal surface then the corrosion reaction proceeds very rapidly. If on the other hand the oxidation occurs so rapidly that the ferrous ions cannot diffuse away from the metal surface, then ferric hydroxide can form on the anode and become protective. Chapter 7: Corrosion Oil Field Chemicals Training Manual 7-13 Property of Nalco Energy Services Confidential & Proprietary – DO NOT DUPLICATE Whether the precipitated ferric hydroxide is protective or not depends upon the nature of the deposit. If the deposit is adherent, continuous and nonporous then it will be protective. This type of deposition is rarely achieved. The normal corrosion reaction in oxygenated systems is: 4Fe 4Fe++ + 8e- (1) 4Fe++ 4Fe+++ + 4e- (2) 4Fe 4Fe+++ + 12e- (3) Overall anode reaction 3O2 + 6H2O + 12e- 12OH- (4) Overall cathode reaction Therefore, balancing the electron producing and electron consuming reactions by combining (3) and (4): 4Fe + 3O2 + 6H2O 4Fe+++ + 12OH- (5) and finally: 4Fe+++ + 12OH- 4Fe(OH)3 Chloride ions can interfere with the formation of a protective layer and corrosion rates will then continue to increase with oxygen concentration. The amount of oxygen present in water is a function of the pressure in the system, temperature and chloride content. Oxygen is less soluble in saline water than in fresh water. Temperature Dissolved Oxygen Content (ppm) °C (°F) A B C 0 (32) 14.6 13.0 11.3 5 (41) 12.8 11.4 10.1 10 (50) 11.3 10.1 9.0 15 (59) 10.1 9.1 8.1 20 (68) 9.1 8.3 7.4 25 (77) 8.4 7.6 6.7 30 (86) 7.6 6.9 6.1 Where: A = Chloride content zero B = Chloride Content 10,000 ppm w/w C = Chloride content 20,000 ppm w/w Very small concentrations of oxygen (<1 ppm) can be very damaging. Chapter 7: Corrosion Oil Field Chemicals Training Manual 7-14 Property of Nalco Energy Services Confidential & Proprietary – DO NOT DUPLICATE Also, because of its depolarizing role oxygen will drastically increase the corrosivity resulting from other dissolved gases such as H2S and CO2. Concentration cells, or differential aeration cells can cause preferential attack or pitting. Whenever there is a difference in the oxygen content of water in two areas of a system, corrosion occurs preferentially in the areas exposed to the lowest oxygen concentration. Typical examples are crevices and water-air interface. In oil and gas production systems, only limited parts contain oxygenated fluids. Any oxygen present when the sedimentary rocks were laid down millions of years in the past will have reacted to form an oxide. This means that there is no free oxygen in the reservoir and as long as oxygen ingress is prevented the oil and gas production system will not suffer from oxygen attack. However, in sections of certain systems, notably the oily water effluent treatment plants, oxygen is not excluded and oxygen corrosion is experienced. Carbon Dioxide Corrosion caused by carbon dioxide is known as “sweet corrosion.” Carbon dioxide is about 36 times more soluble in water than oxygen at 25°C. It dissolves in water forming carbonic acid. This lowers the pH of the water and increases its corrosivity. The dissociation of carbon dioxide in water depends upon pH and can be described as follows: CO2 + 2H2O → 2H2CO3 2H2CO3 → H3O+ + HCO3- HCO3- + H2O → H3O+ + CO32- 2H3O+ → 2H+ + 2H2O Chapter 7: Corrosion Oil Field Chemicals Training Manual 7-15 Property of Nalco Energy Services Confidential & Proprietary – DO NOT DUPLICATE The overall reaction for the dissociation of carbon dioxide in water is: a) CO2 + H2O → 2H+ + CO3 The corrosion due to carbon dioxide proceeds as follows: b) Fe Iron Atom Fe2+ Ferrous Ion + 2e- Electrons Anodic Reaction c) 2H+ Hydrogen Ion + 2e- Electrons H2 Molecular Hydrogen Cathodic Reaction d) Fe2+ Iron Ion + CO3- Carbonate Ion FeCO3 Iron Carbonate Corrosion Product Combining a) and d), the overall reaction is therefore: Fe + H2O + CO2 FeCO3 + H2 The important factors governing the solubility of carbon dioxide are pressure, temperature, pH, and water composition. Pressure is most often the controlling factor, especially in gas condensate systems where the dissolved mineral content is low. It is usual to use the partial pressure of carbon dioxide as a measure of the potential for corrosion. Partial pressure = total pressure x mol. fraction carbon dioxide For example, in a system where the pressure is 6,000 psi with a gas containing 1.17 mol % carbon dioxide. Partial pressure = 6,000 x 0.0117 = 70.2psi The following yardstick has been used to assess corrosivity of gas condensate wells producing small amounts of low salinity water: 1. A partial pressure above 30 psi indicates that corrosion is almost certain. 2. A partial pressure between 7 and 30 psi indicates that corrosion is possible. 3. A partial pressure below 7 psi indicates noncorrosive conditions. Chapter 7: Corrosion Oil Field Chemicals Training Manual 7-16 Property of Nalco Energy Services Confidential & Proprietary – DO NOT DUPLICATE The above is based on the API guidelines that apply to most cases. However, recent field studies suggest that significant corrosion can occur even under 7 psi of CO2 pressure. The presence of dissolved acid salts can buffer the water such that large increases in carbon dioxide may produce only a small change in pH. The solubility of carbon dioxide is inversely proportional to temperature changes. Figure 6 illustrates the relationships between pH, pressure, temperature and the solubility of carbon dioxide in water. pH Pressure (psi) Pr es su re (1 00 0 ps i) ppm CO2 in Brine T1 T2 Te m pe ra tu re ppm CO2 P2 P1 (a.) (b.) (c.) T1 < T2 P1 < P2 Figure 6: (a) Effect of pressure of carbon dioxide on pH (b) Solubility of carbon dioxide with pressure (c) Solubility of carbon dioxide with temperature Chapter 7: Corrosion Oil Field Chemicals Training Manual 7-17 Property of Nalco Energy Services Confidential & Proprietary – DO NOT DUPLICATE Hydrogen Sulfide Corrosion caused by hydrogen sulfide is known as ‘Sour Corrosion’. Hydrogen sulfide is about 70 times more soluble in water than oxygen. Hydrogen sulfide represents a particularly serious corrosive problem because it can attack steel by three different mechanisms: acid attack, galvanic attack, or hydrogen attack. Acid attack — In the presence of water, hydrogen sulfide dissolves to form a weak acid, which then dissolves iron to form complex sulfides. In general terms the corrosive reaction can be described as: H2S Hydrogen Sulfide + Fe Iron FexSy Complex Iron Sulfides + 2H Atomic Hydrogen Galvanic attack — Iron sulfide is one of the most insoluble compounds known and tends to deposit on, and adhere to, the metal surfaces. Iron sulfide is cathodic to steel and so stimulates the generation of an electric circuit, which results in further attack on the iron. If the entire iron surface is covered with iron sulfide deposits then this will disrupt the adsorption of electrodes at the cathodic sites and stop the reaction. However, iron sulfide films are not normally continuous or adherent. Chapter 7: Corrosion Oil Field Chemicals Training Manual 7-18 Property of Nalco Energy Services Confidential & Proprietary – DO NOT DUPLICATE Hydrogen attack — Hydrogen attack takes two forms, namely “hydrogen blistering” and “hydrogen embrittlement.” In both cases hydrogen atoms are generated by the standard corrosive reactions. Under normal circumstances these hydrogen atoms combine in pairs to form hydrogen gas molecules, which escape from the surface into the environment. However, hydrogen atoms are sufficiently small to diffuse into the steel where they cause damage. Some substances such as sulfide ions reduce the rate of formation of hydrogen molecules from atoms. Therefore, in the presence of sulfide ions, there is a greater concentration of hydrogen atoms on the surface and hydrogen damage is more severe. − Hydrogen blistering — Hydrogen atoms diffuse through the steel and at some point combine to form molecular hydrogen. Hydrogen molecules are too large to diffuse through the steel, so are trapped, and build up as additional atomic hydrogen diffuses in and recombines. An accumulation of gas, under rising pressure, finally becomes so great that the metal is ruptured. The blister type of failure is a result of conditions that lead to the formation of hydrogen gas at a specific depth below the metal surface. Accumulated gas, therefore, lies in a plane parallel to the surface. Pressure is ultimately relieved along this plane. The outward signs of this appear as a characteristic bulge or blister, which may range from microscopic size to several inches in diameter. − Hydrogen embrittlement — This occurs in high strength steels where the metal lattice is highly strained. When atomic hydrogen diffuses into this lattice, it is further strained rendering the steel brittle and less ductile. The failure of these high strength steels due to hydrogen embrittlement does not necessarily occur immediately on applying a load. Often, there is a long period where no damage is observed, followed by a sudden failure. The time to failure increases as the H2S concentration decreases. As little as 0.1 ppm H2S in water and partial pressure as low as 0.001 atmosphere can cause this problem, although with very long time to failure. Hydrogen sulfide can be produced by microorganisms known as “sulfate reducing bacteria” (SRB). The presence of two or more of the gases (oxygen, carbon dioxide, or hydrogen sulfide) greatly increases the corrosive effect. Chapter 7: Corrosion Oil Field Chemicals Training Manual 7-19 Property of Nalco Energy Services Confidential & Proprietary – DO NOT DUPLICATE 7.2.4.3 Physical Effects Corrosion rates are affected by the various physical conditions that exist in the system, such as, temperature, pressure and fluid velocity. Temperature — The effect of temperature can vary according to other conditions that prevail at the time. Temperature increases can produce the following effects: − The rate of the corrosion reaction will increase. As a rule of thumb, chemical reaction rates double for every 460F (80C) rise in temperature. − The solubility of dissolved gases will decrease. In open systems, dissolved gases can escape as a rise in temperature reduces their solubility. In a closed system, the gases cannot escape. Thus, the corrosivity of water will increase with temperature rise up to the point that dissolved gases escape and then decrease, but in a closed system will continue to increase. − The solubility of dissolved salts will be altered. Calcium or magnesium bicarbonate dissolved in water will decompose as the temperature rises. Released carbon dioxide may produce higher corrosion rates, but the resulting calcium and magnesium carbonates may deposit on the metal surface and provide a protective scale. Pressure — The major effect of pressure is the increase in dissolved gas as pressure increases, with a consequent increase in corrosivity of the system. Velocity — The effect of velocity is variable. − Increase in velocity tends to increase general type corrosion rather than pitting type corrosion. − Low velocities tend to increase pitting corrosion but decrease general corrosion. − High velocities combined with the presence of suspended solids or gas bubbles produces an effect known as “erosion corrosion” and also “impingement” or “cavitation.” − Low velocities favor the growth of SRB and thus the production of corrosive hydrogen sulfide. − Low velocities in mixed hydrocarbon and water systems favor the separation of the two phases and thus increase the corrosion rate, while high velocities favor emulsification and water entrainment with reduced corrosion. Chapter 7: Corrosion Oil Field Chemicals Training Manual 7-20 Property of Nalco Energy Services Confidential & Proprietary – DO NOT DUPLICATE 7.3 Conducting a System Survey Guidelines for performing a system survey can be found in Attachment 1 in section 7.12, Appendix at the endof this chapter. 7.4 Types of Corrosion Failure of metals due to corrosion can occur in many ways. The most common form of corrosion is uniform loss of metal, but in oil and gas production operations, metal loss is frequently localized in the form of discrete pits or larger localized areas. Metals can also crack due to corrosion without any perceptible loss of material. It is important to know the various forms that corrosion can take and how it can cause problems in oil and gas operations. For convenience corrosion can be classified into eight types, based upon the physical appearance of the corroded metal. They are: Uniform corrosion Galvanic or bimetallic corrosion Concentration cell corrosion Pitting corrosion Intergranular corrosion Stress corrosion Erosion/corrosion, impingement, cavitation To see the effects of the various types of corrosion, please see Basic Corrosion Identification. 7.4.1 Uniform Corrosion This type of corrosion occurs when the anodic and cathodic areas keep shifting and corrosion takes place more or less uniformly over the entire exposed metallic surface. The metal becomes progressively thinner and eventually fails. This form of corrosion destroys the largest amount of metal, on a tonnage scale. However, technically, uniform attack causes the least concern since service life can be accurately estimated based on relatively simple laboratory tests. Localized corrosion often results in more unexpected failures. Chapter 7: Corrosion Oil Field Chemicals Training Manual 7-21 Property of Nalco Energy Services Confidential & Proprietary – DO NOT DUPLICATE 7.4.2 Galvanic or Bimetallic Corrosion This type of corrosion occurs when two different metals are in contact with each other and exposed to a corrosive electrolyte. This coupling of dissimilar metals is referred to as a “bimetallic couple.” Corrosive attack on the more reactive metal is increased and corrosive attack on the less reactive metal is decreased. The more reactive metal becomes the anode and the less reactive becomes the cathode; a galvanic cell is produced. For example, when copper and steel are connected and placed in an electrolyte, such as water, steel becomes an anode. The steel is said to be anodic to the copper, which is cathodic. Since metal loss occurs at the anode the steel corrodes. The driving force for the current, and hence corrosion rate, is the potential difference between the two metals. This is the principle of the “dry battery.” This principle can also be utilized beneficially in cathodic protection, where for example, steel is connected to a more reactive metal such as magnesium. The steel then becomes cathodic relative to the magnesium, which becomes the anode and corrodes preferentially. Figure 1, in the Appendix, shows a simple galvanic series for metals exposed to water. The farther apart the two metals are in this series, the greater the potential difference when they are coupled. The metal higher in the series becomes anodic to the one below it and preferentially corrodes. A general rule indicating the likely severity of corrosive attack in galvanic corrosion is the “Area Principle” or “Area Effect.” This states that the total corrosion is proportional to the total area exposed to the corrosive electrolyte. Also, where conditions for galvanic corrosion exist the least resistant metal will suffer almost all of the corrosion. Thus steel rivets in monel (a copper/nickel alloy) or copper sheet will corrode rapidly whereas monel or copper rivets in steel plate do not corrode. The total corrosion in terms of metal loss at the anode is proportional to the total area exposed. As the ratio of the cathodic area to the anodic area increases the corrosion rate of the more anodic metal is rapidly accelerated. Rapid catastrophic failure can result if small areas such as rivets, welds or flanges are anodic to the bulk material. The area affect can also be seen in the pitting of fresh steel pipe. As it comes from the steel mill the pipe is covered in mill scale. Mill scale is an electrical conductor and cathodic to steel. Therefore, areas that are covered with mill scale are protected and corrosive attack is concentrated on those areas where there is no mill scale. Eventually the mill scale loosens and is removed in the fluid stream so this type of attack occurs only in the early life of the system. Chapter 7: Corrosion Oil Field Chemicals Training Manual 7-22 Property of Nalco Energy Services Confidential & Proprietary – DO NOT DUPLICATE Other examples of galvanic corrosion are: Weld-line corrosion The welding process sometimes creates a microstructure near the weld, which differs in potential from the parent steel. This is called HAZ (heat affected zone). The different areas have different tendencies to corrode. Care is thus taken during welding to avoid this, e.g., by post-weld heat treatment. Ringworm corrosion In pipe or tubing manufacture the heat required in “upsetting” the pipe end causes the heated end to have a different grain structure from the rest of the pipe. A transition zone is formed near the upset run out, which is susceptible to corrosive attack. The corrosion occurs in a tube a few inches from the upset either in a smooth fashion or as severe pitting. Ringworm corrosion can be avoided by fully heat treating the tubing after upsetting. 7.4.3 Concentration Cell Corrosion Localized differences in electrolyte composition are referred to as concentration cells. A difference in potential is created when a single metal is exposed to water containing zones where the dissolved substances differ, or are present in different concentrations. The part of the metal in contact with the highest concentration of ion or substance becomes cathodic to that part of the metal in contact with the lowest concentrations of ion or substance. Examples of concentration cells are: Crevice corrosion Crevices on the metal surface promote the formation of concentration cells. For example, in oxygenated systems, oxygen in the crevice may be consumed more rapidly than fresh oxygen can diffuse into the crevice. This causes the pH in the crevice to decrease providing an acidic environment which accelerates corrosion. Another mechanism is described below (4. Deposits). Chances are that both occur. Oxygen tubercules This type of corrosion results from a similar mechanism to that of crevice corrosion but is caused by the formation of a porous layer of iron oxide or hydroxide which unevenly deposits on the steel surface. Chapter 7: Corrosion Oil Field Chemicals Training Manual 7-23 Property of Nalco Energy Services Confidential & Proprietary – DO NOT DUPLICATE Differential aeration cells An air/water interface in an atmospheric tank is one example of a differential aeration cell. The water near the surface contains more oxygen than the water below the surface. This difference in oxygen levels causes preferential attack at the water line. Deposits A deposit on the metal surface exposed to aerated water will corrode beneath the deposit as the oxygen level at that location becomes less than the oxygen concentration in the bulk liquid. As oxygen is hindered from migrating into the deposit, the area under the deposit becomes anodic relative to the surrounding area. Figure 7 illustrates this type of corrosion. The effect of dissolved solids on corrosivity is complex. Not only is the concentration effect important, but also the species of the ions involved. Some dissolved ions such as carbonate and bicarbonate may reduce corrosion by forming a tenacious layer. Others such as chloride and sulfate may increase corrosionby interfering with the formation of a protective layer and stabilizing pH. 7.4.4 Pitting This form of corrosion is not only the most difficult to predict, but also is probably the most vicious type. In this type the anodic area remains fixed in one place and corrosion therefore proceeds inwardly on one spot. The entire driving force of the corrosion reaction is concentrated at these localized spots where the corrosion rate will be many times greater than the average corrosion rate over the entire surface. The pits that result may be wide and shallow or deep and narrow. Pitting is more dangerous than general corrosion because the pitted area can become penetrated in a relatively short time. The formation of local cells due to a partial destruction or breakdown of protective scale causes pitting of carbon steel. When a corroding metal becomes covered with a corrosion product that is dense and adherent, the product protects the metal from further corrosion. If the protective scale is removed from localized areas then these become anodic to the other areas beneath the scale, which remains protective. The anodic areas corrode preferentially and pitting occurs. Oxygen, hydrogen sulfide, and carbon dioxide are the commonly encountered corrosive species that cause pitting in oil field systems. Chapter 7: Corrosion Oil Field Chemicals Training Manual 7-24 Property of Nalco Energy Services Confidential & Proprietary – DO NOT DUPLICATE Cl- O2 Na+ Ca2+ O2 O2 O2 Cl- Cl- Cl- Na+ (a) Debris settles on metal surface Fe2+ Fe2+ Fe2+ Anodic Area 2e 2e 2e Cathodic reaction O2 + 2H2O + 4e- 4OH- Cl-Cl - Cl- O2 O2O2 Na+Na+ (b) Oxygen can reach metal surface only at open surface. Cathodic reaction continues O2 + 2H2O + 4e- 4OH- Cl- Anodes Fe2+ Fe 2+ Fe2+ Fe Cl- Cl- Na+Na+ Na+ O2 O2 O2 Ca2+ Ca2+ (c) Oxygen continues to depolarize the cathodic area while chlorine diffuses into the porous deposit. Na+ Na+ FeCl Cl- Cl- Cl- FeCl2 Fe2+ Fe(OH)3 deposits O2 + 2H2O + 4e- 4OH- (d) The iron within the deposit remains soluble as Fe2+ in the absence of O2; and corrosion increases as ionic strength in the deposit increases. Figure 7. Chapter 7: Corrosion Oil Field Chemicals Training Manual 7-25 Property of Nalco Energy Services Confidential & Proprietary – DO NOT DUPLICATE Stainless steels are extremely susceptible to pitting because of the properties that make them stainless. Stainless steels are resistant to normal corrosion because protection is provided by the formation of a thin oxide layer. When this layer is destroyed in localized areas these become anodic and pit. High chloride levels in oilfield waters exacerbate pitting by creating a very aggressive environment within the pit as it forms. 7.4.5 Intergranular Corrosion In this form of corrosion, localized surface attack occurs along the metal grain boundaries. This results from a metallurgical structure that causes the grain boundaries to be more susceptible to attack than the grains themselves. Intergranular corrosion is experienced in many alloys including austenitic stainless steel, copper, aluminum and nickel alloys. There are numerous ways in which the alloys can be made resistant to intergranular attack, but most rely upon proper treatment during manufacture, such as annealing and careful control of the chemical composition of the alloy. 7.4.6 Stress Corrosion This is the acceleration of corrosion caused by stress. This is caused by an interaction between chemical and physical forces, either of which alone might not have caused the corrosion. In the absence of stress the metal would not corrode as readily, and in the absence of the corrodent, the metal could easily withstand the stress. The result of the combined effect is a brittle failure of a normally ductile metal. Stress corrosion results from the exposure of an alloy, under stress, to a particular corrosive environment. No one corrosive species causes stress corrosion in all alloys and most alloys are subject to attack in only a few specific corrosive environments. Mild steels are susceptible to sodium hydroxide (caustic) and nitrate attack. High strength steels are susceptible to hydrogen attack. Austenitic stainless steels are susceptible to chloride attack. Copper-based alloys are susceptible to ammonia and oxygen. Aluminum, nickel and titanium alloys are the most resistant to stress corrosion cracking, but even these alloys can be attacked under specific conditions. Chapter 7: Corrosion Oil Field Chemicals Training Manual 7-26 Property of Nalco Energy Services Confidential & Proprietary – DO NOT DUPLICATE 7.4.7 Erosion Corrosion, Cavitation, and Impingement Most metals owe their corrosion resistance to the formation of a protective film on the metal surface, usually formed from the metal oxide. Erosion corrosion is a type of attack where the protective film is removed at localized areas. This type of attack takes the form of a very rapid pitting or grooving attack at the areas where the protective film has been removed, usually by the physical attack of gas bubbles, liquid droplets (in gas systems) or suspended solids. Carbon steel and other low alloy steels are particularly susceptible to this attack. Cavitation is a localized form of corrosion, combined with much mechanical damage that occurs in turbulent areas of liquid flow. The formation and collapse of bubbles in the fluid cause it. Cavitation occurs wherever the absolute pressure at a point in the liquid stream is reduced to the vapor pressure of the liquid, such as around pump impellers. Damage is caused by repeated impact blows produced by the collapse of the voids within the fluid. Impingement is similar to cavitation attack, but is localized. It often results from turbulence associated with small particles adhering to a metal surface. The resulting attack consists of pits, which are elongated and undercut on the downstream end. This type of corrosion occurs in pumps, valves, orifices, on heat exchanger tubes, and at elbows and tees in pipelines. 7.5 The Prevention of Corrosion The four main ways in which corrosion can be avoided are through the use of: 1. Appropriate corrosion resistant materials for construction. 2. Coatings, linings, etc. 3. Cathodic protection. 4. Chemical corrosion inhibitors. Chapter 7: Corrosion Oil Field Chemicals Training Manual 7-27 Property of Nalco Energy Services Confidential & Proprietary – DO NOT DUPLICATE 7.5.1 Materials of Construction Mild steel is the material most often used in oil/gas production systems, especially for equipment such as wells, pipelines, vessels and tanks. For situations where more resistant material is required alternatives may be used, such as: Ferrous alloys − Stainless steels (e.g., 316 SS) − Martensitic steels (e.g., 13 Cr, 15 Cr) − Duplex steels (e.g., 22 Cr, 25 Cr) Non-ferrous alloys − Nickel-based alloys ⎯ Hastelloy (Ni - Cr - Mo) ⎯ Inconel (Ni - Cr - Fe) ⎯ Monel (Ni - Cu) − Copper based alloys ⎯ Admiralty metals − Aluminum-based alloys − Titanium The high cost of alloys and special metals is only justified when compared to the cost of maintenance or replacement, such as in an offshore environment. Other alternatives are often more attractive. The choice of material is usually made at the design stages. This decision involves metallurgists, production engineers and service companies who supply chemical inhibitors. Once the decision is made it is usually more expedient to then apply chemicalinhibition if unforeseen corrosion occurs. It is not proposed to discuss here in detail the different types and relative merits of the various metals and alloys used in oil/gas production systems. Chapter 7: Corrosion Oil Field Chemicals Training Manual 7-28 Property of Nalco Energy Services Confidential & Proprietary – DO NOT DUPLICATE 7.5.2 Coatings, Linings and Nonmetallic Piping For the purpose of this manual, we will discuss only internal coatings applied for protection against corrosion. A coating may be defined as a thin material applied as a liquid or powder, which, on solidification, is firmly and continuously attached to the material which it is designed to protect. For internal use, this may be called a lining. It is necessary that coatings have the following properties: Be flexible Be resistant to impact Be resistant to chemical attack from the fluids to be contacted Are nonporous to water Have good adhesion and cohesion Be stable at the temperature to which they are exposed Coatings may be classified into two main types: inorganic coatings and organic coatings 7.5.2.1 Inorganic Coatings Inorganic coatings include both sacrificial coatings, which furnish cathodic protection at small breaks in the coating, and nonsacrificial coatings, which protect only the area actually covered. Sacrificial coatings include galvanizing, or coating with other metals anodic to the metal to be protected, and massive suspensions of zinc particles in silicate or organic coatings. The zinc particle coating in organic medium, being nonconductive is less effective than that in silicate carrier. Sacrificial coatings are sensitive to extremes of pH, highly basic or acidic environment may quickly remove the anodic coating. Nonsacrificial coatings include metal plating cathodic to the metal to be protected, such as nickel, and nonmetallic coatings such as ceramics. It is essential that cathodic metal plating is nonporous to water. Nickel is such a cathodic coating, applied electrolytically or by a chemical process or by metalized spray. Ceramic coatings are effective against corrosion but are costly to apply and tend to be very fragile. For this reason, they are limited to relatively small pieces of equipment. Limited use has been made of cement coatings, mainly in tanks, filters and water disposal pipes and tubing. Cement linings are damaged by pH levels below 5 and by high sulfate levels. One disadvantage of cement lining is its porosity. Chapter 7: Corrosion Oil Field Chemicals Training Manual 7-29 Property of Nalco Energy Services Confidential & Proprietary – DO NOT DUPLICATE 7.5.2.2 Organic Coatings Organic coatings for internal application consist mainly of epoxy resins, phenolic resins, polyurethane and polyesters (PVC is not suitable in the presence of hydrocarbon). The phenolics, epoxies and polyurethanes are limited to a low nominal thickness because of their brittle nature. These coatings are acceptable if fiberglass or asbestos fibers are used as reinforcement. One of the main problems with organic coatings is that of mechanical damage to the surface which then completely nullifies the beneficial effect of the coating. 7.5.2.3 Nonmetallic Piping Nonmetallic piping should be briefly considered since its use is possible in some applications. Nonmetallic piping does not corrode in the strict sense, but it may deteriorate or be weakened by attack from its environment. There are various non-metallic materials used in piping such as: Extruded Thermoplastic Pipe —This material can be repeatedly reheated, softened and reshaped without destruction. Examples are: − Polyvinyl chloride (PVC) − Chlorinated polyvinyl chloride (CPVC) − Polyethylene (PE) − Polypropylene (PP) − Polyacetal (PA) − Acrylonitrile-butadiene-styrene (ABS) − Cellulose acetate butyrate (CAB) Glass Reinforced Thermoset Pipe — This material is chemically set and cannot be softened or reshaped. Examples are: − Fiberglass reinforced epoxy (FRE) − Fiberglass reinforced polyester (FRP) Cement Asbestos Pipe — This consists of a homogenous material made from cement, asbestos fiber and silica. It can be epoxy lined. Chapter 7: Corrosion Oil Field Chemicals Training Manual 7-30 Property of Nalco Energy Services Confidential & Proprietary – DO NOT DUPLICATE Plastic Lined Pipe — Nonmetallic pipes are attractive from many angles provided they meet the technical requirements. It is essential that the advantages and disadvantages be carefully studied. Advantages include: − Immune to corrosion by water − Light weight − Easily jointed and installed − Smooth interior allowing for reduced friction losses Disadvantages include: − Limited temperature and pressure working range − Require careful handling during installation − May be adversely affected by exposure to sunlight − Low resistance to vibration and pressure surges − More susceptible to erosion − Low mechanical strength Chapter 7: Corrosion Oil Field Chemicals Training Manual 7-31 Property of Nalco Energy Services Confidential & Proprietary – DO NOT DUPLICATE 7.5.3 Cathodic Protection Cathodic protection involves the application of a direct current from an external source to a metal surface immersed in an electrolyte to oppose the discharge of corrosion current from anodic areas. When such a protection system is installed, all exposed portions of the protected metal surface become a single cathodic area. Two methods are used: sacrifical anodes and impressed current: Sacrificial Anodes The choice of material used as sacrificial anodes is limited to those that are less noble in the galvanic series than those to be protected. For example, for the protection of steel the materials used as sacrificial anodes are usually aluminum, magnesium and zinc because of the great potential difference between them and steel. Zinc is used in low resistivity soils and water. Aluminum is excellent in saline water and also has a high energy capacity per anode weight. This relates to the rate at which the anode is consumed in use. For example, typically magnesium is consumed at an approximate rate of 17 pounds per ampere per year, zinc at a rate of approximately 26 pounds per ampere per year and aluminum alloy at approximately 7 pounds per ampere per year, for a similar system. Impressed Current For many systems, the amount of protective current required is too large for a practical size of sacrificial anode. In these situations it is more practical to use a silicon/iron alloy as an anode by connecting it to the positive side of a DC generator, at the same time connecting the negative side to the metal to be protected. In this way, generated currents can be used to make the protected metal cathodic. It is always important to ensure that anodes are properly installed so that minimum electrical resistance exists between anode and the surrounding electrolyte. For example, anodes used to protect structures should be placed in areas of low soil resistance with low resistance material packed around the anode to serve as a backfill. It is also important to minimize stray currents. In general, sacrificial anodes are used where the required amounts of protective current are small and well distributed, such as along a pipeline. They are also limited to soils and waters of low resistivity. On the other hand impressed currents are used to generate much larger currents and require an external power source. Impressed currents are most often used to protect storage tanks. Chapter 7: Corrosion Oil Field Chemicals Training Manual 7-32Property of Nalco Energy Services Confidential & Proprietary – DO NOT DUPLICATE Figure 8 demonstrates the theory of cathodic protection. Cathodic protection is used effectively to provide external protection to oil and gas lines and vessels, but is not effective in the protection of inner surfaces. +External DCPower Source Inert Anode Sacrificial Anode Current Flow From Anode Reduces Corrosion Current to Zero IMPRESSED CURRENT SYSTEM SACRIFICIAL SYSTEM Figure 8. 7.5.4 Chemical Corrosion Inhibitors An inhibitor is a substance, which when added to a system, slows down or even stops a chemical reaction. A corrosion inhibitor, therefore, is a substance, which when added to a corrosive environment, effectively decreases the corrosion rate of metals within it. One commonly used classification relates to whether the inhibitors are inorganic or organic. Chapter 7: Corrosion Oil Field Chemicals Training Manual 7-33 Property of Nalco Energy Services Confidential & Proprietary – DO NOT DUPLICATE 7.5.4.1 Inorganic Corrosion Inhibitors There are four categories of inorganic corrosion inhibitors, but the two main types are anodic and cathodic. The following chart describes each and provides examples. Type of Inorganic Corrosion Inhibitor Description Examples Anodic These inhibitors reduce corrosion by disrupting the electrochemical reactions at the anodic sites of the metal surface. The mechanisms involved vary depending upon the inhibitor used and are not easily explained. Essentially the most important mechanism is that of passivation. The passivating effect is detected as a shift in the corroding metal electrode potential to a more noble value, which makes it less reactive. Chromate — Chromates form films or complex precipitates that thinly blanket the metal surface. The film is initiated at the anode but may eventually cover the entire metal surface. Nitrites Silicates Molybdates These types of inhibitors are not suitable for oil/gas production systems. Cathodic These inhibitors are generally less effective than anodic inhibitors. They function by forming a film, often visible, on the cathodic surface. This polarizes the metal by restricting the access of dissolved oxygen to the metal surface. The film also acts to block hydrogen evolution and prevent subsequent depolarization. Polyphosphates Zinc Phosphonates These types of inhibitors are not suitable for oil/gas production systems. Combined Anodic/Cathodic Experience has shown that a combination of anodic and cathodic inhibitors can give an enhanced effect. This synergistic effect can be quite considerable. For example, chromate by itself requires 200 to 300 mg/l CrO4- - to prevent corrosion in a particular aqueous environment; but chromate combined with zinc and various organic and inorganic phosphates provides equal or better results at only 20 to 30 mg/l chromate. Zinc/chromate Chromate/polyphosphate Zinc/polyphosphate Polyphosphate/silicate These combinations are incompatible with oil/gas systems and, therefore, are not used. Chapter 7: Corrosion Oil Field Chemicals Training Manual 7-34 Property of Nalco Energy Services Confidential & Proprietary – DO NOT DUPLICATE Type of Inorganic Corrosion Inhibitor Description Examples Neutralizing This type of inhibitor chemically combines with a corrosive component of the metal environment, thus minimizing corrosive attack. Most neutralizers are organic chemicals, but examples of the inorganic type are: Oxygen scavengers, such as sodium sulfite or ammonium bisulfite, which reduce the oxygen content of injection waters, thus rendering them less corrosive. Ammonia gas is added to overhead distillation streams in refineries to neutralize acidic gases produced during the distillation process. Caustic soda is also used in refinery distillation units. Added to the crude oil feed it reacts with magnesium chloride, preventing its subsequent hydrolysis to hydrochloric acid. Neutralizer dosage is high, since it reacts stoichimetrically with the corroding species. It is convenient at this point to mention organic neutralizers, which work similarly to neutralize corroding species. These include morpholine which reacts with hydrochloric acid in refinery overhead streams, triethanolamine and diethanolamine which react with carbon dioxide and hydrogen sulfide in gas dehydration systems frequently located in oil/gas systems and sweetening units, and finally cyclohexylamine used to react with carbon dioxide in steam generator condensate return systems. Chapter 7: Corrosion Oil Field Chemicals Training Manual 7-35 Property of Nalco Energy Services Confidential & Proprietary – DO NOT DUPLICATE 7.5.4.2 Organic Inhibitors Organic corrosion inhibitors are carbon-based chemicals with nitrogen, sulfur, or phosphorous containing groups. These organic inhibitors cannot be specifically designated as cathodic or anodic since, as a rule, they affect the entire surface of a corroding metal. These inhibitors reduce corrosion by generating a protective barrier film on the metal surface. They are often called adsorption inhibitors. The first molecular layer formed may be strongly bonded perhaps by an electrical charge exchange analogous to a chemical reaction or by a physical bonding. The physical bonding process probably takes place for the deposition of subsequent layers of film. Most organic adsorptive inhibitors are long-chain molecules composed of two sections that exhibit different properties. At one end of the chain is a group with polar characteristics: the chain itself is nonpolar and hydrocarbon soluble. A simplified inhibition method has been postulated, which states that the polar head of the molecule attaches and bonds to the metal surface. The attachment mechanism is probably a combination of chemisorption and physical adsorption by Van der Waals forces. The strength of this bond has a significant effect upon the persistence of the inhibitor. The hydrocarbon soluble, nonpolar section of the molecule is then orientated outward from the surface of this metal to generate an oleophilic or oil wettable surface. By definition, this surface then is hydrophobic, or water repellent, and so the metal is isolated and protected from the corrosive aqueous phase. An idealized diagram of this concept is shown in Figure 9. METAL SURFACE NON-POLAR TAIL (OIL SOLUBLE) POLAR HEAD Figure 9. Chapter 7: Corrosion Oil Field Chemicals Training Manual 7-36 Property of Nalco Energy Services Confidential & Proprietary – DO NOT DUPLICATE In a hydrocarbon water system, the inhibitor exists in equilibrium between the two phases. A certain number of inhibitor molecules may be dissolved in each phase. Any additional inhibitor will exist as colloidal micelles. The micelles are not surface active and function mainly as reservoirs to maintain the concentration of soluble film forming molecules in each phase. As soluble inhibitor films onto the metal surface, more inhibitor is released from the micelles to maintain the soluble concentration. The attraction of the polar group to the metal surface is much stronger than to the hydrocarbon/water interface. This attraction is not easily reversible. This means that the inhibitor will persist for some time, even where there are no reserves in the environment, such as when addition of inhibitor is interrupted. This persistency characteristic depends greatly upon the particular inhibitor molecule and the environment in the system. Some inhibitors have a pronouncedability to entrain hydrocarbon into the “tail” of the molecule as it is attached and presented to the environment stream. The extra entrained hydrocarbon reinforces the hydrophobic nature of the film. Various factors are important in determining the effectiveness of adsorption inhibitors. These include the type of polar group, the number of bonding atoms, the carbon chain length, and the degree of aromaticity and/or conjugate bonding. 7.5.4.3 Types of Adsorption Inhibitors There are numerous types of inhibitors and combinations thereof. These can be exemplified by their chemical description. The following groups are typical. Primary Mono Amines Unmodified general formula: R - NH2 Modified: a) Salts from acids such as acetic acid: [R-NH3] + [CH3COO]- Chapter 7: Corrosion Oil Field Chemicals Training Manual 7-37 Property of Nalco Energy Services Confidential & Proprietary – DO NOT DUPLICATE b) Ethoxylates: R-N (CH2.CH2O) x H (CH2.CH2O) y H Where x and y very from 2 to 50. c) Amides (See Amides.) Polysubstituted Mono Amines a) Secondary amines R R NH b) Tertiary amines R R NR Diamines Unmodified: R-NH-CH2-CH2-CH2-NH2 Modified: a) Salts with acids (as per mono amines) b) Ethoxylates (as per mono amines) c) Amides (See below.) Chapter 7: Corrosion Oil Field Chemicals Training Manual 7-38 Property of Nalco Energy Services Confidential & Proprietary – DO NOT DUPLICATE Amides Produced by reaction of amine with fatty acid. Unmodified O ║ R - C - NH2 Modified Ethoxylates O ║ R - C - N (CH2.CH2O) x H (CH2.CH2O) y H Polyamines Unmodified: R-(NH-CH2-CH2)n-NH2 Modified as per mono amines. Imidazolines A type of tertiary amine. Unmodified: N CH2 RC N CH2 R’ R’ is usually: (CH2-CH2-NH)nH or (CH2-CH2-O)nH Modified as per A if R’ is CH2-CH2-NH2 Chapter 7: Corrosion Oil Field Chemicals Training Manual 7-39 Property of Nalco Energy Services Confidential & Proprietary – DO NOT DUPLICATE Quaternary Ammonium Compounds Unmodified: [RN(CH3)3] + X - Where X is usually chloride. Modified — by ethoxylation. In all the above groups, R is the oleophillic, hydrocarbon section of the molecule. Commercially the R components are derived from condensation reactions with “tall oils” that contain long chain fatty acids and rosin acids. Tall oils contain 60% to 70% fatty acids and 30% to 40% rosin acids. About 35% of all rosin acid is abietic acid. 7.5.4.4 Physical Characteristics of Corrosion Inhibitors Liquid chemical corrosion inhibitors are invariably a blend of 25 to 45% active inhibitor (and there may be up to three different inhibitors) blended with 55 to 75% of a complex solvent system comprising a basic solvent together with additional surfactants with specialized characteristics (co-solvent, antifoam, surface cleaners, emulsion breaker, etc.). Solubility This physical characteristic is of prime importance and allows liquid chemical corrosion inhibitors to be classified according to their solubility and dispersibility in water and hydrocarbon. Not only does solubility affect the filming properties, but it also controls the ability of the inhibitor molecules to be transported to the areas of corrosive attack. An inhibitor is generally considered soluble in a solvent if the inhibitor-solvent mixture remains clear. An inhibitor is considered dispersible in a solvent if it can be evenly dispersed in the solvent by moderate agitation. For these test purposes, the quantity of solvent is equal to or greater than the quantity of inhibitor. If the dispersion breaks rapidly in say less than one minute, it is known as a “temporary dispersion.” An inhibitor that remains uniformly dispersed in the solvent is a “dispersible inhibitor.” Depending upon the proportions of hydrocarbon/water and the inhibitor, some inhibitors may be partly soluble and partly dispersible in a solvent system. Chapter 7: Corrosion Oil Field Chemicals Training Manual 7-40 Property of Nalco Energy Services Confidential & Proprietary – DO NOT DUPLICATE The usual classification given to inhibitors based on their solubility is: Water soluble Oil soluble Oil soluble/water dispersible Limited solubility Oil soluble inhibitors are generally more persistent than water soluble inhibitors. Persistent in this context means strength of film adhesion. The more persistent the inhibitor, the less chance it will be washed away. Limited solubility inhibitors are the most persistent but their limited solubility decreases the feasibility of transporting them to the area of corrosion. Emulsion and Foam Forming Characteristics Filming corrosion inhibitors are surfactant and thus have a tendency to promote emulsions and foams in oil/water systems. Fluids from the system should always be tested to give assurance that emulsion and foaming characteristics for the recommended inhibitor are acceptable. A simple set of tests can be set up to do this. Compatibility with Other Chemicals It is recommended that the compatibility of the inhibitors be checked with regard to other chemicals in the system. Although there may be no apparent incompatibility when two or more chemicals are added at the low use concentrations, it is possible that they may nullify each other’s effect. On the other hand, if the chemical user wishes to mix two or more chemicals together before addition to the system, then greater care has to be taken since many oilfield chemicals have different solvent systems to those used in corrosion inhibitors. For the same reason, many oilfield corrosion inhibitors are not compatible with each other. An investigation should be made before any chemicals are mixed together. Thermal Degradation/Stability Corrosion inhibitors have temperature limits above which they lose their effectiveness and can also change their chemical compositions resulting in polymerization or “gumming.” This effect is also related to the time of exposure to the temperature. It is important that the inhibitor will withstand the temperature of its environment for the duration of its contact time, not only to ensure its continued effectiveness but also to avoid problems it may cause on decomposition. Chapter 7: Corrosion Oil Field Chemicals Training Manual 7-41 Property of Nalco Energy Services Confidential & Proprietary – DO NOT DUPLICATE 7.6 Value/ROI Calculations Obtain the current value/ROI calculations from the appropriate resource. 7.7 Failure Analysis Corrosion and/or mechanical conditions can cause failures. Correct identification of the cause of the failure allows you to get to the root cause of the problem and take the correct action to prevent future failures. If a failure is caused by corrosion, many times the type of corrosion can be identified visually by the “signature,” or pattern, that it leaves on the metal. Corrosion failures can be reduced or eliminated by the use of corrosion inhibitors. If, however, the failure is caused by mechanical conditions, corrosion inhibitors will not eliminate the mechanical stresses and, therefore, may not reduce failures. If necessary, a detailed analysis can be requested from the Sugar Land Metallurgical Laboratory. Be aware that although this analysis can provide valuable information to you and your customer, it can be costly and time consuming. Call your Research Group Leader for instructions on how to obtain this analysis.Described below are some corrosion signatures to look for when viewing a piece of metal: General Corrosion — Characterized by a uniform thinning of the metal without appreciable localized attack Under Deposit Corrosion — A type of localized corrosion that is characterized by any metal loss under a deposit Erosion Corrosion — Degradation of metal caused by a rapidly moving corrosive fluid; characterized by localized metal loss adjacent to the disrupted fluid flow, often resulting in the formation of horseshoe shaped pits with the “U” oriented in the direction of fluid flow Galvanic Corrosion — May show either generalized or local attack but will always involve two dissimilar metals; keep in mind that galvanic corrosion can occur even if one of the metals is present initially as an ion in the liquid phase. CO2 Corrosion — Characterized by pits with sharp edges and gently sloping walls; pits are distinctly round in shape, with round bottoms, and are often connected; frequently referred to as “ringworm” corrosion Oxygen Corrosion — Can vary in appearance depending on conditions; may cause general corrosion producing red or orange iron oxide (rust) deposits; more typically oxygen will cause distinct separated pits that tend to have very steep walls with sharp edges H2S Corrosion — Characterized by cone shaped pits with gently sloping edges; the metal around the pits will typically be covered with a dark iron sulfide coating; it may also be characterized by sulfide stress cracking. Chapter 7: Corrosion Oil Field Chemicals Training Manual 7-42 Property of Nalco Energy Services Confidential & Proprietary – DO NOT DUPLICATE Microbiologically Induced Corrosion (MIC) − Sulfate Reducing Bacteria (SRB) Corrosion — A type of MIC; SRB corrosion typically appears as clusters of distinct hemispherical pits that look like overlapping “grape clusters” or “rings within rings” − Acid Producing Bacteria (APB) Corrosion — A type of MIC; the bacteria produce lactic acid and acetic acid; APB corrosion typically appears as deep, narrow pits characterized as “worm holes” with smooth unattacked metal in between Weak-Acid Corrosion — Characterized by smooth walled pits with plateaus of unattacked metal in between Strong Acid Corrosion — Characterized by sponge-like appearance; pits are under-cut (they get wider as they get deeper); there are no plateaus of unattacked metal in between pits; attack will occur preferentially along welds and other stress lines. To better identify the various types of corrosion, please see the Basic Corrosion Identification handbook. 7.8 Corrosion Inhibitor Selection Process 7.8.1 Overview The test schedule for a typical corrosion inhibitor selection study is conducted in the following order: Field characterization Solubility/dispersibility screening Bubble test screening Rotating cylinder screening (if there are still a large number of candidates) Flow loop screening Jet impingement The study usually starts with a large list of candidates (ca 20), which would be progressively reduced at each stage. (The rotating cylinder screening is used only if dynamic tests are needed for a large number of candidates.) Usually, four products would be tested in the flow loop stage. All of the tests should be conducted under replicated field conditions at the correct operating temperature. Test solutions should be fully de-aerated with CO2 or the appropriate gas mixture, normally at 1 bar (absolute). The solutions should also contain any other oilfield chemicals such as scale inhibitor and demulsifier because in some cases these can severely affect corrosion inhibitor performance. This step is frequently not possible in new fields, so a final compatibility test must be completed as soon as the other chemicals have been chosen. Chapter 7: Corrosion Oil Field Chemicals Training Manual 7-43 Property of Nalco Energy Services Confidential & Proprietary – DO NOT DUPLICATE Important performance factors that need to be considered in the development of an inhibitor selection strategy are: Partitioning behavior. Film stability/persistency. Compatibility with other additives. Environmental impact. These will decide the appropriateness of an inhibitor for field trial/deployment and give a practical indication of the expected injection rate. 7.8.2 Test Schedule 7.8.2.1 Field Characterization and Testing Before any selection procedure begins, the most important step is to characterize fully the system. This will involve flow modeling to characterize the flow regimes and range of wall shear stresses experienced in the pipeline, and to identify critical areas where inhibition may be difficult because of local flow disturbances. This way the right conditions can be selected for the test methods. Full water analysis and operational conditions are also mandated so that the water chemistry used in the tests can be accurately replicated. Uninhibited field samples of crude oil should always be used wherever possible. 7.8.2.2 Replicating Field Conditions in the Laboratory Internal corrosion of oil and gas pipelines by transported fluids is complicated and is frequently tricky to replicate in the laboratory. Complete recreation of field conditions at a single laboratory test facility is not possible. Laboratory tests are basically conducted in a closed facility that is only charged once with the test environment; but in the field there is typically a once-through situation. For reproduction and standardization, polished steel specimens are regularly used in laboratory tests. These specimens consequent surface condition may be far different from that of the steel being used in the field where corrosion is of consequence. Obviously, it is important to recognize the confines of laboratory tests. They are a compromise in terms of copying actual field conditions. Even so, they are still valuable even if they eventually supply only a qualitative ranking of conditions or inhibitors, instead of a quantitative measure of absolute corrosion rates in the field. Chapter 7: Corrosion Oil Field Chemicals Training Manual 7-44 Property of Nalco Energy Services Confidential & Proprietary – DO NOT DUPLICATE An accurate simulation of field corrosivity begins with recreating system chemistry and temperature. The brine composition, crude oil type and water/crude oil ratio are especially important. The tests should be conducted at atmospheric pressure with the fluids being saturated with a gas mixture containing CO2 (and/or H2S) at the correct fugacity. An inert gas such as nitrogen or argon makes up the remainder of the mixture. Certainly, this is only possible for acid gas fugacities less than 1 bar. Pressurized equipment is available for higher values. Another approach often used in inhibitor selection for oilfield CO2 corrosion is to use testing as a ranking exercise, with 1 bar (absolute) of CO2 used throughout. This frequently surpasses the severity of the field conditions. In addition to these variables, it is important to recreate the hydrodynamics of the field situation when conducting the laboratory test. Liquid shear stress is considered an important hydrodynamic variable throughout the industry. This surface parameter best identifies the influence of a flowing fluid on the formation and stability/persistency of an adsorbed inhibitor film. Nevertheless, it is important to remember that this still shows only one, although significant, aspect of the influence of flow. In cutting back to meet laboratory testing restrictions, matching the surface shear stress will often rule out the ability to recreate the actual flow regime that is causing shear stress in service
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