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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(i.e., stratified or wavy flow, plug or slug flow). The implications of this are not clear; however, they probably influence protective film formation, inhibitor partitioning, access of the hydrocarbon phase to the steel surface and any mass transfer effects having to do with bulk fluid flow. To create confidence in the repeatability and reproducibility of test methods, it is important to develop a set of standard procedures and conditions that can not only be done on a regular basis for quality control purposes but also to characterize any new equipment in the inhibitor evaluation program. The standard procedure should include all aspects of the corrosion test, ranging from steel quality, specimen preparation, solution preparation and flow rate (shear stress), to corrosion monitoring method. 7.8.2.3 Solubility/Dispersibility Screening A product which is soluble in water only is not appropriate for use in a low water cut crude oil system because it would be difficult to deliver to all the water wet areas of the pipewalls. To address this concern all chosen products are first qualitatively checked for their solubility in brine and in oil. A transparent oil such as “maltenes” (xylene/ kerosene/gas oil) is used to copy crude oil. Corrosion inhibitors must be soluble or dispersible in both brine and maltenes in order to advance to the next stage of testing. Chapter 7: Corrosion Oil Field Chemicals Training Manual 7-45 Property of Nalco Energy Services Confidential & Proprietary – DO NOT DUPLICATE 7.8.2.4 Bubble Test Screening The “bubble test” is a simple sparged beaker test that can be set up rather rapidly. Therefore, it is best suited for quickly conducting a large number of tests (i.e., in the first stage of corrosion inhibitor selection) or for screening a wide range of field conditions. It is suitable to use a framework of several cells connected to an automated corrosion rate measuring system. The bubble test is used first when screening a large number of corrosion inhibitor packages. With this method, rapid screening can be done, instantaneously identifying any inhibitors that are incompatible with the test solution. The effect of inhibitor concentration on performance is reviewed as well as the time to reach maximum inhibition (adsorption kinetics). Oilfield corrosion inhibitors normally take up to 40 minutes to reach maximum inhibition. A product with adsorption times considerably more than this value is immediately rejected. The minimum corrosion rate is obtained for each inhibitor at a specific concentration; adsorption kinetics are used to rank inhibitors in a short-list for the next testing stage. The main limitation of the bubble test is that the shear stresses in the stirred solution are considerably less than those experienced in a pipeline. Determining the exact shear stress in the cell is not a straightforward task but an estimate can be taken from the equation for a rotating cylinder electrode. For a 3.8 cm magnetic stirrer bar rotating at 300 rpm the shear rate at the outside edge is 1.2 Pa. The value at the electrodes is probably less than this. In a standard export pipeline the average wall shear stress is ca 8 Pa. 7.8.2.5 Flow Dynamic Evaluation of Preferred Candidates The rotating cylinder electrode (RCE) and the flow loop test methods are then used to evaluate chosen candidates from the bubble test. The RCE is a useful intermediate step that can reduce the number of inhibitors advancing to the final flow loop stage. Again, simulated conditions are used that now include the flow effect. Tests involve examining the effect of inhibitor concentration on performance both in brine alone and in brine that contains 500 ppm crude oil. Inhibitor performance can be significantly affected by trace amounts of crude oil. The 500 ppm crude oil is typically added closer to the end of an inhibited run. A further test supplies a qualitative assessment of susceptibility to film breakdown for each of the inhibitors under consideration. A full anodic voltage scan in connection with the inhibited rest potential is applied to the test specimen to observe the voltages necessary for film breakdown and refilming. This is equivalent to noticing localized corrosion on stainless steels. Again, inhibitors are ranked on performance with a weighting based on their performance in the film breakdown test. Chapter 7: Corrosion Oil Field Chemicals Training Manual 7-46 Property of Nalco Energy Services Confidential & Proprietary – DO NOT DUPLICATE Rotating Cylinder Electrode High shear stress can be obtained in an electrochemical cell like the bubble test using a RCE. The arrangement is comparable to the rotating disc electrode (RDE) except that instead of the electrode being on the bottom, i.e., on the flat end of the cylinder, it is a small cylinder mounted along the shaft. Another difference is that while the RDE produces laminar flow contiguous to the electrode even at high rotation speeds, the RCE gives turbulent flow at all except the lowest speeds. This is because the Reynolds number necessary for the laminar to turbulent transition is lower on the side of the cylinder (>200) than on the bottom (104 -105). Because a mainstream commercial system can generate rotation speeds up to 10,000 rpm, shear stresses as high as ca 90 Pa can most likely be produced. While flow induced corrosion has been widely studied using both flow loops and the rotating cylinder, the RCE technique has become the popular choice for corrosion related studies. This is partially because it is easy to use and relatively low cost. It is currently used regularly in chemical vendor laboratories and contract corrosion research labs for corrosion testing and inhibitor screening. Flow Loop Of the numerous test methods available for corrosion inhibitor selection, the flow loop is the most costly and time consuming to perform. However, recent studies have shown that the loop is the superlative method to replicate flow disturbances at welds and bends that can have a considerable effect on the internal corrosion of pipelines. Consequently, it is important that ultimate corrosion inhibitor selection for internal pipeline protection is performed in the flow loop. Jet Impingement Jet impingement tests are used to screen corrosion inhibitors under extremely high shear stress (up to 1,000 Pa), representative of the most aggressive conditions encountered in the field, such as, slug flow, erosional velocities etc. The apparatus can be a part of a recirculated loop or a type of flow-through system, the latter design providing additional information about the film persistency properties of the tested products. The jet impingement test is also a rapid screening tool that can significantly speed up the product selection process, allowing for the evaluation of up to nine formulations per day. Chapter 7: Corrosion Oil Field Chemicals Training Manual 7-47 Property of Nalco Energy Services Confidential & Proprietary – DO NOT DUPLICATE 7.8.3 Performance Factors 7.8.3.1 Oil/Water Partitioning Studies Corrosion inhibitor partitioning characteristics must be identified before an accurate estimate of injection rate can be obtained and to ensure full protection in areas of water drop out or wetting. Evaluating inhibitor partitioning should center on corrosion performance instead of an analytical approach. Two tests can be employed: the equilibrium partitioning test where the equilibrium inhibitor performance is evaluated; and the partitioning kinetics test where the transfer rate from the oil phase to the water phase rate is assessed. In the equilibrium test, a known amount of corrosion inhibitor is allowed to disperse between a crude oil and brinephase over a period of up to 24 hours. Normally a range of water/crude oil ratios (1:9, 1:1, 8:2 v/v) and corrosion inhibitor concentrations are used. Three inhibitor concentrations are typically chosen to cover the range included in the flow loop calibration runs. The fluids are examined visually during each test to make certain that the corrosion inhibitor does not trigger the formation of a stable emulsion or any excess foaming. These can be costly problems to control in the field if they necessitate the use of extra demulsifier or anti-foam chemicals on top of the levels normally used in the fluids processing. After 16 hours, the brine phase is separated from the crude oil and its corrosivity is measured in the bubble test or flow loop. The resulting corrosion rates are compared to the bubble test or flow loop calibration curves of corrosion rate versus inhibitor concentration. This partitioning behavior can now be determined and an approximation of the dosing level of inhibitor needed in the field, into two- phase mixtures, to achieve satisfactory inhibition in the water phase. A complementary method to the equilibrium test is the partitioning kinetics test. A range of water/crude oil ratios (1:9, 1:1, 8:2 v/v) and corrosion inhibitor concentrations are used in this situation. Three inhibitor concentrations are normally chosen which include the range covered in the flow loop calibration runs. A known amount of corrosion inhibitor is added to the crude oil phase. The crude oil that contains the corrosion inhibitor is then put in contact with the brine phase and then small aliquots of brine are removed at different time intervals for later corrosion rate evaluation in the bubble test equipment. In this test, the corrosion rate as a measure of the amount of inhibitor in the aqueous phase is then related back to a partitioning rate. Chapter 7: Corrosion Oil Field Chemicals Training Manual 7-48 Property of Nalco Energy Services Confidential & Proprietary – DO NOT DUPLICATE 7.8.3.2 Persistency Studies Film persistency is a advantageous characteristic in a continuously injected or batch treatment corrosion inhibitor. This property makes it possible for inhibition to stay effective through operational upsets, extreme changes in flow rate/flow regime or interruptions in chemical deployment. A test method has been developed at Sunbury to look into this corrosion inhibitor property. In this method, which is based on the RCE apparatus, the concentration of corrosion inhibitor in the stripping liquid stays low. Thus the importance of mass transport declines and arguably can be overlooked in relation to the effect of shear stress acting on the inhibitor film. The test method monitors inhibitor performance under brine laydown conditions using the LPR technique. The effects of either uninhibited brine or solvent washing on the corrosion rate are then observed. This technique is limited because corrosion measurements can be made only in aqueous solution. This can be overcome by using the secondary harmonic generation (SHG) laser technique that facilitates the in-situ monitoring of adsorbed inhibitor film in either aqueous or transparent oil phases. 7.8.3.3 Compatibility Any potential product must be compatible with the environment in which it will be applied. Therefore, some or all of the following compatibility tests must be carried out as part of the selection process: Fluid compatibility — tests the solubility characteristics of the inhibitor in the system fluids to ensure there is no detrimental effect on performance and that the inhibitor can be transported through the system. Chemical compatibility — tests the effect on, or by, other chemicals in the system, e.g. scale inhibitors, emulsion breakers, asphaltene inhibitors, antifoams. Material compatibility — tests the effect on materials of construction of the chemical storage and injection system. Umbilical testing — ensures compatibility with materials of construction at the temperatures/pressures encountered in umbilical systems. Tests on the changes in physical properties of the inhibitor are included. Chapter 7: Corrosion Oil Field Chemicals Training Manual 7-49 Property of Nalco Energy Services Confidential & Proprietary – DO NOT DUPLICATE 7.8.3.4 Environmental Impact Currently, performance data, partitioning data and economic considerations are all used to choose which inhibitors should undergo compatibility testing and field trials. Another factor growing in importance is the environmental friendliness of corrosion inhibitors, and certainly other production chemicals. Increasing awareness and concern for the environment will without doubt require more rigorous legislation to control discharges into coastal and offshore waters. In the United Kingdom, the issue is pending the development of definitive guidelines on testing and acceptance criteria. It could place a restriction on the use of many existing production chemicals, bringing new greener chemistries into the market. 7.8.4 Field Assessment of Performance The final stage of any selection is confirming field performance. This can be done by conventional field corrosion monitoring or sidestream work and in the longer term by inspection. Nevertheless, these methods do have their problems. For example, flow conditions in a sidestream may be completely different from those in the pipeline. In addition, with certain designs of sidestream there is a pressure drop that can affect system corrosivity by changing the acid gas fugacity. Additionally, in many cases only the separated aqueous phase passes through the sidestream, consequently the effect of crude oil is not accurately measured. 7.9 Guidelines for Application of Corrosion Inhibitors There are many techniques used to apply corrosion inhibitors in oil and gas production systems. All have the same aims of laying down an inhibitor film that is impervious to the corrosive environment and of replenishing this film either continuously or periodically by batch treatment. The type of treatment and type of inhibitor is dependent upon the system. Specific areas of the production system that may experience corrosion are: Oil producing wells Gas producing wells Injection wells Production flow lines and pipelines Separators Effluent systems Gas compressor system Gas dehydration system Storage systems We will deal with these in more detail. Chapter 7: Corrosion Oil Field Chemicals Training Manual 7-50 Property of Nalco Energy Services Confidential & Proprietary – DO NOT DUPLICATE 7.9.1 Oil Producing Wells The problems occurring in producing wells are corrosion/erosion attack on the steel tubing caused by: High velocities. High conductivity brines. Fluids saturated with CO2 and/or H2S. The following sections address the different production wells and their inhibitor application methods, In addition to any system specific monitoring techniques. 7.9.1.1 Flowing Oil Wells Naturally flowing oil wells, those that do not require any form of artificial lifting, flow because: 1. Reservoir pressure is high. 2. The gas-liquid ratio is high. 3. The water percentage is low. 4. Or a combination of these factors. Treatment Methods Flowing oil wells that produce low percentages of water are usually not corrosive, but there are exceptions. If monitoring and/or experience indicate tubing corrosion is occurring, then inhibitor treatment may be required. Because of the nature of the well, the most practical batch inhibitor treatment method is tubing displacement (presuming that the tubing is set on a packer). Tubing Displacement Due to the relatively high pressure and fluidcolumn found in flowing oil wells, it may be difficult to pump the necessary amount of fluid to displace it to the bottom. Pump selection should provide both volume and pressure capability to handle this problem. Care should be exercised that wells are not fractured during tubing displacement treatments and that inhibitor is not displaced into the formation. Chapter 7: Corrosion Oil Field Chemicals Training Manual 7-51 Property of Nalco Energy Services Confidential & Proprietary – DO NOT DUPLICATE Nitrogen Squeeze As bottom hole pressure declines, flowing oil wells often reach the point where tubing displacement treatments will kill the well. To return the well to production, it may be necessary to displace with nitrogen using a coiled tubing unit. In these cases, the corrosion engineer should investigate the economics of discontinuing tubing inhibitor versus using nitrogen to lighten the displacing fluid so that the well can easily be returned to production. 7.9.1.2 Gas Lift Wells Several options and limitations apply to selection of inhibitor treatment strategy for gas lift wells, including: Gas lift wells usually have some standing fluid level in the tubing when shut-in. If a gas lift well is treated by pumping into the wellhead, sufficient fluid must be pumped at each treatment to assure movement of the inhibitor to the bottom of the tubing (full tubing displacement). Treatment programs involving injecting inhibitor into the gas lift depends on the configuration of the gas lift system. If individual wells are served by separate gas lift lines emanating from a central manifold, treatment at the manifold can be provided into each line from a single supply. If the gas lift system provides some type of lateral distribution, this is not feasible, and separate treatment of individual wells at the well would be required. Corrosion of gas lift tubing strings occurs mainly above the operating valve mandrel. If monitoring indicates this is the case in the prospective well, then treatment through the gas lift gas is feasible. If tubing corrosion is occurring below the operating valve, that area must be protected in some other manner, such as plastic coating or alloy tubulars. It is likely that as water cuts in gas lift wells increase, the accompanying increase in total fluid stream will result in tubing fluid velocity, mainly above the operating valve, exceeding erosional velocity. When this occurs, inhibitor treatment may be unable to effectively control corrosion. In such cases, plastic coated tubing should be used with supplemental inhibitor treatment at a reduced level. Chapter 7: Corrosion Oil Field Chemicals Training Manual 7-52 Property of Nalco Energy Services Confidential & Proprietary – DO NOT DUPLICATE Treatment Methods Tubing Displacement Tubing displacement is accomplished by pumping a slug of inhibitor, mixed with one to five barrels of diesel oil, lease crude/condensate, or field salt water as a diluent, into the well through the crown valve or gauge fitting with a pump truck followed by sufficient displacement fluid to move the inhibitor slug to the bottom of the tubing. The well is then returned to gas lift. There is little advantage in keeping the well shut-in after treating to permit better filming; an effective film should be essentially secured in 15 minutes or less. Alternatively, the inhibitor can be mixed with the total tubing volume of fluid, but the gain in having to mix and pump only one type of fluid is offset by the reduced concentration in inhibitor in the total fluid volume. Because of the reduced concentration, this method is not felt to be effective. Tubing displacement loads a gas lift well with a full head of fluid. Although the well can be returned to production with gas lift, it may be some time before the water cut and oil producing rate are stabilized at pretreatment rates. As a result, operating personnel may object to this method. There is no specific guideline for volume of neat inhibitor to use in batch type treating. The recommended minimum quantity is that represented by a 3-mil coating on the inside surface of the tubing. A 2 1/8” O.D. tubing string at 6,000 feet would require 71/2 gallons. Another guideline providing for a 25 ppm concentration is the total volume of production between treatments (about 1 gallon per 1,000 barrels). This guideline becomes meaningless if the treatment interval is too long; the persistence of an inhibitor film is not exceeded by use of increased volumes of batch treatment inhibitor. The correct treatment interval is a function of the well’s producing characteristics and the inhibitor’s performance characteristics, and must be optimized for each well or type of well in a field by appropriate monitoring. A one-week or shorter interval is probably uneconomical. If, because of high producing rate or severe corrosiveness, a short interval is needed, either a different inhibitor or alternative control method such as plastic coating or alloy tubulars should be considered. On the other hand, intervals of longer than one month are excessive; the program in such case is likely ineffective or may not be necessary at all. Chapter 7: Corrosion Oil Field Chemicals Training Manual 7-53 Property of Nalco Energy Services Confidential & Proprietary – DO NOT DUPLICATE Annular Slug The annular slug is a batch treatment injected into the annulus at the wellhead or through the gas lift entry line. Since injection is against gas lift pressure, a high pressure injection pump is needed. The treatment technique involves a slug of inhibitor, properly diluted, pumped into the annulus, preferably with some prewetting fluid and after-flush to avoid inhibitor dry-out in the dry gas atmosphere of the upper annulus. The batch is carried with the gas lift through the operating gas lift valve into the tubing. The treatment interval and volume of inhibitor for each treatment may be determined in a manner similar to a tubing displacement treatment. Annular Continuous In fields where gas lift systems emanate from a central gas lift header or manifold, usually at a test site, to the individual wells, treatment can be efficiently provided by injecting the neat liquid inhibitor continuously or sequentially into the individual gas lift lines at the manifold. The inhibitor should enter the gas lift zones as a liquid and no attempt should be made to atomize the fluid; both calculation and experience indicate that atomized inhibitor will not be carried in a gas stream beyond 100-200 feet before reverting to a liquid form. Movement of liquid inhibitor into wells has been found to be feasible in gas lift lines as large as 2 1/2 inches O.D. and several thousand feet long. The inhibitor probably accumulates and moves along as slugs, but the net delivery of inhibitor appears to be essentially levelled out by the time it enters the tubing through the gas lift valve. Continuous systems should be designed and the inhibitor selected so that it is injected neat (without dilution). This requires an inhibitor that is specifically formulated to avoid drying or polymerization in the dry gas lift gas stream. Provided such an inhibitor is chosen, and no extremely low environmental temperatures are encountered (-30°F), there is no advantage to diluting the inhibitor and the cost of dilution is avoided. Quantities of inhibitor delivered into each gas lift line should be adjusted to provide for a 20 ppm inhibitor concentration in the produced total fluid from the well. Initial treatment volumes for the first week of treatment for any well should be three to five times this treatment volume. Chapter 7: Corrosion Oil Field ChemicalsTraining Manual 7-54 Property of Nalco Energy Services Confidential & Proprietary – DO NOT DUPLICATE 7.9.1.3 Submergible Pumped Wells Treatment Methods Submergible pumped wells are usually prolific fluid producers, with high water cuts. The resulting tubing fluid velocity is relatively high so that film persistency is limited. For this reason, continuous treatment is the preferred method. The recommended concentration is 20 to 25 ppm based on total fluid production introduced into the wellhead annulus. Neat inhibitor may hang up and dry out in the upper annulus; therefore, it should be diluted with an appropriate flush fluid. A side-stream flush connected from the flow line can be used, but the connection may plug. The most satisfactory control is usually secured by installing plastic coated tubing and supplementally batch treating with inhibitor. Inhibitors used should be compatible with cable armor, which is usually galvanized, and with the cable insulation material used. If inhibitor is injected neat, some precaution should be observed to assure the inhibitor is not injected during downtime or pump malfunction. Chapter 7: Corrosion Oil Field Chemicals Training Manual 7-55 Property of Nalco Energy Services Confidential & Proprietary – DO NOT DUPLICATE 7.9.2 Gas Producing Wells The technology involved in treating gas wells is usually more complex than oil wells for the following reasons: 1. Pressures encountered in the tubing strings are almost invariably higher than in oil wells, with two resulting effects: a. Tubing failures in gas wells create higher risk potentials. b. Treatment of a high pressure well is a more difficult operation. 2. Other parameters, such as temperature, velocity and fraction of acid gases, quite frequently exceed those of oil wells. 3. Completion philosophy requires redundant producing pressure containment strings in corrosive high pressure gas wells. Tubing cannot simply be suspended in the production casing for the purpose of circulating inhibited fluids around bottom. 4. The mitigating effect on corrosion of a liquid hydrocarbon film is present only to a limited extent in gas wells or may be absent entirely. In corrosive wells, this lack must be compensated for by increased inhibitor. This complexity correspondingly translates itself into a treatment selection routine, which requires evaluation of all significant parameters to determine optimum treatment objectives. For the purposes of establishing treatment criteria, gas wells are classified as moderately aggressive and highly aggressive. A gas well should be regarded as highly aggressive if all of the following parameters are exceeded: a. Flowing bottomhole pressure above 6,000 psi b. Bottomhole temperature above 300(F and CO2 partial pressure above 100 psia, and/or H2S partial pressure above .05 psia c. Produces formation water Otherwise, the well should be regarded as moderately corrosive, unless operating experience indicates a highly corrosive environment exists. Chapter 7: Corrosion Oil Field Chemicals Training Manual 7-56 Property of Nalco Energy Services Confidential & Proprietary – DO NOT DUPLICATE 7.9.3 Injection Wells Injection wells differ from producing wells in that the fluid handled is moving from the surface where it is accessible for treatment before it enters the well. Surface handling offers the capability of removing most or all of the materials which cause corrosion so that corrosion problems in injection wells can usually be minimized with good design and operating practices. Nevertheless, certain precautions need to be observed with each type of injection well to assure corrosion will not occur. 7.9.3.1 Gas Injection Wells Gas to be injected into a reservoir will usually have been dehydrated to below the wellhead temperature dewpoint. If this is the case, no corrosion should occur in the injection well, even if the gas contains large quantities of CO2 or H2S, and no inhibitor should be used. If undehydrated gas is to be injected, inhibitors can successfully control corrosion, but will likely plug the sand face and reduce injectivity. In such wells, plastic coated tubing and inert alloy wellhead and packer components should be employed. A possible inhibitor solution is to apply an oil soluble organic inhibitor continuously via an atomizer. The inhibitor must be compatible with the temperature downhole and may be applied neat or diluted in diesel. 7.9.3.2 Water Injection Wells (Waterflood and SWD) Salt water that is free of dissolved CO2, H2S and O2 and does not contain sulfate-reducing bacteria is relatively noncorrosive. In particular, the use of any filming corrosion inhibitors should be avoided, since other agents for corrosion control are more practical and economical. In addition, corrosion inhibitor may restrict injectivity by plugging or altering the wetting characteristics of the reservoir rock. For corrosion control measures in water injection wells, the following practices should be observed. 1. Water should not be delivered directly form pressured vessels to the injection pump, but should pass through one or more atmospheric tanks or vessels so as to flash off any dissolved CO2 and H2S. 2. All water handling equipment should be effectively gas blanketed to avoid oxygen entry. The maximum level of dissolved oxygen in injected water should not exceed .05 ppm (50 ppb), and lower levels may be desirable. Either stripping towers or oxygen scavengers or both should be employed if needed to reduce O2 concentrations to below this level. Oxygen scavengers should be catalyzed, and initial treatment levels should be 10 ppm for every ppm or fraction of O2 present. Maintenance scavenger treatment should be adjusted to carry 5 ppm excess scavenger through the system. Chapter 7: Corrosion Oil Field Chemicals Training Manual 7-57 Property of Nalco Energy Services Confidential & Proprietary – DO NOT DUPLICATE 3. Sulfate reducing bacteria should be reduced to 10 colonies/ml or less in the water entering the injection wells, by periodic (biweekly) slug treatments with a bactericide. Treatment should be made as far upstream in the handling system as feasible. 4. Although not a corrosion control measure, injected water should be clarified to a maximum of 2 ppm in sandstone or 4 ppm in dolomite (limestone) reservoirs. The acceptable oil content for subsurface injection is generally 25 ppm under normal operating conditions and a maximum of 60 ppm under upset conditions. A surfactant should be added in concentrations of about 10 ppm if oil concentration causes formation plugging. 5. Injection lines, laterals and well tubing should be cement lined or plastic coated, unless experience indicates bare pipe is acceptable. 6. Injection lines and laterals should be designed so periodic pigging can be performed if subsequent operating experience shows the injection water has high sediment content. Pigging precautions should be observed in coated lines to avoid damaging coatings. 7.9.4 Production Flow Lines and Pipelines Based on the velocity, flow lines and pipelines may experience corrosion in low-lying sections of the pipe where highly conductive formation water saturated with acid gases (CO2 and/or H2S) collects. At the other end of the spectrum, high velocity corrosion is also very common. The solution is to apply an organic inhibitor. The choice of application method depends upon the type of system and product selection. 7.9.5 Separators Problems are caused in separators by corrosion from the separated water that is saturated with the acidic gases CO2 and H2S. Some corrosion is caused by hydrogensulfide produced from SRB introduced from the effluent system. The solution is to apply an organic corrosion inhibitor, which may be of the water-soluble type, continuously upstream of the separators. The inhibitor is usually applied neat via an injection quill. For corrosion caused by SRB being introduced from the effluent system, a water soluble corrosion inhibitor that also has biocide properties may be injected continuously. Alternatively, a biocide may be batch treated using say 200 ppm once per week for a period of say six hours. This slug treatment should be added upstream the separators neat via an injection quill. Chapter 7: Corrosion Oil Field Chemicals Training Manual 7-58 Property of Nalco Energy Services Confidential & Proprietary – DO NOT DUPLICATE 7.9.6 Gas Compressor System Corrosion in the gas compressor system is caused by the condensation of water saturated with acid gases CO2 and/or H2S, in the cooler scrubber. The solution is to apply an organic inhibitor with or without additional neutralizer. A water soluble inhibitor should be continuously applied neat, via an atomizer upstream of the cooler. If a volatile, neutralizing amine is added it should be chosen and dosed at a level to buffer the pH to an acceptable level. 7.9.7 Gas Dehydration System Corrosion in this system is due to the condensation of water, extracted by glycol, and saturated with acid gases CO2 and/or H2S. The solution is to apply a neutralizing amine such as an ethanolamine to control pH at 7 to 8.3. If the system requires it, a copper inhibitor should also be introduced. For serious corrosion, an organic inhibitor of the water-soluble type should also be added to maintain control. The addition rate will depend upon whether the system is open or closed and the selected inhibitor. Other measures that aid in minimizing corrosion include the following: The glycol storage tank should be gas blanketed to exclude air/oxygen. Reboiler temperatures should be kept as low as practicable (less than 400°F) to avoid glycol decomposition and fouling. Decomposition results in buildup of acid components which increase corrosivity. The concentration of salt in the glycol from salt water entrainment in the gas should be avoided. If salt concentrations exceed 50 to 100 ppm, consideration should be given to replacing the glycol. If corrosion problems persist, the glycol should be analyzed to help pinpoint the problem. If corrosion problems continue to persist, and particularly where a high CO2 fraction is present, inhibition may be inadequate and a replacement of affected components, using high alloy materials, is advisable. Chapter 7: Corrosion Oil Field Chemicals Training Manual 7-59 Property of Nalco Energy Services Confidential & Proprietary – DO NOT DUPLICATE 7.9.8 Storage Systems Corrosion in storage systems and associated pipework is mainly due to the action of SRB, generating hydrogen sulfide. It is common to avoid this corrosion by building the storage tank in lined steel and to fabricate the pipework in resistant materials if possible. Also, if necessary, apply a suitable H2S scavenger. Alternatively, an environmentally acceptable biocide could be applied by batch technique. 7.10 The Detection and Monitoring of Corrosion The development and implementation of an effective corrosion control strategy falls into three main categories: failure analysis/risk assessment; control procedures; and monitoring and inspection. These three categories are all interdependent because corrosion monitoring and inspection results must be used to reassess and change, where necessary, the risk and criticality assessment and any control procedures. The first two categories of the corrosion control strategy, failure analysis/risk assessment and control procedures, were already addressed in the above sections; this section will deal specifically with monitoring and inspection. 7.10.1 Reasons for Corrosion Monitoring In all cases, established monitoring and inspection procedures will need to confirm: Actual versus predicted corrosion rates. Process parameters within design limits. Correct operation of control measures. Monitoring and inspection are two overlapping tasks. The first responsibility is the ongoing corrosion process monitoring and necessary control measures. The second task involves ensuring mechanical integrity. Inspection also provides datum points used to relate to or quantify corrosion monitoring. In a corrosion control strategy, these tasks are used to determine whether the expected corrosion is actually happening, the corrosion rate and the effectiveness of any control measures. Chapter 7: Corrosion Oil Field Chemicals Training Manual 7-60 Property of Nalco Energy Services Confidential & Proprietary – DO NOT DUPLICATE 7.10.2 Monitoring Techniques A summary of the features of the six most widely used techniques is shown below. These techniques are also discussed in the REDIFAX. Technique Time for Individual Measurement Type of Information Speed of Response Possible Environment Electrical Resistance Probe Instantaneous Integrated Corrosion Moderate Any Linear Polarization Probe Instantaneous Rate Instantaneous Electrolyte Corrosion Coupons Long Duration of Exposure Average Rate and Type Poor Any Galvanic Probe Instantaneous Corrosive State Fast Electrolyte Hydrogen Probe Fast Total Corrosion Poor Nonoxidizing Electrolyte and Gases Test Nipple Spool Pieces Long Duration of Exposure Average Rate and Type Poor Any Please note that not all methods are necessary or appropriate for your system. It is recommended that the method(s) and frequency be mutually agreed upon with the customer. 7.10.2.1 Corrosion Coupons The simplest means for assessing the corrosivity of an environment to a specific material is to expose a specimen to that environment and to measure the corrosion rate over a given period. The specimen may consist of a simple coupon, test nipple, spool or special devices for assessing pitting, stress corrosion, hydrogen embrittlement, etc. A test coupon is a small piece of metal that is inserted into the system and allowed to corrode. The coupon is carefully cleaned and weighed before and after insertion in a system. The corrosion rate is determined based on the weight loss. Specially designed holders are available which allow the simultaneous exposure of many coupons. These coupons must be electrically insulated from each other and from the support, unless bimetallic corrosion effects are being studied. Figures 10 and 11 illustrate two typical assemblies. Chapter 7: Corrosion Oil Field Chemicals Training Manual 7-61 Property of Nalco Energy Services Confidential & Proprietary – DO NOT DUPLICATE Coupon Preparation Since the critical measurement is weight loss, a large surface area/mass ratio is desirable to improve accuracy. The coupons may be in the form of plates, rods or discs, or any other convenient shape. The edges need to be machined and polished to avoid preferential attack caused by residual stresses introduced when cutting the specimen. Holder Stainless Nuts Flat Insulation Plate Coupon Insulating Washer Stainless Bolt Insulating Sleeve Figure 10. Pipe Plug Insulator Rod Style Coupon Figure 11. Chapter 7: Corrosion Oil Field Chemicals Training Manual 7-62 Property of Nalco Energy Services Confidential & Proprietary – DO NOT DUPLICATE It is possible to simulate many metallurgical conditions by suitable treatment of the specimen in orderto obtain a wide range of data. Stressed coupons and simulated crevices can be included. All traces of grease, oxides and other contaminants must be removed before installation. To improve reproducibility, the surface finish should resemble that of the system under investigation. It is usual to polish the surface with a 120 metallographic paper or give a light sand blasting. Gloves should be used when handling the coupons after the final degreasing operation before installation. Specimen identification marks are essential and should preferably be positioned where the coupon holder will protect them. Exposed etched numbers may disappear in use and stamping on an exposed surface may introduce stress or crevice corrosion. Predrilled holes in the coupon at coded locations are often the best means of identification, assuming no stress has been introduced in the drilling operation. Location Corrosion does not necessarily occur uniformly throughout a system. For example, within a vessel different environments will exist, e.g., liquid, liquid/vapor, hydrocarbon, water, etc. Different corrosion rates may be found in each situation. In addition, local variations due to impingement, variable velocities and temperature differences will all give different corrosion ratings. It is therefore necessary to install several coupons in different, carefully chosen locations, to fully monitor the system. Installation Systems are available which allow on stream lines up to 10,000 psi to be “hot tapped” and coupons installed and removed as required. This facility is restricted to smaller coupons, but duplicate specimens may be mounted on a central support. This “access under pressure” does give some control over the length of time a coupon is exposed. It is not necessary to wait for a routine shutdown before access can be made. Exposure Time Short-term exposure gives a quick answer, but such results can be misleading. In the initial evaluation of a system that is possibly not in control, a relatively short two-week exposure is a good rule of thumb. After control is established, typical exposure time is from 30 days and even up to three months. In any case, it is important that time is allowed for the coupons to attain steady state corrosion. Chapter 7: Corrosion Oil Field Chemicals Training Manual 7-63 Property of Nalco Energy Services Confidential & Proprietary – DO NOT DUPLICATE Coupon Corrosion Assessment After exposure to the system, the coupons should be carefully examined and a record made of the appearance of corrosion products before cleaning and weighing. Accumulated corrosion products and deposits should be removed either mechanically by scrubbing, scraping, sandblasting etc., or chemically by solvents, or pickling in inhibited acids or alkalis. From the weight loss, known coupon dimensions and the metal density, the corrosion rate can be calculated from the following equation: (Area Factor*) ° (WT. Loss in Mg) Corrosion Rate (mpy) = Days Exposed The area factor is computed from the exposed surface area and density of the steel. Results Corrosion 0 to 1 mpy Nil or mild 1 to 3 mpy Moderate 3 or more mpy Severe Corrosion rate measured in this way assumes that metal loss has occurred uniformly. A visual examination using a metallurgical microscope can be used to detect the presence of localized corrosion in the form of pitting, intergranular corrosion and stress corrosion cracking. Value of Coupon Technique This technique has an advantage in that many different materials can be exposed to one location and also that data on the form of corrosion of the specimen can be obtained. The main disadvantage of this technique is its inability to detect the short-term effect of changes in process conditions. In addition, the behavior of the specimen may not always be representative of that of the system. The corrosion coupon technique is simple but should be regarded as a back up to confirm the results obtained by the other methods. Chapter 7: Corrosion Oil Field Chemicals Training Manual 7-64 Property of Nalco Energy Services Confidential & Proprietary – DO NOT DUPLICATE 7.10.2.2 Electrical Resistance Probes (ERP) Electrical resistance instruments quantify metal loss by measuring the increase in resistance of a metal specimen as its cross sectional area is reduced by corrosion. Description The ERP consists of a metal wire, strip or tube, fabricated from the same metal as the system under investigation. (See Figure 12.) Strip Loop Tube Loop Wire Loop Tube Loops Flush Mounts Figure 12. Available CORROSOMETER® element styles. A test element normally in the form of a wire, tube or strip, is sealed with epoxy resin or ceramic into the end of a probe alongside a reference element that is protected against corrosion by ceramic or epoxy filling. In this way, the reference element can be subjected to temperatures similar to the test element. A second reference electrode is placed within the body of the probe and used to check measurements on the integrity of the filling system and internal circuits of the probe. The reference electrode forms the second arm of a resistance bridge when measurements are made. It is protected mechanically on the probe by a perforated shield. Commercial probes are available in a range of alloys with a variety of element types and thickness. Choice of element is a compromise between working lifetime and sensitivity. The greatest sensitivity is obtained by using thin elements but their lifetime is much shorter than with less sensitive thicker elements. Chapter 7: Corrosion Oil Field Chemicals Training Manual 7-65 Property of Nalco Energy Services Confidential & Proprietary – DO NOT DUPLICATE The most sensitive elements are made of thin foil. Tube element probes are perhaps the best compromise for field use since they combine average sensitivity with strength for use in high fluid velocity. Unlike the wire element, the development of a pit in a tube element has relatively little effect on cross sectional areas and thus readings are less likely to confuse interpretation. ERPs are available which can be installed so that they are located “flush” with the metal surface of the system. This installation eliminates any erroneous results caused by the ERP extending into the process flows. Application Details The electrical resistance technique is accepted and used extensively in the process and other industries. The technique has limitations; correct probe selection and location can be critical. Type of Environment The ERP can be used to measure corrosion in liquid or vapor phase and the liquid does not have to be an electrolyte. The probe design and materials set the main limitations, and the fact that corrosion must be roughly uniform. Location As with coupons, the probe has to be located in a position where conditions are representative of the corroding area. Temperature and velocity are important variables. Impingement of high velocity fluids directly on to the probe should be avoided unless erosion/corrosion effects are being studied. Where fluid velocity is critical, more accurate results can be obtained by using flush mounted probes. It is advisable to install several probes, some in locations where corrosion rates are likely to be the highest and some in locations where corrosion will be “average.” Potential Errors in the Use of ERPs The main cause of error in interpretation of results is the assumption that the corrosion indicated by the change in resistance of the test element is proportional to that of the plant. This technique cannot follow the rapid changes ofcorrosion rate and a longer-term view is required. In streams with rapidly fluctuating temperatures, the precision of individual readings is reduced and averaging of results is necessary. This occurs because the exposed test element responds to changes of temperature more quickly than does the protected reference element. Localized corrosion, such as pitting, stress corrosion etc., cannot be readily detected by the electrical resistance probe. Initially the effect of localized corrosion on the probe is small. Toward the end of the probe life a marked increase in apparent corrosion rate can be due to localized corrosion on the element. Chapter 7: Corrosion Oil Field Chemicals Training Manual 7-66 Property of Nalco Energy Services Confidential & Proprietary – DO NOT DUPLICATE Most corrosion products or deposited materials do not affect the electrical resistance measurements significantly since the electrical conductivity of the metal is much higher than that of the deposit. However, certain deposits such as sulfides do cause problems in sour systems. Data Loggers A potential problem with the ERP is measurement. To accurately assess the corrosive attack being experienced by a system, the installed ERPs have to be regularly measured. The more frequent the measurement, the more clearly the status of the system can be determined. This either requires regular visits by process operators, which is a drain on limited manpower resources, or wiring of ERPs back to the control room, which is extremely expensive. The result frequently is that ERPs are only measured once or twice per week, which does not give a satisfactory “picture” of the status of the system. A method of overcoming this problem is to install a data logger. These are available from Nalco Ltd., as well as various instrument companies, and comprise a box (approximately 12” x 8” x 5”), which is installed close to the ERP and connected to it. The logger will measure the readings from the ERP, the frequency can be from two to three times per hour to two to three times per week, and record it electronically. The stored data can then be retrieved and examined when convenient to the operator. 7.10.2.3 Linear Polarization Probes (LPR) Linear polarization offers a means for instantaneous measurement and read out of corrosion rate, unlike electrical resistance which requires a comparison of readings over a period of time. Description The principle of the LPR probe is similar to electrolysis. An anodic battery half-cell and a cathodic half-cell create a complete cell when in a conductive liquid solution. The completed battery cell induces an electric current resulting in decomposition into ions (corrosion) of the metal used in the pipeline or vessel wall. This occurs as a result of electron transfer between the atoms of the metal and atoms of the elements or compounds present in the environment of the metal. The electric current so produced is directly proportional to the rate of metal loss (Faraday’s Law). However, it is not possible to measure the corrosion current externally with an ammeter. This is because the cathodic current and the anodic current have the same magnitude and thus cancel out each other to give a ZERO net current. In order to achieve a measurable current, a small external voltage must be applied. It was found that the resulting current is directly related to the corrosion rate as described by the following equations. Chapter 7: Corrosion Oil Field Chemicals Training Manual 7-67 Property of Nalco Energy Services Confidential & Proprietary – DO NOT DUPLICATE The applied current required to change the electrical potential of the corroding specimen does not affect the rate and type of corrosion reactions, provided the change in potential is no more than 10 to 20 millivolts. The applied current is then assumed to be proportional to the corrosion current. The relationship can be expressed as follows: IappIcorr = B ∆Ε Where: Icorr = Corrosion rate of specimen Iapp = Applied current required to change the electrical potential of the specimen by ∆Ε Ε = Required voltage potential (10 to 20 mV) B = Stern-Geary constant (usually assumed 26 to 30mV Thus if B is a known value, the measurement of applied current (Iapp) required to change the potential of the specimen by a known amount (∆Ε) leads to the corrosion current. The corrosion rate of a steel specimen in mils (1/1,000 inch) per year can be calculated as follows: mpy = 0.46 ° I A A cm corr ( ) ( ) μ 2 ⎡ ⎣⎢ ⎤ ⎦⎥ Where: A = Surface area of the corroding specimen. This formula is derived by using Faraday’s Law, noting that the rate at which metal dissolves due to corrosion is proportional to the corrosion current per unit surface area. In practice, the constants can be compensated for in the measuring instrument. If the electrode area (A) and the potential change (∆Ε) are set at fixed values, then the instrument can be calibrated to give a direct corrosion rate read out. Chapter 7: Corrosion Oil Field Chemicals Training Manual 7-68 Property of Nalco Energy Services Confidential & Proprietary – DO NOT DUPLICATE Commercial Instruments Linear polarization instruments are available in either 2-electrode or 3-electrode types. (See Figure 13.) Test Test Test AuxiliaryReference Figure 13. The 2-electrode system consists of a potentiostat and probe. The probe assembly is mounted in piping or vessels and connects to the meter by cable. The 2-electrodes are made of the metal to be studied. Corrosion rates are determined by measuring the applied current required to polarize the electrodes to a 10 to 20 millivolt potential difference. Polarity is then reversed and the process repeated. The average reading is then corrected for IR drop due to the resistivity of the electrolyte and converted to corrosion rate based on the aforementioned equation. The 3-electrode system utilizes a potentiostat and a probe with three electrodes made of the metal being studied. Power is applied across two of the electrodes and sufficient current applied to polarize the test electrodes by 10 millivolts. The test electrode potential is measured with reference to the unpolarized third electrode using a high input impedance voltmeter (a.k.a. electrometer). The reference electrode reduces the effect of IR drop when using low conductivity liquids. This type of system can be calibrated to read corrosion rates directly. Chapter 7: Corrosion Oil Field Chemicals Training Manual 7-69 Property of Nalco Energy Services Confidential & Proprietary – DO NOT DUPLICATE Both two and three electrode probes are available with replaceable probe elements that may also be used as weight loss coupons. Probes can be obtained in flush mounted configurations for use in pipelines. Either portable reader or a full size instrument can be used to record data. A remote data collector is useful for hard to access areas. Limitations The technique requires the presence of a continuous electrolyte. Measurement cannot be made in gas or oil. Measurements can be made in oil and water mixtures if water is the continuous phase, and provided the elements are not fouled by the oil or iron sulfide. Thus the LPR is not applicable to the majority of the oil/gas systems and is generally used only in the oily effluent process streams. The technique is limited to situations where uniform corrosion is expected and is not suitable where pitting or localized attack is expected. 7.10.2.4 Galvanic Probes The galvanic probe consists of a pair of electrodes made of dissimilar metals, usually brass and steel. The electrodesare connected to each other externally and the probe inserted into a tank or pipeline. The two metals assume different potentials, and when connected, an electric current flows. The amount of current that flows is proportional to the corrosivity of the environment. The system is used as a qualitative check on changes in the corrosion rate of the system. Galvanic probes are mainly used for the detection of oxygen ingress or biological activity, both of which result in cathodic depolarization. Figure 14 shows a typical galvanic probe assembly. Nylon Insulator Steel Electrode Brass Electrode 1” MPT To Current Monitor Chapter 7: Corrosion Oil Field Chemicals Training Manual 7-70 Property of Nalco Energy Services Confidential & Proprietary – DO NOT DUPLICATE Limitations This technique is generally applicable to monitoring dissolved oxygen and not suitable for measurement of attack due to CO2 or H2S encountered in oil production systems. The probe is susceptible to fouling as with other techniques but more so. 7.10.2.5 Hydrogen Probe Many corrosion reactions evolve hydrogen, which can lead to damage and equipment failure. These include hydrogen embrittlement and hydrogen blistering. The corrosive attack of metals under anaerobic, acid conditions commonly found in oil and gas systems results in the generation of atomic hydrogen. Atomic hydrogen is capable of permeating metals, which is the root cause of hydrogen damage. Atomic hydrogen enters the granular or interstitial voids in the metal, and having done so may then combine to form molecular hydrogen (H2), which is too large a molecule to permeate further. The accumulation of recombined hydrogen produces considerable pressures within the metal, leading to blistering or cracking of the metal. The phenomenon of hydrogen permeation through metals can be used to detect corrosion. The procedure is known as hydrogen flux monitoring (HFM). The process can be either “intrusive” or “non-intrusive”: Intrusive The term intrusive means that the monitoring device extends into the process being monitored. The probe consists of a thin walled steel shell that allows atomic hydrogen to diffuse through into a narrow annular space, which is connected to a pressure gauge. The amount of hydrogen passing through is estimated by the rate of increase of pressure. A bleed valve is required to periodically release hydrogen pressure to avoid rupture of the tube. Chapter 7: Corrosion Oil Field Chemicals Training Manual 7-71 Property of Nalco Energy Services Confidential & Proprietary – DO NOT DUPLICATE Figure 15 shows a simplified diagram of an intrusive device. Pressure Guage Bleed Valve Coated Area Exposure Area Metal Figure 15. Nonintrusive The principle of the probe described above is the same except that the nonintrusive device does not enter into the system. Instead, it is externally applied to the pipeline or vessel surface itself. (See Figure 16.) Metal Pressure Gauge Bleed Valve Patch Figure 16. Chapter 7: Corrosion Oil Field Chemicals Training Manual 7-72 Property of Nalco Energy Services Confidential & Proprietary – DO NOT DUPLICATE Hydrogen atoms generated by the corrosion reaction pass through the metal wall entering a containment area formed by welding on a patch contoured to fit the surface. The patch is connected to a pressure gauge and the rate of increase in pressure due to recombined hydrogen molecules is measured. A variation on the patch probe utilizes a special hydrogen-detecting device that replaces the pressure gauge. In the hydrogen-collecting area above the patch is located a detector consisting of three major elements. These are a “palladium working” electrode, a proton conducting electrolyte and a defect tungsten bronze reference electrode. When the working electrode is exposed to hydrogen, a potential difference is generated which is proportional to the hydrogen concentration at the working electrode. The resulting electrical output can be fed to a continuous readout instrument. The hydrogen probe can be used to provide quantitative measurements by computing the area of the diffusion cell and the volume of the annulus and using gas-law calculation to relate the volume of diffusing gas to the observed increase in pressure. In use, stabilized conditions may not be reached until the hydrogen transmission metal has become hydrogen saturated. This may take up to 48 hours. Measurements should be observed until a steady state exists at which point maximum accuracy will be obtained. 7.10.2.6 Chemical Methods Iron Counts The presence of iron, either dissolved or particulate, in the system fluids can be an indication of corrosion. It is usual to measure the dissolved iron in the aqueous fluids but it is also important to note that particulate iron corrosion products, such as iron sulfide, will travel with the hydrocarbon. Therefore, if iron counts are to be used, both hydrocarbon and water phases should be examined. Use of iron counts involves three stages. These are sampling, analysis and interpretation. Sampling is the most important stage since all data will depend on obtaining a representative sample. It is preferred that samples should be analyzed immediately after being taken. Suitable field tests exist which will give accurate results. Because of the risk of precipitation of iron salts leading to erroneous results it is normal practice to determine the total iron content of a sample. Soluble iron test methods are available if required but greater care must be taken to protect the sample from precipitation of soluble iron. Chapter 7: Corrosion Oil Field Chemicals Training Manual 7-73 Property of Nalco Energy Services Confidential & Proprietary – DO NOT DUPLICATE Interpretation of results requires some knowledge of the system. It is useful to know: 1. Has the system been recently worked on? Equipment changes within a few days of sampling may produce high iron counts due to the dislodgment of particulate corrosion products. Upstream acid workovers will lead to a short-term corrosive environment. 2. Does the water composition itself change from sample to sample? This is of importance in gas systems where water can be condensed, with little dissolved solids, or be formation water, which is saline. Samples from the same point can vary as slugs of the different types of water pass through the system. Condensed water will be saturated with any acid gases present. Formation water may have dissolved iron present from the formation. 3. Where in the system is the sample point? Are all the samples that are to be compared taken from the same point? Iron counts from systems containing oxygen or H2S can be misleading since corrosion products may have been precipitated and settled somewhere in the system. Hydrogen sulfide attack may not release any dissolved iron to the fluids. Because of this, use of iron counts should generally be confined to a “sweet corrosion” environment where the fluid temperature is moderate (<180°F). If the fluid temperature is too high, iron counts can decrease as a result of iron carbonate formation. It can be a quick and efficient method for evaluating the effectiveness of a chemical corrosion inhibitor program where a reduction of iron counts from a pretreatment level indicates success. Since iron counts are mostly done by ICP or AA, it would be useful to compare the iron counts with the manganese (Mn) concentration. If the increased iron counts are due to corrosion, one would expect an increase in manganese concentration because most carbon steels are C-Mnsteels. Corrosion Product Deposit Analysis Knowledge of the composition of corrosion product deposits helps to evaluate the type of problem and detect changes in the system. Deposit analysis is usually carried out in a laboratory some time after sampling. Since some corrosion products change significantly on exposure to air, e.g., oxidation of iron sulfides, it is advisable to note the appearance at the time of taking the sample. Chapter 7: Corrosion Oil Field Chemicals Training Manual 7-74 Property of Nalco Energy Services Confidential & Proprietary – DO NOT DUPLICATE Gas Analysis Carbon dioxide, hydrogen sulfide and oxygen are the gases most important for corrosion to occur. In gas systems, knowledge of the presence and level of any of these gases will forewarn the operator of impending corrosion problems. Field tests are available for the determination of these gases. Microbiological Activity The presence and activity of various microorganisms in a system should be known. The corrosion problems related to microbiological activity are the subject of a later section. It is important that this activity is monitored as part of the corrosion monitoring program. Residual Inhibitor Testing If chemical corrosion inhibitors are used it is helpful to know the level present downstream of the injection point. By their intended action, inhibitors film out on metal surfaces. It is important that sufficient inhibitor is present throughout the system to provide adequate protection. Field tests exist for most inhibitors but often naturally occurring components in the fluids will interfere. Tests need to be carried out with the various inhibitors and system fluids to establish the feasibility of determining inhibitor reserves. Nalco has developed a number of proprietary analytical tests for residual analysis. These include: 1) GC/MS method; 2) NEEIT method; 3) UV method; and 4) colorimetric method. 7.10.2.7 Inspection Tools Detailed description of the various tools available for downhole, pipeline or vessel inspection is beyond the scope of this section. The general principles involved include: Caliper Studies A caliper measures the internal diameter of a pipeline or tubing, indicating general corrosion and pitting. Feelers grouped around the tool detect irregularities in the metal surface. It also measures the deformation of the tube (i.e., if the cross section is deformed from circular to elliptical). The readings from the feelers can be transmitted to an instrumental read-out. Scale and corrosion products can mask the pits and some pits may be missed because of the spacing of the feelers. Chapter 7: Corrosion Oil Field Chemicals Training Manual 7-75 Property of Nalco Energy Services Confidential & Proprietary – DO NOT DUPLICATE Plastic lined and coated piping may be damaged by the caliper survey, and protective scale and corrosion inhibitor film may be removed. Many operators apply corrosion inhibitor immediately after caliper studies to minimize damage to surfaces. Despite these disadvantages, caliper surveys can be useful for the measurement of the progress of corrosion, especially in downhole equipment. Magnetic Flux Loss This tool measures wall thickness providing a record of corroded areas, leaks and holes. An AC current is imposed on a coil, generating a magnetic flux. The magnetic flux passes out through the vessel wall and a portion passes back to the receiver portion of the tube. As the flux penetrates the metal it is attenuated and shifted in phase. The thicker the metal wall, the greater the attenuation and phase shift. The tool is precalibrated with walls of known thickness. The tool measures a loss due to both internal and external corrosion. The tool can be run through the system in the presence of fluids and is unaffected by scale or deposits. The limitations are: 1. No differentiation can be made between internal and external loss of metal. 2. Holes below one inch in diameter cannot be readily detected. 3. Variations in wall thickness due to manufacturing tolerances and variations in the metallurgy giving different magnetic permeability make interpretation difficult. It is usual to run an electromagnetic tool on a new system and to use this for future reference to detect changes. 4. It is difficult to detect longitudinal cracks. Chapter 7: Corrosion Oil Field Chemicals Training Manual 7-76 Property of Nalco Energy Services Confidential & Proprietary – DO NOT DUPLICATE Ultrasonic Inspection Ultrasonic techniques utilize ultrasonic energy to measure the thickness of a metal object and to locate defects or flaws in the metal. In ultrasonic inspection, a transducer generates a sound wave. The sound wave is transmitted through a liquid to the metal surface. The ultrasonic wave travels through the metal until it encounters an interface or discontinuity such as the other side of the metal wall. The sound wave is reflected back through the metal to a receiver where it is transformed into an electric impulse. The impulse is projected on to a cathode ray tube screen as a vertical line. The interval between the initial pulse and the reflection is proportional to the distance traveled, usually twice the thickness of the metals or distance to a discontinuity. This technique is also known as the “pulse echo” technique and is very commonly used in the field. Usually the initial measurements are made when the system equipment is installed. Future readings during the lifetime of the system can then be compared to the original. Limitations of the method are: 1. Scale deposits on the surface may reduce accuracy. 2. The detector probe has to be precisely oriented in order to get reproducible results. 3. Interpretation requires a skilled operator. 4. Low sensitivity. 5. It requires access to the pipe wall, which may be difficult for buried or insulated pipes. Radiography Radiography involves the passing of x-rays or gamma rays from a source through the metal onto a photographic film. Radiography is used primarily to inspect wells but can be used to detect pitting or other localized corrosion damage. Visual Inspections This is the most reliable technique of all. It is difficult to carry out in most cases and impossible in others. Every opportunity to visibly inspect system equipment should be utilized. Photographs must be taken and records made. Chapter 7: Corrosion Oil Field Chemicals Training Manual 7-77 Property of Nalco Energy Services Confidential & Proprietary – DO NOT DUPLICATE 7.10.3 Monitoring Guidelines The guidelines contained in the following sections have been determined by assessing the severity of the anticipated corrosion rate, type of service and type of corrosion control technique(s) being used. In general for the more severe anticipated corrosion rates, a higher level of monitoring is recommended. Items constructed of corrosion resistant materials may not require any corrosion monitoring. The overall corrosion monitoring philosophy for items constructed of carbon steel is based on the following techniques: 1. Ultrasonic wall thickness checks and/or visual inspection and/or intelligent pigs. Gives an assessment of integrity. 2. Corrosion coupons. Gives a guide to overall corrosion penetration and corrosion mechanism. 3. Corrosion probes. Gives an on line guide to corrosivity of process environment. 4. Chemical analysis of samples. Monitors operating conditions to provide information on corrosion mechanisms and rates. Guidance is also given on the use of other specialized techniques, which could be used in specificapplications. Guidelines as to the frequency of corrosion monitoring and target corrosion control rates are given in the tables listed below. These tables can be found in section 7.12, Appendix at the end of this chapter. Table 1: Guideline Frequency for Corrosion Monitoring Table 2: Average Target Control Corrosion Rates Table 3: Location and Types of Corrosion for Oil Production Facilities Table 4: Location and Types of Corrosion Monitoring for Gas Production Facilities Table 5: Location and Types of Corrosion Monitoring for Water Injection Facilities Table 6: Location and Types of Corrosion Monitoring for Fuel Gas Facilities Table 7: Corrosion Monitoring Requirements for Pipelines Table 8: Hardware Requirements for Corrosion Monitoring The location of intrusive monitoring tools is important to the success of the monitoring system in obtaining an accurate reading. Chapter 7: Corrosion Oil Field Chemicals Training Manual 7-78 Property of Nalco Energy Services Confidential & Proprietary – DO NOT DUPLICATE 7.10.3.1 Oil Production Facilities Guidance on the location and type of corrosion monitoring is provided in Table 3. The philosophy adopted is that each item of equipment or piping where fundamental operating conditions are significantly different shall be assessed for monitoring. These locations are summarized below: Each well Each flow stream into each separation train Each main gas outlet from each individual vessel in the separation train Water outlet from produced water treatment system (in addition access fittings should be provided in the production water downstream of each separator) Crude oil flow stream at outlet of the train or at inlet to export pipeline Each vessel For non-corrosive service, corrosion monitoring should be limited to ultrasonic wall thickness inspections, visual inspections, and routine process monitoring, or as prescribed by the operator. 7.10.3.2 Gas Production Facilities Guidance on the location and type of corrosion monitoring is given in Table 4. The philosophy adopted is that each item of equipment where operating conditions are significantly different shall be assessed for monitoring. Each wellhead Each flow stream into each separation train Each main water stream at outlet of train Hydrocarbon condensate stream at outlet of train or at inlet of export pipeline Export pipeline inlet (if gas from final separator vessel is dried or compressed or otherwise treated after separation) At separator inlets and outlets within gas compression facilities At separator inlets and outlets within gas drying facilities Each vessel. For non-corrosive service, corrosion monitoring should be limited to ultrasonic wall thickness checks, visual inspections, and routine process monitoring. Chapter 7: Corrosion Oil Field Chemicals Training Manual 7-79 Property of Nalco Energy Services Confidential & Proprietary – DO NOT DUPLICATE Care should be taken when using ER probes in sour crude/gas systems as the high conductivity of the corrosion product (iron sulphide) can result in erroneous readings from the probes and/or completely “short” the probe and indicate extremely high corrosion rates. 7.10.3.3 Water Injection Facilities Guidance on the location and type of monitoring is provided in Table 5. The philosophy adopted is that monitoring (particularly continuous monitoring of oxygen) is required at various locations so that the source of any process upset can be quickly identified. Corrosion monitoring in water injections systems is also heavy dependent on accurate fluid (water) analysis. The operators specification should be reviewed to establish the correct metrics. Monitoring is recommended on the following locations: - At the outlet of the deaerator tower At the outlet of the booster pump (if space permits) At the outlet of the main pump At each wellhead At the outlet of any filters (likely to be on existing installations only, where the filters are in the deaerated water stream). 7.10.3.4 Cooling Water Facilities Cooling water facilities where constructed of materials that are susceptible to corrosion or stress corrosion cracking in normal operational or upset conditions should be monitored. Generally, the location of monitoring is at one convenient position in the cooling water stream. The recommended monitoring techniques are chemical analysis, galvanic probe, pH monitor, corrosion coupon, ultrasonic wall thickness checks and internal visual inspection. 7.10.3.5 Fuel Gas Systems (Wet) Each item of equipment and piping where operating conditions are significantly different shall be assessed for monitoring in the following locations: Scrubber vessel inlet Scrubber vessel outlets For non-corrosive service, monitoring should be limited to ultrasonic wall thickness checks, internal visual inspections, and routine process monitoring. See Table 6: Location and Types of Corrosion Monitoring for Fuel Gas Facilities. Chapter 7: Corrosion Oil Field Chemicals Training Manual 7-80 Property of Nalco Energy Services Confidential & Proprietary – DO NOT DUPLICATE 7.10.3.6 Pipelines Corrosion monitoring requirements for pipelines are given in Table 7, which depend on the specific service conditions. In addition, all pipelines should be designed to accommodate the passage of internal inspection pigs. The frequency of inspection by pigging shall be determined by analysis of the specific operating conditions, design philosophy and availability of suitable inspection tools. It should be, where possible, sufficient to provide time for remedial action to be taken if corrosion rates are found to be higher than predicted. Information obtained from the topsides corrosion monitoring should be extrapolated to assess the conditions in the sub-sea sections of the pipeline and in the event that corrosion is suspected. 7.10.3.7 Other Techniques For Specialized Applications Corrosion monitoring techniques used should not necessarily be limited to those stated in the attachments. If there is a specific requirement then other monitoring techniques may be employed to ascertain the true nature and degree of corrosion. Some examples of other techniques for specialised applications are given below: - Linear Polarization Resistance (LPR) for rapid accurate determination of corrosivity of aqueous systems as a monitor for inhibitor efficiency; Hydrogen patch probes for monitoring hydrogen permeation in H2S rich streams; Thin Layer Activation (TLA) for highly sensitive corrosion rate or erosive wear determination. FSM for pipelines (Field Signature Method) This is a rapidly expanding field within the corrosion industry and due attention should be paid to any new techniques developing in the market. 7.11 Measuring and Reporting Following a thorough monitoring program, it is important to capture and record key performance indicators. It is suggested that these KPIs be mutually agreed upon between the customer and sales before the chemical program is initiated. Some standard KPIs include the following: Cost per water volume treated — actual versus plan Cost per BOE — actual versus plan Chemical consumption — actual versus plan Conformance to monitoring schedule Coupon results and trends Chapter 7: Corrosion Oil Field Chemicals Training Manual 7-81 Property of Nalco Energy Services Confidential & Proprietary – DO NOT DUPLICATE 7.12 Appendix 7.12.1 Attachement 1 ATTACHMENT 1(a) PRODUCING WELLS 1. Customer 2. Location • geographic area • field • unit/platform • well numbers 3. Type of Production • oil• gas • water 4. Production Method 5. Total Number of Wells 6. Production Volumes • BOPD (barrels oil per day) • BWPD (barrels water per day) • MMSCF/d (million standard cubic feet gas per day) 7. Bottomhole Conditions (shut in) • temperature • pressure 8. Wellhead Conditions (producing) • temperature • pressure 9. Tubing • grade • diameter 10. Casing Diameter Chapter 7: Corrosion Oil Field Chemicals Training Manual 7-82 Property of Nalco Energy Services Confidential & Proprietary – DO NOT DUPLICATE ATTACHMENT 1(a) (Continued) 11. Tubing/Casing Annulus • packer installed • permanent completion fluid • downhole injection capability • sliding sleeves installed 12. Downhole Configuration • casing depth • tubing depth • perforation depth(s) • total depth • pump depth • other 13. Water Analysis 14. Corrosive Agents • type • concentration (PPM or Mal. %) 15. History of Problems • corrosion • scale • bacteria • other 16. Specific Problem Locations 17. Chemical Treatment Background • product • price • method • frequency/duration • rate 18. Monitoring Information • methods • locations • results 19. Customer's Treatment Program Objectives Chapter 7: Corrosion Oil Field Chemicals Training Manual 7-83 Property of Nalco Energy Services Confidential & Proprietary – DO NOT DUPLICATE ATTACHMENT 1(a) (Continued) 20. Treatment Limitations • product • procedures • cost • other 21. Action Steps Required - Exxon Chemical 22. Special Product Evaluation Procedures (Customer Tests) 23. Other Pertinent Information 24. System Design Chapter 7: Corrosion Oil Field Chemicals Training Manual 7-84 Property of Nalco Energy Services Confidential & Proprietary – DO NOT DUPLICATE ATTACHMENT 1(b) FLUID TRANSPORT LINES 1. Customer 2. Location • geographic area • field • unit/platform • well numbers 3. Type of Production • oil • gas • water 4. System Type • produced fluid flowlines • crude pipeline • water disposal • gas transmission 5. Total Number of Wells 6. Fluid Volumes • BOPD (barrels oil or hydrocarbon condense per day) • BWPD (barrels water per day) • MMSCF/d (million standard cubic feet gas per day) • lb/MMSCF (pounds of water per million standard cubic feet of gas) 7. Inlet Conditions • temperature • pressure • dew point of gas 8. Outlet Conditions temperature pressure 9. Line Dimensions • internal diameter • length 10. Pipe Construction • wall thickness • seamless • welded • other Chapter 7: Corrosion Oil Field Chemicals Training Manual 7-85 Property of Nalco Energy Services Confidential & Proprietary – DO NOT DUPLICATE ATTACHMENT 1(b) (Continued) 11. Pigging Facilities/Procedures 12. Internal Coating 13. Cathodic Protection Program 14. Water Analysis 15. Corrosive Agents • type • concentration (PPM or Mol. %) 16. History of Problems • corrosion • scale • bacteria • other 17. Specific Problem Locations 18. Chemical Treatment Background • product • price • method frequency/duration • rate 19. Monitoring Information • methods • locations • results 20. Customer's Treatment Program Objectives 21. Treatment Limitations • product • procedures • cost • environmental • other 22. Action Steps Required - Exxon Chemical 23. Special Product Evaluation Procedures (Customer Tests) 24. Other Pertinent Information 25. System Diagram Chapter 7: Corrosion Oil Field Chemicals Training Manual 7-86 Property of Nalco Energy Services Confidential & Proprietary – DO NOT DUPLICATE ATTACHMENT 1(c) SURFACE VESSELS/EQUIPMENT 1. Customer 2. Location • geographic area • field • unit/platform • well numbers 3. Type of Facility • desalter • separator • treater • heat exchanger • knockout drum • cooler • other 4. Unit Design Capacity • BFPD (barrels fluid per day) • MMSCF/d (million standard cubic feet gas per day) 5. Number of Units 6. Fluid Volumes • B0PD (barrels oil or hydrocarbon condensate per day) • BWPD (barrels water per day) • MMSCF/d (trillion standard cubic feet gas per day) 7. Fluid Characteristics • salinity • gravity • solids/wax 8. System Conditions - Inlet • temperature • pressure • water content/RS&W 9. System Conditions - Outlet • temperature • pressure • water content/BS&W Chapter 7: Corrosion Oil Field Chemicals Training Manual 7-87 Property of Nalco Energy Services Confidential & Proprietary – DO NOT DUPLICATE ATTACHMENT 1(c) (Continued) 10. Construction • metallurgy • wall thickness • corrosion allowance • internal coating • other 11. Immediate Upstream Facilities 12. Immediate Downstream Facilities 13. Fluid Residence Time 14. Corrosive Agents • type • Concentration (PPM or Mol. A) 15. History of Problems • corrosion • scale • Bacteria. • plugging • other 16. Specific Problem Locations 17. Chemical Treatment Background • product • price • method • rate/concentration • frequency/duration 18. Monitoring Information • methods • locations • results 19. Customer's Treatment Program Objectives 20. Treatment Limitations • product • procedures • cost • other Chapter 7: Corrosion Oil Field Chemicals Training Manual 7-88 Property of Nalco Energy Services Confidential & Proprietary – DO NOT DUPLICATE ATTACHMENT 1(c) (Continued) 21. Action Steps Required - Exxon Chemical 22. Special Product Evaluation Procedures (Customer Tests) 23. Other Pertinent Information 24. System Diagram/Flour Sheet. Chapter 7: Corrosion Oil Field Chemicals Training Manual 7-89 Property of Nalco Energy Services Confidential & Proprietary – DO NOT DUPLICATE ATTACHMENT 1(d) INJECTION/DISPOSAL SYSTEMS 1. Customer 2. Location • geographic area • field • unit/platform • well numbers 3. Type of Injection • produced water • source water • sea water • hydrocarbons • gas 4. Number of Wells • source • injection 5. Injection Volume • per well - barrels per day • total - barrels per day 6. Water Analysis 7. Production Method 8. Downhole Configuration • casing depth/diameter • tubing depth/diameter perforation depth(s) • total depth • other 9. Line Dimensions • internal diameter • length 10. Pigging facilities/Procedures 11. Internal Coating 12. Corrosive Agents • type • concentration Chapter 7: Corrosion Oil Field Chemicals Training Manual 7-90 Property of Nalco Energy Services Confidential & Proprietary – DO NOT DUPLICATE ATTACHMENT 1(d) (Continued) 13. History of Problems • corrosion • scale • bacteria • other 14. Specific Problem Locations 15. Chemical Treatment Background • product • price • method • frequency/duration • rate 16. Monitoring Information • methods • locations • results 17. Customer's Treatment Program Objectives 18. Treatment Limitations • product • procedures • cost • other 19. Action Steps Required - Exxon Chemical 20. Special Product Evaluation Procedures (Customer Tests) 21. Other Pertinent Information 22. System Diagram Chapter 7: Corrosion Oil Field Chemicals Training Manual 7-91 Property of Nalco Energy Services Confidential & Proprietary – DO NOT DUPLICATE ATTACHMENT 1(e) HYDROSTATIC TESTING/MOTHBALLING 1. Customer2. Location • geographic area • field • unit/platform • well numbers 3. Type of Facility • pipelines • oil/gas treating equipment • storage tanks • other 4. Fill fluid • surface water • source water • hydrocarbon • dry gas 5. Volume/Dimensions of Unit 6. Total Number of Units 7. Water Analysis 8. Microbiological Contamination 9. Duration of Exposure 10. Fluid Disposal Capability • environmental limitations • total volume • dilution • treating • other 11. Subsequent System Use Chapter 7: Corrosion Oil Field Chemicals Training Manual 7-92 Property of Nalco Energy Services Confidential & Proprietary – DO NOT DUPLICATE ATTACHMENT 1(e) (Continued) 12. Monitoring • methods • locations 13. Customer's Treatment Program Objectives 14. Treatment Limitations • product • product interactions • procedures • cost • other 15. Action Steps Required - Exxon Chemical 16. Special Product Evaluation Procedures (Customer Tests) 17. Other Pertinent Information 18. System Diagram Chapter 7: Corrosion Oil Field Chemicals Training Manual 7-93 Property of Nalco Energy Services Confidential & Proprietary – DO NOT DUPLICATE 7.12.2 Tables for Corrosion Monitoring Guidelines Table 1 - Guideline Frequency for Corrosion Monitoring SERVICE TYPE FREQUENCY Dry oil and gas production Corrosion coupons Annual Wet oil and gas production Corrosion coupons Six monthly Water systems Corrosion coupons Six monthly Dry oil and gas Probes Six monthly Wet oil and gas Probes Monthly Wet oil and gas Probes Monthly Water systems Probes Monthly All oil and gas production Chemical samples Analysis for [CO2] [H2O] [C1-] [Fe] [H2O] [sand] [inhibitor] Recording to T, P, pH Monthly Weekly Water injection (and cooling medium if necessary) 02 monitoring Continuous with daily calibration checks All oil and gas production and water injection (if applicable). Ultrasonic wall thickness checks in selected locations. As per the CRA Coated vessels Internal visual inspection As per the CRA All piping and equipment Internal visual inspection As per the CRA NOTE: Operational experience may dictate that longer or shorter frequencies are required at the discretion of the corrosion engineer responsible for the facilities. CRA = Corrosion Risk Assessment. Chapter 7: Corrosion Oil Field Chemicals Training Manual 7-94 Property of Nalco Energy Services Confidential & Proprietary – DO NOT DUPLICATE Table 2 - Average Target Control Corrosion Rates ITEM TARGET CONTROL CORROSION RATE Piping and equipment with no corrosion allowance. To be determined by consideration of wall thickness and operating pressure as per Ref. 1 below. Piping and equipment with 1-1.5 mm corrosion allowance Lesser of 0.1 mm/year or 0.5% wall thickness/year Piping and equipment with 3 mm corrosion allowance 3/(Design Life) mm/year Piping and equipment with 6 mm corrosion allowance. 6/(Design Life) mm/year Piping and equipment default corrosion rate 0.25 mm/year NOTES - The above table gives an indication of the maximum corrosion rates that should be recorded for pipework of given corrosion allowances, before additional control measures are indicated. It is intended that corrosion probes/coupons are selected with reference to the above target rates and the sensitivities required by section 3.3 of this Standard. - For pipework with different corrosion allowances to those listed above the relevant target control corrosion rate shall be obtained by extrapolating the above date. - Further corrosion beyond the corrosion allowance may be acceptable by consideration of wall thickness and operating pressure. Chapter 7: Corrosion Oil Field Chemicals Training Manual 7-95 Property of Nalco Energy Services Confidential & Proprietary – DO NOT DUPLICATE Table 3 - Location and Types of Corrosion for Oil Production Facilities Location TYPE SC CP CC U V Wellhead flowlines R R R R R Inlet to separation train R R R R R Gas outlet from each separator vessel R R R R Crude outlet from train (or inlet to crude export pipeline) R R R R R Water outlet from separation train R R R R R Water outlet from produced water treatment system R R R R R All vessels R ¾ SC = Sample Connection ¾ CP = Electrical Resistance Corrosion Probe ¾ CC = Corrosion Coupon ¾ U = Ultrasonic Wall Thickness Check ¾ V = Internal Visual Inspection ¾ R = Type of Monitoring is required at frequency indicated in the attached table Chapter 7: Corrosion Oil Field Chemicals Training Manual 7-96 Property of Nalco Energy Services Confidential & Proprietary – DO NOT DUPLICATE Table 4 -Location and Types of Corrosion Monitoring for Gas Production Facilities Location TYPE SC CP CC U V Wellhead flowlines R R R Inlet to each separator R R R R Gas outlet from each separator vessel R R R R Produced water at outlet of train R R R R R Hydrocarbon condensate stream at outlet of train R R R R R Export pipeline inlet (if gas is dried, compressed or otherwise treated after separation) R R R R R ALL VESSELS R Gas Drying Facilities Separator inlets R R R R Separator outlets (Gas) R R R R Separator outlets (Liquid) R R R R R Gas Compression Facilities Separator inlets R R R R Separator outlets (Gas) R R R R Separator outlets (Liquids) R R R R R ¾ SC =Sample Connection ¾ CP = Corrosion Probe ¾ CC = Corrosion Coupon ¾ U = Ultrasonic Wall Thickness Check ¾ V = Internal Visual Inspection ¾ R = Type of Monitoring required at frequency indicated in the attached table Chapter 7: Corrosion Oil Field Chemicals Training Manual 7-97 Property of Nalco Energy Services Confidential & Proprietary – DO NOT DUPLICATE Table 5 - Location and Types of Corrosion Monitoring for Water Injection Facilities Location TYPE Q SC GP CC BP U V Outlet of Deaerator R R R R R Outlet of booster pump (if space available) R R R R Outlet of main pump R R R R R R R Each wellhead (Local) R R Each wellhead (Remote) R R R R R R Outlet of filter (if filter is in deaerated water stream) R R R R ¾ Q = Oxygen Cell Analyser ¾ SC = Sample Connection ¾ GP = Galvanic Probe ¾ CC = Corrosion Coupon ¾ BP = Bioprobe ¾ U = Ultrasonic Wall Thickness Check ¾ V = Internal Visual Inspection ¾ R = Type of Monitoring is required at frequency indicated in the attached table
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