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Corrosion problems in production

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Corrosion of metal in the presence of water is a common problem across many industries. The fact that most oil and gas production includes co-produced water makes corrosion a pervasive issue across the industry. Age and presence of corrosive materials such as carbon dioxide (CO2) and hydrogen sulfide (H2S) exacerbate the problem.

Corrosion control in oil and gas production is reviewed in depth in Treseder and Tuttle,[1] Brondel, et al.,[2] and NACE,[3] from which some of the following material is abstracted.

Corrosion chemistry of steels

Iron is inherently (thermodynamically) sufficiently active to react spontaneously with water (corrosion), generating soluble iron ions and hydrogen gas. The utility of iron alloys depends on minimizing the corrosion rate. Corrosion of steel is an “electrochemical process,” involving the transfer of electrons from iron atoms in the metal to hydrogen ions or oxygen in water. The corrosion reaction of iron with acid is described by the equation


This reaction is made up of two individual processes, which are


[the generation of soluble iron and electrons (this is the “anodic” process—the oxidation of the metal)] and


[the consumption of the electrons by acid to generate hydrogen gas (this is a “cathodic” process—the reduction of protons)].

This separation of the overall corrosion process into two reactions is not an electrochemical nuance; these processes generally do take place at separate locations on the same piece of metal. This separation requires the presence of a medium to complete the electrical circuit between anode (site of iron dissolution) and cathode (site for corrodant reduction). Electrons travel in the metal phase, but the ions involved in the corrosion process cannot. Ions require the presence of water; hence, corrosion requires the presence of water. This overall process is shown schematically in Fig. 1.[3] The space between the anode and cathode may be small or large depending on a number of factors.

Acid is not the only corrodant possible. Another common cathodic process is the reduction of oxygen, which is written as


This reaction can also take place at a location different from that of iron dissolution.

The other chemical constituents in the vicinity of the anodic sites determine the ultimate chemical fate of the Fe++ ion, such as the precipitation of iron-containing solids on or near the corroding surface.

The net rate of corrosion is determined by how fast the corrodant arrives at the iron-atom/water interface, how much corrodant is present, the electrical potential (energy) of the corrodant (oxygen has a higher potential than do protons), and the intrinsic rate of the cathodic reactions—electron transfer processes involving protons and oxygen are not instantaneous and depend on the nature of the solid surface on which they occur.

“How fast the corrodants arrive” has two aspects:

  • Mass transport in the corroding fluid
  • Permeating surface barriers between the iron metal and the water phase

Surface barriers are placed barriers, such as:

  • Paint or plastic coatings
  • Passivating oxide films inherent to the metal (discussed later)
  • Low-permeability corrosion products (e.g., siderite, as formed in the presence of certain oils and/or inhibitors)

Nature of steels

Alloying iron with carbon (usually 0.2 to 1%) forms steel (low-alloy steel)—a far stronger metal than iron, hence, suitable for oilfield use. Other components can be added to iron to enhance corrosion-resistance properties.

Some of the carbon added is insoluble, forming iron carbide (Fe3C), which accelerates the cathodic processes necessary for corrosion to take place, accelerating the corrosion rate. One of the major, ubiquitous impurities in steel is sulfur, and it is a major source of corrosion instability. This element is highly insoluble in iron and precipitates in the form of insoluble sulfide inclusions, in particular MnS and (Mn, Fe)S. These inclusions are generally the sites of pitting (discussed later).[4]

Grain boundaries are also areas that are chemically active.[3] When iron solidifies during casting, the atoms, which are randomly distributed in the liquid state, arrange themselves in a crystalline array. This ordering usually begins simultaneously at many points in the liquid, and as these blocks of crystals and grains meet, there is a mismatch in the boundaries. There are areas of higher energy. Chemical impurities in the melt tend to accumulate at these grain boundaries and are more susceptible to chemical attack than the iron surface itself.

Plain carbon steels are processed by one of four heat treatments:

  • Annealing
  • Normalizing
  • Spherodizing
  • Quench and tempering

These treatments determine, in part, the physical and corrosion properties of the metal. Annealing or normalizing results in greater corrosion resistance than spherodizing or quench and tempering. The logic is that these treatments determine, in large, part of the physical dimensions and distribution of the impurities and inclusions in the metal.

The corrosion products formed in oxygen-containing water on mild steel are FeOOH, likely amorphous, and magnetite.[4] Below 200°C, these oxides, in the absence of reactive inclusions, are protective. In the presence of dissolved CO2, FeCO3 films form, which can sometimes be protecting (discussed later).

The compositions of corrosion-resistant alloys (CRAs) are chosen to spontaneously generate surface oxide films that will be stable and impermeable in the presence of the more aggressive corrodants. In oilfield use, it is also required that these films spontaneously reform if ruptured, as, for example, during and after erosion by sand or scratching by wireline/caliper tools. CRAs include the ferrous stainless steels and nonferrous nickel and cobalt alloys. Stainless steels contain at least 12% chromium. These alloys passivate in oxidizing environments through the formation of a thin layer of chromium oxide—containing film on the surface of the alloy. The crystallinity of this film decreases with increasing Cr content in the steel, becoming more glass-like and more protective.[5] Again, various inclusions can be weak points in the passivating film. The surfaces of nickel-based CRAs, such as Incoloy 800™, are a passivating nickel ferrite (Ni0.8Fe2.2O4).

There are four classes of stainless steels that are based on chemical content, metallurgical structure, and mechanical properties. These classes are:

  • Martensitic
  • Ferritic
  • Austenitic
  • Duplex

The manufacturing processes for CRAs are more complex than those producing low-alloy steels. Stainless steels are less costly than the nickel and cobalt alloys, though they are 1.5 to 20 times more expensive than low-alloy steels.

Oilfield corrosion

Oilfield corrosion can be divided into corrosions due to oxygen, "sweet" corrosion, and "sour" corrosion.

Corrosion because of oxygen is found with surface equipment and can be found downhole with the oxygen introduced by waterflooding, pressure maintenance, gas lifting, or completion and/or workover fluids. It is the major corrodant of offshore platforms, at and below the tide line. The chemistry of this process follows the equations previously given.

“Sweet” corrosion is generally characterized first by simple metal dissolution followed by pitting. The corrodant is H+, derived from carbonic acid (H2CO3) and the dissolution of CO2 in the produced brine. The pitting leaves distinctive patterns (e.g., “mesa” corrosion), attributable to the metallurgical processing used in manufacturing the tubing. “Ringworm” corrosion is caused when welding is not followed by full-length normalizing of the tubular after processing. Corrosion inhibitors and CRAs are effective in mitigating sweet corrosion. Naphthenic acids and simple organic acids indigenous to crude oil also contribute to corrosion.

“Sour” corrosion (H2S) results in the formation of various insoluble iron sulfides on the metal surface. Not only is H2S an acidic corrodant, it also acts as a catalyst for both the anodic and cathodic halves of the corrosion reaction. Galvanic corrosion (bimetallic corrosion) is caused by the coupling of a corrosive and noncorrosive metal in the presence of a corrodant. Erosion is yet another category of corrosion. Erosion corrosion is the acceleration of corrosion because of the abrasion of metal surfaces by particulates (e.g., sand). Finally, there is corrosion caused by acids—those used to stimulate wells (HCl and HF).

Oilfield corrosion can take specific forms:

  • Metal wastage
  • Pitting
  • Crevice corrosion
  • Intergranular corrosion
  • Stress corrosion cracking (SCC)
  • Blistering
  • Embrittlement
  • Sulfide stress cracking (SSC)
  • Corrosion fatigue

The first five forms involve primarily carbonic acid and/or dissolved oxygen as corrodants. Items 6 through 8 are induced primarily by H2S.

Corrosive failure by uniform loss of metal is only infrequently seen during the production of oil and gas. It is, however, the first step in corrosive failure of steels by means of localized corrosion. A circumstance for severe metal wastage is the pumping of poorly inhibited matrix stimulation acids.

Pitting is the common failure mode of sweet corrosion and corrosion because of dissolved oxygen. All passivating/protecting films on steel contain weak spots that will preferentially dissolve and form pits. As mentioned, these areas are generally the sulfide inclusions. Chloride ion weakens the repassivating film, allowing continued dissolution. The decreasing pH within the pit also enhances continued corrosion. The driver for theses processes is the large cathodic area of the metal oxide surface vs. the small anodic pit. Pitting is particularly dangerous because penetration through a tubular can occur relatively fast. Other corrosion mechanisms, such as SCC, frequently start at pits. Oxygen scavengers are typically used to remove this gas in an attempt to minimize the pitting problem. However, small amounts may remain (e.g., 20 ppb), and these can be sufficient to induce corrosion.

Carbonic acid, the driver for sweet corrosion, is a weak acid. The pH of the formation water depends on the CO2 partial pressure, temperature, and alkalinity (controlled primarily, but not exclusively, by the presence or absence of carbonate minerals in the formation). Shown in Fig. 2, as a function of CO2 partial pressure, are computed pH values for a seawater brine (containing 140 ppm alkalinity) and a seawater brine saturated in calcite at 50 and 150°C (substantially higher alkalinities). For the common case of carbonate-containing reservoirs and moderate temperatures, produced waters should have pH values of 6 or greater. Waters exposed to greater amounts of CO2 in noncarbonate-containing reservoirs can have pH values of 4 or less.

Such corrosion induced by CO2 is a function not only of CO2 partial pressure and temperature but also of the crude oil. Crude oil contains surface-active chemicals—some oils contain more than others. These chemicals (e.g., resins and asphaltenes) can impact the corrosion process, at least for low-alloy steels. For a fixed brine composition, WOR, temperature, and pressure, corrosion in the presence of some crudes can be negligible, while in the presence of others, it can be extreme under identical environmental conditions.[6][7] Sweet corrosion generally results in the deposition of insoluble FeCO3 (siderite) on the steel surface. It has been suggested that this selectivity to oil composition relates to the physical morphology of the FeCO3 corrosion product—a compact, tight film can protect the steel; a loose, poorly adherent film does not.[7] An example is shown in Fig. 3. The average uniform corrosion rate for steel in Crude B was 0.6 mil/yr; the corrosion rate in Crude E was 26 mil/yr. Many corrosion inhibitors apparently act by the same mechanism (i.e., the generation of siderite films similar, and/or more compact than those formed from Crude B).[7]

Alternatively, it has been suggested that wettability plays the dominant role, whereby the surface-active components in the crude oil provide for a water-wet surface (high corrosion rates) or an oil-wet surface (low corrosion rates).[8] Regardless of the mechanism, crude oil can modify the corrosion rate. The penalty for ignoring the effect of crude-oil chemistry is the cost of overtreating or using more expensive alloys than are required.

A crevice, such as the junction space under a bolt or the physical junction of two metal parts, is in effect a pit. Uniform corrosion can initiate (in the presence of a corrodant) within the crevice and continue, driven by the large cathodic area outside the pit or crevice.

Stress corrosion cracking is intergranular corrosion, but it takes place only when the metal is under stress and in the presence of a corrodant. The corrodant can be specific—not all corrodants induce SCC on all alloys. Metal wastage is generally small; SCC is often preceded by pitting. High-strength steels are more susceptible to SCC than low-strength alloys. The severity of intergranular corrosion generally depends on the metallurgical history of the steel. Austenitic steels (common stainless steels) are particularly susceptible to intergranular attack.

Blistering, as well as embrittlement and sulfide stress cracking, a subclass of SCC, all stem from the same cause: the presence of H2S in the system and at the metal surface. The roots of the problem are in the mechanism for the cathodic discharge of hydrogen. The mechanism already discussed for the cathodic portion of the acid-induced corrosion process itself, involves two steps.




(i.e., the proton is first reduced to a hydrogen atom on the metal surface (H), followed by the combination of two hydrogen atoms to yield hydrogen gas). Hydrogen sulfide inhibits the combination of hydrogen atoms (as does arsenic and some other corrosion inhibitors). Accordingly, the hydrogen atoms can penetrate into the metal where they cause the corrosion problems that were already listed. This is shown schematically in Fig. 4.[2]

This hydrogen entry into low-strength steels can result in hydrogen blisters, if there is a macroscopic defect in the steel such as an inclusion. Such a void can provide a space for the hydrogen atoms to form hydrogen gas. Pressure builds and blisters form resulting in rupture and leakage.

Embrittlement (hydrogen-induced cracking and hydrogen embrittlement cracking) causes failure at stresses well below the yield strength . This phenomenon usually occurs only with high-strength, hard steels, generally those having yield strengths of 90,000 psi or higher. Tubing and line pipe (electric welded and seamless) are susceptible to this effect. The dominating factor is the metallurgical structure of the steel relating to its method of manufacture.

SSC cracking failure requires only low concentrations of H2S. The time to failure decreases as stress increases. Cracking tendency increases as pH decreases. SSC can be thought of in the same language as that used in describing hydraulic fracturing. There is a critical “stress intensity factor” below that at which a fracture (crack) will not propagate. This factor is related linearly to tensile strength. Some of this problem has been attributed to the effects of cold working on the alloys. Alloys that were stress relieved were found to increase in resistance to SSC.[9]

Wells producing hydrocarbon liquids, with the hydrogen sulfide, are less susceptible to SSC, pitting, and weight loss. For example, certain Canadian condensate wells have produced fluids with 40 mol% H2S and 10% CO2 for 30 years without serious corrosion problems. Stability is associated with a protective iron sulfide film, wetted by the oil/liquid hydrocarbon. These wells also had a BHT of 90°C; iron sulfide films are less effective in preventing corrosion above 110°C.

Steels, repeatedly stressed in a cyclical manner, may fail in time (corrosion fatigue). It is required for failure that the stress be above a critical value called the “endurance limit” (nominally 40 to 60% less than the tensile strength). The presence of a corrodant substantially reduces the fatigue life of a metal. Cyclic stress can be looked upon as a method of accelerating failure because of the other mechanisms previously described.

Bimetallic corrosion/galvanic corrosion can occur when two metals are coupled (in electrical contact) and a corrodant is present. The more reactive metal corrodes faster, while the less-reactive metal shows little or no corrosion. The more-reactive metal cathodically protects the less-reactive metal (exploiting cathodic protection to prevent corrosion is discussed later). In general, the total corrosion of the anodic material is proportional to the exposed area of the cathodic material. Thus, steel rivets in monel corrode very rapidly, while monel rivets in steel cause little damage.

Weld-related corrosion is a variant of galvanic corrosion. When a metal is welded, the welding process can generate a microstructure different from that of the parent metal. As a result, the weld may be anodic vs. the parent metal and may corrode more rapidly. This corrosion may take the form of localized metal wastage; if H2S is present, there is SSC cracking of hard zones in the metal or in the heat-affected zone. Similar problems can arise with electric-resistance-welded pipe.

Metal wastage in sweet systems is avoided by using weld consumable with a higher alloy content than that of the base metal; recourse is made to laboratory measurements to achieve the proper weld-metal/base-metal combination. Welding procedure standards are available to avoid hard zone SSC. Chemical inhibition is also effective in protecting welded pipe.

Preventing corrosion

The paths to obviating corrosion problems are conceptually straightforward:

  • Isolate the metal from the corrodant
  • Employ a metal alloy that is inherently resistant to corrosion in the corrosive medium
  • Chemically inhibit the corrosion process
  • Move the electrical potential of the metal into a region where the corrosion rate is infinitesimally small (“cathodic protection”)

An alternative is to live with the corrosion and replace the corroded component after failure.


Isolation is the regime of paints, coatings, and liners. An introduction to the subject is given in NACE,[3] from which some of the following discussion is abstracted; a detailed discussion of these subjects is in NACE.[10] For any coating to be effective, it must be sufficiently thick to completely isolate the item being protected from the environment. Small holes in the coating (“holidays”) result in the rapid formation of pits. Considerable care and quality control is required to guarantee the generation of holidays during service.

Organic coatings, such as asphalt enamel and coal tar enamel, are used to protect equipment concerned with the handling of oil and gas. Baked thin-film coatings, such as thermosetting phenolics and epoxies (applied in multiple coats), can be used to protect tubular goods. External protection of pipelines frequently involves use of adhesive tapes made of polyethylene or similar materials. Fusion bonded epoxy has been used successfully to protect a 150-km seawater-injection line (oxygen was the corrodant, much of which, but not all, was removed by scavenging chemicals).[11]

Inorganic coatings include both sacrificial coatings, which furnish cathodic protection (see below for mechanism) at small breaks in the coating, and nonsacrificial coatings, which protect only the substrates actually coated. Sacrificial coatings include galvanizing or coating with other metals anodic to the substrate and heavy suspensions of anodic metals (e.g., zinc particles, in silicates or organic vehicles). Zinc-silicate coatings (paints) are often used to coat the splash zone of drilling and production platforms. The zinc metal provides for cathodic protection of the steel substrate. Below the water line, the most economical approach to corrosion control is cathodic protection (see below). The pH of the environment is important— highly basic or acidic environments can remove coatings.

Nonsacrificial inorganic coatings include metal platings, such as nickel and nonmetallic coatings such as ceramics. Nickel can be applied by electroplating or electroless plating. Ceramic coatings, when properly applied, are highly effective, but they are also costly and fragile. Other systems, while not truly coatings, perform the same function (e.g., Portland cement and plastic liners). Plastic liners have been used for internal protection of tubing and lined pipe. Some liners are sealed into individual joints of pipe and tubing; some are fused into one continuous close-fitting liner through the entire pipe. Both cement and plastic liners are suitable for water lines.

The proper application of coatings is, in large part, an art form. Accordingly, it is also not possible to overemphasize the need for close inspection of the coating process, good quality control, and testing that the coating has been complete.

Corrosion resistant alloys

From a cost point of view, low-alloy steels are preferred. In certain cases, “minor” alterations in alloy composition can minimize corrosion. For example, L-80 steel with a tempered martensitic structure and a chromium content > 0.5% has been used without problems in 20-ppb oxygen-containing environments, while a similar steel with < 0.1% Cr has shown serious corrosion.[12]

The choice of using CRAs or chemical means to solve the more severe corrosion problem comes down to economics (available capital vs. long-term operating costs). Remoteness of operation becomes an important consideration in determining operating costs, as does downtime and deferred/lost oil because of repeated intervention for inhibitor application. Availability and cost of platform space is a consideration for offshore facilities.

The corrosion-control effectiveness of CRAs depends on the chemical severity of the environment. Crevice corrosion, pitting attack, and SCC are the primary concerns. The corrosion resistance of annealed austenitic stainless steels, such as 304 and 316, is affected by the presence of chlorides and temperature; type 304 is less corrosion resistant than type 316. Both materials are susceptible to SCC when the temperature is above 150°F. Both alloys are also low-strength steels. Alloys 654 SMo and AL6XN can be manufactured to higher strengths and are more resistant to SCC. Austenitic stainless steels are probably the most susceptible of all ferrous alloys to pitting.

Martensitic stainless steels have had the widest range of use of any of the available CRAs. Such steels may be manufactured through heat treatment into tubular products with acceptable yield strengths for downhole tubing. Many millions of feet of tubing type (grade L-80) 13Cr are in corrosive well service; it is considered the material of choice for deep sweet-gas wells with temperatures less than 150°C. About 35% of the L-80 13Cr usage was for oil wells. The passivity of 13Cr is destroyed by high chloride levels, particularly at high temperature, which can lead to pitting and crevice corrosion.

Duplex stainless steels are high-strength alloys achieved by means of cold working. Such steels are more corrosion resistant than martensitic steels but are similar in resistance to SSC. Cold-worked duplex has been used to 0.3 psi H2S. Annealed duplex is more resistant to H2S and SSC than the cold-worked versions. Annealed duplex line pipe has been used in wet CO2 service (99%) without problems. 22Cr duplex steel has been used where pH2S was between 0.5 and 1 psi. Such steels have been used successfully in HT/HP wells (e.g., 350°F and 14,000 psi), producing no H2S. However the copresence of chloride, stress, and dissolved oxygen can induce SSC. Wells not exposed to even small amounts of oxygen have operated successfully.[13]

The material most commonly used for sour service is AISI Type 4130 steel, modified by microalloy additions with a quenched and tempered microstructure (martensite).[14] C-110 steel has been used as casing in North Sea wells (30 to 60 bar CO2 and 30 to 50 millibar H2S).[15] An overview of CRAs and their use in sour service is given in Treseder and Tuttle.[1]

Nickel and cobalt alloys are used in the most severely corrosive conditions (high pressure, high temperature, and high H2S contents). C-276, a nickel-based alloy, can be used to 8,000 psi H2S and 400°F. Nickel alloys have found extensive use in the Mobile Bay fields. They are less expensive than the cobalt alloy MP35N previously used for such extreme conditions. Nickel alloys are also used as weld cladding for wellhead and valve equipment.

Chemical inhibitors

As with scale problems, the appropriate addition of chemicals can often inhibit corrosion problems, including some effects of H2S. The delivery techniques are often the same, but the inhibition mechanisms and types of chemicals are different.

Neutralizing inhibitors reduce the hydrogen ion in the environment. Typically, they are:

  • Amines
  • Ammonia
  • Morpholine

They are effective in weak acid systems but are stoichiometric reactants: one molecule equivalent of inhibitor per molecule of acid. They have found minimal use in the oil field.

Scavenging inhibitors are compounds that also remove the corrodant. Oxygen scavengers are commonly used in the oil field (e.g., in removing oxygen during water injection).

The majority of the corrosion inhibitors employed during production form thin barrier layers between the steel surface and the corroding fluid. The concept is that the organic inhibitor will strongly adsorb on the metal wall to form a barrier, possibly only a few molecules thick, which will prevent access to the corrodant and possibly leave the surface oil-wet (further retarding access of the corrodant). The generic name given to these compounds is “filming amines.” This name is qualitatively correct in that most inhibitors are indeed nitrogen-containing, and the inhibitor does finally reside on the surface. The specific mechanism can be more complicated. For example, the inhibitor can interact with the corrosion product to increase its adherence and to lower its permeability. Such layers are likely to be far thicker than a few molecules.[7]

Regardless of the specific mechanisms involved, the inhibitor must contact the metal substrate. The general procedures are:

  • Tubing displacement
  • Displacement from the annulus
  • Continuous injection
  • Squeeze into the reservoir as liquid or gas
  • Weighed liquids/capsules/sticks
  • Vapor-phase inhibitors

The first two batch treatments are operated by pushing the inhibitor-containing fluid across the face of the production tubulars top-down (Item 1) or bottom-up (Item 2). The inhibitor film then persists on the metal surface for some period of time ranging from days to months, depending on the specific environment and materials.

Continuous injection is done, if the well completion allows for a “macaroni string” reaching to the perforations. This technique often includes a simple-to-complicated valving system; it should be remembered that valves can plug. Injection through the annulus has also been used.

Inhibitor squeezing into the formation is an alternative. Here, the mechanism is different than that of scale inhibitor squeezes. The large amount of inhibitor that returns initially is not wasted, but is intended to coat the tubular and production equipment with an adsorbed, persistent film of inhibitor. The small amounts of inhibitor that subsequently desorb from the formation are intended to repair holes that are generated in the initial film.

Weighed liquids/capsules/sticks are all variations on the theme of placing inhibitor in the rathole where it is slowly released into the wellbore fluid, continuously depositing and/or repairing the protective film.

Vapor-phase corrosion inhibitors are organic compounds that have a high vapor pressure, generating volatile corrosion inhibitors (such as some amines) that allow this inhibitor material to migrate to distant, and often otherwise inaccessible, metal surfaces within the container. Such inhibitors have been used on the Trans-Alaska pipeline to protect low-flow areas, dead legs, and the annular space in road casings and contingency equipment. The concept has also been applied to storage tank protection.[16]

Filming-amine inhibitors are intended to protect steels from the action of “natural” corrodants in the produced hydrocarbon and water phases. They are generally not effective in protecting the steels from the acids used to stimulate wells or from the partially spent acids returning from such treatments. These tasks are accomplished by the inclusion of large dosages of different inhibiting chemicals with the stimulation acids. Such inhibitor systems are also available to handle low-alloy steels and CRAs in HT/HP conditions.[17] Concern for stability of CRAs during matrix stimulation of deep hot wells has resulted in the use of organic acids such as acetic acid and formic acid rather than HCl. Inhibitor systems have been developed for these chemicals as well.

Cathodic protection

This technology is used to protect pipelines, offshore platforms, and surface equipment. Corrosion is an electrochemical process:

  • Iron atoms give up electrons
  • Electrons flow through the metal to the corrodant
  • Ion movement in the water film contacting both corrodant and iron metal completes the electrical circuit

In certain important cases, it is possible to reverse this current flow out of the steel surface by the application of an external power supply (i.e., make the surface to be protected cathodic rather than anodic). The technology involved in employing cathodic protection must take into account:

  • Quantity of current required
  • Composition and configuration of the impressed current anode
  • Resistivity of the corroding medium
  • Size of the item being protected
  • Accessibility of the surface being protected
  • Length of the item being protected


  1. 1.0 1.1 Treseder, R. and Tuttle, R. 1998. Corrosion Control in Oil and Gas Production. Item No. 37741, NACE, Houston.
  2. 2.0 2.1 Brondel, D. et al. 1994. Corrosion in the Oil Industry. Oilfield Review (April): 4.
  3. 3.0 3.1 3.2 3.3 Corrosion Control in Petroleum Production. 1979. NACE, Houston, TPC No. 5, Chap. 7.
  4. 4.0 4.1 Szklarska-Smialowska, Z.: Pitting Corrosion of Metals. 1986. NACE, Houston, 69–96.
  5. Krueger, J. 1982. Passivity and Breakdown of Passivity. Electrochemistry in Industry, Ch. 5, 317-330, ed. U. Landau, E. Yeager, and D. Kortas. New York City: Plenum Press.
  6. Efird, K.D. and Jasinski, R. 1989. Effect of Crude Oil on Corrosion of Steel in Crude Oil/Brine Production. Corrosion 45 (2): 165.
  7. 7.0 7.1 7.2 7.3 Jasinski, R. 1986. Corrosion of Low Alloy Steel in Crude Oil/Brine/CO 2 Mixtures. Proc., The Electrochemical Society: Surfaces, Inhibition and Passivation, Princeton, 86, No. 7, 139–148.
  8. Smart, J.S. 2001. Wettability—A Major Factor in Oil and Gas Corrosion. Materials Performance 40 (4): 54.
  9. Treseder, R. and Badrak, R. 1997. Effect of Cold Working on SSC Resistance of Carbon and Low Alloy Steels—A Review. Paper 21 presented at NACE Corrosion 97, Houston (March).
  10. Coatings and Linings for Immersion Service. 1998. NACE International, Houston, TPC No. 2.
  11. Chen, E.Y. and Ahmed, T. 1998. Why Internally Coated Piping Is Used for the World's Largest Seawater Injection System. Presented at the SPE Annual Technical Conference and Exhibition, New Orleans, Louisiana, 27-30 September 1998. SPE-49211-MS.
  12. Nice, P. and Ueda, M. 1998. The Effect of Microstructure and Chromium Alloying Content to the Corrosion Resistance of Low-Alloy Steel Well Tubing in Sea Water Injection Service. Paper 3 presented at NACE Corrosion 98, Houston (March).
  13. Mowat, D.E., Edgerton, M.C., and Wade, E.H.R. 2001. Erskine Field HPHT Workover and Tubing Corrosion Failure Investigation. Presented at the SPE/IADC Drilling Conference, Amsterdam, 27 February–1 March. SPE-67779-MS.
  14. Echaniz, C., Morales, C., and Pereze, T. 1998. The Effect of Microstructure on the KISSC Low Alloy Carbon Steels. Paper 120 presented at NACE Corrosion 98, Houston (March).
  15. Linne, C. 1998. Heavy Wall Casing in C-110 Grade for Sour Service. Paper 117 presented at NACE Corrosion 98, Houston (March).
  16. Gandhi, R. 2001. Storage Tank Bottom Protection Using Volatile Corrosion Inhibitors. Materials Performance—Supplement (January) 28.
  17. Frenier, W., Hill, D., and Jasinski, R. 1994. Corrosion Inhibitors for Acid Jobs. Oilfield Review 1 (2): 15.

Noteworthy papers in OnePetro

Kriel, B.G., Lacey, C.A., and Lane, R.H. 1994. The Performance of Scale Inhibitors in the Inhibition of Iron Carbonate Scale. Presented at the SPE Formation Damage Control Symposium, Lafayette, Louisiana, 7-10 February 1994. SPE-27390-MS.

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