Nov 11
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Corrosion in Petroleum Industry
The Petroleum industry contains a wide variety of corrosive environment s. Some of these, many are unique to this industry. Thus it is convenient to group all these environments together. Corrosion problems occur in the petroleum industry in at least three general areas: (1) production, (2) transportation and storage, and (3) refinery operations.
Production. Oil and gas fields consume a tremendous amount of iron and steel pipe, tubing, pumps, valves, and sucker rods. Leaks cause loss of oil and gas and also permit infiltration of water and silt, thus increasing corrosion damage. Saline water and sulfides are often present in oil and gas wells. Corrosion in wells occurs inside and outside the casing. Surface equipment is subject to atmospheric corrosion. In secondary recovery operations, water is pumped into the well to force up the oil.
Condensate wells Condensate wells handle fluids (gas containing dissolved hydrocarbons) at pressures up to 10,000 lb/in2. Depths run up to 15,000 ft. Carbon dioxide is the chief corrosive agent, with organic acids contributing to the attack. Approximately 90% of the corrosive condensate wells encounter conditions as follows: (1) depth greater than 5000 ft, (2) bottom hole temperature above 160 F and pressure above 1500 lb/in2, (3) a carbon dioxide partial pressure above 15 lb/in2, an (4) a wellhead pH of less than 5.4.
Corrosion characteristics of a well are determined by (1) inspection of surface equipment, (2) analysis for carbon dioxide, organic acid, and iron, (3) coupon exposure tests, and (4) tubing-caliper surveys. Determination of iron content and tubing-caliper surveys are used to measure the effectiveness of inhibitor treatment.
Earlier practices involved addition of neutralizers such as ammonia, sodium carbonate, sodium hydroxide, and sodium silicate, but these were replaced in many cases by organic inhibitors, available in oil-soluble, water-dispersible, or water-soluble forms.
In some applications, alloy steels have replaced the medium-carbon manganese steels (J-55 and N-80) previously used. Straight chromium and nickel on corrosion of steel by condensate-well fluid. Straight chromium stainless steels, Stellite, Monel, and copper-base alloys are commonly used for valves and other wellhead parts. Galvanic corrosion is apparently not a factor because substantial amounts of high-conductivity water are not present.
Sweet oil wells It appears that corrosion in high-pressure flowing wells that produce pipeline oil has become almost commonplace in many areas. Three methods are used to combat this corrosion – coated tubing, inhibitors, and alloys. Coated tubing has found most favor, and until recently, backed-on phenolics have been used for almost all coating installations. Air-dried and baked epoxy resins are now being used in increasing amounts.
Sour oil wells these wells handle oil with higher sulfur contents than sweet wells and represent a more corrosive environment. In high H2S wells there may be severe attack on the casing in the upper part of the well where the space is filled with gas. Water vapor condenses in this area and picks up H2S and CO2.
Corrosion is reduced by inhibitors which are injected continuously or periodically depending on the well corrosivity.
Offshore drilling Offshore drilling presents many interesting corrosion problems. Platforms are built over the water and supported by beam piles driven into the ocean floor. Each beam is surrounded by a pipe casing or protection. Similar platforms are used far out at sea for radar towers.
A variety of corrosion prevention methods are used in such structures. These include : (1) Adding inhibitors to the stagnant seawater between beams and casings, (2)Cathodic protection, with sacrificial anodes or impressed currents, of underwater structures, (3)Paints and other organic coatings to protect exposed structures above the splash zone, (4) Monel sheathing at the casing splash zone. This portion of offshore structures is the most susceptible to rapid corrosion.
Transportation and storage Petroleum products are transported by tankers, pipelines, railway tank cars,and tank trucks. The outside submerged surfaces surfaces of tanks an the outside surface of underground pipeline s are protected with coatings and by using cathodic protection. Cathodic protection is also applied to the inside of tankers to prevent corrosion by seawater used for washing or ballast. Gasoline-carrying tankers present a more severe internal corrosion problem than oil tanks because the gasoline keeps the metal too clean. Oil leaves a film that affords some protection. Tank cars and tank trucks are coated on the outside for atmospheric corrosion.
Internal corrosion of storage tanks is due chiefly to water, which settles and remains on the bottom. Coatings and cathodic protection are used. Alkaline sodium chromate (or sodium nitrate) has been found to be an effective inhibitor for corrosion of domestic fuel oil tanks.
Internal corrosion of product pipelines can be controlled with coatings and inhibitors (a few parts per million) such as amines and nitrites. Ingenious methods for coating pipelines in place underground have also been developed.
Refinery operations Most of the corrosion difficulties in refineries are due to inorganics such as water, H2S, CO2, sulfuric acid, and sodium chloride, and not to the organics themselves. For this reason, the petroleum industry has much in common with the chemical industry.
Corrosive agents may be classified into two general categories: (1) those present in feedstock or crude oil, and (2) those associated with processes or control.
Water is usually present in crude oils, and complete removal is difficult. Water acts as an electrolyte and causes corrosion. It also tends to hydrolyze other materials, particularly chlorides, and thus forms an acidic environment.
Carbon dioxide has, in recent years, come to be recognized as one of the most important corrosive agents, especially in operations where gas is the feedstock, or raw material. Many gas wells produce large quantities of carbon dioxide.
Salt water is produced in most oil wells, and relatively large quantities of it get into the refinery, either in the water emulsified in the crude or in the crystalline form dispersed in the crude. The salts are calcium chloride, magnesium chloride, and sodium chloride. Desalting methods include washing and settling, addition of chemicals such as sulfonates to break the emulsion, centrifuging, and filtering. Salts and water are usually removed as quickly as possible, but the operations are frequently incomplete. If they are not removed, or only partially removed, hydrochloric acid oten forms. Magnesium chloride is readily hydrolyzed. In this case, ammonia may be needed in amounts equivalent to three times the stoichiometric equivalent of sulfide and chloride ions.
Hydrogen sulfides, mercaptans, and other sulfide compounds are present in many of the crudes and gases processed by refineries. These are removed by reaction with sodium hydroxide, lime, iron oxide, or sodium carbonate, but for various reasons they are frequently not removed until the final operation is approached. Corrosion problems are associated with the refining process itself or with processes utilized to remove sulfur compounds.
Nitrogen is becoming an important consideration in some of the newer processes. Nitrogen is present in some crudes, but a more important source is the nitrogen in air. Large quantities of air are used in some of the burning operations associated with catalytic cracking processes. Ammonia and cyanides will form under certain conditions when nitrogen is present. The former can damage heat exchangers made of copper-bearing alloys. Cyanides are an important factor controlling the diffusion of hydrogen into steel.
Oxygen (or air) is drawn into tanks and other equipment as they are emptied, or enters during shutdown periods. It could also be drawn into the system by pumps. Oxygen can also be present as result of reactions of other compounds, such as water and carbon dioxide. The water used in the system often contains oxygen in solution.
Sulfuric acid is used in large quantities in many refinery operations such as alkylation and polymerization. The acid becomes contaminated and its corrosion characteristics may change. Utilization of this acid and its recovery or concentration presents corrosion problems that are extremely important to the refinery. For example, sludges often contain large quantities of carbon or carbonaceous material which make the acid strongly reducing in nature. These may attack stainless steels, and under the same conditions the copper-base alloys will give better performance.
Ammonia is used to control the pH of water and to reduce chloride acidity in the process streams. This procedure works well if the pH is 7, but is damaging to copper-bearing alloys if the pH is 8 or above. Ammonia is added to vapors in the process and also to condensers to neutralize acid condensate. It is desirable to add ammonia just before the aqueous phase forms.
Hydrochloric acid forms because of hydrolysis as described earlier. Sometimes it is an intentional addition to the process stream. This is fairly volatile acid so it is often present in distillation columns and also in the condensed petroleum fractions (hydrofluoric acid is used in one alkylation process).
Caustic (sodium hydroxide) and lime are sometimes added for hydrogen sulfide removal and for neutralization. Lime and caustic additions to the crude reduces the amount of HCl present in the overhead vapors. These chemical are dispersed in oil before adding to the stream for better mixing. Less than the theoretical additions are made to avoid an excess of alkali. Caustic sometimes causes deposits (and clogging) that are difficult to remove. It also causes stress corrosion.
Naphthenic acid, when present in oils, can be quite corrosive at 430 to 750 F, and type 316 stainless is sometimes required as a constructional material. Substantial amounts of this acid are present in some oils. For less severe conditions 5% Cr steel is satisfactory. Monel is used when temperatures are below 500 F.
Polythionic acid causes rapid intergranular SCC of sensitized austenitic stainless steels in some refinery operations. Type 304 is susceptible. This attack is minimized if properly heat-treated (not sensitized) 304 or the low-carbon or stabilized types are used.
Refinery corrosion is sometimes separated into two classifications: (1) low-temperature corrosion and (2) high-temperature corrosion. The dividing point is usually 500 F. Presumably, water can exist below 500 F, and the mechanism of aqueous corrosion apply. The high-temperature mechanism take over above 500 F. Perhaps another reason for the division at 500 F is that ordinary carbon steel is economical for handling most crudes and naphthas up to this temperature, but alloy steels and other materials must be used at higher temperature. This is a general classification and should not be regarded as a strict division.
Such a classiication is not entirely satisfactory, even if it applies directly for actual operating conditions at temperature. For example, high-temperature equipment is generally affected by water and other condensates that form when the equipment is shut down, when it is purged with steam or water, or when it is started up again. Many fail to recognize the effect of the conditions that exist when the equipment is not in operation – not only in refineries but in many other process industries as well.
Alloy used in refinery operations Ordinary carbon steel is by far the most important alloy, since it accounts for over 98% of the construction materials used in the industry. As a general rule, every attempt should be made to use steel. This can be done by modifying the process in some manner such as lowering the temperature or adding inhibitors. Steel is the least expensive engineering metal aside from cast iron. In some cases, alloy steels are more economical because they have a longer service life, and they should be judiciously selected, where applicable.
Carbon steel is often unsuitable for heat-exchanger tubes because of corrosion by the cooling water. Brass, arsenical Admiralty Metal, red brass, and cupronickels are widely used. Austenic stainless steels are expensive and may crack in chloride-containing waters. These steels, however, are used for tubing in stills and gas-cracking tubes. In some cases, a single tower is lined with two or three different materials to take care of the changing corrosiveness from the top to the bottom of the tower.
Corrosion by sour crudes increases with temperature (increases rapidly around 800 F) and with increasing sulfur content. Chromium is the most beneficial alloying element in steel for resistance to sulfur compounds. Accordingly, the chromium content of steel is increased with increasing sulfur and temperature starting as low as 1% Cr. Experience indicates that 2.25% Cr, 1% Mo stel is generally adequate for less than 0.2% H2S in the gas stream. High sulfide contents require 5% Cr or higher. The Cr-Mo steel mentioned above and 4 to 6% Cr, 0.5% Mo steel are widely used in refineries.
In addition to the “naturally occurring” carbon dioxide, some severe problems have been encountered because of CO2 injection or flooding to enhance recovery of oil. Two basic component s of the mechanism are consistent with actual experiment: (1) The main cathodic reaction is the reduction of undissociated carbonic acid or hydrogen ion, and (2) the expected high corrosion rates from the latter reaction are not achieved many systems because of the inhibiting effect of ferrous carbonate scale. The severe corrosion in amine-gas-treating systems occurs because the cathodic reaction involves carbonic acid, which comes from thermal decomposition of bicarbonate ion on heating surfaces.
Suggested use of high-chromium steels and also high alloys such as Incoloy 825 where severe corrosion of carbon steel is observed. Recommended also coatings and inhibitors. A criterion for evaluating and predicting th sour resistance of high alloys through multiple regression analysis of laboratory data with the aid of computer. Sour resistance (SR) value consists of major alloy components and their coefficients, which are a function of given environmental parameters. Useful relationships with corrosion behavior in brine solutions containing H2S and CO2 up to 250 C are shown.
Source: http://corrosion-malaysiapetroleum.blogspot.com/2008/06/corrosion-in-petroleum-industry.html