Chapter 4
The problems encountered and protective measures discussed in this section are based on state-of-the-art as practiced daily by corrosion and petroleum engineers and production personnel. These are not all of the methods employed for corrosion protection by any means, but they represent the most commonly used processes.
Drilling Fluid Corrosion
Due to the nature of drilling conditions, corrosion is a problem in water-based drilling fluids. Important considerations are the causes of corrosion and the rate and forms of corrosion attack.
As discussed in the section “Causes of Corrosion” of this article, drilling fluids contain the corrosive elements of oxygen, carbon dioxide, hydrogen sulfide, ionic concentration, and l0w pH. Physical conditions causing corrosion include metal composition, metal properties, string design, stress, and temperature. Combined physicochemical corrosion accelerators include stress corrosion and erosion-corrosion. Microorganisms also introduce biological causes of corrosion in drilling environments. Table 4 lists the major causes and remedies of corrosion in drilling fluids.
Oxygen Corrosion Control
Oxygen causes crevice corrosion under deposits and is considered to be the most serious corrosion accelerator in drilling environments. Oxygen enters the drilling fluid system externally from the atmosphere, usually by way of solids control and mud mixing equipment (Ref 67). The operation of this equipment to reduce air entrapment into the circulating system is an effective technique for limiting oxygen levels. Foaming problems are characteristic of some mud systems and can result in high oxygen levels on the high-pressure side of the pump. Deforming the fluid or maintaining properties to release gas quickly is required to overcome this problem.
Oxygen scavengers, such as sodium sulfite or ammonium bisulfite, are used to remove oxygen from drilling fluid (see the discussion “Environmental Control” in this article). Treatment methods involve a continuous addition of chemical at the rate of 10 mg/L sulfite ion for each 1 mg/L of oxygen present in the fluid. A residual sulfite concentration of approximately 100 mg/L is maintained in the drilling fluid as a functional means of controlling oxygen in drilling systems. Oxygen scavenger catalysts are frequently required to overcome interfering side reactions that prevent the oxygen-sulfite reaction. Calcium in the fluid can combine with sodium sulfite and form calcium sulfite precipitate, thus preventing the sulfite ion from scavenging oxygen. Aldehydes and chlorine dioxide used as biocides in drilling fluids react with sulfite ions and may prevent oxygen removal. The addition of cobalt or nickel catalysts overcomes many of these problems by increasing oxygen-sulfite reaction rates.
Passivating compounds, such as sodium chromate or nitrite, are used to protect equipment during air, mist, or foam drilling operations. Treatment levels range from approximately 500 to 2000 mg/L of chromate or nitrite ion in fresh to slightly brackish fluid. Higher concentrations are required in high-brine solutions, and sodium nitrite is not recommended above approximately 25 000 mg/I. of chloride ton concentration. A noteworthy disadvantage Qf using passivating agents is the tendency toward accelerated pitting attack if treatment levels arc too low or if deposits exist under which the metal cannot be passivated. Zinc compounds are often combined with passivating agents to reduce pitting tendencies. Treatments for controlling deposits are recommended to mitigate under-deposit attack and are covered in the discussion “Scale and Deposit Control” in this section. Chromate or nitrite compounds are not compatible with sulfite-type oxygen scavengers.
Care should be exercised in the use and disposal of chromate compounds. These materials are classified as carcinogens, and personnel safety should be ensured. Injection of drilling fluid within deep formations has been used to dispose of excess or waste fluid.
A clear advantage is gained in the use of sodium chromate or nitrite chemicals when hydrogen sulfide is encountered in the well. These compounds oxidize and remove H2S (see the discussion “Hydrogen Sulfide Corrosion Control” in this section).
Atmospheric corrosion occurs on drilling equipment in urban, polluted, tropical, and marine environments. Protective coatings are commonly applied at the steel mill or storage yard and periodically between drilling operations. Many coating compositions are commercially available for both short- and long-term storage (2 or 3 years). The filming inhibitors that are typically used during drilling often provide good atmospheric protection for short periods between jobs. For long-term exposure, careful surface cleaning and selected atmospheric coating are recommended.
Hydrogen Sulfide Corrosion Control
Hydrogen sulfide causes two forms of corrosion surface attack-under-deposit (crevice) corrosion and sulfide stress cracking. Corrosion control methods include selecting resistant materials, removing the H25 from the fluid, and reducing stress. Hydrogen sulfide enters the drilling fluid primarily from the formation, but it can also come from thermally degraded mud products, sulfate-reducing bacteria, and makeup water.
Alkaline pH control and sulfide scavengers are used to neutralize, precipitate, and/or oxidize H2S. Film-forming amine-type inhibitors are recommended for coating the drill string. Caustic soda or calcium hydroxide treatments are used to neutralize the acid gas. Alkaline pH above 9.5 results in the production of sodium bisulfide or sodium sulfide products that are almost totally water soluble. This treatment provides both personnel safety and corrosion protection.
Compounds of iron oxide (Fe3O4), zinc carbonate, zinc oxide, and zinc chelates are used to precipitate sulfide ions from solution. Pretreatments of approximately 1 kg/barrel (2 lb/barrel) of one of the scavengers are commonly recommended as a precaution against a small influx of H2S entering the mud system and causing damage. Tests are used to monitor scavenger concentrations and treatment requirements. Sodium chromate, zinc chromate, or sodium nitrite compounds are used to oxidize H2S to sulfate or elemental sulfur. The oxidizing process is a fast and efficient method of removing H2S from the system. There is no compatibility problem with the sulfide scavengers listed above. Formaldehyde and chlorine dioxide are compounds that are frequently used as drilling fluid biocides. These products react with hydrogen sulfide, offsetting its corrosive action; however, their biocidal properties are diminished or eliminated in the process.
Filming amine inhibitors provide protection from hydrogen sulfide surface attack and hydrogen embrittlement. Oil-soluble filming inhibitors applied directly on the drill pipe are recommended to offset corrosion fatigue and hydrogen embrittlement. Care should be taken with cationic filming inhibitors, which can damage mud properties by flocculating the anionic clays in drilling systems. Oil muds provide the most effective protection against all corrosion causes, including H2S. The oil phase provides a nonconductive film covering exposed equipment and thus preventing the corrosion process.
Stress reduction by mechanical changes, such as rotary speed and less weight on the bit, is effective in reducing sulfide-induced embrittlement failures. Torque-reducing agents, particularly in high-angle drilling, are effective in lowering stress.
Material selection for drill pipe and casing can have a significant effect in controlling sulfide-stress cracking. The brittle failures related to H2S are linked to the hardness and yield strength of the steel. Steels with hardness levels below 22 HRC or with maximum yield strengths of 620 MPa (90 ksi) have few sulfide stress cracking problems. Cold work, such as tong or slip marks, increases the hardness of steel, and sulfide-stress cracking then becomes a problem. The service stresses in drilling frequently demand materials of great strength, requiring hardness and strength levels that are susceptible to sulfide-stress cracking. Because of such requirements, the primary means of avoiding sulfide stress cracking is by control of the drilling fluid. A full discussion of the metals used in sulfide environments is provided in NACE MR-0l-75 (Ref 5).
Higher temperatures (above 80 “C, or 175 “F) reduce sulfide-stress cracking failures on high-strength steel. This factor can become advantageous in drilling and production operations if properly controlled.
For example, an influx of H2S while drilling may not cause damage if the fluid temperature is above 80 “C (175oF) in the hole. If H2S is detected, scavenging should always be completed before operations are begun that would lower the metal temperature, such as pulling the drill pipe from the hole.
Carbon Dioxide Corrosion Control
Carbon dioxide causes pitting primarily by under-deposit corrosion cell action. Corrosion control methods involve controlling the pH in the higher alkaline ranges. An effective technique is to treat the mud with calcium hydroxide to neutralize this acid-forming gas and to precipitate carbonates, thus lowering CO2 levels. Film forming inhibitors of the oil-soluble amine type applied by spraying the outside of the drill pipe and batch treatments for inside diameter filming are recommended to penetrate pits and deposits, stopping their corrosion action. Control of CO2 is quite similar to H2S corrosion control, and these two gases often enter the mud from the formation together.
Scale and Deposit Control
Mineral scale, corrosion by-products, and mud that form deposits on exposed metal are a major factor in setting up conditions that result in under-deposit pitting attack. The prevention and removal of these deposits with scale inhibitors is quite effective in offsetting this most serious drilling fluid corrosion problem. Inhibitors such as organic phosphonate, phosphate esters, and others of the acrylic, acrylamide, or maleic acid base structures have been effective. Products that exhibit threshold effect, temperature stability, and strong surface-active characteristics are useful. Treatments are variable because of environmental conditions, which differ greatly in drilling fluid compositions. As general rules apply, treatments of 15 to 75 mg/L are used on a daily basis for most mineral scale control. Treatments above this level are used to control deposits of metal corrosion by-products. Considerably higher treatment levels, up to 1000 mg/L, are used to provide corrosion protection. Care should be exercised in using the higher treatment levels, because these compounds may alter mud properties because of their dispersing characteristics.
Primary Production
There are two main types of producing oil wells: artificial lift wells and flowing wells. Artificial lift wells can be further divided according to the method used to pump the hydrocarbon to the surface. These include rod-pumped wells, wells that use downhole hydraulic pumps, and gas-lift wells. Approximately 90% of the artificial lift wells in the United States
Artificial Lift Wells
Rod-Pumped Wells. In a rod-pumped well, the potential for corrosion damage is aggravated by the sucker rods alternately being stretched and compressed and by the abrasion of the rod couplings on the inside of the tubing. It is common for a well to have continuing sucker rod failures. Pulling and replacing the rods is a quick fix, but the problem will continue to exist until the root cause of the failure is identified and corrected. Identifying the problem is the most important step, because corrective action cannot be taken if the cause is not clear. Rod breaks should be inspected immediately after the rod string is pulled to determine if corrosion is occurring and to determine the steps that can be taken immediately to prevent a recurrence.
Corrosion in rod-pumped wells can be caused by several mechanisms, as discussed below. Galvanic corrosion is caused by dissimilar metals in contact or by the difference in metallurgy between two areas on a sucker rod. Most galvanic corrosion on rods is caused by differences in metal condition caused by hammer, wrench, or tong marks and the grooves left by rod-straightening machines. The impact area will be cathodic to the body of the rod, and corrosion will occur adjacent to the mark. Sucker rods have a soft decarburized layer or skin of low-carbon steel 0.13 to 0.2mm (5 to 8 mils) thick. This layer can be broken by careless handling.
Bent rods are sometimes straightened and used again. This is poor practice, because a bent rod is permanently damaged and should be discarded. The rod-straightening machine will put spiral grooves around the rod, and corrosion will occur directly adjacent to the groove.
Any of these conditions will lead to pitting, and stress raisers will be set up. The cyclic stresses resulting from alternately stretching and compressing the rods during pumping operations will lead to rapid failure.
Stray current from surface equipment or leakage from a cathodic protection system will cause severe corrosion where the current leaves the rod string. It is usually seen on couplings or the part of the rod that is close to the coupling.
Damage from oxygen corrosion may take place when the rods are stored outdoors or when oxygen enters the well bore through the annulus. Rusting of stored rods will often cause pitting, and rust deposits can set up concentration cells or under-deposit corrosion when the rods are run in the hole. Oxygen entry into the well bore in wells that pump off or oxygen introduced during inhibitor treating operations will aggravate other forms of corrosion by depolarizing the cathodes on the metal surface during the corrosion reaction. Oxygen corrosion generally occurs in the lower part of the well: the casing, pump, tubing, and the lower part of the rod string. The effect lessens in the upper part of the well, because the oxygen is depleted by the corrosion reaction.
Carbon dioxide or sweet corrosion is caused by CO2 from produced gases dissolving in water and forming carbonic acid. The carbonic acid ionizes to bicarbonate ions and hydrogen ions. A low pH results, and the bicarbonate and the carbonic acid will react directly with the steel rod and cause metal loss and pitting.
The pits formed are usually round bottomed with sharp sides, and they may be connected in a line or will sometimes form a ring around the rod. Fatigue cracks will be initiated at the bottom of the pits.
Carbon dioxide corrosion is aggravated by the presence of oxygen and organic acids. Oxygen depolarizes the cathodes, and organic acids deplete the bicarbonate ion concentration, which dissolves protective carbonate scale. The formation of iron carbonate scale is the major limiting factor in CO2 corrosion.
Many pumping wells are in the temperature range (<100 oC, cr212 oF) that is most conducive to CO2 pitting. At these temperatures, the iron carbonate scale is formed mainly away from the surface, with some forming as a noncontinuous layer. Accelerated metal loss occurs in the gaps in the scale layer, and pits are formed.
Carbon dioxide corrosion may be sudden and catastrophic when breakthrough takes place in CO2 floods. Wells that have been noncorrosive have failed within weeks after breakthrough.
Hydrogen sulfide ionizes in water to form HS- and hydrogen ions. It is characterized by metal loss and pitting and can be quite severe. The iron sulfide formed generally does not form a protective layer and is usually cathodic to the metal surface. Even if a protective sulfide layer is formed, a break in this layer will result in pitting.
The presence of oxygen will increase the corrosion rate, and oxygen, in addition to depolarizing the cathodes, reacts with iron sulfide and forms elemental sulfur. This removes any protective sulfide layer and increases the corrosion rate.
Elemental sulfur is corrosive to steel and further increases the corrosion rate.
Organic acids increase the corrosion rate by dissolving iron sulfide scale and leaving the metal bare. They also lower the pH and increase the driving force of the corrosion reaction. At pH less than 6, hydrogen sulfide reacts directly with the metal, and little or no iron sulfide is formed on the surface.
The pits formed during H2S corrosion are generally small, round, and cone shaped. The acute angle at the bottom of the pit is a stress raiser, and it leads to cracking. Pits are usually not connected and are in a random pattern.
The amount of H2S present has a direct effect on the time to failure of rods due to cracking. In some cases, corrosion pits are so small as to be undetectable before cracking occurs, or cracking may take place quickly at dents or nicks on the rods.
In addition to metal loss and pitting, sulfide stress cracking may occur in H2S corrosion. The corrosion reaction generates hydrogen ions that combine to form atomic hydrogen. Atomic hydrogen penetrates the metal along grain boundaries and recombines to molecular hydrogen. The molecular hydrogen generates high pressures, and the metal cracks at grain boundaries. The microcrack acts as a stress raiser and quickly propagates.
Rod-on-tubing abrasion is common, and it aggravates corrosion reactions. Surface scale is removed, leaving bare metal. The adjacent areas covered with scale are cathodic to the bare metal and increase metal loss. Both the rod couplings and the tubing are damaged. Severe abrasion will lead to galling or removal of large portions of metal, which are literally torn away.
The flow velocities in pumping wells are generally not high enough to influence the corrosion rate, but localized areas of high velocity around rod protectors and restrictions due to scale buildup in the tubing could occur. High velocities can remove protective scale and inhibitor films, particularly if solids are present.
Elimination of Sucker Rod Corrosion. Once the cause of the corrosion has been found, corrective action is required so that the problem does not recur. The first step is to determine if the pumping program is correct. If the rod string and pumping procedure are not dynamically balanced, excessive tensile and compressive stresses are applied that will hasten fatigue failure and cracking due to corrosion.
The range of load, that is, the difference between the load of the upstroke and the downstroke, should be kept to a minimum. Long strokes at low speed will give the lowest load. The load is due to the weight of the rods and the fluid column on the upstroke and the weight of the rods on the downstroke.
The upstroke causes stretching, and the downstroke releases this stress, causing flexing of the rod. This cyclic stress induces fatigue failure; therefore, minimizing stress will reduce breaks caused by corrosion-induced cracking.
Proper rod string makeup will also reduce failures. Recommended torque loading should be followed when making up the string to be sure that the coupling is not in excessive stress or is not subject to play or movement resulting from too little torque during makeup. Hitting the rods or couplings with hammers and the use of pipe wrenches an the string should be avoided to eliminate marks that can lead to cracking.
Fluid pounding should be avoided. Fluid pounding is caused by the pump not filling completely on the upstroke and the plunger hitting the fluid on the downstroke. The sudden stop of movement causes a shock wave to propagate up the rod string. Fluid pounding can be the most damaging factor in rod failure. Rod guides can be installed to prevent rod-on-tubing wear.
Once mechanical deficiencies are corrected, an inhibition program should be initiated. Corrosion inhibitors can prevent or greatly reduce failures caused by pitting or fatigue and will ensure that the changes made in rod loading and handling will be effective.
Sucker rods arc sometimes stored outdoors or in areas where internal storage is conducive to corrosion, such as coastal and industrial areas and in oil fields that produce hydrogen sulfide. Oxygen corrosion or rust is aggravated by the deposition of salt from marine environments, such as spray on offshore platforms and coastal areas. In warehouses and under sheds, the presence of sulfur dioxide, oxides of nitrogen, and H2S will initiate corrosion attack and increase rusting.
The rod body and threads should be regularly inspected for corrosion damage. After inspection, the rods should be cleaned, and protective coatings should be applied.
Suitable coatings that will provide protection for a minimum of 2 years should be applied by the manufacturer over rods and couplings. An oil-soluble coating is preferred, and it should be maintained by reapplication during storage. Used sucker rods should be cleaned and coated before storage.
Sucker rods should be protected when pulled during work over operations. A batch of oil and inhibitor solution can be pumped into the tubing before pulling, or the rods can be coated after pulling.
Couplings should be dipped in or brushed with an oil-inhibitor mixture before makeup. Care should be taken so that the amount of inhibitor added is not excessive. Thus, proper makeup can be performed.
It is recommended that inhibitor be added to the tubing when the rods are run in the hole for initial filming. When the well is placed in production, one tubing volume of fluid should be circulated.
Once the well is in production, an inhibition and monitoring program should be initiated. An inhibitor is selected by testing for efficiency, usually with laboratory tests. These tests may include a wheel test, in which the inhibitor is added to bottles or high-pressure cells, rotated in a heated oven, and compared to an untreated control for percent protection and lack of pitting. Other tests include the stirred flask test and flow tests. All of these tests are designed to duplicate field conditions or to determine response to different corrodents under specified parameters.
There are several methods by which the cell can be treated. These include batch, continuous, and squeeze treatment, which are covered in the discussion “Inhibitors” in this article and are discussed in the section “Use of Inhibitors” of the article “Corrosion Protection Methods for the Petrochemical Industry” in this Volume. Other methods include tubing displacement after unseating the pump and the use of weighted inhibitors, sticks, or encapsulated inhibitors.
Downhole hydraulic pumps operate by pumping clean crude oil with a surface engine-driven pump down a string of tubing to operate a downhole hydraulic pump. The downhole pump lifts one barrel of fluid for each barrel of power fluid. The power oil is commingled with the produced fluid and separated on the surface.
Problems can arise if the power oil carries water and solids or if C02, H2S, or organic acids are present. The use of corrosion-resistant alloys and inhibitors can alleviate corrosion, Inhibitors are continuously added to the power fluid at the surface pump suction. Scale inhibitors and demulsifiers can also be added to the power fluid to prevent scale deposition and carryover of water into the power fluid.
In gas-lift wells, pressurized gas is injected into the annulus and through a gas-lift valve into the tubing. Fluid is displaced upward and out of the well by the gas. The process is repeated in batches or slugs in an intermittent system, or as a steady stream in a continuous-flow system. The velocities and turbulence encountered may increase corrosion initiated by H2S and CO2. Corrosion-resistant alloys can be used in gas-lift valves, and tubing can be protected by inhibitors.
Inhibitors are added into the lift gas at the surface and are carried with the gas stream into the tubing. Protection is provided above the lowest gas-lift valve. If corrosion occurs below the valve, batching or squeezing may be required for complete protection. The inhibitor selected is usually oil soluble and water dispersible, and it can be diluted with hydrocarbon to assist in carrying it downhole.
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