Fundamentals of Corrosion and Corrosion Control
Corrosion can be defined as the degradation of a material due to a reaction with its environment.
Degradation implies deterioration of physical properties of the material. This can be a weakening of the material due to a loss of cross-sectional area, it can be the shattering of a metal due to hydrogen embrittlement, or it can be the cracking of a polymer due to sunlight exposure.
Materials can be metals, polymers (plastics, rubbers, etc.), ceramics (concrete, brick, etc.) or composites-mechanical mixtures of two or more materials with different properties. Because metals are the most used type of structural materials most of this web site will be devoted to the corrosion of metals.
Most corrosion of metals is electrochemical in nature.
All regulated underground storage tank systems must have cathodic protection.
Regulations and Standards require corrosion protection for underground storage tanks because unprotected steel underground storage tank systems corrode and release product through corrosion holes.
Tank and piping are completely made of noncorrodible material, such as fiberglass- HDPE
Corrosion protection is also provided if the tank and piping are completely isolated from contact with the surrounding soil by being enclosed in noncorrodible material (sometimes called “jacketed” with noncorrodible material).
Tank and piping made of steel having a corrosion-resistant coating AND having cathodic protection .
A corrosion-resistant coating electrically isolates the coated metal from the surrounding environment to help protect against corrosion. An asphaltic coating does not qualify as a corrosion-resistant coating.
Tank made of steel clad with a thick layer of noncorrodible material but this is not applicable to pipes. Galvanized steel is not a noncorrodible material.
Impressed current system.
An impressed current system uses a rectifier to convert alternating current to direct current .
This current is sent through an insulated wire to the “anodes,” which are special metal bars buried in the soil near the underground storage tanks.
The current then flows through the soil to the underground storage tank system and returns to the rectifier through an insulated wire attached to the underground storage tank. The underground storage tanks is protected because the current going to the underground storage tank overcomes the corrosion-causing current normally flowing away from it.
Sacrificial anode system.
Another type of cathodic protection is called a sacrificial anode or galvanic system. Although sacrificial anode systems work with new underground storage tanks, corrosion protection experts generally agree that sacrificial anodes do not work effectively or economicall with most existing steel underground storage tanks.
Only a qualified cathodic protection expert candetermine what kind of cathodic protection will work at your underground storage tank site.
Operation and maintenance requirements
A qualified cathodic protection tester must test the system within six months after installation and every three years thereafter.
A negative potential of –850 millivolts or –0.85 volts should be obtained between the UST system and a reference electrode touching the soil above the tank.
Results of the last two inspections performed by a qualified cathodic protection tester must be kept.
In addition, an impressed current system must be checked by the owners or operators every 60 days to ensure that the system is operating properly.
A log must be kept for the last three check ups to show that the impressed current system is operating properly.
The records may be kept at a central office rather than the facility itself.
Laying a pipeline with corrosion protection
Corrosion Problems in Oil Industry Need More Attention
18th February 2003Dr A K Samant, Suptdg. Chemist, Mud Services, Assam Asset, Sivasagar, Assam
Corrosion is becoming an increasing threat to the integrity of oil field structures including pipelines, casing and tubing world wide.
Failure of any of these systems could have disastrous consequences and may lead to safety problems both in onshore and offshore.
In oil field, if corrosion is left unattended, it may cause failure either due to leaks in pipelines or collapse of well casing and tubing and thus significant losses of the products transported can take place.
Plants would have to be shut down plant, contamination of products might take place and pollution and fire are possibilities. Since corrosion can not be eliminated entirely, the aim should be to reduce the corrosion risk to an acceptable level. Condition assessment of oil field installation, therefore, is of great concern not only in India, but all over the world. There is a need for uniform, consistent and reliable guidelines for assessment of health of existing structures, pipelines and well casings. Considering the importance of pipelines and well casings, a brief analysis of both the systems has been carried out.
Protection Of Pipelines
Pipelines are considered as the safest and most economical method of delivering hydrocarbon products from one place to other both in offshore and onshore. However, like all other engineering plants, they are also susceptible to failure due to various reasons.
Pipeline failures are reported both in onshore and offshore.
Three-phase well fluid carrying pipelines, containing both water and corrosive gases such as carbon dioxide and hydrogen sulphide, are particularly susceptible to internal corrosion. When a new pipeline is planned to be installed, its integrity is assured by providing sufficient wall thickness, suitable material and quality control and by adopting suitable corrosion protection system. Pipelines are susceptible to both internal as well as external corrosion.
The most common external corrosion protection system for pipelines is corrosion coating and installation of cathodic protection system. To achieve the effective protection, it is necessary to adopt both the above techniques together. For internal corrosion protection, mostly chemicals like corrosion inhibitors are used. However, when pipeline is found contaminated with bacteria, biocides and bactericides are used. Biocides are those chemicals, which kills the bacteria completely, whereas bactericides are chemicals, which suppress the growth of biological activity up to a permissible limit.
Offshore as well as onshore, fluid flowing through pipelines, have been found to be contaminated with bacteria.
Failure investigation of some of the leaked pipelines showed bacterial induced corrosion as a major factor for pipeline leaks offshore and onshore. Some operators are also using internal protective coatings as protective measure. In both the situations, quality of material used and application techniques play important role for complete protection against corrosion. This should be followed by a systematic operation of the line in such a way that they do not deviate from operational requirement specified by codes/standards. Pipelines deterioration can be minimised by periodic monitoring of pipelines using suitable measures like corrosion probes, coupons, fluid analysis and online monitoring loop lines etc. Further, maintenance measure should be both cost effective and prevent failure.
Periodic Assessment Of Pipeline ConditionFor the periodic assessment of the lines following techniques should be used:
1. Evaluation of corrosivity of fluid flowing through pipeline by corrosion monitoring probes
2. Monitoring of efficacy of cathodic protection and coating damage assessment
3. Measurement of wall thickness / metal loss in critical areas
4. Condition assessment based on analytical techniques. The purpose of above studies is to identify the most critical segment of the pipeline and detect the damage or defects before they cause serious problems. For prediction of corrosivity of flowing fluids, software is available. These software works based on the fluid parameters and operating data. Analysis of oil associated water and gas for presence of carbon dioxide and hydrogen sulphide gas, sulphate reducing bacteria and acid producing bacteria, bicarbonates and chloride ions, flow velocity, operating pressure and temperature etc. helps in assessing the corrosivity of fluid.
Monitoring of efficacy of cathodic protection system and survey for detection of coating damage are performed to assess the external condition of pipeline. As mentioned earlier, pipeline failures are possible and reported, both due to internal as well as external factors. Therefore, both internal as well as external monitoring of pipeline is required for complete health assessment.
The monitoring methods may be used in combination for more realistic picture of corrosion in the pipeline and information should be maintained in the form of records before installation and removal of corrosion monitoring devices:
1. Operating pressure and temperature
2. Fluid analysis results like a) Water content and its composition b) CO2 and H2S content c) Number and types of bacteria
3. Flow rate
4. Pigging frequency
5. Corrosion inhibitor and bactericides dose, frequency and injection methods Corrosion control by protective coating supplemented with cathodic protection shall be provided in the initial design based on the study of environment and soil condition along the pipeline route and maintained during the service life of the pipeline system. During construction and initial phase of operations, temporary arrangement should be made to protect the pipeline cathodically. However, the pipeline system shall be permanently protected within a year of pipeline installation. External coating must be properly selected and applied. Coated pipeline shall be carefully handled and installed.
Continuous potential logging (CPL) survey, once in five years or whenever inadequate corrosion protection is observed, should be carried out Direct Current Voltage Gradient (DCVG), Current Attenuation Test (CAT) Surveys to elaborate the coating defects should also be carried as and when required.
Isolation of cathodically protected pipeline is recommended to minimise current requirement, facilitate testing and trouble shooting and improve current distribution. When two or more pipelines are laid in the same ROW / ROU periodical interference survey shall be conducted and suitable mitigating measures to be taken to avoid interference between the lines. Where stray current is known to exist which adversely affects the level of corrosion protection of the pipeline, additional monitoring should be carried out on monthly basis. Underground pipelines are generally routed under roads and railways in steel casings.
Wherever these are essential, casing pipes should be electrically isolated from the carrier pipes by providing isolating spacers. The isolating spacers should be designed and spaced to withstand the loads caused by the movement of the carrier pipe under operational conditions.
Periodic Pigging Of Pipeline
Pigging should not only be used to remove scales and wax from internal pipe wall but effort should be to remove bacterial colonies, corrosion deposits by using suitable scrapers, and to facilitate the corrosion inhibitor film formation, thereby to reduce under deposit corrosion. Chemical injection in conjunction with pigging programme offers an efficient and cost effective technique to control internal corrosion in pipelines that carry oil with high water percentage and low flow velocities.
Intelligent Pigging For Safe Operation Of Pipeline
Intelligent or smart pigs can detects and measure the pipe wall defects such as corrosion, weld defects and cracks. The use of intelligent pigs for inspection of pipelines has increased considerably. The most commonly used intelligent pigs use magnetic flux leakage (MFL) technique to detect corrosion pits and planar and axially oriented cracks. However, advance MFL based intelligent pig has been used to detect circumferentially oriented cracks in both oil and gas pipelines. Ultra sonic based intelligent pigs require a liquid coupling between transducers and the pipe wall and therefore restricts their use in gas lines unless they are run in a slug of liquid or the coupling has been attached by some means. The primary use of the results from an inline inspection using intelligent or smart pigging is not restricted to find out the health of the pipeline, but to calculate the maximum allowable operating pressure (MAOP) at which the pipeline can still safely be operated.
Protection Of Well Casing & Tubing
Conditions such as poor cementing, large variations in the casings metallic composition, fluid salinities, dissolved corrosive gases, etc. have been recognized as corrosion promoters in well casing and tubing. Downhole corrosion monitoring, to evaluate both – the extent of metal losses and the corrosion rate, is vital as corrosion initiation and propagation can not be predicted from theoretical estimates. Drill pipes are subjected to corrosion in the hole, standing in the rig, laying on the rack or during movement of location. Down hole corrosion is more detrimental, as it occurs in conjunction with cyclic loading. Large number of corrosion cells are formed on drill pipe and well casing surface due to material inhomogeniety and because of the presence of deposits or scales. Local corrosion may also be occurred due to formation of concentration cells causing pitting. Because of the presence of hydrogen sulphide and dissolved salts, corrosion fatigue and stress corrosion cracking are a major cause of drill pipe failures. Sulfide stress corrosion cracking is most common in presence of hydrogen sulfide and when the stress in the drill pipe and casing is higher. Corrosion inhibitors and biocides are used to control the corrosion and bacterial growth, but there is no assurance that they will do so, since a packer fluid remains in place until it is necessary to do remedial work on the well, which may not be for years. Therefore, leaving a water base drilling mud / brine in the hole as a packer fluid may result in development of casing or tubing leaks in the course of time. Similarly, on external surface of casing, generation of hydrogen sulphide by bacteria and high concentration of sulfates results in deterioration of cement. Corrosive fluid, water, microorganisms etc. penetrates the poor permeable cement and then able to attack the external casing metal resulting in leakage.
Once leaks have started, corrosive water enters the well and can attack the casing wall.
Offshore, well casing corrosion is a matter of serious concern.
Well casing survey of these wells is the prime concern. The some of the tools employed for well casing and tubing corrosion survey are Casing Inspection Tool (CIT), Multi-frequency Electromagnetic Thickness Tool (METT), Digital Cement Evaluation Tool (CET-D) & Corrosion and Protective Evaluation Tool (CPET). NACE standard RP-01-86 describes four methods or criteria for designing and evaluating cathodic protection systems for well casings. They are downhole potential profile surveys, E/Log i polarisation curves, mathematecal modelling combined with the measured wellhead potential, and average current density over the casing. Each technique has its advantages and disadvantages. None of the techniques gives direct information in polarisation of the casing surface at depth.
Potential profile survey is the only technique in which the flow of protection current at depth can be confirmed. Downhole potential profile measurements have been used for a number of years in evaluating and optimising well casing cathodic protection. Recent advances in instrumentation have enabled high-resolution potential difference and casing resistance measurements to be recorded.
As a consequence, current and current density profiles are free of the ambiguities present in earlier measurements.
Corrosion control is an important consideration. The periodic monitoring techniques and analytical assessment of corrosion severity is very important and critical since it provides the direction to ensure proper utilisation of materials and corrosion control methodologies. Therefore, correct and appropriate condition assessment techniques should be used to avoid premature failure and ensure maximum safety