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Corrosion inhibition and management (including H2S and CO2)
ABSTRACT Results of a literature and an experience survey on materials selection in subcritical and supercritical water oxidation processes are presented in this paper. Some hydrothermal process environments with moderate pH levels and low levels of reactive halide ions were mild enough to allow the use of AISI 316 and similar stainless alloys. The engineering alloys most commonly utilized in hydrothermal oxidation processes were found to be alloys C-276 and 625. However, the corrosivity in some environments appeared to be beyond the limits of alloys C-276 and 625 and required materials with higher corrosion resistance. Titanium alloys such as T1-Gr2, Ti-Gr9 and Ti-Gr12 had value in terms of their corrosion resistance under some cases of highly oxidizing conditions. For severe applications, noble metals such as Pt, Pt-Ir and Pt-Rh were used as liners and overlays to minimize corrosive attack, Newer developed alloys such as alloyC-4, C-22, 59,686 and C-2000 haven?t yet been evaluated in hydrothermal oxidation process environments, In addition to materials selection, design innovations were used to minimize conditions for corrosive attack in process equipment. INTRODUCTION Near complete destruction of hazardous waste is achieved by hydrothermal oxidation processes. Basically, the aqueous waste is heated and pressurized in the presence of air or oxygen. During hydrothermal oxidation of hazardous waste, the materials of construction of the preheating parts, reactor, heat exchanger, and cooldown parts are subjected to gases, liquids, and solids of various compositions at high temperatures and pressures. Both strength and corrosion resistance are important because chemical and mechanical effects at these conditions interact. High temperatures accelerate corrosion processes. Some gases and liquids which are harmless at room temperature, become aggressive to materials when hot ?l].Chemical composition of the hazardous waste being oxidized plays a large role in the corrosion process. Corrosion rate of most engineering materials increases as the pH decreases. Halide ions such as chloride, fluoride, etc. can cause stress corrosion cracking and breakdown of passive films. In addition to the direct attack to the film, under oxidizing environments, chloride can combine with iron to form ferric chloride with has a melting point of about 280 C. This contributes to the formation of a liquid salt on the alloy surface which removes protective oxide films ?2-31.The sulfate ion is also a primary aggressive ion. Sulfate deposits are known to induce hot corrosion. This type of corrosion occurs when salts or ashes accumulate on the surface of alloys and accelerate the corrosion process under these deposits ?4].Fluoride and bromide can also interact with specific alloys at high temperature and decrease their corrosion resistance. A literature review and an experience survey on materials selection in subcritical and supercritical water oxidation processes are presented herein. The sources of the published literature included technical, trade and news publications, The experience survey information was obtained from individuals in academic, research and commercial organizations working on hydrothermal oxidation processes.
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- Water & Waste Management (1.00)
- Materials > Metals & Mining (1.00)
- Energy > Oil & Gas > Upstream (0.87)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.68)
- Well Completion > Well Integrity > Subsurface corrosion (tubing, casing, completion equipment, conductor) (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (1.00)
- Health, Safety, Environment & Sustainability > Environment > Waste management (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Materials and corrosion (1.00)
ABSTRACT As fiberglass reinforced plastic (FRP) continues to grow as a material of construction in applications such as tanks, packed bed scrubbers, piping, ductwork, and specialty equipment, the number of FRP structures which require repair or which have in some way lost their utility as they were initially designed will continue to grow. In some instances, damaged or obsolete FRP structures may be modified or repaired to a condition which can provide extended service lifetimes; this may result in lower life cycle costs than wholesale replacement. A number of factors must be assessed prior to design of repairs or modifications, such as the current condition of the structure, the material used in the initial fabrication, and the goals of the project. A thorough examination of these factors will help assess the plausibility and type of modification(s) required. A procedure for surface preparation and laminate application is provided. INTRODUCTION The use of FRP as a viable material for applications where chemical resistance, high strength-to- weight ratio, and low life cycle costs are important continues to grow in a variety of industries. FRP is the material of choice in storage tanks, corrosion resistant grating, safety appurtenances (ladders and safety cages), packed bed scrubbers, piping, ductwork, and specialty equipment. As the growing number of existing FRP structures age or degrade, it will become common for FRP structures to require repair. A repair may be needed where a defect (such as a blister, inclusion, worm hole, or pit) or an area cracked due to impact, overloading, thermal shock, etc. would affect the structural stability or corrosion resistance of an FRP laminate. Localized abrasion damage may also require repairs. Chemical degradation can be repaired by replacing affected resin rich or structural layers, although this is much less common due to the expense involved. In some cases, the original design of the structure may not be suitable for the current or future service in its current form. This could be due to the geometry of the structure, a new service environment, a new operating temperature, a change in the operating loads, or degradation of the mechanical properties of the laminate. Loss of properties can be caused by penetration of a material which degrades the laminate or from long term exposure to elevated temperatures. Some of the means of assessing the condition of the structure and the procedures required to upgrade or repair the structure are described below.
- Facilities Design, Construction and Operation > Processing Systems and Design (0.89)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (0.55)
INTRODUCTION ABSTRACT Two case histories in which high pressure natural gas coolers had failed due to the presence of carbon dioxide are reviewed. CO* along with CO and H$S are acid gases usually present in natural gas feeds. Carbonic acid can form in aqueous condensate, lowering the pH and locally corroding mild steel tube metal. Stress corrosion cracking (SCC) can occur in tubing containing residual tensile stresses from welding or manufacturing. Bicarbonates and carbonates concentrated in condensate from CO2 and CO present in natural gas are required to produce SCC. Cathodic depolarizers such as oxygen in conjunction with the presence of carbonic acid will increase the corrosion rate of mild steel. Oxygen also increases the susceptibility of mild steel to carbonate SCC. Heat Exchanger Design Shell-and-tube-type heat exchangers are used as heat transfer equipment in chemical plants, petroleum-refinery service, and natural gas processing. Tubular Exchanger Manufacturers Association (TEMA) recommends that heat exchanger sizes of shells and tube bundles be designated by numbers and that heat exchanger types be designated by letters. For example SIZE 17-192 TYPE CEN (Figure 1) represents a fixed-tube sheet exchanger (N) having stationary and rear heads integral with tube sheets (C), single pass shell (E), 17 in ( 43.2 cm) inside diameter with tubes 8 ft (2.4 m) long. The main function of the heat exchangers presented in this paper was natural gas cooling by means of water. General design considerations pointed out a DJN type of heat exchanger with a special high pressure closure at the front end (D), a divided flow shell (J) and fixed tube sheets (N), (Figure 2). CO2-H20 Corrosion Corrosion due to wet gases containing CO* has been well studied and numerous data have been reported in the literature. In the present study, corrosion of high pressure gas coolers, many significant factors common to gas lines and other plant equipment are found. Accordingly, when aqueous condensate is present or forms in a system containing CO;! , severe pitting and general attack can ensue. The corrosion is caused by the formation of carbonic acid in an aqueous phase (an active participation of e- shown in parenthesis indicates an alternative electrochemical reduction of CO2 at the surface) CO2 + Hz0 (+e) ti H&03 (+e) f) H? + HCO; (+e- + 1/2H2 + HC03) (1) and subsequent reaction of either undissociated carbonic acid or bicarbonate ion with the carbon steel surface Fe + H2C03 + HC03- + H? + Fe2+ + FeC03 + 2H? (2) The partial pressure of CO2 in a wet gas stream will affect the corrosion rates of carbon steel. Estimations of the corrosion rate of carbon steel, as a function of temperature and CO2 partial pressure, can be made using the dewaard-Milliams nomogram? which is based on corrosion rates of cleaned carbon steel surfaces. However, the dewaard- Milliams nomogram does not take into account flow induced film stripping (due to excessive velocity or turbulence) or the presence of other gases such as H2S or 02. Nonetheless, carbon steel is usually acceptable for wet CO2 service if the CO2 partial pressure is less than about 4 psia (27 kPa). Carbon steel corrosion rates normally increase dramati
- Well Completion > Well Integrity > Subsurface corrosion (tubing, casing, completion equipment, conductor) (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Materials and corrosion (1.00)
ABSTRACT A study was performed to assess the corrosion rate in a gas sweetening plant using electrochemical methods. The tests were performed by using samples of the amine in service. Coupons made of A-106carbon steel were tested, as this material is typically used in most vessels. The variables studied included the actual temperature of different plant units at both rich ad lean amine conditions, and the degree of C02 saturation. The results show an increase of the uniform corrosion rate with temperature, which reflects the effect of heat stable salts in the corrosivity of the amine evaluated. Also, from the analysis of the potentiodynamic carves at different conditions, the risk for Alkaline Stress Corrosion Cracking (ASCC) was assessed. The association of this risk with actual plant conditions shows which vessels are susceptible to both amine corrosion and ASCC which allowed to develop a corrosion profile for both the lean and rich amine parts of the circuit, INTRODUCTION In the oil and gas industry, the amount of acid gases CO2 and H2S must be kept under rigorous control, due to their corrosive influence upon the processes and equipment used downstream from the oilfield patch. The most widespread method of C02/H2S control is the use of amine process, where removal of these natural gas contaminants occurs by chemical equilibrium reactions with amine solvents, such as MEA, DEA, TEA ]. The basic layout for an amine sweetening plant consists of a close circuit process, where the natural gas containing the C02/H2S contacts, in counter current, the amine solvent at the gas scrubber or contactor, Then, this loaded amine solution referred as rich amine goes through the amine stripper where it is exposed to water vapor at temperatures over 150C, ad devoid of most of the content in the acid gases, resulting in amine solution called lean amine. The most severe corrosion problems found in this kind of gas sweetening plant are general corrosion and stress corrosion [W From the standpoint of corrosive behavior, it cracking, Also, hydrogen related problems are found in refinery based units . has been found that the interaction between the amine solvent and the acid gases is complex and related to the amine solvent [2.31 me main aspects that control the corrosive behavior of the amine composition and operating parameters of the plant solvent can be summarized as follows. Effect of Acid Gases Content The corrosion process in amine gas treating plants will depend on different parameters such as: the ratio of partial pressure of H2S and C02, and the operating conditions of the circuit (i.e. temperature, flow rate, amine concentration, etc.), which could yield a combination of corrosion products with protecting properties ?2]. The protective nature of corrosion products is not only related to the ratio of partial pressures C02 / H2S and temperatures, but also depends on the actual total C02 pressure considered in the circuit due to its influence on solution pH. At low partial pressures of C02, solution pH can be expected to be over 8, so the alkaline nature of the amine solution can form a protective layer due to its interaction with H2S 141,The opposite happens at high pressures of C02 where the ratio C02/H2S and the amine concentration in the process, control the corrosive mechanisms. API ?2]suggest that if the steel is exposed to gas containing in excess 95% C02 most of the corrosion can be attributed to this gas, and that the amine solution can be considered not severely corrosive if the ratio of H2S/C02 is below 1/20, due to a stable formation of a protective layer of iron sulfide. Also, associated to the C02/H2S partial pressure ratio is the s
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Downstream (1.00)
- Well Completion > Well Integrity > Subsurface corrosion (tubing, casing, completion equipment, conductor) (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (1.00)
- Health, Safety, Environment & Sustainability > Health > Noise, chemicals, and other workplace hazards (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Materials and corrosion (1.00)
ABSTRACT The design of FRP corrosion resistant equipment is sometimes difficult because the material properties are complex and FRP is often molded into complex shapes. There are several types of software available to aid the designer of FRP. For typical designs, easy-to use design rules programs are available which calculate thicknesses and also estimate the fabrication costs. User friendly lamination analysis software can be used to predict material properties and run pressure, vacuum, and axial load calculations for cylinders. For the more advanced user, Finite Element Analysis software can be used to design virtually any geometry with complex loading and material properties. INTRODUCTION Engineers who are accustomed to working with isotropic materials such as metals may find it difficult to design or review the design of FRP (fiberglass reinforced plastic) pipe, tanks, vessels and structures used in corrosion resistant applications. Beginning with the aerospace industry, a variety of software has been developed which makes this task much easier. With the exception of Finite Element Analysis, most of this software is relatively easy to use. The three categories of software which will be examined are (1) Design Rules and Cost Analysis, (2) Lamination Analysis, and (3) Finite Element Analysis. DESIGN RULES AND COST ANALYSIS Design Rules and Cost Analysis software has been developed especially for corrosion resistant FRP components such as vessels or pipe. These programs are useful to specifying engineers, reviewers, design engineers and fabricators. A typical program consists of the design section and the cost analysis section. Design is done by rules or formulas such as those found in ASME RTP-1 Subpart 3A. The user must input the required data such as diameter, height, head geometry, specific gravity, wind speed, seismic zone, type of construction, etc. and the program will calculate the required wall thicknesses, hold down lug requirements, etc. The Cost Analysis section takes the results of the design section and computes a cost based on raw material and labor data which has been entered into the program. Material cost data includes costs for resin, various types of reinforcements, consumables, etc. Additional costs are appurtenances such as nozzles, hold down lugs, lifting lugs, etc.
- Materials > Metals & Mining (1.00)
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- Aerospace & Defense (0.76)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (1.00)
- Data Science & Engineering Analytics > Information Management and Systems (0.94)
ABSTRACT A non-toxic corrosion inhibitor based on organic compounds was developed to replace a heavy metal toxic inhibitor in MEA plants. The tasks involved in the development program are presented in this paper. A search for non-toxic organic chemicals with potential inhibitive properties was performed first followed by the preliminary screening tests. The best three chemicals were then tested in stirred autoclave at several concentrations. Slow strain rate runs were also performed to test the susceptibility of welded as well as non-welded carbon steel specimens to stress corrosion cracking. The single best performing chemical was then tested under turbulent and laminar flow conditions in a flow loop. High alloys materials typically found in amine plants were also tested in an autoclave setting to determine if they were compatible with the inhibitor. The single best performing inhibitor was then finally tested in a refinery gas plant for 18 months. The corrosion rates data, analytical results and physical inspection of the field equipment showed that the non-toxic corrosion inhibitor was very effective in reducing corrosion. Based on the results of the laboratory and field testing program, it was decided to replace the previous toxic corrosion inhibitor by the newly developed non-toxic corrosion inhibitor. INTRODUCTION Amine plants, using MEA as a sweetening agent, always exhibit some degree of corrosion. The latter is minimized by keeping the amine clew holding acid gas loading within specifications, operating the still at the lowest temperature possible and maintaining a regular testing program. Compounds based on inorganic, toxic materials such as arsenic are still used as corrosion inhibitors in many amine plants around the world. However, most manufacturers, especially in the USA are not producing these chemicals anymore. Due to non-availability of these toxic materials and other environmental and safety problems in their disposal/storage, alternative non-toxic and organic chemicals are needed to solve the corrosion problem. This paper presents the methodology used to develop a non- toxic corrosion inhibitor for replacement of a heavy metal toxic inhibitor in a MEA plant used for C02 removal. The tasks involved in this program included: 1. The search for candidate compounds. 2. The screening tests on all candidate inhibitors to select the best performing inhibitor compatible and their optimum concentration 3. The autoclave tests to verify corrosion behavior of the best inhibitor and to test Stainless steel and Monel materials. 4. The slow strain rate tests for evaluation of SCC of steel base metal and welded specimens with and without inhibitor. 5, The dynamic flow loop tests to simulate field flow conditions. 6. The field test. SEARCH FOR CANDIDATE COMPOUNDS The process for the search for candidate corrosion inhibitors compounds involved extensive literature, patent, and computer database searches of commercially available chemical agents with potential viability for use as corrosion inhibitor formulations. The search was based on several requirements including volubility, temperature stability, cloud point in amine solvents. Additional requirements were that none of these compounds were based on inorganic, toxic materials such as arsenic. Thirty six(36) corrosion inhibitors based primarily on organic constituents compatible with MEA and meeting all the requirement specified above were selected. SCREENING TESTS The initial screening tests consisted of exposing two duplicate carbon steel specimens in 4 oz. jars filled with C02 saturated 20% MEA solution and 1000 ppm inhibitor at a temper
- Water & Waste Management > Water Management > Water & Sanitation Products (1.00)
- Materials > Chemicals > Specialty Chemicals (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
ABSTRACT Amine units are generally used in refineries and petrochemical plants to remove acid gases such as hydrogen sulfide (H2S) and carbon dioxide (C02) from process streams. Commonly, corrosion of carbon steels in amine units is not caused by the amine itself but by its reaction with dissolved gases. In this paper, fundamental aspects concerning the susceptibility of carbon steels to stress corrosion cracking in amine solutions are presented, and special attention is given to a recent study on a commercial mixture of amines. An overview is made on the methodology used. INTRODUCTION Stress corrosion cracking (SCC) of carbon steel equipment in amine units has been experienced in several plants in the petroleum and gas industries. Amine corrosion is caused by one or more of the following factors: high operation temperatures, high molar ratios acid gas/amine, H2S/C02 ratio in the feeding gas, amine contamination or degradation products, amine characteristics and concentration II]. Stress corrosion cracking, on the other hand, occurs in places of high hardness, high concentration of residual stresses, or both. Corrosion is the result of the simultaneous presence of a corrosive media an a tensile stress, either an internal residual stress or one externally applied. In the following pages, the susceptibility to stress corrosion cracking of an ASTM A-106 carbon steel is evaluated in an amine solution (commercial). This solution is used to remove C02 in the sweetening unit E] Tablazo II located in Zulia state, Venezuela. A simplified flow diagram is shown in Figure 1. The carbon steel evaluated is used in pipelines in this plant. These pipes, as the rest of the components, are submitted to severe operation conditions. EXPERIMENTAL The method adopted at INTEVEP to study the phenomenon of stress corrosion cracking in the laboratory includes different laboratory tests, electrochemical and mechanical, complemented with material characterization and fractographic analysis. Electrochemical tests include potentiodynamic curves and polarization resistance tests. Mechanical tests comprise those realized at a constant load and those at slow strain rates (SSR). Table 1shows the chemical composition of ASTM A-106 gr. B steel. The probes utilized correspond to those specified in the standard test method norm NAC33TMO177-90 as sub-standard probes for tensile tests. The probes were machined from a section of a component of the amine unit. The solutions used, lean and rich, were taken from the plant at the entrance and outlet of the regenerator. Amine concentration was 50% and its pH was around 10. Polarization resistance (Rp) tests were done at two different conditions, using Nitrogen (N2) and carbon dioxide (C02) atmospheres. 800 ml of amine solution from the plant were used for each experiment. Test temperature was 93C. Rp measurements were taken every fifteen minutes for a total time of 15hours, then a potentiodynamic sweep was performed. SSR tests were performed at a rate of 10-5-104S-l.The equipment utilized allows the continuous display of load and elongation, while controlling temperature and deformation. Temperature was fixed at 83°C because the cell is made of Plexiglas and higher temperatures could cause leaks of the solution during the experiment. The first experiments, used as a baseline, were done in a dry nitrogen atmosphere. The other series of experiments were done with the commercial amine lean and rich, using N2and C02 as the saturation gas.
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- South America > Venezuela (0.35)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Downstream (1.00)
INTRODUCTION ABSTRACT The benefits of composite materials - light weight, corrosion resistance, handling ease, etc., have tong been appreciated. Composite piping systems are gaining wide acceptance in various industries such as petrochemical, offshore oil & gas, pulp and paper, and marine industries. The modern numerically controlled, multi-axis filament winding machines have brought the manufacturing of composite pipe into a new era. With the Multi-Angle filament winding technology, an optimal combination of different winding angles can be designed to satisfy specific mechanical requirements such as hoop and axial stiffness and strength, support span, internal and external buckling pressure, etc. In this paper, comparisons are demonstrated among several multi-angle pipe with traditional 54- degree wound pipe on various mechanical properties. Over the past twenty years, the various resin manufacturers have done an excellent job of identifying the range of chemical environments and maximum temperatures their resins can be considered for long term performance Today, it is unusual to hear of a premature failure due to chemical attack on a properly manufactured and cured laminate. If the chemical engineer and/or corrosion engineer can find their intended service listed in a corrosion guide published by a reputable resin producer, potential problems due to chemical attack are highly unlikely. Composite Pipe Systems are lightweight, corrosion resistant, and are much less expensive than stainless steel, copper-nickel or exotic alloys. It is estimated that composite pipe systems can be designed to handle over 90 percent of the chemical solutions used in the Chemical Process Industries today, as long as the service is within the temperature limits of the resin chosen and the operating pressure is under 150 psi, (10 Bar). In addition, composite pipe systems offer low maintenance, low friction losses, low thermal conductivity, and the ability to design for F/MESS FOR PURPOSE: While standard composite piping materials are non-conductive, withstand hydrocarbon fires up to 2OOOF, (1lOOC). However, today, as in the past, many mechanical and civil engineers responsible for detail piping design do not understand the unique mechanical characteristics of composite materials and the design flexibility available to the design engineer. The ability to design for ?FITNESS FOR PURPOSfis one of the major advantages of composite pipe systems.
- Geology > Geological Subdiscipline > Geomechanics (0.35)
- Geology > Mineral > Native Element Mineral (0.35)
- Materials > Metals & Mining (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Reservoir Description and Dynamics (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Piping design and simulation (0.92)
- Well Drilling > Wellbore Design > Wellbore integrity (0.63)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (0.56)
ABSTRACT Extensive measurements on E-glass/vinylester rods exposed to air, water, and ammonia solutions at temperatures between 23°C and 80°C for 7 to 224 days showed that integration of the chemical, thermochemical, and mechanical data is necessary for developing useful models of FRP degradation. For instance, fiber dissolution is a major mechanism in basic environments while resin hydrolysis is most pronounced in acidic environments . I,* Dramatic increases in degradation rates may be observed in some cases of environmental exposure after a certain induction period, even at relatively low temperature (below Tg). The degradation following an initial period during which the properties of the composite remain unaffected or even improve is due to hydrolytic depolymerization becoming the predominant mechanism once post curing has achieved its maximum extent. Applied mechanical stress was not observed to aggravate the effects of exposure to water at temperature of 60°C. INTRODUCTION Characterization of the effects of environmental exposure on the degradation of fiber reinforced plastics (FRPs) is a crucial step in the evaluation of the possible applications of these materials for civil and military purposes. Measurements of physicochemical and mechanical properties of these materials are essential in seeking to understand the effects of the environment on the strength and on the chemical resistance of FRF?s and in the identification of the degradation mechanisms. A previous paper? described the development of accelerated test methods to enhance the degradation and of methodology that makes it possible to use the results of short-term tests as a basis for long-term predictions. Another paper indicated that thermogravimetric analysis (TGA) and differential scanning calorimetry (DSC) are useful techniques in monitoring the degradation processes, especially when used in combination with accelerated tests at elevated temperatures. It was shown that TGA measurements of weight loss upon heating 150°C to 300°C following environmental exposure are indicative of the extent of matrix depolymerization during the preceding exposure. The weight gain during exposure and on the weight loss during the subsequent thermogravimetric analysis were measured as a function of the temperature of the exposure. The effective activation energy of the degradation processes of a E-glass/polyester rod was determined to be approximately 65 kJ3. In the present study, it was observed that exposure to 80°C appears to be a promising technique of accelerating the degradation of FRPs without changing the corrosion mechanisms. Table 1 shows that in the case of E-glass/vinylester plate material, upon changing the exposure medium from de-ionized water to 3% ammonia, the subsequent TGA weight loss between 150 and 300 C increased by a factor of around 3. This factor was obtained when the exposure took place both at a temperature of 23 C and when it took place at a temperature of 80°C although the absolute TGA weight losses were much larger at 80°C. The similarity between the magnitude of the effect of change in chemical environment at 23°C and 80 C, respectively, indicates that over this temperature range the degradation mechanism remains unchanged. Furthermore, the differences among various materials are also unchanged within this temperature range (Table 2). Accordi
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- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Materials and corrosion (0.50)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (0.40)
- Reservoir Description and Dynamics > Reservoir Characterization (0.35)
ABSTRACT In a previous work, a relationship was established between a vacuum loss method and a conventional electrochemical technique for measuring hydrogen permeation through metals. In this paper, mathematical expressions are derived and used in order to quantitatively compare electrochemical transients typically obtained in the laboratory, with the vacuum loss data that could be obtained in the field. The effects of capillary tubing length, temperature and metal wall thickness on both the time and magnitude response are assessed. These expressions will allow to use the vacuum loss hydrogen patch probe as an on-line sulfide stress cracking or hydrogen induced cracking susceptibility monitor, based on correlation found in the laboratory using electrochemical techniques. INTRODUCTION One of the methods commonly used in the field to monitor internal corrosion rates of pipelines or reactors, non intrusively, is known as the Hydrogen Permeation Method. The principles behind this method, advantages and disadvantages have been extensively discussed in the literature?. The use of this technique for quantifying internal corrosion rates can be considered a controversial issue, because the relationship between the corrosion rate and the hydrogen flux is not straight forward. This relationship depends not only on the corrosion kinetics, but also on the parameters controlling hydrogen transport through the materials and interfaces involved. Besides, them are many other techniques for measuring corrosion rates directly, which compete with the hydrogen permeation method. However, the hydrogen permeation method has one competitive advantage over other techniques, when it is important to assess the susceptibility of materials to fail from hydrogen related phenomena, such as sulfide stress cracking (SSCC), hydrogen embrittlement (HE) or hydrogen induced cracking (HIC, SOHIC). Many testing methods have been developed to assess in the laboratory the SSCC susceptibility of candidate materials for sour service. Most of these methods are included in standard procedures, such as NACE TMO177-90?. However, the need of such practices to be accelerated leads to the use of aggressive environments that do not represent in an adequate way the conditions commonly found in the oil field. Gn the other hand, the constant extension rate, CERT?, and the fracture mechanics approach using double cantilever beam specimens, DCB4 can assess the SSCC susceptibility in different testing solution and conditions. Therefore, they have the potential of been used in establishing environmental envelopes inside which a given steel will exhibit crackingS. However, none of these methods can be used on-line to determine in the field the susceptibility of steels to suffer SSCC. If a correlation between SSCC susceptibility of a given material with hydrogen permeation is known, it may be possible to extrapolate laboratory results to other set of field conditions that induce similar hydrogen flux or concentration inside the metal. For example, a correlation has been reported between normalized strain to failure and the normalized hydrogen, showing a trend that is dependent on the environmental parameters involved in the test6,?. This relationship has been extended to other OCTG materials at different temperatures, obtaining a c
- Well Completion > Well Integrity > Subsurface corrosion (tubing, casing, completion equipment, conductor) (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Materials and corrosion (1.00)