Stress corrosion cracking (SCC) of stainless steels and Ni-base alloys in chloride environments has been widely studied and the results to date suggest that SCC only occurs at potentials above a critical potential. Many researchers have demonstrated that this critical potential is the repassivation potential for localized corrosion of the material of interest. Corrosion resistant alloys (CRAs) have been widely used in the oil and gas production environments where low alloy steels typically have lower chance to withstand the corrosive conditions. It is highly likely that SCC of CRAs only occurs above the repassivation potential of the material in H2S containing environment. This paper summarizes the work conducted to determine the repassivation potential of 2507 super duplex supermartensitic stainless steel (UNS S32750). It was demonstrated that the model predicted repassivation potential data agree well with the experimental values. Crack growth rate (CGR) tests were performed and showed the correlation of SCC occurrence at potential above the repassivation potential.
The oil and gas industry is moving into deeper water and deeper reservoirs for drilling and production as a result of dwindling production from easily accessible shallow reservoirs. The new discoveries since mid-80’s and early 90’s in the coast of Brazil, the Gulf of Mexico, West Africa, South China and the North Sea have the water depths greater than 1500 m (4,900 ft).1 Temperature and pressure in these deep reservoirs can dramatically increase with the depth of the well. Pressures and temperatures approaching 160 MPa (23,000 psi) and 300°C, respectively, have been forecasted for depths greater than 10,000 m (32,800 ft). 2-7
The environments in the high pressure and high temperature (HPHT) wells are usually composed of a mixture of H2S and CO2. While a moderately sour gas could have between 20 and 100 ppm of H2S, the CO2 concentration of such system could be as high as 1-3%.8 In addition to H2S, extreme environments usually have concentrations of CO2 (g) greater than 3%.8, 9 Elemental sulfur (S0) could be found if the concentration of H2S is greater than 5-10%.9-12 Finally, traces of Hg and organic acids (mostly acetic acid, HAc) are not uncommon in the gas phase of deep and ultra deep wells.10 The composition of the water will change with the life of the well. Typically, the condensed water in the gas wells contains a very low concentration of chlorides whereas the produced water extracted from the field will have very high concentration of chlorides. The condensed water is generally not buffered (i.e., possibly low pH) while the produced water is often a buffered environment. In the NACE survey,13 a wide spectrum of chloride concentrations in produced waters is reported, ranging from 2,000 to 200,000 ppm.
Vapor Phase Corrosion Inhibitors (VCIs) are used for safe and cost-effective protection of a wide range of metal articles. One large market includes packaging materials for storage and transportation of metal parts. Plastic packaging films can be readily impregnated with VCIs to provide corrosion protection, in addition to the basic physical barrier (against water, dirt, vapors) afforded by the plastic. Generally, VCI containing plastic films are recyclable. Likewise, they can be made from recycled plastics. However, when manufacturing with commercially available recycle streams, use of the recycled plastic is often limited by contamination and extent of polymer degradation.
This paper will discuss the benefits of using in-house recycling lines; including improved environmental profile, better quality, and cost saving. The results are supported by data and experience with in-house recycling lines at two production facilities.
Vapor Phase Corrosion Inhibitors (VCIs) are a well-known and highly versatile range of products for the prevention of corrosion.1 VCIs can be delivered to the target metal in a variety of ways. One common product is plastic packaging. 2 Plastic VCI films are a versatile and highly effective article for protection of items from corrosion. They are generally made from polyethylene, which is readily available, cost effective, and usually recyclable. 3 Production of VCI films usually results in the production of at least some “Scrap” film. This may be film of variable size produced during production start-up, or film that does not meet specifications. Scrap can be disposed as trash, but is preferably recycled. The usual mode of recycling is to reprocess it (melt processing) into pellets which can be re-used in production of new film. 3 It is often referred to as “Repro”. Reprocessing can be done in-house with dedicated machines or the scrap can be sent to external facilities that specialize in recycling. The quality of Repro can vary considerably with the quality/purity of the scrap and the conditions used for reprocessing (particularly temperature and shear). 4 In this paper, we report on studies varying the source and quantity of Repro and the effects on product quality. Results and commercial implications are discussed.
Salgado, Diana (The University of Akron) | Lillard, Scott (The University of Akron) | Stenta, Aaron (The University of Akron) | Clemons, Curtis (The University of Akron) | Kreider, Kevin (The University of Akron) | Golovaty, Dmitry (The University of Akron) | Young, Gerald (The University of Akron)
We present a coordinated experimental and mathematical modeling effort to develop a three-stage model for determining the spatial and temporal potential, current, ionic species, and damage profiles for alloy 625 crevice corrosion applications in seawater solutions. In this effort stage one is defined as oxygen depletion inside the crevice, stage two the development of a critical crevice solution, and stage three long-term aggressive dissolution. In stage one, deoxygenation allows separation of the anodic and cathodic sites. In stage two, the critical crevice solution forms at the crevice tip then diffuses toward the crevice mouth. During this stage only minimal damage occurs. In stage three, once the critical crevice solution reaches a critical distance from the crevice mouth equivalent to IR* rapid propagation begins. We show that with appropriate experimental input data, and knowledge from the solution of the species dependent system, a damage evolution well-mixed model provides comparable results.
Alloy 625 (UNS N06625), is a nickel-chromium-molybdenum alloy containing niobium which is widely used in the aerospace, chemical, petrochemical, marine service and nuclear industries for corrosion and heat resistance applications. The excellent corrosion resistance of this alloy has been attributed to the combined effect of its Cr (20-23 wt %) and Mo (8-10 wt %) content. Its Niobium content (Nb ~4wt%) has also been reported to contribute to corrosion resistance1–8.
Nickel alloy 625 generally has an excellent corrosion resistance when exposed in highly oxidizing and reducing environments due to the formation of a protective passive film/oxide layer on the alloy surface9. The oxide layer is extremely stable and keeps uniform corrosion rates sufficiently low. However, nickel alloys, such as alloy 625, have been found to be susceptible to crevice corrosion when exposed to natural and chlorinated seawater6,10,11. This type of damage occurs when narrow gaps develop resulting in a localized solution chemistry that leads to the breakdown of the passive film and the onset of rapid dissolution within the crevice. Metal surfaces shielded by gaskets, washers, bolt heads, lap joints, O-rings, or natural deposits are typical places for this type of corrosion to occur. To describe the mechanism of crevice corrosion several models have been proposed. The Oldfield and Sutton12 model explains the crevice corrosion process conceptually and mathematically. The model describes four fundamental steps leading to crevice corrosion. Initially there is deoxygenation within the crevice, increasing pH and Cl- of the crevice solution, crevice corrosion initiation due to breakdown of the passive film, and finally propagation of attack. Oldfield and Sutton define a CCS as a solution of pH and Cl- concentration sufficient to produce an anodic current of at least 10 µA/cm2. They determined that for alloy 625 the critical crevice solution required a pH in a range of -0.25 to 0.50 and 6M Cl- 13.
Degradation of buried metallic piping from corrosion is a significant issue facing owners and operators of nuclear power plants. This paper discusses the results of a major cathodic protection (CP) system upgrade project for buried piping and underground storage tanks at a nuclear power plant in South Carolina. To provide for effective CP, the design engineer needed to take into account the requirement for higher current demand, the location of electrical grounding, reinforced concrete foundations, bare or poorly coated structures, uniform current distribution, depth to bedrock, anode bed configuration, structure connections, test station type and location, system balancing, close interval survey results, rectifier design, operation and maintenance. The database for the system is incorporated into a mapping visualization program, so the system engineer can effectively monitor and trend the CP system performance. Criteria for effective CP in grounded mixed-metal piping systems are also discussed.
The Catawba Nuclear Station (CNS) is a Pressurized Water Reactor (PWR) generating station having a total capacity of 2,258 megawatts. CNS is located on a 391 acre peninsula reaching into Lake Wylie, near the town of York, South Carolina. Unit 1 began commercial operation in 1985, followed by Unit 2 in 1986. The U.S. Nuclear Regulatory Commission (NRC) issued a renewed license to Duke Energy for Units 1 and 2 in 2003, which expires in 2043. Therefore the plant has been in operation for over 30 years, and the design life of any supplemental CP should be for at least 28 years.
The original CP system that was installed at CNS during plant construction consisted of ten (10) rectifiers, 43 semi deep anode beds, 22 distributed anodes and several test stations with permanent reference electrodes. The original anode wells consisted of three (3) 3 in (7.6 cm) dia. × 60 in (1.5 m) long graphite anodes spaced vertically in coke breeze backfill and encased in an 8 in (20.3 cm) dia. schedule 80 steel pipe. A review of historical records indicated that with the exception of the underground storage tanks and piping for the diesel generator (FD) system, the CP systems at Catawba have experienced various levels of intermittent operation since 1985. Shortly after commissioning, the entire system (excluding the FD system) was reportedly shut down for a period of approximately five (5) years. This was apparently due to low potentials and reported stray current interference problems. In 1993 rectifiers 8 and 9 (transformer yard and switchyard) were abandoned in place due to ineffective operation. Numerous other maintenance problems, including anode well depletion, rectifier problems and cable breaks, have also been reported since initial inception.
Song, Fengmei (Shell Global Solutions (US), Inc.) | Huizinga, Sytze (Shell Global Solutions (US), Inc.) | Skogsberg, Lillian (Shell Global Solutions (US), Inc.) | Stockman, Jeff (Shell Global Solutions (US), Inc.) | Wilms, Marc (Shell Global Solutions (US), Inc.) | Smit, Johan (Shell Global Solutions (US), Inc.) | Caldwell, Eric (Shell Global Solutions (US), Inc.)
A fitness for purpose stress corrosion cracking (SCC) assessment was performed to evaluate the suitability of a 13Cr-5Ni-2Mo 110 ksi (758 MPa) grade martensitic stainless steel as a potential well tubing material for oil and gas production from deep water reservoirs. Conditions were chosen to reflect those expected in producer wells, including the possible presence of H2S as a result of reservoir souring due to seawater flooding. A detailed analysis of existing martensitic stainless steel test data for sulphide stress corrosion (SSC) and SCC revealed the need for a qualification test program to fully cover the conditions identified.
Both static Creviced C-ring and dynamic Cyclic Slow Strain Rate (CSSR) tests for assessing SCC resistance were undertaken in concentrated brine at 200°F (93°C). The test program and the results obtained are detailed and compared against existing data, thereby further defining the safe operating envelop for SCC and SSC of 13Cr-5Ni-2Mo 110 ksi grade martensitic stainless steels in environments that are outside of current experience.
For standardization of production tubing materials used for two reservoirs in a deep water field: Reservoir A and Reservoir B, two materials were identified as candidates for use: 13Cr-5Ni-2Mo 110 ksi (Super 13Cr-110) martensitic stainless steel and 22Cr duplex stainless steel (UNS(1) S32205). Assessment with existing laboratory test data and field experience suggests the 22Cr duplex stainless steel is qualified for use for the given well conditions. However, it is twice as expensive and requires much longer lead time to order than Super 13Cr-110. Therefore, if safety and/or integrity cannot be compromised, Super 13Cr-110 is the preferred choice.
In evaluating Super 13Cr-110, two environments must be considered to properly address environmentally assisted cracking (EAC). A condensed water environment at wellhead during well shut-in is used to evaluate SSC at low temperatures. A production environment at the bottom-hole for a particular reservoir was used to evaluate SCC at elevated temperatures. Design conditions for each of the two reservoirs are presented in Table 1, and the main parameters of consideration are temperature, pressure, H2S, and CO2 contents in gas phase and chloride content and pH in the water. Localized pitting is also evaluated as this is associated with the onset of cracking.
Corrosion tests were carried out to determine the effect of iron content on localised corrosion and stress corrosion cracking (SCC) resistance of Ni-Cr-Mo alloy weld overlays (i.e. Alloy 625) in H2S environments. In addition, the influence of iron content on the fatigue crack growth rate (FCGR) of the weld overlay in both air and a sour environment was investigated. Weld overlays with a range of iron contents (5–36%), were examined. These weld overlays were manufactured using gas metal arc/metal inert gas (GMA/MIG) welding and gas tungsten arc/tungsten inert gas (GTA/TIG) welding techniques and the required iron level in the weld overlay was achieved by changing the welding parameters. SCC tests were conducted in 25%w/v sodium chloride (NaCl) solution containing H2 S and CO2 (pH2 S=14 bara, pCO2 =28 bara) at 177°C. FCGR tests were conducted in air and in 25%w/v NaCl solution saturated with an H2 S/CO2 gas mixture (pH2 S=0.4 bara) at ambient temperature and pressure.
Corrosion-resistant weld overlays are often used to improve the service life of components made with an otherwise corrosion-prone material, such as carbon or low alloy steel. Ni-Cr-Mo welding consumables, such as Alloy 625 (ERNiCrMo-3), are commonly used for applications in seawater and sour environments. It has been known that the corrosion resistance of the weld overlay can be influenced by elemental segregation during solidification and by dilution from the carbon/low alloy steel substrate. The influence of the welding processes (e.g. MIG, TIG) on dilution has been studied by Gittos and Gooch. 1-2 However, there is lack of data to demonstrate the effect of dilution level in the overlay on localised corrosion resistance (Kumar and Lee, 3 Chubb and Billingham4) and corrosion fatigue performance. To ensure the enhanced corrosion resistance offered by the corrosion-resistant overlay, current conservative approaches include the restriction of iron level in the overlay (e.g. 5-10%) and the number of the weld layers (e.g. 2-3 layers to achieve a thickness ≥3 mm). For example, DNV(1) -OS-F101:20075 defines a limit for the iron content of overlays of less than 10%.
A cyclic-temperature environment is recognized as a severe condition for coatings. In oil and gas plant facilities a dehydrator is a typical kind of equipment operating in the most severe cyclic-temperature environment ranging from ambient to 300 deg-C. For a dehydrator, three coatings (i.e., “a heat resistant silicone liquid coating”, “an inorganic copolymer or coatings with an inert multipolymeric matrix liquid coating” or “a thermal sprayed aluminum coating”) are typically applied.
However, no experimental data comparing the performance of these coatings, i.e., heat cycle stability and corrosion resistance, under standard test conditions have been reported. Furthermore, no standard test method has been established to evaluate the coating performance in a cyclic-temperature environment ranging from ambient temperature to 300 deg-C.
This paper summarizes an overview of coatings for a cyclic-temperature environment first, and proposes a simple test method which includes a heat cycle between 21 to 300 deg-C simulating the dehydrator operation and exposure to salt spray. The performances of the three coatings were evaluated using this method. Finally, based on the test results and on information from recent process plant construction projects, factors to be considered for coating selection in the cyclic-temperature environment are discussed.
Coatings are one of the most economical methods to prevent the external corrosion of equipment and piping in a harsh environment. Coatings are usually selected based on the operating temperature. However, for a cyclic-temperature environment, which is recognized as making equipment and piping highly susceptible to deterioration and subsequent corrosion, special attention is needed and robust, corrosion resistant coatings should be applied.
In this connection, newly attempted and developed coatings are being used for such cyclic-temperature environments. For example, the use of Thermal Sprayed Aluminum (TSA) coatings has increased greatly over the use of conventional heat resistant silicone liquid coating in recent years, and the developed liquid high temperature coatings are also currently available and are starting to be applied.
However, there have been no reports which compare the performance of such coatings under standard test conditions in a cyclic-temperature environment, and no standard test methods for such conditions have been proposed.
Brasses used in potable water distribution systems had up to 8% lead until January 2014. Thereafter, the 2011 Federal Reduction of Lead in Drinking Water Act came into force to protect the public from lead exposure, requiring new brass alloys that do not exceed a surface-weighted average of 0.25% Pb, and which are termed “nonleaded”. Many nonleaded brass products are now available, but their propensity to fail as a result of erosion corrosion is unknown This study tested the performance of commercially available nonleaded brass elbows (C46500) in a recirculating Cross-linked Polyethylene (also called, PEX) rectangular pipe loop by exposing to hard water with high concentrations of suspended aragonite particulates that form at high temperature and conditions on the surface of heating elements. Fully penetrating leaks occurred in the elbows in an alarming 13.5 days at 13 ft/s (4 m/s) and 50-55°C at pH 7.5, whereas an identical condition without particles remained undamaged. Further investigation showed erosion corrosion can be severely accelerated dependent on pH, flow velocity, particle size, and type of disinfectants present. This is the first study to demonstrate that nonleaded brass fittings (C46500) are especially vulnerable to rapid failures due to erosion corrosion.
Used as an engineering alloy for over a millennium, brasses (typically copper-zinc alloys with other trace metal elements) are widely used for intricate components in drinking water distribution systems. The plumbing devices with critical brass components include pipes, plumbing fittings, valves, heat exchanger tubes, water meters, backflow preventers, bearings, and pump impellers. These copper alloys are preferred for such applications because of their “good strength and ductility …combined with excellent corrosion resistance and superb machinability.”¹ In general, the service life of these components is expected to be at least 20 years, and more commonly 50 to even 100 years performance can be achieved.
The principal corrosion mechanisms for galvanized steel electric power utility transmission and distribution (T&D) structures (poles, lattice towers and anchor rods) are presented in this paper.
Several important factors often associated with corrosion of galvanized utility structures are deficiencies in corrosion control, improper coatings and not considering soil corrosivity conditions. In general, soil corrosivity, cathodic protection/coating, stray current, and copper grounding should be considered in corrosion mitigation and design of T&D structures. These factors are of primary consideration when accelerated corrosion attack occurs. If identified early on, potential failures can often be prevented. This paper includes a discussion on metallurgy of galvanized steel, soil corrosivity, T&D specific structural zones and system wide cathodic protection as a mitigation technique. This paper combines four past publications as well as presents new information and strategies for corrosion prevention for electric power utility T&D structures.
Galvanized steel is one of the most often specified materials for the manufacturing of poles, lattice towers and other transmission and distribution (T&D) assets commonly used in the electric power utility industry. The galvanized poles and towers are often embedded with the depth dependent on soil strength and applied overturning moment. Galvanizing is to meet ASTM (1) specification Al23 requirements for pole and A153 for hardware. Methods to mitigate corrosion, beginning from the manufacturing process and through the various life cycle phases are addressed in the following sections.
Metallurgical Aspects of Galvanized Steel Poles and Towers
Electric power T&D pole and lattice tower steel material typically conforms to the mechanical and chemical properties listed in ASTM specification A572-04. The minimum yield strength of this material is 65,000 PSI. The maximum silicon content of all steels is 0.06 % to ensure an adequate free zinc and uniform galvanized finish. The mechanical strength requirements for structural performance, such as tensile strength, (assuming the inherent material strength remains constant), is then dependent on the material cross-sectional area. If inadequate, tensile failures could occur at locations where corrosion has produced localized reductions in cross-sectional areas and created stress raisers. Higher tensile strength steels have less ductility and toughness, and these steels are considered notch sensitive. Normal constructional steels would not typically be notch sensitive but high strength low alloy (HSLA) steels can be notch sensitive. Corrosion pitting can create the notch which then may become the location of crack initiation. Pitting or reduced areas that are due to corrosion can also initiate mechanical fatigue cracks. As a quality control check to ensure a selected steel material has adequate notch sensitivity and toughness several tests are usually employed with the most common a Charpy V-notch (CVN) Impact Test.
This paper presents an experience in utilizing Thermal Spray Coating Technology on top of weld build-up of CS Pressure Vessel eroded shell. The column is under rich amine service and had severe erosion on some of its internal surface of the shell. Column trays collapse had directed the flow of hot rich amine into the internal service of the shell causing sever erosion. Wall thickness of eroded area decreased below the minimum thickness Tmin. Minimum required wall thickness was restored by weld build-up in accordance with ASME PCC-2 (Repair of Pressure Equipment and Piping). Moreover, PWHT was required by the standard after retention of nominal wall thickness in order to relieve the residual stresses introduced to the melt after weld build-up in order to avoid any Stress Corrosion Cracking. However, heat treatment of this column was infeasible due to stability analysis results that show instability of the column during heat treatment. Moreover, laying down the column to perform PWHT is highly costly and would significantly impact shutdown schedule of the unit. Therefore, thermal spray metal coating has been utilized as a cladding layer on top of weld build-up surface in order to isolate the welded surface from corrosive environment and hence avoid stress corrosion cracking.
On site repair of pressure vessels and columns is challenging specially in corrosive environment. Welding on the vessel shell introduces residual stress that if not being relieved would result in stress corrosion cracking. To relive the residual stresses, heat treatment is required. However, PWHT might not be viable on site due to several reasons including the structural stability of the vessel during heat treatment. New technologies are employed as alternative to PWHT including thermal spray metal coating. Metal or thermal spraying is a technology, which protects and greatly extends the life of a wide variety of equipment in the most hostile environments. Thermal spray coating for corrosion resistance typically includes Ni-based alloys such as Alloy C-276 (UNS-N10276). Thermal spraying involves the projection of small molten particles onto a prepared surface where they adhere and form a continuous coating.