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Production Chemistry, Metallurgy and Biology
ABSTRACT ABSTRACT Extensive testing has been performed at the Lawrence Livermore National Laboratory (LLNL) to determine the corrosion characteristics of nickel (Ni)-based alloys such as Alloy 22 (N06022) and three titanium alloys. The studies focused in three major areas: (a) Immersion tests at the long-term corrosion test facility (LTCTF), (b) the determination of the corrosion potential (Ecorr), and (c) the measurement of the repassivation potential. A review summary of the previously published results from LLNL in the three mentioned areas is presented. Examination of specimens removed from the LTCTF yielded significant information regarding the general, localized and stress corrosion cracking resistance of Alloy 22, four other nickel-based and three titanium alloys. Results from the Ecorr studies were significant but not conclusive. Current Ecorr results mainly opened areas for future research. Repassivation potential studies helped understanding the role of temperature, chloride concentration and inhibitive effect of nitrate but other areas such as fabrication effects still need to be investigated in more detail. A list of suggested future studies in the three areas mentioned above is also offered. INTRODUCTION The Yucca Mountain Project (YMP) is currently preparing a license application for the nation's first repository for spent nuclear fuel and high-level radioactive waste. 1 For more than two decades, the Project conducted an extensive scientific effort to determine whether Yucca Mountain, Nevada is a suitable site for a deep underground facility called a repository. The purpose of a repository is to safely isolate highly radioactive nuclear waste. On July 9, 2002, the U.S. Senate cast the final legislative vote approving the development of a repository at Yucca Mountain. The bill was signed into law by the current President. Existing plans call for submitting an application to obtain a license to construct the repository from the U.S. Nuclear Regulatory Commission no later than June 30, 2008. Yucca Mountain is located on federal land in a remote area of Nye County in southern Nevada, about 100 miles northwest of Las Vegas, Nevada. The proposed Yucca Mountain repository withdrawal area would occupy about 230 square miles (150,000 acres) of federal land that is currently under the control of the U.S. Department of Energy, the U.S. Air Force, and the Bureau of Land Management. Yucca Mountain is a ridge comprised of layers of volcanic rock, called "tuff." This rock is made of ash that was deposited by successive eruptions from nearby volcanoes, between 11 and 14 million years ago. These volcanoes have been extinct for millions of years. Yucca Mountain receives less than 7.5 inches (191 mm) of precipitation on average per year. With its desert climate, deep water table, and thick layers of stable rock, Yucca Mountain provides an excellent geologic setting for a repository. Even though the geologic site is stable, it is planned to complement the many natural features with additional engineered barriers. The repository design includes a series of emplacement tunnels excavated deep underground in solid rock. The layout and attributes of these tunnels are engineered to manage the heat that would be generated by the waste.
- North America > United States > Nevada > Nye County (1.00)
- North America > United States > Nevada > Clark County > Las Vegas (0.24)
- Geology > Mineral > Halide (0.67)
- Geology > Geological Subdiscipline > Volcanology (0.54)
- Water & Waste Management > Solid Waste Management (1.00)
- Materials > Metals & Mining (1.00)
- Government > Regional Government > North America Government > United States Government (1.00)
- Energy > Power Industry > Utilities > Nuclear (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 > Environment (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Materials and corrosion (1.00)
ABSTRACT Resistance to atmospheric stress corrosion cracking (ESCC) and crevice corrosion was examined for various candidate canister materials in the spent fuel dry storage condition using concrete casks. A constant load ESCC test was conducted on the candidate materials in air after deposition of simulated sea salt particles on the specimen gage section. UNS S31260 and S31254, highly corrosion resistant stainless steels (SS), did not fail for more than 46,000 h at 353 K with relative humidity of 35 %, although S30403 SS and S31603 failed around 500 h by ESCC. Crack growth measurement was done to explain this result. Cracking on S31603 propagated around 3x10 m·s at K values larger than 10MPa·m at 353K with RH=35%. S31260 SS showed crack growth rate of 4x10m·s at the same condition. Crevice corrosion potentials of S31260 and S31254 SS became larger than 0.9 V (SCE) in synthetic sea water at temperatures below 298 K, while those of S30403 and S31603 SS were less than 0 V(SCE) at the same temperature range. No rust was found on S31260 and S31254 SS specimens at temperatures below 298 K in the atmospheric corrosion test consistent with the temperature dependency of crevice corrosion potential. From the test result, the critical temperature of atmospheric corrosion was estimated to be 293 K for both S31260 and S31254 SS. INTRODUCTION In the dry storage of spent nuclear fuels using concrete casks, stainless-steel canisters act as an important barrier for encapsulating spent fuels and radioactive materials. According to the spent fuel storage concept, the decay heat of spent nuclear fuels dissipates through the canister wall by air cooling. Hence, the canister wall is in direct contact with air containing sea salt particles and is possibly contaminated by chlorides, because the interim storage facilities for spent nuclear fuels will be built in coastal regions in Japan and the expected service life of storage canisters is 40 to 60 years. Stainless steels are widely used as structural materials for chemical and nuclear power plants because of their excellent general corrosion resistance, mechanical properties, and weldability. However, austenitic stainless steels are susceptible to stress corrosion cracking (SCC) in certain environments under tensile stress. SCC induced by sea salt particles and chlorides, for example, has been observed on various structures of chemical plants built in coastal regions [1]. This type of SCC is referred to as external SCC (ESCC) or atmospheric SCC since the cracking starts from the outside of the equipment in air. ESCC manifests itself as intergranular or transgranular cracking depending on the material and environmental conditions. Intergranular SCC is commonly observed in sensitized parts of stainless-steel structures at approximately ambient temperature. On the other hand, transgranular SCC is observed regardless of the material?s condition at relatively high temperatures above 327 K. As one environmental factor, moderate relative humidity (RH) is necessary to moisten the chlorides adhering to stainless-steel surfaces. The relative humidity at which ESCC easily to occur (RHL) is dependent on the type of chlorides. For example, Shoji et al. reported [2] RHL values of 60% for NaCl and 30% for MgCl2.
- Transportation > Passenger (1.00)
- Transportation > Ground > Road (1.00)
- Materials > Metals & Mining (1.00)
- (2 more...)
- 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)
History And Operation Of The Hanford High-Level Waste Storage Tanks
Edgemon, Glenn L. (ARES Corporation ) | Anda, Vanessa S. (ARES Corporation ) | Berman, Herb S. (CH2M HILL Hanford Group, Inc. ) | Johnson, Michael E. (CH2M HILL Hanford Group, Inc. ) | Boomer, Kayle D. (CH2M HILL Hanford Group, Inc. )
ABSTRACT The Hanford Site is a 560 square mile complex established by the U.S. government in 1943 to produce plutonium for nuclear weapons, ultimately bringing an end to World War II. Plutonium production activities continued after the war through 1991, at which point the site's mission changed from plutonium production to environmental cleanup and restoration. Production activities at the site resulted in a broad range of contaminated materials and facilities, including 57 million gallons of high-level (i.e., highly-radioactive) nuclear waste in liquid and solid forms. The high-level waste was stored as it was created, first in single-shell tanks built between 1943 and 1964, then in more-robust double-shell tanks constructed between 1968 and 1986. Due to waste leakage in a small number of single-shell tanks and the potential for additional single-shell tank failures, all single-shell tanks were removed from service by 1980. All pumpable liquid has been transferred to sound double-shell tanks. The double-shell tanks have either exceeded or are expected to exceed their design life, and are managed under a comprehensive integrity management program. Key features of the program include the application and optimization of a waste chemistry specification designed to minimize corrosion in the double-shell tanks, laboratory studies and the installation of double-shell tank corrosion monitoring systems to improve the understanding of waste corrosivity, the development and application of an extensive non-destructive examination program to detect excessive corrosion or other forms of double-shell tank degradation should they occur, and the development and application of a comprehensive structural analysis program. Together, these programs help to ensure the continued availability of the site's double-shell tanks for the balance of the cleanup mission. INTRODUCTION The Hanford Site is a 560 square mile complex located along the Columbia River in southeastern Washington State (Figure 1). The site was established in 1943 by the U.S. government as part of the Manhattan Project to produce the plutonium necessary for the development of nuclear weapons. Plutonium manufactured at the site's first reactor, known as the "B-Reactor," was used to build the first nuclear bomb, tested at the Trinity site near Alamogordo, New Mexico, then "Fat Man," the bomb dropped on Nagasaki, Japan to bring an end to World War II. Following the end of World War II and throughout the Cold War Era, the Hanford Site continued to play a critical role in the nation's defense. Plutonium production for the manufacture of nuclear weapons was the site's principal goal. Between 1944 and 1987, the site constructed and operated eight additional graphite-moderated, light-water, production reactors to irradiate fuel and produce plutonium (Figures 2-10), six large chemical separations plants to extract plutonium from the fuel, and a variety of laboratories, support facilities, and related infrastructure to support production. Tables 1 and 2 summarize the operational dates of the Hanford reactors and chemical separations facilities. TABLE 1 - HANFORD PRODUCTION REACTORS (available in full paper) TABLE 2 - HANFORD CHEMICAL SEPARATIONS FACILITIES (available in full paper) In 1987, N-Reactor, the final reactor still engaged in the production of plutonium, was shut down. Plutonium extraction operations were halted in 1988.
- North America > United States > Washington (0.48)
- North America > United States > Texas (0.46)
- North America > United States > New Mexico > Otero County > Alamogordo (0.24)
- Asia > Japan > Kyūshū & Okinawa > Nagasaki Prefecture > Nagasaki (0.24)
- Government > Regional Government > North America Government > United States Government (1.00)
- Government > Military (1.00)
- Energy > Oil & Gas > Upstream (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 > Environment > Waste management (1.00)
- (3 more...)
Corrosion Issues Related To Disposal Of High-Level Nuclear Waste In The Yucca Mountain Repository
Duquette, David J. (United States Nuclear Waste Technical Review Board) | Latanision, Ronald M. (United States Nuclear Waste Technical Review Board) | Di Bella, Carlos A.W. (United States Nuclear Waste Technical Review Board) | Kirstein, Bruce E. (United States Nuclear Waste Technical Review Board)
ABSTRACT The policy of the United States is to dispose of high-level nuclear waste underground in geologic repositories. The U.S. Department of Energy (DOE) has been developing plans for a repository to be located at Yucca Mountain, Nevada, and intends to submit a license application to the U. S. Nuclear Regulatory Commission (NRC) for that repository in June 2008. This paper discusses DOE's bases for and approach to modeling the localized and general corrosion aspects of the Alloy 22 outer shell of the container that DOE plans to use for encapsulating the waste in the repository. The modeling is necessary to predict the corrosion behavior for the container's extraordinarily long "service period" - more than a million years. INTRODUCTION The Nuclear Waste Policy Amendments Act of 1987, passed by Congress and signed by the President in late December of that year, established the U.S. Nuclear Waste Technical Review Board (Board) as an independent agency within the Executive Branch. The duties of the Board are to evaluate the technical and scientific validity of activities undertaken by the Secretary of Energy for managing and disposing of high-level nuclear waste. The Board consists of 11 members nominated by the National Academy of Sciences and appointed by the President to 4-year terms. Board members, all of whom serve part-time, are chosen from a broad range of scientific and engineering disciplines, including geologists, hydrogeologists, risk analysts, transportation specialists, microbiologists, and other relevant disciplines. The Board membership always has included one or two corrosion experts. The Board is supported by a small permanent staff at the Board office in Arlington, Virginia. The role of the Board is not to drive the scientific or technical aspects of the Yucca Mountain Project, or to advise formally on what scientific or engineering data need to be generated to make disposal of high-level nuclear waste acceptable. However, the make-up of the Board and the format the Board uses when meeting with representatives of DOE and other entities, including NRC, the technical community, the State of Nevada, and the public, allow individual members, or small groups of members, to offer helpful technical advice to DOE. The Board provides data and information that will be helpful to the Secretary of Energy and Congress in their making fully informed decisions on the program for managing and disposing of high-level nuclear waste. WASTE FORMS AND REPOSITORY CHARACTERISTICS Most high-level nuclear waste consists of spent fuel from domestic nuclear electric power plants, but it also includes spent fuel from research and defense applications and high-level nuclear waste from reprocessing for both defense and commercial reasons. The waste is radioactive and emits both radioactivity and heat as it decays. DOE is responsible for developing a repository for the permanent underground disposal of high-level nuclear waste at a site in Nevada at Yucca Mountain, adjacent to the Nevada Test Site and about 75 miles northwest of Las Vegas. DOE is preparing an application for a license to construct the repository for submittal to the NRC.
- North America > United States > Nevada > Nye County (1.00)
- North America > United States > Virginia > Arlington County > Arlington (0.34)
- North America > United States > Nevada > Clark County > Las Vegas (0.25)
- Geology > Mineral > Halide (0.46)
- Geology > Geological Subdiscipline > Environmental Geology > Hydrogeology (0.34)
- Water & Waste Management > Solid Waste Management (1.00)
- Government > Regional Government > North America Government > United States Government (1.00)
- Energy > Power Industry > Utilities > Nuclear (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 > Environment (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Materials and corrosion (1.00)
ABSTRACT A common method of corrosion control of buried pipeline is that of cathodic protection involving the use of sacrificial anodes. To ensure maximum effectiveness of an anode, a suitable backfill material of Gypsum/Bentonite is required to maintain the necessary current flow. This material is generally inert and moisture retentive. In the River Project of Libya,the bentonite used was collected from two different clay member formations.The destructive inspection of zinc anodes revealed that the backfill material used from one formation (No. 1) has dried quickly and shrunk away from the anode and the other backfill used from formation No. 2 was still moisture retentive and working properly. Therefore a laboratory tests were carried out to determine the causes of the shrinkage of formation 1 and also to identify the characteristics of Bentonite used and its suitability for use in the backfill, and how to delay the moisture content loss with minimum shrinkage. This study has included chemical, physical, mineralogical and geotechnical laboratory tests. The tests revealed that the Bentonite which was in use (formation No.1) was in commercial terms relatively low grade (c. 46% Montmorillonite ) with liquid limit values of c. 120%, and the gypsum was relatively pure, being composed of >95% gypsum, and the backfill mixture contained c. 11% Montmorillonite. Engineering testing suggests that if the ground conditions cause the backfill to dry, shrinkage may lead to a loss of anode function. Such shrinkage would be reduced if the backfill was emplaced at lower moisture content and higher density, this is also likely to increase its ability to absorb water. However, if the backfill does dry out, the anode may also not function correctly. Also this test revealed that the Bentonite should be calcium based not sodium based. INTRODUCTION Galvanic sacrificial zinc anodes are used to protect the steel in the Great Manmade River Project pipeline that carries water from a sandstone aquifer in the Libyan interior to the coastal area. The pipeline has an internal diameter of 4 m and external diameter of 4.5 m. The zinc anodes are placed in 9 m deep holes and backfilled with a standard backfill mixture of 75% gypsum, 25% Bentonite and emplaced at a Bentonite mix to water ratio of 1.75:1.0, which provides a bulk density of 1.48 to 1.60 Mg/m3. The zinc is wired into the steel of the pipe. The anodes are placed every 10 m over the 5000 km length of the pipeline. The Bentonite is mixed with the gypsum at the required ratios and then prepared as a dry powder. The moisture content of the Bentonite used in the mix varies. For this reason it is likely that the Bentonite solid is present at least than 25% of the mix. In the places where the calcium bentonite of formation No.2 (in accordance to specification of Appendix 1) is used, GMRA has not experienced any problem, but in the place where the bentonite of formation NO.1 is used, it has experienced problems. This problem was most notable in the desert, where the Bentonite backfill has shrunk away from the zinc anodes reducing the efficiency of the anode and potentially compromising the steel in the pipeline.
- North America > United States (1.00)
- Africa > Middle East > Libya (0.34)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.68)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (0.57)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (0.54)
ABSTRACT ABSTRACT Pipelines that operate at high temperatures require new coating materials for protection. Development of those coating materials requires new chemistry. It also requires the development of new test methods. This paper reviews coating requirements and existing test procedures applicable to high temperature coatings. It proposes new test methods for better evaluation of the new coatings. It also provides test data and results from example candidate coatings for high operating temperature pipelines. Key Words: fusion-bonded epoxy, FBE, pipecoating, semi-interpenetrating network, semi-ipn, high temperature, glass transition, cathodic disbondment, adhesives. INTRODUCTION Single layer fusion-bonded epoxy (FBE) Dual layer FBE 3-layer polypropylene (PP) 3-layer PP insulation systems Multi-layer insulated systems Many pipelines operate at temperatures far above ambient. There are several reasons that include high-temperature materials coming out of the ground and materials that must maintain a high temperature. Examples include tar-sand hydrocarbons and gas with hydrates. Depending on the circumstances and environment, the pipeline coating may be:In the case of FBE systems without a polyolefin overcoat, the corrosion coating must have a glass transition temperature, Tg, above the operating temperature of the pipeline to prevent damage from pipe movement. In the case of systems with a thick polymer overcoat, the FBE is protected from damage and may be serviceable on pipelines operating above the Tg of the corrosion coating. The insulated system may be foamed or syntactic polyurethane over an FBE corrosion coating and not necessarily bonded to it. Other systems include multilayered coatings with either foamed or syntactic PP insulation layers incorporated as part of the coating system. Whatever type of material selected, it must not only meet "normal" pipecoating requirements, but it must also provide long term performance at temperature not seen historically by underground and underwater pipeline coatings. There are many potential technologies that may address these requirements. This paper will review new FBE and PP adhesive (part of a three-layer PP system) coating technology designed for high temperature pipelines. Potential high-temperature technologies. Due to the severity of new anticorrosion coating service temperatures, new materials must be developed to survive these more difficult environments. Common fusion bonded epoxies, customarily utilized for oil and gas pipeline protection, encounter problems because of their relatively low glass transition temperatures, which lead to issues of maintaining adhesion to steel substrates. Multifunctional epoxy resins have commonly been used to produce highly crosslinked coatings with high glass transition temperatures. FBE coatings formulated with these resins exhibit poor flexibility, poor impact resistance, and reduced adhesion to steel. However recent advances in epoxy technology have made the formulation of FBE coatings with high glass transition temperatures, good adhesion, and good mechanical properties possible. In addition to epoxy resins, other materials may be suitable for use in high temperature pipecoating applications. One approach to making high glass transition temperature thermosetting materials has been the use of acrylonitrile-butadiene rubber toughened vinyl ester resins. Vinyl ester precursors ranging in number average molecular weight from 3600 to 3800 have been made into toughened coatings having glass transition temperatures a few degrees above 140°C.
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Midstream (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)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Piping design and simulation (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Materials and corrosion (1.00)
ABSTRACT The continued development of the oil sands in northern Alberta Canada has led to increased use of thermal recovery methods such as Steam Assisted Gravity Drainage (SAG-D) for extraction of the bitumen from deep reserves. The transportation of this heated bitumen to the processing facilities generally requires the use of insulated pipes capable of withstanding internal service temperatures as high as 150°C. Based on existing Canadian regulations, it has been necessary to use anticorrosion coatings under the thermal insulation on buried pipelines intended for petrochemical service. Traditionally, anticorrosion coatings such as cold applied tapes, 2 or 3 layer polyethylene systems, and also epoxy coatings have been available for insulated pipelines operating at temperatures of up to 110°C. The introduction of new heat resistant insulating foams capable of withstanding much higher operating temperatures of at least 150°C has led to the need to also identify compatible anticorrosion coatings. One such material that has been successfully qualified for use with high temperature insulation systems is an epoxy-based coating. In order to evaluate this coating, a variety of methods were used which included; elevated temperature cathodic disbondment testing, thermal gravimetric analysis (TGA), dynamic mechanical analysis (DMA), accelerated heat ageing, and also standard coatings tests specified by the Canadian standard CSA Z245.20. The results of this investigation support the recommendation that the selected coating can withstand operating temperatures of at least 150°C for the expected 30-year life in a typical insulated pipeline. INTRODUCTION Ongoing development of the oil sands in northern Alberta Canada has led to increased use of thermal recovery methods such as Steam Assisted Gravity Drainage (SAG-D) for extraction of the bitumen from deep reserves. This heavy crude oil has a high viscosity at standard temperatures and requires considerable heat to allow it to flow. Thus, the transportation of the bitumen to the processing facilities often requires the use of buried insulated pipes capable of withstanding internal service temperatures as high as 150°C. In order to reduce the likelihood of corrosion and potential rupture of the pipeline, it is typically necessary to apply anticorrosion coatings to the external surface of the steel carrier pipe for use underneath the thermal insulation. Traditionally, anticorrosion coatings such as cold applied tapes, 2 or 3 layer polyethylene systems, and also epoxy coatings have been used for this purpose on insulated pipelines operating at conventional temperatures of typically less than 110°C. The recent development of heat resistant insulating polyurethane foams capable of withstanding higher temperatures of at least 150°C has created the need for qualifying compatible anticorrosion coatings that can also remain stable for the expected service life of the pipeline that is typically specified as up to 30 years. This paper discusses the various methodologies that were used to evaluate and qualify one such coating for the use in the new insulation systems. COMPONENTS OF THE INSULATION COATING SYSTEM The coating materials typically used on insulated pipes for buried service include the following (see Figure 1): Anticorrosion coating. Polyurethane foam thermal insulation layer, and Polyethylene protective topcoat / outer jacket layer.
- Research Report (0.34)
- Overview (0.34)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Well Completion > Well Integrity > Subsurface corrosion (tubing, casing, completion equipment, conductor) (1.00)
- Reservoir Description and Dynamics (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)
Comparison Of Polysiloxane Two-Coat Systems Vs. A Traditional Three Coat System As External Paint Systems Over Steel For Canadian Applications
Al-Borno, Amal (Charter Coating Service (2000) Ltd ) | Brown, Mick (Charter Coating Service (2000) Ltd ) | Worthingham, Robert (TransCanada Pipelines Ltd ) | Cetiner, Matt (TransCanada Pipelines Ltd )
INTRODUCTION ABSTRACT A laboratory study was conducted to examine the potential impact of replacing a three-coat paint system with proposed polysiloxane two-coat alternatives. All three systems use a zinc-rich epoxy primer. The three-coat system has an intermediate epoxy coat and an aliphatic polyurethane topcoat. The two-coat systems use polysiloxane chemistry based topcoats that are applied directly to the primer in one coat. One of the two-coat systems was from the same manufacturer as the three-coat system. All three coatings were applied by the same applicator under controlled and supervised conditions. Tests examined physical properties, adhesion and weathering characteristics. Although there were some minor differences in the performance of the coating systems, the study indicates that replacement of the currently used three-coat system with the tested two-coat systems would not result in significant reduction in coating performance or expected service life. Tests examining extra demands made on coatings exposed to the cold environments of Canada showed a noticeable but similar reduction in the flexibility and impact resistance characteristics of all the coatings when tested at -30°C versus at room temperature and 0°C. The paint used on above ground structures by TransCanada is currently a three-coat system. A laboratory study was conducted to examine the potential impact of replacing this three-coat paint system with proposed polysiloxane two-coat alternatives. All three systems use a zinc rich epoxy primer. The three-coat system has an intermediate epoxy coat and an aliphatic polyurethane topcoat. The two-coat systems use polysiloxane chemistry based topcoats that are applied directly to the primer in one coat. One of the two-coat systems was from the same manufacturer as the three-coat system. All three coatings were applied by the same applicator under controlled and supervised conditions. Tests examined physical properties, adhesion and weathering characteristics. This paper discusses the findings of this study. Paint Systems Good adherence to the steel substrate. In order to provide an attractive and protective coating on a steel surface, a paint system must have the following properties:
- Well Completion > Well Integrity > Subsurface corrosion (tubing, casing, completion equipment, conductor) (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Downhole chemical treatments and fluid compatibility (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)
Corrosion And Mechanical Properties Of Diamond-Like Carbon Films Deposited Inside Carbon
Boardman, B. (Sub-One Technology ) | Boinapally, K. (Sub-One Technology ) | Casserly, T. (Sub-One Technology ) | Gupta, M. (Sub-One Technology ) | Dornfest, C. (Sub-One Technology ) | Cao, Y. (Sub-One Technology ) | Oppus, M. (Sub-One Technology )
ABSTRACT A new enabling technology for coating the internal surfaces of pipes with a hard, corrosion and wear resistant diamond-like-carbon (DLC) coating is described. The improvement in corrosion and wear resistance is shown based on changes in film chemistry, structure and thickness. Corrosion resistance is measured based on exposure to HCl, NaCl and H2S environments. Mechanical properties include high hardness, high adhesion, and good wear resistance in dry and wet sand slurry environments. It is suggested that this new technology enables wide spread use of DLC based coating to increase component life in applications where internal surface of pipes are exposed to corrosive and abrasive environment especially in the oil and gas industry. INTRODUCTION Diamond-like carbon (DLC) coatings have excellent properties such as high wear resistance, very low friction coefficient and high corrosion resistance. Because of these excellent properties, DLC coatings have attracted great attention for use in various applications in industries such as oil and gas, semiconductor, medical and automotive. In the oil and gas industry, DLC coatings are especially expected to improve tribological and corrosion performance of components that experience extreme environments provided the coating can be applied to internal surfaces of pipes, pipe joints, drilling fixtures, and drilling bores, etc. For piping or tubing that delivers corrosive material, obviously the interior surface that is in contact with the corrosive material is the surface that must be coated. There are several methods available to deposit DLC or other coatings at the outer surface of components; such as chemical vapor deposition (CVD), physical vapor deposition (PVD), electroplating, flame spray and sol-gel. However, coating internal surfaces remains a challenge especially for large aspect ratio (length to diameter ratio) components and very limited information is available in the literature. In the case of very low-pressure techniques such as PVD, where the pressure is below or near the molecular flow region, coating internal surfaces has been limited to tubing with large diameters and short lengths, due to line of sight deposition. CVD techniques are limited in this application as well, due to the need to supply heat for the chemical reaction, which damages heat sensitive substrates. PECVD (plasma enhanced chemical vapor deposition) can be used to lower the temperature required for reaction, but then there is difficulty in maintaining a uniform plasma inside the pipe and preventing depletion of the source gas as it flows through a pipe placed inside a vacuum chamber. This article reports result of a study demonstrating the potential of a new PECVD technology to deposit DLC based films on internal surfaces of pipes with excellent corrosion and wear resistance characteristics. The results are obtained on rough ( Ra ~ 100 ? 200µin ) carbon steel substrates through the use of a multi-layer coating that provides strong adhesion to the substrate and reduced stress, as demonstrated for the former by the lack of corrosive undercutting between the substrate and the coating and for the later by the ability to deposit thick coatings. The surface roughness is controlled through blasting of the pipe interior, to bring the roughness into the desired range.
- Overview (0.54)
- Research Report (0.34)
- Energy > Oil & Gas (1.00)
- Materials > Metals & Mining > Steel (0.36)
ABSTRACT Fluoropolymers are well known for their non-stick properties. They also possess outstanding chemical resistance even at high temperatures. Coatings made from fluoropolymers also possess these properties. The oil and gas industry has believed that fluoropolymer coatings do not work in production tubing because they do not adhere sufficiently. In this paper, we report on a series of new fluoropolymer coatings which have been designed to provide excellent adhesion, even under harsh conditions. A testing protocol has been developed to compare coating performance in high temperature, high pressure, in sweet, sour or hydrochloric acid environments. This protocol and results are reviewed. It is shown that twenty four hour autoclave testing with rapid decompression can differentiate coating formulations. It is also shown that fluoropolymer based coatings offer promise for use in severe downhole environments. Additional long term or downhole testing is still required. INTRODUCTION Production crude oil and gas tubing is often subjected to severely corrosion environments. The carbon steel most production tubing is made from may require periodic replacement. Often, corrosion resistant alloys (CRAs) are used in place of carbon steel to increase the service life of the tubing string. CRAs are significantly more expensive that carbon steel. One approach to extend the lifetime of carbon steel tubing is to apply aprotective coating to protect the surface from the corrosive environments. Coatings based on epoxy and phenolic resins have been used for corrosion protection for many years in both production tubing and drill pipe. However, where the production fluids and gases contain higher amounts of hydrogen sulfide (H2S), these coatings may not provide adequate protection against corrosion. More corrosion resistant coating systems are needed. Fluoropolymers are resistant to a broad range of chemicals even at high temperature1. This includes corrosive materials often contained in production streams including H2S, carbon dioxide (CO2), produced salt water, hydrochloric acid, and elemental sulfur. When fluoropolymers are used to make coatings, those coatings are often called fluorocoatings. Fluorocoatings have been tried on production tubing in the past. Until recently it was generally believed that fluorocoatings do not work. They are also often called "Teflon®", but Teflon® is a DuPont trademark. Most coatings tested in the past were not DuPont Teflon® products or they were improperly selected. DuPont has hundreds of different fluorocoatings and new ones can be formulated and optimized for specific conditions and performance needs. Properties of fluoropolymer lined or fluorocoated tubing include: Low coefficient of friction Very low free surface energy (Yc<= 18 dyne/cm).2 Smooth surface leading to reduced friction factor and hydraulic improvements Flexibility (fluoropolymers typically have elongation to break of 25-300%). The high flexibility significantly reduces concerns about cracking of the coating as the pipe is handled during shipping, storage and installation and due to stresses caused by thermal expansion and contraction. Resistance to chemical attack These properties are maintained at high operating pressure and high temperatures (up to 260 °C). FORMULATION OF COATING SYSTEMS All the coating systems discussed in this paper include three distinct layers differing in composition. Multiple coating layers have several advantages.
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.90)
- 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)