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ABSTRACT Samples of carbon steel tubes were removed from the radiant section of a fired heater after 40 years operation at 950oF to 1000oF (510oC to 538oC) tube metal temperature. The tubes exhibited significant microstructural degradation in the form of advanced pearlite decomposition and graphitization (graphite nodules). However, no evidence of linking of graphite nodules was observed. This paper highlights the results of an API 579 Fitness for Service analysis using the MPC Omega creep methodology to help show that the tubes have significant remaining creep strength and are suitable for continued service, contrary to the results of an API 530 analysis1,2. INTRODUCTION The Hydrodesulfurizer (HDS) rerun column feed heater described in this paper was originally installed in the 1950?s and is configured with vertical carbon steel tubes of diameter NPS 6 in the radiant section (Figure 1). In June 2003, the heater was opened for inspection during a planned turnaround. The four outlet tubes (#11, #22, #33, #44) were found to be severely bowed and oxidized and were upgraded to 1.25Cr material. The remaining carbon steel tubes showed minor scaling due to oxidation, and no significant loss in thickness was measured. Tube strap measurements showed 1 to 2% diametrical growth in the remainder of the furnace tubes. Although no significant signs of visible damage were evident on the remaining tubes, the refinery was concerned with continued operation of the heater considering the long term history of operation heater at elevated temperature, well beyond the original 100,000-hr design life. An important consideration is that carbon steel is susceptible to a form of damage known as graphitization in which the microstructure of the steel forms graphite nodules (described in more detail below) after extended operation of carbon steel above 800oF (427oC). This form of microstructural degradation also reduces creep life.
- Materials > Metals & Mining > Steel (1.00)
- Energy > Oil & Gas > Downstream (1.00)
ABSTRACT Several independent cases are described to illustrate the approach used for the analysis and evaluation of aging equipment for continued service, in the petroleum refining and chemical process industry. In all cases described, the results were obtained by testing and metallurgically evaluating small samples extracted from the equipment. Charpy impact testing was performed to determine impact test properties as a function of temperature, in one case to verify compliance with requirements and in the other case, as part of a temper embrittlement assessment. Fracture toughness Crack-Tip Opening Displacement (CTOD) testing was performed to obtain the fracture toughness required in the assessment. In the remaining cases the small samples were used to obtain tensile testing specimens and to perform direct metallographic evaluation to determine the nature and extent of the degradation that the steel suffered during service. INTRODUCTION Pressure vessels in the oil refining and process industry usually age with time in service. The degradation mechanisms are multiple and depend on the type and quality of material of construction, the operating conditions, the process fluid, operating history, and time in service. The current approach is to perform fitness for service assessment1 assuming worst case or lower bound values. Metallurgical evaluation is performed in some other cases to determine condition and suitability for continued service. In both cases, it would be ideal to have material properties measured in the equipment or component. Traditional methods to extract samples for performing these mechanical testing are cumbersome and often not practical. Usually the equipment needs to be taken out of service, weld repaired and even post weld heat treated (PWHT).
- Materials > Metals & Mining > Steel (1.00)
- Energy > Oil & Gas > Downstream (1.00)
ABSTRACT High-Temperature Hydrogen Attack (HTHA) is a phenomenon that involves the formation and accumulation of methane (CH4) in steels operating under conditions where there is hydrogen ingress. To account for the phenomenon, it is necessary to know how the supply of solute carbon atoms occurs. What is discussed here concerns only low-carbon steel within the range 0.08–0.30 wt % carbon that has no intended additions of alloying element such as chromium (Cr) or molybdenum (Mo), and that it is typically delivered in the as-hot worked or normalized condition, resulting in microstructure consisting of pearlite colonies within a matrix of ferrite grains. Carbon steels do not normally contain carbon atoms in solid solution, but most are tied to cementite (Fe3C), except when retained in supersaturated solid solution by rapidly cooling from just below the subcritical temperature Ac1, 727 °C (1340 °F), in which case, the solute carbon atoms do not remain in supersaturated solution for long, they precipitate, but the resulting precipitates are rather unstable and get quickly thermally activated when heated to temperatures that are considered relatively too low to significantly affect the cementite in existing pearlite colonies. Thus, these precipitates may supply solute carbon atoms for HTHA damage to occur at temperatures that would not otherwise occur if there were only cementite in existing pearlite colonies. INTRODUCTION During HTHA, the accumulation of methane (CH4) at grain boundaries results in high localized stresses, the formation of voids, fissures, cracks, blisters in the steel and eventually to a substantial deterioration of mechanical properties. This could occur in low-carbon steels operating under conditions where hydrogen dissociates into atoms that are first adsorbed on the surface and then absorbed inside the steel to diffuse as solute hydrogen atoms. These hydrogen atoms react not directly with unstable carbides but rather with solute carbon atoms in the steel to form CH4. The industry relies on so called Nelson curves for material selection in high-temperature high-pressure hydrogen service based on the type of steel, hydrogen partial pressure and temperature.
- Materials > Metals & Mining > Steel (1.00)
- Energy > Oil & Gas (1.00)
ABSTRACT This paper describes a new method for the non-destructive detection of graphitization corrosion in gray iron pipe, based on magnetic flux density measurements. Graphitization corrosion is unique to gray cast iron, which comprises much of the municipal water distribution infrastructure in the United States. Graphitic corrosion is particularly insidious in that graphitized pipe may appear perfectly sound upon visual inspection, despite being embrittled and prone to premature failure under load. INTRODUCTION Graphitic corrosion, or graphitization, occurs when the metallic constituents of gray iron are selectively removed or converted into corrosion products. This process leaves behind the graphite matrix of the gray iron, in the shape of the original casting. While pipes undergoing graphitization may appear sound and may conduct water adequately, the metallic portion of the pipe wall may, in places, be significantly thinner than the apparent thickness of the wall. Graphitized regions of pipe wall will be brittle and subject to failure under load as the result of temperature variation, heavy traffic, or shock. Water main failures are very expensive for municipalities. Not only do they incur expenses in terms of repair, flooding damage, and loss of revenue to affected businesses, but water main failures can potentially interrupt the operation of vital services including medical care and fire fighting operations. Currently, millions of dollars are spent annually by industry and municipalities on the repair of failed gray iron pipe. The rate of failure will only increase in the future as the existing gray iron infrastructure continues to age. Therefore, it is important to develop a sensing technique that will allow for the non-destructive detection of graphitization before failures occur. This will enable repair of graphitized pipe to be undertaken before failure, and so minimize the expense incurred due to corrosion in the water distribution infrastructure. BACKGROUND Gray Iron Metallurgy Krause1 has discussed the metallurgy of gray iron in detail. The most important elements in gray cast iron, aside from iron, are carbon and silicon. The silicon content affects the carbon distribution in the metal. Unlike the carbon in ductile iron and steel, which is disbursed as graphite spheroids and pearlite, respectively, the carbon in gray iron is present in flake form. These flakes form in the eutectic cell boundaries during cooling of the cast metal. As a result, the graphite flakes form a continuous matrix throughout the gray iron. Increasing the silicon content decreases the amount of carbon present in the eutectic, causing more carbon to take the form of pearlite and less to be present in the graphite matrix, in flake form. This lowering of the flake graphite content of the iron results in increased tensile strength. Graphitic Corrosion Graphitic corrosion is one example of the dealloying of a metal. During dealloying, one component of an alloy is selectively dissolved, leaving other components behind. In the case of gray iron, the preferential attack on iron results from graphite's highly noble, or corrosion resistant, position in the galvanic activity series. The relative position of two metals in the galvanic activity series determines which will most readily participate in electrochemical reactions, such as corrosion.
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (0.67)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Materials and corrosion (0.67)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (0.55)
- Well Completion > Well Integrity > Subsurface corrosion (tubing, casing, completion equipment, conductor) (0.48)
ABSTRACT The materials selection for FCCU Regenerator and Reactor (or Disengager) cyclones has always been a complex decision, and recent trends have led to even more factors to be considered. Often, the selection is a least evils decision. There are multiple materials degradation mechanisms, which vary depending on the specific unit conditions, and no one material completely resists them all. Operating temperatures have been increasing in recent years, which has added to the materials problems. In addition, other trends, including the use of partial combustion, close-coupling of cyclones, etc., have increased the complexity of the FCC process. This paper discusses the applicable materials degradation mechanisms, highlighting the operating conditions under which they become critical and the susceptible materials. The recommended materials and some comments on life expectancy for common plant conditions are then given. INTRODUCTION Cyclones are used to remove catalyst from the overhead vapor streams of the Fluidized Catalytic Cracking Unit (FCCU) Regenerator and Reactors (also referred to more accurately as Disengagers). Catalyst which remains in the vapor phase product can cause plugging and erosion downstream, and is costly since when catalyst is lost as carryover, additional fresh catalyst needs to be added to the regenerator to maintain the catalyst volume. There are also yield and selectivity benefits from separating the catalyst from the product gas stream as quickly and efficiently as possible. Figure 1 is a sample process flow diagram of this section of the FCC. Most regenerator and reactor vessels have multiple sets of primary and secondary cyclones (Figures 2 and 3). The cyclone directs the vapor flow by tangential entry into a centrifugal pattern, which results in the catalyst particles being forced to the outside wall and then falling back down into the catalyst bed through cyclone sections called the cone, dust bowl, dipleg and flapper or check valve (Figure 4). The vapor exits out the top. Most cyclones are lined with erosion resistant refractory. This paper focuses on the possible degradation mechanisms and optimum selection of the metallic material, and hence, excludes the refractory selection and installation details from the scope. Some units have additional cyclones outside of the vessels, such as Rough Cut Cyclones to remove the bulk of the catalyst from the riser outlet, Second Stage Regenerator cyclones which can be external, or Third Stage Cyclones which are in regenerator flue gas service. These cyclones are not directly addressed by this paper, but most of the information will still be applicable. Internal cyclones in Resid Fluidized Catalytic Cracking Units (RFCCU) are directly included. The process conditions at the cyclones vary, but the highest temperature locations are summarized below:1 Reactor Regenerator Temperature, °C (°F) Typical Unit: Range of Various Units: * Older units can be 4 bar (60 psia). An industry trend has been that the process conditions have been changing with time, so materials that were used successfully in the past, may not be acceptable for newer designs or revamped units. The primary change is that temperatures have been increasing. In addition, other process changes have been: · Partial Combustion (with two stage regenerators) · Riser Cracking · Higher Cat/Oil Ratios · Faster Catalyst Circulation Rates · Short Contact Times · Close Coupling Materials which have been used for the cyclones in the past include: Regenerator Cyclones: CS, 2 ¼ Cr-1 Mo, 5 Cr- ½ Mo, 303, 304, 304H*, 316, 321* Reactor Cyclones: CS*, C- ½ Mo, 1 ¼ Cr- ½ Mo*, 405* The commonly-used materials today are in
- Materials > Chemicals (1.00)
- Energy > Oil & Gas > Downstream (1.00)
- Energy > Power Industry > Utilities > Nuclear (0.34)