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Oil & Gas
ABSTRACT: Replacing air with oxygen in coal-fired boilers (i.e. oxy-firing) combined with flue gas recirculation is a leading strategy to concentrate CO2 in the flue gas and assist in carbon capture for subsequent sequestration. A significant area of concern is the fireside corrosion with oxy-firing due to the higher CO2 levels in the combustion gas and potentially higher SOx and H2O levels. In order to investigate this complicated issue, laboratory experiments are being conducted with and without synthetic ash to assess the potential effect of oxy-firing on fireside corrosion rates. The initial results of this project focus on commercial and model Fe-base alloys at 600°C. Without ash, a 50%H2O-50%(CO2-0.15O2) environment was the most aggressive condition, requiring higher Cr contents than 100% H2O or Ar-50%CO2. With the specimens covered in ash, several gas compositions were examined including different levels of H2O and SO2 to simulate various oxy-firing strategies. Box plots were used to present the data for several laser cladding compositions for protecting tubes. INTRODUCTION Using oxygen rather than air for coal-fired boilers is a leading concept for enabling large-scale carbon capture and storage.1,2 This strategy potentially could be applied to both new and existing boilers. However, there is considerable concern about the effect of oxy-firing on fireside corrosion rates and several studies have already considered the effect of higher CO2, H2O and SO2 levels.1-7 The fireside environment in which the combustion gas and ash chemistry are dependent on the coal composition is a difficult environment to simulate, since it includes oxidizing and reducing “micro-climates”.8 For the most aggressive conditions experienced by the waterwall tubes in current coal-fired boilers, particularly when substoichiometric low NOx conditions are created, coatings (e.g. weld overlays) are used to protect tubes from fireside corrosion.
ABSTRACT: Corrosion fatigue testing of flexible pipe armour wires requires specialist equipment and controls in order to simulate the conditions and service in a flexible pipe annulus. There has been a significant amount of testing, collective studies and analysis performed over many years that have attempted to establish design curves for flexible pipe armours, however there are still areas of disagreement over some aspects of testing. This paper will provide a best practice guide to testing, analyse and compare data from such testing, and discuss those issues in dispute to draw conclusions based on controlled tests. Potential influences on test results include: frequency effects; performance of welds; the effect of iron saturation; the effect of testing with high partial pressures of CO2 in both sweet and sour environments; wire size effects and supplier variation (for the same specification of wire). Example comparisons and conclusions on each of these will be presented. INTRODUCTION Flexible pipes are manufactured with a composite structure of metals and polymers (Figure 1), each layer left unbonded from the other layers to improve the flexibility of the pipe. Each layer in the pipe performs an important function: the pressure armour wires allow the polymer barrier to contain the pressure in the pipe and help withstand the external hydrostatic pressure in deep water by resisting ovalisation of the carcass and ultimately collapse of the pipe; and the tensile armours take tension in the structure and can also contribute to pressure containment. The methods of fatigue testing of the armour wires and the critical factors influencing the results will be reviewed and discussed in this paper. It is not within the scope of this paper to attempt to compare the following aspects of testing – R-ratio effects, mean stress effects, or temperature effects.
- South America > Brazil (0.47)
- Europe > Norway (0.28)
- North America > United States > Texas > Harris County > Houston (0.16)
Prediction of Dissolver Lifetimes Through Non-Destructive Evaluation And Laboratory Testing
Mickalonis, J.I. (Savannah River National Laboratory Materials Science and Technology) | Hinz, W.R. (Savannah River National Laboratory, Materials Science and Technology) | Woodsmall, T.D. (Savannah River Nuclear Solutions) | Edwards, T.B. (Savannah River National Laboratory, Computational and Engineering Sciences)
ABSTRACT: Non-destructive evaluation (NDE) was used as the primary method of monitoring the corrosion degradation of nuclear material dissolvers and assessing their remaining lifetimes. Materials were typically processed in nitric acid based (4-14 M) solutions containing fluoride concentrations less than 0.2 M. The primary corrosion issue for the stainless steel dissolvers is the occurrence of localized corrosion near the tank bottom and the heat affected zones of the welds. Laboratory data for a range of operational conditions, including solution chemistry and temperature, were used to assess the impact of processing changes on the dissolver corrosion rate. Experimental and NDE-based general corrosion rates were found to be in reasonable agreement for standard dissolution chemistries consisting of nitric acid with fluorides and at temperatures less than 95 °C. Greater differences were observed when chloride was present as an impurity and temperatures exceeded 100 °C. INTRODUCTION For over fifty years at the Savannah River Site, processing of nuclear material has taken place in stainless steel vessels, called dissolver vessels, with nitric acid based solutions of variable strength depending on the material being processed. One facility was installed in the early 1980s to support the production of plutonium-238 (Pu-238) as a power source for deep space exploration and to recover legacy nuclear materials stored at the site. The facility adopted a “run to failure” approach to dissolver vessels and successfully processed with manageable failures. In recent years, however, the dissolver vessels started failing at significant rates when processing difficult materials requiring extremely aggressive flow sheets. Failures led to unplanned outages which negatively impacted the production schedule and involved hazardous work to replace the vessels. A three-prong approach was used to understand the failures and to estimate future lifetimes so outages could be planned to support production schedule.
Assessment Of Corrosion In Prestressed Concrete Piles In Marine Environment With Acoustic Emission
Vélez, William (Civil and Environmental Engineering University of South Carolina) | ElBatanouny, Mohamed (Civil and Environmental Engineering University of South Carolina) | Matta, Fabio (Civil and Environmental Engineering University of South Carolina) | Ziehl, Paul H. (Civil and Environmental Engineering University of South Carolina)
ABSTRACT: Corrosion of prestressed concrete (PC) piles in splash zones is one of the main causes of bridge deterioration in marine environments. The monitoring of corrosion and associated cracking in PC piles is facilitated by the service load conditions, where compressive loads from the prestressing forces combined with dead loads are predominant, and flexural cracking becomes less relevant, thereby reducing sources of AE. This paper presents the experimental design for a pilot research investigation aimed at investigating the capabilities of AE to detect, characterize, and locate corrosion of longitudinal reinforcement in PC piles in marine environments. Scaled PC specimens representative of prestressed piles were designed to produce damage mechanisms and AE sources in the laboratory similar to those encountered in actual PC piles in contact with salt water. A chloridepenetration model was used to design the concrete cover to minimize the corrosion initiation. An experimental setup was designed to have the specimens in direct contact with salt water simulating tidal action. The setup includes an AE monitoring system, with benchmark corrosion measurements being provided through standard half-cell potential and linear polarization resistance measurements. INTRODUCTION Corrosion of steel in partially submerged concrete piles is a serious threat to bridge infrastructure. In coastal environments, the problem has been long recognized1 and various cases have been reported. One such case is the Bryant Patton Bridge in St. George Island, FL, which showed severe corrosion damage on several of its piles when it was replaced in 2004.2 More recently, it was reported that significant corrosion damage was present on prestressed concrete (PC) piles in brackish waters off the coast of Georgia in the US.3 The portion of a partially submerged pile between the high-tide level and a few feet above is typically referred to as the “splash zone”.4
- Geology > Sedimentary Geology > Depositional Environment > Marine Environment (0.81)
- Geology > Mineral (0.69)
- Energy > Oil & Gas > Upstream (0.94)
- Government > Regional Government (0.94)
- 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: This paper gives guidelines for the material selection and corrosion control philosophies for topside process (multiphase/crude, gas, and produced water) and utility (raw seawater, de-aerated seawater, chemical injection, etc) piping and equipment. For process piping and equipment, the paper discusses CO2 internal corrosion predictions on carbon steel, as well as pitting and chloride stress cracking of corrosion resistant alloys due to high chloride contents in the produced water. For the utility systems, the paper discusses the corrosivity of the internal fluids and establishes suitable materials. The paper also addresses external corrosion control strategies based on using high durability painting systems supported by adequate surface preparation requirements. INTRODUCTION Due to the large demand for hydrocarbons, operators are now developing deep water, high pressure, high temperature, high CO2, high H2S, and high chloride fields. This trend results in numerous challenges to the capital cost (CAPEX) and operating cost (OPEX) of projects. Due to the complexity of the topsides processes, the piping and equipment selection represents an important part of the overall project costs (CAPEX/OPEX). The material selection can be optimized based on a good understanding of the corrosion mechanisms and the fluid partitioning through the topsides production systems. At reservoir conditions, the crude exists as a single phase. As the reservoir fluid is produced through the wellbore, flowlines, and risers to arrive at the inlet conditions of the facility, associated gas begins to form as a separate phase due to the reduction in pressure relative to reservoir conditions. The CO2 becomes concentrated in the gas phase by the time it reaches the first stage separator of the topsides processing facility. Special coalescence technologies are applied in the final stages to remove additional waters not able to be removed by gravity separation techniques alone.
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Treatment (0.47)
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > Block 33/9 > Statfjord Field > Statfjord Group (0.99)
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > Block 33/9 > Statfjord Field > Cook Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > Block 33/9 > Statfjord Field > Brent Group (0.99)
- (3 more...)
- Well Drilling > Drilling Fluids and Materials (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)
Pilot Scale Application of a Rapid Instantaneous Corrosion Rate Monitoring System
Choudhury, Mahbuboor Rahman (Department of Civil and Environmental Engineering, Carnegie Mellon University) | Hsieh, Ming-Kai (Department of Civil and Environmental Engineering, Carnegie Mellon University) | Dzombak, David A. (Department of Civil and Environmental Engineering, Carnegie Mellon University) | Vidic, Radisav D. (Department of Civil and Environmental Engineering, University of Pittsburgh)
ABSTRACT: The corrosion rate of metal alloys in power plant cooling system is an important operational parameter, used to evaluate the performance of the corrosion inhibitors. Application of an instantaneous corrosion rate monitoring system will facilitate corrosion management of the overall system by improved regulation of corrosion inhibitor dosing. In this study, a rapid instantaneous corrosion rate monitoring system was used to evaluate instantaneous corrosion rates of mild steel, copper and cupronickel alloys immersed in cooling water of a pilot scale cooling tower. The instantaneous corrosion rate monitoring system was developed by combining the gravimetric weight loss method and electrochemical polarization resistance method. Pilot scale application involved measurement of electrochemical polarization resistance using a three-electrode system. Instantaneous corrosion rates were obtained using the electrochemical polarization resistance values and the modified Stern-Geary coefficients of respective metal alloys. The modified Stern-Geary coefficients were previously determined in bench scale laboratory experiments for each of the metal alloys of interest. The system, tested in the pilot scale cooling towers, gave instantaneous corrosion rates for different metal alloys. It successfully indicated the difference in corrosiveness of different cooling waters, which was also revealed from the average corrosion rate data obtained by gravimetric weight loss method. INTRODUCTION Metal and metal alloys used in the heat exchanger and piping of a thermoelectric power plant recirculating cooling system are subjected to corrosion due to varying makeup water quality. Corrosion inhibitors are used in such recirculating cooling systems in order to manage the corrosion of different metal and metal alloys.1 Corrosion rate monitoring techniques include the gravimetric weight loss method (WLM), the electrical resistance method, the electrochemical Tafel extrapolation method, and the electrochemical polarization resistance method (PRM). These techniques are used to assess the corrosion rate, qualitatively or quantitatively, of different metal alloys exposed to a solution.
- North America > United States > Pennsylvania (0.29)
- North America > United States > Texas (0.18)
- Water & Waste Management > Water Management (1.00)
- Materials > Metals & Mining (1.00)
- Energy > Oil & Gas > Upstream (1.00)
ABSTRACT: A method has been developed for creating diamond-like carbon (DLC) coatings on the interior surfaces of pipes. Newer formulations of DLC coatings have shown resistance to chemical attack in high temperature, high pressure autoclaves tests simulating sour production environments even when the coatings are deliberately mechanically damaged prior to testing. These coating have also been shown to be highly abrasion resistant in standard dry and wet abrasion tests. Thus, DLC coatings may significantly extend component life in abrasive hot sour applications in the oil and gas industry. INTRODUCTION TO DLC PIPE COATINGS Sub-One Technology(1) has developed method using plasma enhanced chemical vapor deposition (PECVD) for applying diamond-like carbon (DLC) to the inside of metal piping or tubing.1 The apparatus, shown schematically in Figure 1, uses the pipe itself as the plasma deposition chamber, with DC pulse biasing of the pipe as the cathode to attract the ionized gaseous precursor (acetylene) to the interior of the pipe, forming the coating. The resulting coatings approach diamond hardness, are hydrophobic, and electrically non-conductive. The coating is deposited in multiple layers as shown in Figure 2. The metal surface is first cleaned at an atomic level by sputtering with a mixture of argon and hydrogen.2 A layer of pure silicon is grown on the substrate surface to optimize adhesion of the successive layers of the coating stack. Multiple layers of DLC with decreasing silicon concentrations are grown in succession, with a final layer being pure DLC. The Si-doped DLC layers in the center of the coating stack act as stress relievers.3 The coating stack shown in Figure 2 is 30 ?m thick. A Critical Difference between DLC Coatings and Coatings Applied as Liquids A critical feature that distinguishes DLC coatings from coatings applied as liquids.
- Geology > Mineral > Sulfide (0.41)
- Geology > Geological Subdiscipline > Geomechanics (0.35)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (0.50)
- Health, Safety, Environment & Sustainability > Health > Noise, chemicals, and other workplace hazards (0.41)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Materials and corrosion (0.34)
ABSTRACT: Direct Assessment (DA) is an accepted methodology to evaluate the impact of external, internal, and stress corrosion cracking on underground pipelines’ integrity. However, for aboveground piping of a facility or for aboveground sections of an underground pipeline, other approaches are more suitable to assess the integrity of the aboveground piping. For many years, a combined methodology for facility piping inspection has been successfully applied to assess integrity of aboveground and underground piping; the combined methodology compromises the application of the American Petroleum Institute (API) Piping Inspection Code and the National Association of Corrosion Engineers (NACE) DA Process. This combined methodology applied since 2005 is discussed in this publication. The riskbased and software-supported methodology, how to establish locations for inspection and examination, how to establish corrosion rates, and how to calculate remaining life and reassessment interval is discussed. In addition to the application of this combined methodology, the results of the assessments are enhanced using software and finite element analysis (FEA) modeling to perform fitness-for-service and remaining stress calculations to address findings identified in the field with visual inspection or nondestructive examinations (NDE). INTRODUCTION Facility piping systems require a significant amount of resources in order to assure its integrity, avoid failures that may generate safety related incidents and possible interruption of operations, with associated business loses. It is a general understanding that facility piping should be inspected for in-service damage such corrosion. In most cases, it is a requirement of a federal regulation, or a state or local jurisdiction. In other cases, it is just an owner’s reactive action after damage mechanisms have been detected or a piping failure has occurred. At the end of the day, the bottom line is to have the right tool or methodology to conduct the inspection of facility piping with a cost-effective approach.
- 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: Many assets in the UK sector of the North Sea are approaching or have passed their intended design life. The general decline of many mature assets has been reversed as new operators invest significantly to increase asset life when compared to the former owners. This poses a number of challenges for continued corrosion control. Operational conditions are likely to have changed radically since original design and assets may be subject to increased water cuts and requirements for gas lift and water injection. The new duty holder of a mature asset must take these factors into account when formulating their own corrosion management system. In 2008, the Company acquired the Cormorant Alpha, North Cormorant, Eider and Tern platforms and the associated pipelines and subsea tie backs. The oldest of these platforms came on line in 1978 and has passed its original design life of 30 years. The purchase also included a share of the Brent main oil line (now operated by the Company) and a share of the Sullom Voe oil terminal. The previous operator had defined these assets as “end of life”. The Company needed an extended life to 2025. This required a substantial re-alignment of corrosion management priorities. Extensive rework of documentation was performed to create a corrosion management system for both pipelines and assets in accordance with recent United Kingdom government and industry recommendations. Government requirements for life extension (KP4) were assessed and the implemented. KPIs, corrosion control matrices, corrosion mitigation measures and corrosion monitoring were redefined and re-engineered to take into account both extended life requirements and future as well as present operating conditions. This publication discusses the issues described above, and the changes in corrosion and integrity management that were required to ensure compliance with the required life extension.
- Materials > Chemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > Europe Government > United Kingdom Government (0.54)
- Europe > United Kingdom > North Sea > Northern North Sea > East Shetland Basin > North Viking Graben > Block 211/26a > Cormorant Field > Etive Formation (0.94)
- Europe > United Kingdom > North Sea > Northern North Sea > East Shetland Basin > North Viking Graben > Block 211/26a > Cormorant Field > Brent Group Formation (0.94)
- Europe > United Kingdom > North Sea > Northern North Sea > East Shetland Basin > North Viking Graben > Block 211/21a > Cormorant Field > Etive Formation (0.94)
- (5 more...)
INTRODUCTION ABSTRACT: Forensic corrosion engineering (FCE) is a practice that seeks to understand the contributing causes and underlying mechanisms of corrosion damage and apply this knowledge to mitigate risk resulting from corrosion threats. This knowledge can also be leveraged through the framework of a Corrosion Management System (CMS). In-depth understanding of the active corrosion threat mechanisms in a pipeline system improves the operator’s ability to identify effective mitigation and monitoring measures and increases confidence in risk management programs. Based on FCE results, application of “lessons learned” is discussed as part of a Corrosion Management System. Essential elements of the FCE approach, which include integrating the disciplines of chemistry, corrosion/materials science, microbiology and oil and gas operations, are also discussed. Corrosion has been reported to constitute over 25% of the failures experienced in the oil and gas industry1. The annual cost of corrosion to the transmission pipeline industry alone has been estimated at $5.4 to $8.6 billion dollars annually2, over half of which is attributed to operations and maintenance (O&M) costs. Integrity management and corrosion control are two major categories of activity contributing to O&M costs. The primary goal of integrity management activity is to maintain the operational integrity of the asset and control HSE risks, while the goal of corrosion control activity is focused on mitigating and monitoring the corrosion threats. Clear identification of the corrosion threat mechanisms is of paramount importance in order to achieve both of these goals. While industry standards for managing integrity of pipeline systems identify analysis of previous failures as a valuable data source3, information resulting from forensic investigation of corrosion damage also supports many objectives of a Corrosion Management System. Forensic corrosion engineering focuses on the physical and circumstantial evidence associated with materials degradation or failures resulting from corrosion.
- Energy > Oil & Gas > Upstream (1.00)
- Energy > Oil & Gas > Midstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.46)
- 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)