Layer | Fill | Outline |
---|
Map layers
Theme | Visible | Selectable | Appearance | Zoom Range (now: 0) |
---|
Fill | Stroke |
---|---|
Collaborating Authors
Results
Development Of A Test Protocol For The Evaluation Of Underdeposit Corrosion Inhibitors In Large Diameter Crude Oil Pipelines
Been, Jenny (Alberta Innovates Technology Futures) | Place, T.D. (Enbridge Pipelines Inc.) | Crozier, Brendan (Alberta Innovates Technology Futures) | Mosher, Michael (Alberta Innovates Technology Futures) | Ignacz, Tom (Baker Hughes) | Soderberg, Jeff (Brenntag Canada) | Cathrea, Colin (Champion Technologies Ltd) | Holm, Michael (GE Water and Process Technologies) | Archibald, Darin (Multi-chem Production Chemicals Co.)
INTRODUCTION ABSTRACT: Pipelines carrying heavy crude oil may be subject to corrosion caused by deposition of sediments, a sludge containing oil, water, and bacteria in a particulate matrix. A standard testing protocol was developed with the participation of five inhibitor vendors. The test protocol includes inhibitor evaluations based on (1) Filming Effectiveness, (2) Partitioning Studies, (3) Sludge Corrosivity and Inhibitor Tests, and (4) Bacterial Kill Studies. The results of the different tests and the relevance of each test with regard to the application are discussed. A successful bacterial kill test approach was established. Initial exposure tests of coupons covered with inhibited sludge in oil are most representative of the pipeline environment, but results were variable. Improvements to the test procedure are presented and explored. Crude oil transmission lines have enjoyed a long history without significant levels of internal corrosion due to the use of sediment and water tariff limits that render the bulk fluid non-corrosive. Velocities are generally sufficiently high to prevent accumulations of the remaining trace quantities of water. However, recent experience has indicated that with less than 0.5% sediment and water, accumulation of solids can occur through a combination of gravitational settling and fluid dynamic effects. The deposition of solids can lead to underdeposit corrosion at unexpected locations such as over bends. It has been suggested that the location, quantity, and character of the deposit may be different for large (>20 inch (50.8 cm)) versus small (<10 inch (25.4 cm)) diameter pipelines. Stratification of solids with different properties likely occurs in thick accumulations, but these are difficult to measure since the only practical pipeline sludge sampling method involves pigging, which thoroughly mixes the sludge. One transmission pipeline operator's internal corrosion management program includes pigging and chemical treatment to mitigate internal corrosion on an as-needed basis. These treatment protocols have largely been adapted from upstream pipeline experience where inhibitor vendors have provided successful chemical programs for several decades. Whereas upstream pipelines transport large percentages of corrosive water, transmission pipelines have very different operating conditions. This transmission pipeline operator's pigging and chemical treatment program is effective. However, there are uncertainties regarding the mechanism by which the inhibitors provide their benefit - specifically against the threat of underdeposit corrosion. Vendors are faced with the challenge to develop a chemistry that will penetrate the deposit and inhibit the underlying steel. Development of the right inhibitor chemistry requires an understanding of the nature of the deposits. Deposits consist of mixtures of hydrocarbons, sand, clays, corrosion by-products, biomass, salts, and water and are generally referred to as “sludge” or “schmoo”.1 The sludge chemistry can vary within a stratified sludge deposit, between different locations, and as a function of transported crude. The water content can be several percent and usually consists of an emulsion. However, a thin film has been observed surrounding grains of sand, where contact with other grains can lead to a water layer on the steel surface.2 Corrosion may be promoted by the presence of salts, organic acids, or bacteria.
- North America > Canada > Alberta (0.29)
- North America > United States > Texas (0.28)
Inhibition Of Co2 Corrosion Of 1030 Carbon Steel Beneath Sand-Deposits
Pandarinathan, Vedapriya (Corrosion Centre for Education, Research and Technology Department of Chemistry Curtin University) | Lepková, Katerina (Corrosion Centre for Education, Research and Technology Department of Chemistry Curtin University) | Gubner, Rolf (Corrosion Centre for Education, Research and Technology Department of Chemistry Curtin University)
ABSTRACT: The performance of three corrosion inhibitors was investigated at 1030 carbon steel surfaces in the presence and absence of a sand deposit. Potentiodynamic measurements showed that the inhibition efficiency to mitigate corrosion reactions decreases in the presence of sand deposit. In contrary, the inhibitor performance was found to increase with longer exposure time of the steel to the corrosive media, at sand deposited surfaces. The differences between the steels corroded with and without sand deposit in the presence of an inhibitor were confirmed using both potentiostatic polarisation technique and scanning electron microscopy. The inhibition activity of the studied compounds in mitigating under-deposit corrosion of carbon steel has been discussed. INTRODUCTION Investigation of CO2 corrosion processes of 1030 carbon steel surfaces has been widely researched by numerous authors1-7. The impact of solid particles produced during oil and gas operations on the corrosion inhibition of the system is a major concern for the oil and gas industry2,3. CO2 corrosion is enhanced in the presence of entrained sand particles in the pipelines leading to severe corrosion damage underneath the settled sand deposits4,5. It has been reported that under-deposit corrosion leads to localized corrosion and formation of pits on the metal surface6. In previous investigations, the mechanism of under-deposit corrosion has been related to a galvanic corrosion between surfaces with and without sand deposits 7-10. The control of under-deposit corrosion is currently being accomplished through methods such as pigging and the use of corrosion inhibitor chemicals. While the CO2 corrosion inhibition of mild steel surfaces has been largely investigated, only limited studies have been undertaken to evaluate the inhibition efficiency under a produced sand layer. Little attention has been paid to the principles of inhibition offered by the applied corrosion inhibitors under circumstances where sand deposits are formed, but pigging is not possible11,12. It has been shown that the sand particles can adsorb the corrosion inhibitors applied to the system thereby reducing the activity of the inhibitor13. The organic compounds such as imidazolines, quaternary ammonium compounds, thiols, pyrimidine based compounds, several mercaptans, phosphate esters etc. have been reported as potential CO2 corrosion inhibitors for industrial applications14-17. The aim of this study is to evaluate the performance of a range of corrosion inhibitors under sand deposited carbon steel surfaces in CO2 environment. Electrochemical investigations were conducted under potentiostatic and potentiodynamic conditions to determine the corrosion processes proceeding at the sand-deposited surfaces18,19. The estimated corrosion rates as a function of exposure time from the electrochemical test results and also from weight-loss immersion tests are presented. The surface morphology of the corroded structure plays an important role in determining the inhibition principles20,21. The surface characteristics of the corrosion scale formed in the presence and absence of sand deposits have been analysed using scanning electron microscopy. The influence of sand particles on the inhibition activity of the studied inhibitors has been discussed. EXPERIMENTAL PROCEDURE Test Materials The electrochemical corrosion tests were conducted using 1030 grade carbon steel electrodes embedded in epoxy resin.
- Oceania > Australia (0.68)
- North America > United States > Texas > Harris County > Houston (0.16)
- Materials > Metals & Mining > Steel (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.34)
- 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 An under deposit corrosion test method has been developed where three carbon steel specimens are mounted together in an assembly. Two of the specimens are covered by sand or another deposit, while one specimen is not covered. The potential difference and galvanic current between sand covered and not covered specimens is measured. The corrosion rate of all three specimens is measured by linear polarization resistance measurements, while the galvanic current is measured by zero resistance ammetry. The paper summarizes the test method and presents experience in using the test method for both film-forming inhibitors and pH stabilization. INTRODUCTION The use of carbon steel in combination with CO2 corrosion inhibitors represents an economically favorable alternative for transportation of unprocessed oil and gas compared to the use of corrosion resistant materials. Corrosion inhibitors used for this application generally contain specifically designed surface active compounds. These compounds adsorb to surfaces and interfaces in the fluid, like solids, emulsions, droplets etc. 1-8 . The surfactant molecules also partition between phases (hydrocarbon or aqueous phase) according to their solubility in the respective phase 1 . Solid particles can consume a significant amount of corrosion inhibitor by adsorption when the surface area is large 2 . This can result in a reduction in inhibitor concentration to levels below the minimum effective concentration. If the entrapment of the inhibitor by solids is not properly accounted for this effect may lead to failure of the system 1-4 . Produced solids affect not only inhibitor performance but many other aspects of the petroleum production as well. Sand particles are known to cause erosion corrosion. They can also form sand beds in some part of the pipelines or in separators. Severe corrosion attack can occur under such deposits 3 . Little has been published about the inhibitor performance in the presence of solids. This paper presents a test method for laboratory testing of CO2 corrosion inhibitor performance in the presence of sand deposits and discusses the experience using this method. The test method was developed to assess the performance of corrosion inhibitors in presence of sand deposition on parts of the steel surface. The cases used as examples in this paper are based on inhibitor addition prior to sand deposition. This represents the case of sand deposition under conditions of continuous inhibition at levels which are sufficient for protection of bare surfaces. The presented test method may also contribute to the development of improved inhibitor products. The intention of the present work was not to compare inhibitors. The inhibitors were used as example products in the development of the test method and identification of critical parameters for the testing. GENERAL PROCEDURE FOR UNDER DEPOSIT CORROSION TESTING The test method described here can be performed in a standard 3 liter glass cell. A specially designed specimen holder and lid has been developed. A sketch of the cell design with the specimen holder is shown in Figure 1. The cell lid is equipped with connections for CO2 gas bubbling, solution replenishment, specimen holder, sand filling, solution sampling and temperature sensor.
- North America > United States > Texas (0.28)
- Europe (0.28)
- Water & Waste Management > Water Management > Water & Sanitation Products (1.00)
- Materials > Chemicals > Specialty Chemicals (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)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Materials and corrosion (1.00)
INTRODUCTION ABSTRACT This paper contains the discussion of a case history where corrosion attacks took place in a slightly sour waste water disposal pipeline. The exposure of the waste water to the air had taken place from an open pit, which may have generated elemental sulfur fine particles in the solution. When solids dropped out from the solution, localized attack was detected in the form of underdeposit corrosion. Details are also given on the laboratory testing results and development of a corrosion inhibition program for such an environment. In many onshore operations, the integrity of a waste water disposal pipeline can be extremely important since any failures of the pipeline may directly result in a shutdown of the entire upstream oil and water separation processes. The main water source to be disposed is generally the produced water after a series of surface facilities, such as, separators, filters, clarifier tanks, cone bottom storage tanks, etc. There are also many waste water sources which are much dirtier in terms of solid content to be transported in the waste line after commingling with the produced water. These waste waters can be from vacuum trucks, drains, scrubbers, soft water cogeneration units and generators and are first dumped into waste pits which could be directly opened to the air. After temporary solids settle out they are pumped into storage tanks and then go through a filtration process whenever the tanks get full. It is then easy to determine that these waste waters are generally full of solids collected from either reservoir or surface facilities. Unfortunately, the filtration process involved can be quite inadequate and ineffective sometimes to get rid of all the suspended solids, particularly the fine particles. The ratio of waste water and the produced water varies from system to system and therefore the quality of the water being sent down to the waste pipeline can differ from month to month, not to mention the variations from the variable field conditions. From a corrosion perspective, it is not hard to concede that the waste water could pose a high risk to the integrity of the carbon steel pipelines in terms of underdeposit corrosion (UDC) due to the presence of a significant amount of solids. The standard reduction potential for oxygen is 1.23 V for equation 1, implicating its strong electron removing capability when compared with other acidic species dissolved in the solution. The detrimental impact of the ingress of oxygen for oil and gas pipeline system had been observed and reported by many operators and researchers1-3. The most effective way to reduce the oxygen impact on the pipeline deterioration is the elimination of the oxygen sources, such as using gas blankets and preventing the leakage. The use of an oxygen scavenger, e.g. bisulfite, is also a typical option in the field. But its effectiveness can be largely limited when the oxygen concentration and location are the uncertain factors, as well as its potential deactivation by other chemicals in the water.
- Water & Waste Management > Water Management > Water Supplies & Services (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (1.00)
- Energy > Oil & Gas > Upstream (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)
- Health, Safety, Environment & Sustainability > Environment > Waste management (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Materials and corrosion (1.00)
Flow-Induced Corrosion And Erosion-Corrosion Assessment Of Carbon Steel Pipework In Oil And Gas Production
Barker, Richard (Institute of Engineering Thermofluids, Surfaces and Interfaces School of Mechanical Engineering University of Leeds) | Hu, Xinming (Institute of Engineering Thermofluids, Surfaces and Interfaces School of Mechanical Engineering University of Leeds) | Neville, Anne (Institute of Engineering Thermofluids, Surfaces and Interfaces School of Mechanical Engineering University of Leeds) | Cushnaghan, Susan (Shell UK Limited)
ABSTRACT: A flow-induced corrosion and erosion-corrosion investigation was conducted to determine the degradation rates and mechanisms that had been experienced in service in the pipework of an offshore facility. The investigation reviewed the flow-induced corrosion and erosion-corrosion performance of the carbon steel parent metal of the pipework in comparison to the heat affected zone (HAZ) and the nickel-molybdenum weld material. The programme of experiments assessed the potential of two corrosion inhibitors to adequately control the material degradation caused by static corrosion, flow-induced corrosion and erosion-corrosion on the three regions. Static corrosion tests were performed using linear polarisation in CO2 saturated conditions. Flow-induced corrosion and erosion-corrosion experiments were conducted utilising a submerged impinging jet (SIJ) in CO2 saturated conditions at a fluid velocity of 7m/s with sand loadings of 0mg/L and 100mg/L. The effects of flow-induced corrosion and erosion-corrosion were studied using gravimetric techniques. Mechanisms were discussed based upon results obtained from micro-structural studies. INTRODUCTION CO2 Corrosion, Flow-Induced Corrosion and Erosion-Corrosion of Carbon Steel CO2 is an extremely influential constituent in oilfield production fluids, directly associated with the most prevalent form of corrosive degradation encountered in the oil and gas industry. CO2 corrosion or 'sweet corrosion' of carbon and low alloy steels is not a recent problem, and was first recorded in the United States oil and gas industry in the 1940's, with several investigations subsequently following. The consequences of this particular corrosion mechanism have long been recognised and prompted extensive studies1, 2. The search for a more complete understanding of CO2 corrosion stems from a need for effective steps to control and prevent corrosion3. Since deWaard and Milliams published their empirical equation4, extensive laboratory testing and field experience have been used to explain the mechanisms by which steel corrodes in CO2 containing environments. From these studies, a strong understanding of the mechanisms attributed to CO2 corrosion has been established. Work by deWaard and Milliams4, 7 has led the way in the prediction of CO2 corrosion. Their studies have marked some of the important reference points for CO2 corrosion research over the past few decades, and their most recently revised CO2 corrosion prediction model is still used informally by industries. Today, numerous mechanistic1, 8, semi-empirical9 and empirical models10 have been developed to predict the resistance of materials in CO2 containing environments. Problems tend to arise when empirical and semi-empirical models are used outside of the conditions in which they have been validated experimentally. The effect of fluid flow on corrosion and erosion-corrosion of carbon steel is a recognised phenomenon in the oil and gas industry. In particular, the occurrence of flow-induced localised corrosion (FILC) can dramatically reduce component lifetime, and in some cases cause failure, posing a major threat to the safety and production of oil and gas facilities11. Flow-induced corrosion is controlled by chemical, physical and hydrodynamic parameters and has been shown to be significantly influenced by velocity12. Although fluid hydrodynamics play an important role in flow-induced corrosion, the corrosive nature of the fluid is also a factor requiring consideration.
ABSTRACT: This paper outlines the selection methods for the inhibitor chemical deployed and present the chemical returns profile from the 3 wells treated (some treatments lasting > 450 days) along with monitoring methods utilised to confirm scale control in the wells treated. The paper also explores in detail the issues associated with inhibitor squeeze vs. inhibitor stimulation deployment in deepwater, subsea fields, many of which are currently being developed in the Campos basin, Gulf of Mexico and West Africa, and is a good example of best-practice sharing from another oil basin. INTRODUCTION The fields are located offshore in Angola in approximately 400 meters water depth. The fields are developed with both dry tree wells which are located on the Compliant Tower and subsea wells that are connected to the Compliant Tower via one of three subsea production manifolds. All of the fields are under waterflood. Gas-lift is available for artificial lift. A total of 10 dry tree and 13 subsea production wells have been completed thus far and the development program is still underway. All but two of the producers are completed with cased-hole frac packs. Some wells have multiple, or stacked, frac packs. The field was started up in January 2006. The Basis of design for managing barium sulfate scale was to scale squeeze the wells at seawater breakthrough. In the 4th quarter of 2007, some wells incurred seawater breakthrough much earlier than forecast which led to barium sulfate scale formation and significant production impairment. An ensuing proactive scale management program of both scale squeezes and incorporation of scale inhibitor in the initial completions has resulted in no further scaling events. Reservoir description: The reservoirs are composed of high quality turbidite sands deposited in a middle bathyal slope valley/incised canyon environment. Reservoir quality sands are found as vertically stacked and nested channel complexes that both erode and aggrade preexisting sediments. The turbidite complexes are typically 500-2000m wide, 10-60m thick, and composed of intercutting sand rich turbidite channels, shale-rich mudflows, debris flows and slumps. Nature of the problem Details of scale formation mechanisms are provided elsewhere1-5, as are the reasons why they pose problems in the production well, near-well areas and surface facilities6-8, much less commonly in injection wells9, and never deep within the reservoir10-13. The various techniques that may be adopted to meet the challenges of scale control may be divided into four principal categories, as follows: 1) Selection of injection fluid source 2) Chemical inhibition 3) Chemical/mechanical remediation 4) Flow conformance The range of formation water chemistry present within the four fields under study is presented in Table 1. The intention is to seawater flood all five fields to improve hydrocarbon recovery. It is clear that the range of barium ion concentrations is quite wide and this will result in differing mass of barium sulfate scale and different supersaturation values during seawater breakthrough. Figure 1 shows the mass of barium sulfate with rising seawater fraction in the produced waters for the four fields.
- Africa (1.00)
- North America > United States > Texas (0.29)
- Europe > United Kingdom > North Sea (0.28)
- Geology > Sedimentary Geology > Depositional Environment > Marine Environment > Deep Water Marine Environment (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (1.00)
- Geology > Mineral > Sulfate (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Constituents > Salts/Sulphates/Scales (0.80)
- North America > United States > Texas > East Texas Salt Basin > Alba Field (0.99)
- Europe > United Kingdom > North Sea > North Sea Basin (0.99)
- Europe > Norway > North Sea > North Sea Basin (0.99)
- (5 more...)
ABSTRACT: In this paper, several scale inhibitors and combination scale inhibitor/corrosion inhibitors were developed to meet the requirement for deepwater applications. Following extended stability and compatibility testing, the inhibitors were exposed to the high-pressure flow loop with cyclic temperature variation from seabed temperature to 100°C over a period of 24 hours. The performance of each inhibitor was evaluated after the flow loop exposure. Rheology profiles at both ambient and high-pressure conditions were measured to study the effect of shear rates experienced in deepwater fields. It was found that some products showed poorer performance after going through the flow loop while others maintained similar performance in comparison to the standard samples. The mechanism of this performance difference is discussed in the paper. Based on the full-suite laboratory evaluation, including hydrate inhibition and environmental evaluations, one of the products was selected to be used in a deepwater field. This paper aims to highlight the importance of suitable laboratory equipment and testing procedures to evaluate the inhibitors for deepwater applications. The wide range of temperature variations, high shear, long residence time and high-temperature, high-pressure (HTHP) environment for the deepwater fields has been successfully simulated in the laboratory. INTRODUCTION Several deepwater products were developed with the aim to be effective, stable and tolerant to a wide range of temperatures, increased pressures and shear rates. All of these products have been fully evaluated for their extended stability, compatibility, high-pressure rheology and inhibition performance before and after the exposure to flow loop; these testing results have been revealed and discussed in detail in a previous paper.8 The aim of this paper is to use a specific field example to illustrate how and why a particular product was selected, to highlight the importance of a complete set of deepwater testing including the use of special designed equipment in deepwater chemical evaluations. To illustrate this, a summary of the previous results in relating to the inhibitor selection is provided in this paper, with the addition of corrosion testing results, hydrate protection and environmental evaluation results. The target field is a deepwater development producing from approximately 1,500 m of water depth via a FDPSO (Floating Drilling Production Storage and Offloading Vessel). It is of relative low temperature with maximum reservoir temperature of 75-88°C (167-190°F) and moderate reservoir pressure (~5,000 psi, 34,474 kPa). The main flow assurance challenges were identified as scale, corrosion, wax and hydrate. As the flow lines are located in 1,400 m of water 140 km offshore, chemical application poses a host of logistical and operational challenges. Production chemicals are injected at the subsea wellheads (maximum 88°C) via narrow-bore umbilicals. Due to the water depth, the pressure within the umbilicals is very high and production chemicals can remain in these umbilicals for prolonged periods. Consequently, a product was required that could withstand these severe conditions without degrading when injected. Ethylene glycol is used as umbilical flushing solvent. A total of five subsea chemical products are discussed in this paper.
- North America > United States > Texas (0.46)
- North America > United States > Montana > Roosevelt County (0.25)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (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 > Offshore Facilities and Subsea Systems (1.00)
ABSTRACT: A 316L stainless steel tank storing inhibited acetic acid perforated due to pitting corrosion after less than 1 year in service. This paper presents potentiodynamic polarization, potentiostatic and galvanostatic test results using reagent grade solutions compared to acid from the field. Chlorides in the corrosion inhibitor proved to be the primary cause of the pitting corrosion, which led to severe pitting damage at the weld heat-affected zones. Various preventive measures (cathodic protection) were tested in the laboratory. The primary preventive measure applied was to remove the inhibitor from the acid blend. INTRODUCTION Production platforms in an offshore oil and gas field all carry large 103 m3 and 165 m3 storage tanks built of AISI Type 316L stainless steel to store acetic acid (HAc). The acid is used for pH adjustment to prevent fouling by asphaltenes in the produced crude oil. These tanks are built of 0.5 inch (1.27 cm) thick plate butt-welded with matching filler metal. Each storage tank has an external frame of ASTM A36 carbon steel stiffening beams welded to the stainless steel using Type 309 stainless steel filler metal. Acetic acid stored in these tanks consists of 80 volume % glacial acetic acid, 15 volume% distilled water and 5% corrosion inhibitor. The corrosion inhibitor was added to protect the stainless steel. According to its Materials Safety Data Sheet, the inhibitor consists of 15-30 weight% fatty acid amide hydroxypropyl ether and 40-50 weight % imidazoline derivatives. The storage tanks operate at ambient temperature, which ranges from about -5ºC in the winter to a maximum of about 38ºC in the summer. These tanks were completed in early 2006. They were in place on the production platforms offshore, open to the air, until field start-up beginning in early 2007. Tank “C” was placed in acetic acid service in March 2009. The tank leaked late in 2009. The leaks consisted of deep pits in the weld heat-affected zones (HAZ's). Pitting was observed in the HAZ's of the butt-welded seams and also in areas opposite to the external steel structural beams. EXPERIMENTAL PROCEDURE A 6 inch square (38.7 cm2) sample of plate containing a seam weld and representative pits was cut cold from Tank C and sent to our laboratory for examination. In addition, twenty liters of freshly blended acid from the onshore blending facility was sent for testing, as well as twenty liters of acid from an offshore storage tank. The freshly blended acid had a red tinge to it. The aged acid from the offshore storage tank appeared blackish when first opened but it appeared to take on a green color when held up to the light in glassware. Figure 1 presents a photograph of the pitted plate sample as received. The base metal samples were analyzed for alloy composition using optical emission spectroscopy (OES). Results are presented in Table 1. Results listed as plate “A” are to the left in Figure 1. Results listed as Plate “B” are to the right in Figure 1.
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (1.00)
- Health, Safety, Environment & Sustainability (1.00)
- Facilities Design, Construction and Operation > Processing Systems and Design > Tanks and storage systems (1.00)
The Influence Of Flow Rate And Inhibitor On The Protective Layer Under Erosion-Corrosion Conditions Using Rotating Cylinder Electrode
Akbar, Abdulmuhsen (Institute of Engineering Thermofluids, Surfaces and Interfaces, School of Mechanical Engineering, University of Leeds) | Hu, Xinming (Institute of Engineering Thermofluids, Surfaces and Interfaces, School of Mechanical Engineering, University of Leeds) | Neville, Anne (Institute of Engineering Thermofluids, Surfaces and Interfaces, School of Mechanical Engineering, University of Leeds) | Wang, Chun (Institute of Engineering Thermofluids, Surfaces and Interfaces, School of Mechanical Engineering, University of Leeds)
INTRODUCTION ABSTRACT: This paper reports findings from an investigation into the effect of flow rate and organic inhibitor on the material performance, film thickness and hardness of protective scales formed on X65 carbon steel surface in a rotating cylinder electrode (RCE) system. The experiments were conducted at a temperature of 70 °C, pH of 5.9 and 4.5 g/cm.s² wall shear stress (tw) using both uninhibited and inhibited Forties brine with 25 ppm of inhibitor saturated with carbon dioxide (CO2) containing 0.1% HST60 PSA silica sand, which can be described as semi-spherical with sharp edges. Weight gain/loss was measured for: as-received X65 specimens and specimens before and after removing corrosion scales in both uninhibited and inhibited systems. In addition, the hardness of the surface specimens and scales was measured using a nano-indenter. This was supported by post-test analysis of samples using scanning electron microscopy (SEM), focus ion beam SEM (FIBSEM), energy dispersive X-ray spectroscopy (EDX) to assess the nature, the thickness, the elemental composition and the possible salts forming these protective films. It was found that the weight loss of as-received surfaces was reduced by more than 43% when 25 ppm of inhibitor was introduced. Nevertheless, inhibitor was found not to be effective in reducing weight loss of pre-scaled surfaces. Sweet corrosion is a significant and costly issue in the oil and gas industry 1-5; 12.5% of failures in the oil and gas industry related to the phenomenon. Pipelines transporting hydrocarbons and produced water/seawater injected are in some cases made of carbon steel. Failure of such pipelines results in their shut down and hence costs million of dollars 6-7. The mechanism of carbon dioxide corrosion is a complicated process. It is influenced by different factors and conditions, such as carbon dioxide partial pressure and temperature which affect the corrosion rate, pH value which influences anodic mechanisms for iron dissolution in CO2 solutions 8 and velocity in which turbulence pushes a sweet system into a higher corrosive regime. Corrosion inhibitors are used to prevent or reduce material degradation due to corrosion for carbon steel pipelines. They are widely evaluated under stagnant or low flow rate (<1 m/s), in addition some work has been done to assess the performance of them in multiphase flow 9. However, there is still a need to evaluate the performance of these inhibitors under high shear conditions and especially in erosion-corrosion where sand present. Some investigators 10-16 attempted to study the influence of flow intensity and inhibitor concentration on initiation of flow-induced localized corrosion (FILC) and mechanical properties of corrosion scale products. On the other hand, some other investigators noticed that cracking and spalling of corrosion scales was primarily because of the intrinsic stresses ¹². Fracture toughness is used as a measurement of cracking resistance of the corrosion scale. Gao et al. observed that the fracture toughness changed considerably with flow rate and the scale produced at velocity of 0.5 m/s showed the lowest fracture toughness of 0.64 MPa ¹³.
INTRODUCTION ABSTRACT: Slug flow regime is well known for being a major contributing factor to internal corrosion in pipelines. In this paper a new methodology is introduced to predict the effect of slug flow regime on the performance ofcorrosioninhibitors.First,amechanisticmodelisimplementedtopredicttheflowregimefor multiphasepipelinesbasedonthepipelineoperationalconditions.Second, amethodbasedon momentum and energy equations for multiphaseflowsis appliedto predictthe profile, frequency and length of slug fronts and gas bubbles formed in the slug flow regime. These predictions are then used to perform a numericalsimulation andstudythe effect ofslugflowregime onthelocalshearstress exerted bytheflow overthe protectiveinhibitorfilm. Calculated results are finally usedto assessthe risk for initiation of flow-induced localized corrosion (FILC) and also provide an insight into the selection criteriaofapropercorrosioninhibitor“package”byorforthepipelineoperator.This fundamental engineeringresearchhasbeenconductedasan R&Dprojecttobetterpredictthecharacteristics of differentflowregimesinsidepetroleumpipelines,investigatetheirsubsequenteffectonthe performance of inhibitors and hence predict the overall corrosion inhibitor effectiveness. Internal corrosion has long been recognized as a leading cause for pipelines failures over the past 50 years.Its' prediction and subsequent confirmation via monitoring of the in-situ corrosion rates (general and pitting or localized attack) has been a tremendously difficult challenge for many researchers as well as pipeline operators, particularly where operatingsurveillance or monitoring andinspection budgets are not commensurate with the actual or real corrosion risk threat. Localized pitting corrosion refers to a specialclassof metaldegradationinwhichthe masslossislimitedtolocalregions(ofafewcm typically) within the pipeline.This aspect differentiates it from uniform/general corrosion which is more widespreadandtendstobeshallowasopposedtodeepasinthecaseofpitting.Nonetheless, localized pitting attackistheleading cause of pipelineleaks and hence,localized corrosionis a very complex phenomenon to reliably predict and many commercially available corrosion models are unable to fully explain or predict its initiation growth, passivation and reactivation cycles. 1 Regardless of their cause, film rupture by mechanical or chemical means inevitably creates an anode and cathode area effect relationship which governs in-part the anodic dissolution of the steel matrix. Flow-induced localized corrosion (FILC) is a type of localized corrosion in which the dominant flow regime inside the pipeline subregion which plays a major role in its initiation by controlling the intensity of flow fluctuations and also the local shear stress exerted by the flow over the scale surface. This intensified shear stress initiates micro-cracks which continue to grow and finally generate local defects in the formed scale. The slug flow regime is a common occurrence in two-phase, liquid-gas pipelines and it is well-known to be very corrosive due to its unsteady nature, intermittency and high-pressure drop.
- Well Completion > Well Integrity > Subsurface corrosion (tubing, casing, completion equipment, conductor) (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Materials and corrosion (1.00)