Kus, Slawomir (Honeywell Process Solutions) | Srinivasan, Sridhar (Honeywell Process Solutions) | Yap, Kwei Meng (Honeywell Process Solutions) | Li, Hui (Honeywell Process Solutions) | Kozik, Violetta (University of Silesia) | Bak, Andrzej (University of Silesia) | Dybal, Paulina (University of Silesia)
Electrochemical corrosion monitoring techniques such as Linear Polarization Resistance (LPR), Electrochemical Noise (ECN) or Harmonic Analysis are widely recognized for their responsiveness and accuracy for determination of instantaneous corrosion rate. However, field application has generally been limited by the need for a conductive / aqueous process environment. This limitation stems from the fact that electrochemical systems cannot provide reliable readings in media at conductance levels less than 10μS/cm due to significant impact of solution resistance on measured values of total resistance. Recent progress in multi-technique electrochemical systems involving low frequency impedance and harmonic distortion analysis has been shown to overcome this limitation.
Results from studies on corrosion measurement in low conductive, sulfolane-based solutions are presented in this paper. Sulfolane is commonly used in petrochemical processes for extraction of aromatic compounds including benzene, toluene or xylenes. Sulfolane systems, if contaminated by traces of oxygen and at typical process conditions (170-180°C), may lead to sulfolane decomposition and formation of corrosive by-products. Significant corrosion of steel in Sulfolane applications has been reported, primarily in the reboiler-regenerator section. Considering that conductance of sulfolane mixtures varies from 2 to 5 μS/cm, it is obvious that traditional electrochemical monitoring approaches may fail due to extremely high solution resistance.
This paper details results from laboratory corrosion measurements in low conductivity, sulfolane-based fluids utilizing multi-technique electrochemical monitoring. Corrosion measurements conducted on sulfolane showed the importance of proper adjustment of electrode surface area for obtaining of reliable corrosion readings. It has been shown that industrial-type corrosion monitoring has capability for rapid detection of corrosivity in low-conductive, sulfolane-based fluids. Impact of temperature and sulfolane contaminants (oxygen, chlorides) on corrosion of mild carbon steel has also been studied.
Corrosion and its monitoring in Sulfolane Aromatic Extraction
Sulfolane (2,3,4,5-tetrahydrothiophene-1,1-dioxide) is one of the most common solvents utilized in liquid- liquid extraction of benzene/toluene/xylenes (BTX) from naphtha and gasoline fractions. The aromatics extraction by sulfolane is usually achieved at temperatures in the range 180-200°C in a typical extractor- stripper-regenerator configuration as shown on Figure 1. Pure sulfolane under standard operating conditions is considered to be a stable compound and non-aggressive to carbon steel. However, at temperatures about 200°C, process of sulfolane decomposition spikes followed by generation of SO2 and formation of corrosive H2SO3, as shown in the generic Equation 1 below. Further oxidation may lead to formation of H2SO4 with consequent acid corrosion. At temperatures above 230-240°C, the overall decomposition process accelerates significantly with release of high quantities of SO2. Therefore, it is expected that high-temperature areas in aromatics extraction units, such as reboiler and/or regenerator loops, where temperature excursions are highly likely, will be prone to accelerated sulfolane attack.1-4
M, Amir Q. (Indian Oil Corporation Limited) | Chandrasekaran, Kannan (Indian Oil Corporation Limited) | Srinivasan, Sridhar (Honeywell Corrosion Solutions) | Yap, Kwei Meng (Honeywell Corrosion Solutions)
Accurate quantification of corrosivity of crude oil fractions has been a major challenge for refiners, stemming from inadequate understanding of complex influences of naphthenic acids and type/ morphology, molecular weight of acid species, sulphur content and speciation, temperature, and fluid flow on corrosion. A proprietary model has been developed encapsulating data from Honeywell’s Crude Corrosivity Phase-I Joint Industry Program (JIP), conducted between 2006 and 2011. This research program, sponsored by Indian Oil Corporation Limited (IOCL) and nineteen other global refining and engineering companies, led to the development of the first ever quantitative engineering database and decision-support model to predict corrosion for common materials of construction employed in high temperature refinery crude fractionation. Data were generated in simulated refinery environments for relevant temperature ranges, varying naphthenic acid content, and active Sulphur levels for different process oils.
This paper provides details from the evaluation of the proprietary prediction model and validation studies conducted in IOCL’s refinery crude units. Case studies comparing the model predictions with the refinery inspection / measured corrosion rate data as a function of key operating parameters are provided. Guidelines on the utility of the prediction model and suggestions for improvements are also provided.
The processing of such opportunity crudes offers refinery operators significant economic benefits while posing serious challenges in terms of potential for corrosion damage of unit equipment as well as product quality. Some of the barriers to opportunity crude processing stem from naphthenic acid corrosion, fouling, sulphidic attack, crude compatibility, long term accessibility, crude quality variation, increased hydrogen demand, coke make, reduced product yield of distillates, increased energy demand and increased CO2 emissions. These issues can be addressed in a long-term perspective by design modification, metallurgy upgrading, and adoption of relatively new resid upgrading processes. New refineries can be designed accordingly depending on the premised crude slate. However, older refineries that were designed to process light sweet crude (API > 30°, S < 0.5Wt. with low TAN < 0.5mgKOH/gm) face the challenge of remaining operationally viable when faced with the daunting task of processing high acid and reactive sulphur crudes [2,3]. Against the backdrop of availability of the opportunity crudes, at least over the medium term and in regard to the concomitant economic benefits of refining such crudes or crude blends, it becomes imperative, especially for the older refineries, to look at the challenges and draw short and long-term plans for processing opportunity crudes. This paper evaluates the corrosion behaviour of naphthenic acid bearing crudes and the quantification of corrosion rate of susceptible locations using the crude prediction model. The evaluation and validation has been achieved utilizing several real case studies at IOCL refineries, wherein the performance of the prediction model has been compared against inspection-based corrosion measurements [1-3].
The application of Raman spectroscopy for hydrocarbon speciation is described and recent advances in real time monitoring have been highlighted. The vibrational properties of hydrocarbon molecules were modeled using Density Function Theory and results were correlated with Raman spectra. The speciation of gas mixtures containing C1 – C4 hydrocarbons and concentration of vapor phase components were derived from Raman spectra analysis. Calibration curves showing the dependence of Raman line intensities as a function of hydrocarbon concentration have been presented to validate applicability of Raman spectroscopy for hydrocarbon detection. The minimum hydrocarbon concentration detectable by Raman spectroscopy has also been quantified. Results obtained indicate that Raman spectroscopy is a reliable tool for quantifying and monitoring industrial processes.
AbstractThe application of Raman spectroscopy for hydrocarbon speciation is described and recent advances in real time monitoring have been highlighted. The vibrational properties of hydrocarbon molecules were modeled using Density Function Theory and results were correlated with Raman spectra. The speciation of gas mixtures containing C1 – C4 hydrocarbons and concentration of vapor phase components were derived from Raman spectra analysis. Calibration curves showing the dependence of Raman line intensities as a function of hydrocarbon concentration have been presented to validate applicability of Raman spectroscopy for hydrocarbon detection. The minimum hydrocarbon concentration detectable by Raman spectroscopy has also been quantified. Results obtained indicate that Raman spectroscopy is a reliable tool for quantifying and monitoring industrial processes.
ABSTRACTThis paper summarizes results from Phase III of the joint industry program (JIP) on refinery alkaline sour water (ammonium bisulfide) corrosion. Phase III included a comprehensive engineering analysis of data from all three phases of the Sour Water JIP and the development of “H2S tie-in plots” based on a single parameter (H2S partial pressure), replacing the isocorrosion diagrams based on NH3 partial pressure developed in Phase II, and linking with the H2S isocorrosion diagrams based on H2S partial pressure developed in Phase I. These H2S tie-in plots enabled corrosion rate data for carbon steel and five commonly used corrosion resistant alloys to be contiguously modeled across the entire range of conditions tested — six orders of magnitude of H2S partial pressure, from approximately 0.00004 to 150 psia (0.0003 to 1,000 kPa absolute) — to fully characterize effects of H2S-dominated, NH3- dominated and intermediate sour water conditions. The results clearly demonstrated that NH4HS concentration, flow velocity (wall shear stress), H2S partial pressure, and free cyanide concentration in the NH4HS solution are the key parameters driving severity of refinery sour water corrosion. The effect of temperature was also clarified. Substantial differences in corrosion behavior of carbon steel from the corrosion resistant alloys were observed in low NH4HS concentrations at intermediate H2S partial pressures, where corrosion rates of carbon steel and all the alloys exhibited surprisingly significant dips and peaks on the H2S tie-in plots. The results and analyses of data were synthesized into an enhanced software tool to predict corrosion rates for the six materials (carbon steel, stainless steels, and nickel based alloys) evaluated in the program, addressing a broad range of environmental conditions encompassed by all three phases of the Sour Water JIP.INTRODUCTIONFor several decades the selection of materials of construction to resist ammonium bisulfide (NH4HS) corrosion was primarily based on empirical findings that relied heavily on evaluations of operational experience, along with very limited controlled laboratory tests. Limits on material utilization were for the most part very general guidelines, usually based on the NH4HS concentration and velocity of the sour water stream containing the NH4HS. However, in March 2000 the Sour Water JIP, formally titled “Prediction and Assessment of Ammonium Bisulfide Corrosion Under Refinery Sour Water Service Conditions,” was initiated to develop a quantitative engineering database and provide guidelines to predict corrosion in hydrogen sulfide (H2S)-dominated alkaline sour water systems typically found in refinery services such as the reactor effluent air cooler systems of hydroprocessing units.
ABSTRACTSince the advent of deep sour gas wells (in 1970-80s), the effects of elemental sulfur on increased pitting and stress corrosion cracking (SCC) susceptibility of nickel-based alloys have been documented in the literature. At the same time, methods for testing these materials for resistance to SCC have evolved in several forms that include under and over saturation of elemental sulfur in test environments over a range of temperatures usually in the range 150 °C to over 200 °C. Today, qualification of a variety of corrosion resistant alloys for inclusion into NACE MR0175/ISO 15156 Part 3 references these methods. However, there is little agreement as to the nature of the chemical environments (in terms of elemental sulfur and its speciation) in the test environment and their role in defining severity with respect to SCC.This paper reviews both available SCC data and test methodologies involving additions of elemental sulfur using the abovementioned procedures. It utilizes thermodynamic modeling to assess the chemical speciation of elemental sulfur under selected test conditions. The goal of this study is to gain a better understanding of the connection between the method and quantity of sulfur addition and SCC of corrosion resistant alloys and to give better guidance for selection of test methods to simulate desired service conditions in HPHT wells required by the aforementioned NACE/ISO standard.INTRODUCTIONWith continuous increase in demand of gas and oil, it has been a challenge to drill and produce in deeper and higher pressure hydrocarbon reservoirs. The environments in deep sour wells contain substantial amounts of hydrogen sulfide (H2S), carbon dioxide (CO2), chlorides, and (in some cases) elemental sulfur with high pressure and high temperature (HPHT). Corrosion resistant alloys (CRA) tubing, liners and ancillary downhole equipment have been used in the production of deep sour gas wells due to their tendencies for passivity in corrosive environments.1 CRA cited in the literature represent alloys that are most-commonly used in the completion of corrosive oil and gas wells. CRA have been divided into three categories based on the bulk phase: martensitic stainless steels (MSS), duplex stainless steels (DSS), and austenitic stainless steels and Ni-based alloys. Ni-based alloys have been involved a wide range of alloy compositions (additions of Cr, Ni, Co, Mo, and/or W) with face centered cubic microstructure from UNS N06985 and UNS N10276 to N07725 in severe sour service conditions or offshore operations.1
ABSTRACTThe application of Raman spectroscopy for hydrocarbon speciation is described and recent advances in real time monitoring have been highlighted. The vibrational properties of hydrocarbon molecules were modeled using Density Function Theory and results were correlated with Raman spectra. The influence of pressure and temperature on Raman modes was described. The speciation of gas mixtures containing C1 - C4 hydrocarbons and concentration of vapor phase components were derived from Raman spectra analysis. Calibration curves showing the dependence of Raman line intensities as a function of hydrocarbon concentration have been presented to validate applicability of Raman spectroscopy for hydrocarbon detection. The minimum hydrocarbon concentration detectable by Raman spectroscopy has also been quantified. Results obtained indicate that Raman spectroscopy is a reliable tool for quantifying and monitoring industrial processes.INTRODUCTIONMonitoring techniques play a key role in process optimization. New oil and gas production technologies, including exploration, hydraulic fracturing, natural gas/hydrocarbon transmission and oil conversion depend on development of tools to efficiently manage reservoirs, pipelines and refinery operations to improve throughput/efficiency while enhancing operational safety and reliability. Monitoring process speciation in hydrocarbon applications is a critical industry need from a process optimization and environmental protection perspective. Oil and gas production will be more effective when instrumentation to monitor hydrocarbon conversion through direct measurement of concentration of hydrocarbons, carbon dioxide and hydrogen sulfide at high pressures and high temperatures is available and deployed. Traditional oil and gas process monitoring approaches are based on spectroscopic techniques as mass spectroscopy or gas chromatography. These methods have significant limitations related to detection limits and their selectivity / applicability.1Development of new process monitoring technologies detailed herein stems from the application of Raman Spectroscopy to facilitate continuous monitoring of hydrocarbon recovery processes. Raman spectroscopy facilitates identification and quantization of compounds and can be very effective in monitoring and quantifying hydrocarbons in gas formations, hydrocarbon conversion processes and natural gas transmission. Materials are identified from vibrational spectra, which depend on material chemical composition, structure, strain and structural disorder.2-5 Information encoded in Raman spectra, such as frequency shift of the Raman line with respect to the excitation laser line, the number of observed lines, their half-width, intensity, and polarization properties represent veritable “fingerprints” of the component species under investigation. Since Raman spectra provide information on the distribution of ions in the vapor, liquid or solid phases, Raman spectroscopy can become a powerful analytical technique for chemical and structural identification of compounds in different states.2,4,6,7
ABSTRACTIn oil and gas production, the potential damage to the oil and gas transportation lines caused by Top of the Line Corrosion (TLC) has become a key concern for pipeline operators given the inability of currently available prediction models to accurately capture the phase behavior and concomitant water condensation, a precursor to TLC. Another concern with TLC is that continuous corrosion inhibitor application is usually not effective as TLC occurs in stratified flows where corrosion inhibitors can hardly reach corroding locations.This paper details a TLC model integrated into a CO2/H2S corrosion prediction model developed by the authors' organization. The TLC model determines the top of the line corrosion rate of carbon steel based on water chemistry and film-wise condensation rate. The effect of various glycols, such as Monoethylene Glycol (MEG), Diethylene glycol (DEG) and Triethylene Glycol (TEG), are included. Experimental data and field data were used for model validation and the predicted condensation rates and the TLC rates demonstrated good agreement.INTRODUCTIONTop of the line corrosion (TLC) typically occurs in carbon steel pipelines/flowlines in which wet gas or stratified multiphase flow are transported. A significant temperature difference between the line and the ambient environment is required to initiate TLC. Although normally corrodes at a lower rate comparing to aqueous phase corrosion under similar conditions, TLC becomes a concern because continuous corrosion inhibitor application is usually considered not effective for TLC. This is because conventional corrosion inhibitors tend to stay in the liquid phase and are unable to reach the top portion of the pipe in stratified flow where TLC is expected. Several studies have been presented to demonstrate the effectiveness of TLC corrosion inhibitors in lab testing either through volatile components14 or through forming foam matrix22, 33; however, field application is not yet sufficient to build confidence on such TLC inhibitors. The TLC issue remains as a design challenge for engineering companies who sometimes resort to robust TLC models to give a design guideline.
Li, Hui (Honeywell Process Solutions) | He, Jie (Honeywell Process Solutions) | Meng Yap, Kwei (Honeywell Process Solutions) | Kus, Slawomir (Honeywell Process Solutions) | Srinivasan, Sridhar (Honeywell Process Solutions)
ABSTRACTInjection water/brine handling systems are important elements of the oil & gas field operations. Considering carbon steel as default material of construction for water/brine handling pipelines, a rapid determination of steels' corrosion is the key-element of the oil & gas field's integrity management. Daily, weekly or monthly- corrosion rate quantification with weight-loss coupons or permanent/periodic Ultrasonic Thickness (UT) measurements cannot provide reliable data that can be correlated to process upsets. Modern, on-line, real time corrosion monitoring technologies, including high resolution electrical resistance (ER) and multiple electrochemical methods such as Linear Polarization Resistance (LPR) or Electrochemical Noise (ECN) provide capabilities for corrosion detection in the matter of hours, minutes or seconds.Electrical Resistance technology depends on physical destruction of the sensing element. Simple correlations between corrosion rates, sensor's span (thickness), sensitivity and service life, lead to situations when high-resolution ER technology becomes operationally impractical due to requirements for frequent replacement of sensing element. Parallel, typical electrochemical measurements facilitated by LPR can be affected by e.g. presence of iron sulfide-based surface deposits that may engender depolarization of working electrode.Research undertaken by the authors' organization has demonstrated that simultaneous application of different electrochemical techniques ECN, Harmonic Distortion analysis (HDA) or Low Frequency Impedance (LFI), facilitates elimination of most of limitations related to traditional LPR. In this paper, research focused on evaluation of on-line, electrochemical corrosion monitoring, incorporating multi-technique approach in varied concentrations of NaCl brines, saturated with CO2 or CO2/O2 mixtures. Electrochemical corrosion data were compared with high- resolution ER technology and weight loss coupon data. This comparative study offers insights relevant to accuracy, sensitivity and responsiveness of different corrosion monitoring techniques in brine environment.INTRODUCTIONWater injection system is an integral part of oil and gas field production due to natural decay of formation pressure as field ages. In order to maintain high throughput of oil production, the utilization of water injection system may be as early as a few years after the field production is commenced. Any downtime of water injection system not only directly impact the oil production, but also poses a risk of irreversible changes in reservoir structure and inability to maintain the previously achieved pressure level after extended period of water injection downtime. In addition, the high pressure experienced in water injection system, especially downstream of the water injection pump, represents a significant concern to the safety of personnel and equipment. Maintaining integrity of water injection system poses a significant challenge to facility/corrosion engineers. This is mainly due to the difficulty of controlling oxygen ingress and micro-organism growth in the system. For systems utilizing carbon steel as the material of construction, it is imperative to implement online, real-time corrosion monitoring techniques so that any corrosion change can be captured in timely fashion and correlated with particular system upsets. That will allow informed decision to be made by corrosion engineers and remedial measures can be taken to prevent future corrosion incidents.
Storage and handling systems for concentrated (90-98%) sulfuric acid are traditionally designed from carbon steel. However, recent industry practices show an increased propensity for utilization of highly-alloyed stainless steels and nickel based alloys, primarily stemming from the need to overcome known limitations of carbon steel related to its susceptibility to erosion-corrosion at velocities above approximately 0.9 m/s. The austenitic stainless steels UNS(1) S31600/03 and nickel alloy UNS N08020 are usually used as the “first choice” materials due to their commonly accepted, high corrosion resistance in concentrated H2SO4 environment within temperature range 20°- 40°C at flow velocities varying from 0.9 m/s to 1.5 m/s. It is commonly believed that the true scalable hydrodynamic parameter in sulfuric acid alkylation is the wall shear stress which has a somewhat linear relationship to corrosion rate and can be easily calculated and/or predicted. However, experience has shown that UNSS31600/03 and UNS N08020 can occasionally exhibit unexpectedly severe corrosion due to instability of the passivation films responsible for their corrosion resistance. This phenomenon may have serious implications for field operability of those materials due to sudden appearance of active corrosion. A systematic study on the corrosion behavior of different materials varying from carbon steel to nickel alloys UNS N10276 and UNS N10675 was completed by the authors (during research program “Sulfuric Acid Alkylation JIP”†) in sulfuric acid with concentrations ranging from 87% to 99.5% at temperatures between 5°C and 40°C, with wall shear stresses ranging from zero (stagnant) to 300 Pa. The results were incorporated into a predictive model for sulfuric acid corrosion. A case study of actual failure of pipeline made of UNS N08020 in concentrated sulfuric acid service is presented and compared with the sulfuric acid corrosion model predictions.