Top Of Line Corrosion Research Articles

Transient modelling of water condensation rate for top of line corrosion

Top of line corrosion (TOLC) is typically a concern in the first few kilometres of wet gas pipelines where water in the warm gas condenses on the cold pipe walls. With the introduction of a subsea tieback to existing infrastructure, the changing fluid composition and temperature profiles may increase condensation in sections not previously expected to have condensation. Accurate prediction of the water condensation rate (WCR) becomes essential to support reliable corrosion modelling. Transient flow simulation of pipeline operating conditions and detailed heat transfer modelling is required to calculate the WCR. This calculation is complicated because the mass of water condensation is very small compared to the fluid mass in the pipeline, and sensitive to glycol that is often present in the aqueous phase for hydrate management purposes. This paper introduces a method to calculate WCR by using detailed transient modelling of the pipeline operating conditions. The fluid thermal hydraulic behaviour and hydraulic pressure drop in the pipeline are considered in the model. The fluid composition in the pipeline and glycol component in the aqueous phase are calculated by using a PVT software package. A few sensitivity studies will also be presented. The implications of Equation of State (EoS) and transient flow module on WCR calculation will be quantified. The WCR sensitivity results will be analysed based on varying inlet temperatures, glycol concentrations, and pipeline heat transfer coefficients. A WCR calculation method will be recommended for TOLC modelling.

Effect of the Water Condensation Rate with the Presence of Gas Condensate in the Wet Gas Pipeline

Pipelines are a common medium to transfer hydrocarbons, but their integrity is compromised by corrosion issues specifically in top of line corrosion (TLC) due to several influence factors such as water condensation. Water condensation occurs due to a significant variance in temperature outside the pipeline and inside the pipeline as water condenses in the inner pipeline. Hence, this paper aims to study the water condensation rate (WCR) behaviour in the presence of gas condensate in wet gas pipelines. The objectives of the research are to determine the components of the gas condensate by characterizing the gas condensate using Gas Chromatography-Mass Spectrometry (GC-MS) and Fourier-Transform Infrared Spectroscopy (FTIR) equipment and later to determine the effect of gas condensate on water condensation rate by conducting 2 different experiments. The condition of TLC was imitated by using a customized TLC testing unit, whereby 2 sets of API 5L X65 carbon steel coupons were used. Meanwhile, the delta temperature of the gas and steel obtained by regulating the temperature setting of the chiller and hot plate respectively enabled the water condensation process to be simulated. Throughout the 7-days of experiments, the gas and steel temperature were daily monitored and the water that only condensed on the surface of the coupons was collected and measured. Subsequently, the WCR was determined. The first objective was achieved as the result from GC-MS showed that there were 67 compounds in the condensate, and 5 functional groups were detected using FTIR, which confirmed that the gas condensate used in this experiment was similar to the gas condensate obtained from the pipelines. The second objective proved that condensate affected the water condensation rate, in which the WCR was reduced by about 73% with the presence of condensate. This WCR reduction is postulated because of the two different liquids (water and hydrocarbon) competing for the same surface area (top metal coupon) to condense.

Top-of-line corrosion via physics-guided machine learning: A methodology integrating field data with theoretical models

An artificial learning method for predicting top-of-line corrosion (TOLC) in oil/gas production from an existing oil field production data was presented, along with verifications and a few real-world applications. The developed algorithm was aimed to boost fundamental understanding of the day-to-day unit operations and periodic maintenance and inspection of oil/gas pipelines via a particular inline inspection technique (magnetic-flux-leakage measurements) and corrosion inhibitor applications. A recurrent neural network was utilized to establish a model for oil field production while a series of small neural networks representing the fundamental physics of TOLCs were included. The relevant physical models are those relating to (i) electrochemistry of corrosion mechanisms, (ii) gas–liquid phase flows and atomizations, and (iii) the condensation rates at the top of the lines. By incorporating these networks into the operation data, the developed learning algorithm gives accurate TOLC prediction for the complex oil field structures. The results show that the estimation models based on the physics-guided artificial neural network present the root-mean-square error within 10%. The developed software also offers insights into the essential parameters for the better prevention of the TOLC in pipelines.

Top of line corrosion in gas-condensate pipelines

Low alloyed carbon steel is the only viable material of construction for long pipelines transporting unprocessed gas-condensate. The water that condenses is highly corrosive because it contains dissolved acid gases, i.e., CO2, H2S and organic acids like acetic and formic acid. The high velocity gas also contains droplets of water and condensate, and these will deposit if they hit the steel surface. Monoethylene glycol (MEG) injected to prevent ice and hydrates must be considered when predicting the composition and corrosivity of the aqueous phases in the pipeline. The liquids gathering at the bottom of the pipe have a higher heat capacity than the gas, and the temperature at the top of the pipe will be slightly lower than at the bottom. As the produced fluids cool during the transport from the hot wells to the process plant, water will condense on the cold pipe surface and more at the top than at the bottom. The literature on Top-of-line corrosion (ToLC) has grown steadily since the first reported case in 1960. There are also several prediction models for ToLC. This review is an overview of the main factors that cause ToLC and how these are modelled. Mass transfer from the aqueous phase at the bottom to the top contribute to the condensation. Despite the low MEG to water ratio in the gas due to the difference in vapour pressure, the fraction of MEG in the condensing water may be considerable. The concentration of MEG in the aqueous phase at the top depends on the mass transfer from bottom. The same is the case for organic acids. Liquid droplets entrained in the gas may deposit top of line and contribute to the chemistry of the aqueous phase. Models for ToLC must thus not only predict the composition of the condensing phases but also the mass transfer to be able to estimate the corrosion rate.

The effect of volatile organic acids and CO2 on the corrosion rate of carbon steel from a Top-of-Line-Corrosion (TLC) perspective

Models for predicting top-of-line corrosion (TLC) rates on carbon steels are important tools for cost-effectively designing and operating natural gas transportation pipelines. The work presented in this paper is aimed to investigate how the corrosion rates on carbon steel is affected by acids typically present in the transported pipeline fluids. This investigation may contribute to the development of improved models. In a series of experiments, the corrosion rate differences for pure CO2 (carbonic acid) corrosion and pure organic acid corrosion (acetic acid and formic acid) on X65 carbon steel were investigated at starting pH values; 4.5, 5.3, or 6.3. The experiments were conducted in deaerated low-salinity aqueous solutions at atmospheric pressure and temperature of 65 °C. The corrosion rates were evaluated from linear polarization resistance data as well as mass loss and released iron concentration. A correlation between lower pH values and increased corrosion rates was found for the organic acid experiments. However, the pH was not the most critical factor for the rates of carbon steel corrosion in these experiments. The experimental results showed that the type of acid species involved and the concentration of the undissociated acid in the solution influenced the corrosion rates considerably.

The effect of ethanol added to the natural gas stream on the top of line corrosion: An approach on vapor phase condensation and carbonic acid generation yield

This study investigates the side effect of ethanol, added to the natural gas stream as hydrate inhibitor, on vapor condensation and top of line corrosion (TLC). The methodology presented allowed the measurements of both condensation and TLC rates under 1 barg and 8 barg CO2 partial pressures. Tests were performed without any hydrate inhibitor and with ethanol or monoethylene glycol (MEG) for comparison. Ethanol greatly reduced TLC rates, providing TLC rate inhibition efficiencies of at least 80% in the absence of acetic acid (HAc) and above 42% when HAc is present. Simulated data indicates ethanol concentration of 70% w/w in the condensates, indirectly reducing the conversion degrees of dissolved CO2 into H2CO3 (for instance, 0.01 instead of 0.12 at 8 barg in the absence of HAc). Also, the presence of ethanol reduces the dissociation of HAc into free H+ and Ac− when compared with other condensates. Therefore, indirectly, ethanol reduces the cathodic reactions’ rates and, hence, the anodic reaction rate. Additionally, ethanol changed the condensation mode from dropwise to Marangoni, which proved to be convenient since it probably provided low water concentration at the solid-liquid interface. These observations bring up the benefit of adding ethanol to the natural gas stream not only as hydrate inhibitor but also as a support for consolidated TLC prevention techniques.

Phase Equilibria of Acid-Gas Aqueous Systems (CO2, H2S, CH4, Water) and In-Situ pH Measurements in Application to Top-of-Line Corrosion

SummaryWe present thermodynamic modeling and pH measurements of fluid systems containing acid-gases (e.g., CO2 and H2S), water, and hydrocarbons—replicating the production and shutdown conditions in sour fields—for the purpose of evaluating top-of-line corrosion (TLC) and wellbore integrity and screening/selection of the proper wellbore materials. In particular:An equation of state (EOS) model using Peng-Robinson EOS in combination with the Huron-Vidal (HV) mixing rule for an aqueous subsystem is developed. In the model, subject EOS parameters are calibrated against existing thermodynamic data (saturation data for pure components and solubility data for binary systems) in literature. New in-situ pH measurement data are presented for a model system corresponding to a sour field. It was found that the wellbore can be subjected to pH levels as low as 2.7 with reservoir fluid containing 12 mol% CO2 and 88 mol% CH4 with downhole flowing conditions of 200 bar and 150°C and wellhead shut-in conditions of 300 bar and 4°C, as observed from the experiments. A modeling workflow is developed to estimate pH of the condensed water as a function of temperature and composition of the aqueous phase. The comparison between prediction and experimental measurement shows a very good match between the two (within pH ±0.1).Such studies (pH measurements and prediction) are not available in the literature but play important roles in material screening and assuring wellbore integrity for sour fields. More importantly, sensitivity analysis can be performed to investigate the effects of various factors (such as reservoir temperature/pressure, shutdown conditions, and compositions or extent of souring) on pH prediction. Furthermore, the methodologies developed through this work can also be extended to reservoir facilities, pipelines, sour gas disposal/handling units, and downstream systems such as water utilities, reactor plants, and refineries. The work can also support regulation/licensing for these sour systems.

CO2 Top-of-Line-Corrosion; Assessing the Role of Acetic Acid on General and Pitting Corrosion

Based on a review of both literature and field data, it is apparent that the role of acetic acid (HAc) in oilfield brines is both extremely complex and somewhat controversial. Although it is commonly believed that the presence of this organic compound enhances both the general and the localized corrosion rate of carbon steel, HAc has recently been reported to also act as a weak general corrosion inhibitor in specific aqueous environments. These observations prompted a study into whether such behavior is apparent in a CO2 top-of-line corrosion (TLC) scenario, i.e., when HAc dissolves into condensed water that forms on the upper internal wall of carbon steel pipelines during wet-gas stratified flow. Four different water condensation rates/temperature TLC conditions were selected to investigate the role of HAc on both the kinetics and mechanism of carbon steel dissolution. A miniature three-electrode setup was developed to characterize the real-time TLC response through the implementation of electrochemical measurements. Surface analysis techniques (microscopy and profilometry) were also performed to complement the electrochemical results. Collective consideration of the corrosion response and condensate chemistry indicates that similar effects were observed to those reported in the literature for bulk aqueous environments, in that the introduction of HAc can result in either accentuation or a minimal/inhibitive effect on general corrosion depending upon the operating conditions. The minimal/inhibitive effects of HAc were apparent at a surface temperature of 20.5°C and water condensation rate of 0.5 mL/m2·s, as no significant increase in corrosion was observed, despite a significant reduction in condensate pH being generated by the presence of HAc. X-ray photo-electron spectroscopy analysis of the inhibited steel specimen in the presence of HAc revealed the presence of iron acetate on the steel surface, which may have been at least partially responsible for the observed inhibitive effect. Extended duration experiments over 96 h revealed that both general and localized corrosion are not significantly affected by HAc addition at low temperature, whereas the level of degradation increases at higher surface temperature over longer periods.

Laboratory investigation on the condensation and corrosion rates of top of line corrosion in carbon steel: a case study from pipeline transporting wet gas in elevated temperature

ABSTRACTA glass cell was designed to simulate the condition for top of line corrosion encountered in wet gas transportation pipelines. Aqueous solution of 3 wt-% NaCl saturated with CO2 at atmospheric pressure was employed. Effect of temperature gradient in the formation of condensation and its rate was investigated. API 5L Grade X65 carbon steel material was used as the working electrode for the experiment. The condensation rate was measured for the temperature gradient of 20°C, 30°C and 50°C under atmospheric condition for 24 h duration of the experiment. The corrosion rate of the specimens was measured using weight loss and Linear Polarisation Resistance (LPR) techniques. The LPR probe was immersed in the collected condensed water from the experiment to calculate the corrosion rate. The measured corrosion rate from the weight loss technique was in agreement with the corrosion rate measured from LPR. The corrosion rate measurement was repeated with the addition of 1000 ppm of pH modifying agent. This study indicates that the corrosion rate of pipeline and piping when subject to temperature gradient of 50°C and above is very high and alarming.

Electrochemical and Molecular Dynamics Evaluation on Inhibition Performance of 2-(1-Methyl-Nonyl)-Quinoline

A novel vapor phase inhibitor, 2-(1-methyl-nonyl)-quinoline, was designed to cope with top-of-line corrosion (TLC) in wet gas pipelines and characterized via electrochemical measurements, scanning vibrating electrode technique (SEVT), surface analysis techniques, and molecular dynamics methods. 2-(1-methyl-nonyl)-quinoline showed parallel adsorption and was predominantly a cathodic-type inhibitor. The inhibition efficiency increased with temperature (30–50°C) and pH (4.15–5.76), and reached 97.25% at a concentration of 0.0282 mol/L. The SEVT showed that the average current density of the X80 steel specimen without inhibitor (anode region, 6.58087 µA/cm2) was about 2.5 times that of the other with inhibitor (cathode region, −2.61974 µA/cm2).

Corrosion behavior of novel 3%Cr pipeline steel in CO2 Top-of-Line Corrosion environment

CO2 Top-of-Line Corrosion (TLC) of carbon steel pipelines is a serious problem for wet gas transportation. We have studied the corrosion behavior of novel 3%Cr (3Cr) pipeline steel and conventional carbon steel (X70) in the simulated CO2 TLC environment. The composition and morphology of the corrosion scale are characterized by X-ray diffraction, energy dispersive X-ray spectroscopy and scanning electron microscopy analyses. The results indicate that 3Cr pipeline steel shows superior resistance to CO2 TLC, exhibiting uniform corrosion with duplex corrosion layer, while X70 suffers severe localized corrosion. It was suggested that the inner Cr enriched layer enhanced the protective ability of the scale to steel substrate and improved the resistance to localized corrosion in CO2 TLC environment.