Top of Line Corrosion Testing for a Gas Field with Acetic Acid and Low CO 2

Transcription

1 Paper No Top of Line Corrosion Testing for a Gas Field with Acetic Acid and Low CO 2 Gaute Svenningsen and Rolf Nyborg Institute for Energy Technology P.O. Box Kjeller Norway Lucia Torri, Tiziana Cheldi and Paolo Cavassi ENI, Materials and Corrosion Technologies Dpt. Via Emilia 1, San Donato Milanese (MI) Italy ABSTRACT Top of line corrosion (TLC) was studied in a flow loop under conditions representative for a gas field with a low CO 2 partial pressure of 0.35 bar and presence of acetic acid in the gas. The temperature in the experiments was 60 and 90 C, and Mono Ethylene Glycol (MEG) was present in the bulk aqueous phase. The water condensation rates used in the experiments were calculated from multiphase flow simulations for the planned pipelines. The experimental results showed that the condensed water contained both MEG and acetic acid. With this low CO 2 partial pressure, the organic acids gave a significant contribution to the overall TLC rate. At C and high acetic acid, the TLC rates were 0.13 mm/y. When the organic acid content was reduced by 90 % the TLC rates were reduced with approximately 50 %. At 60 C the condensation rates were lower but the iron solubility higher, and the TLC rate was 0.11 mm/y. Investigation of exposed corrosion coupons showed that a partly protective film of iron carbonate corrosion products had formed on the surface. The surface film reduced the TLC rate but did not provide full protection. The TLC rates measured in the experiments were lower than modelled TLC rates for cases with high organic acid content, showing that the TLC model was on the conservative side for such cases. Key words: Top of line corrosion, TLC, acetic acid 1

2 INTRODUCTION Background This paper presents TLC work that was carried out in connection with a gas field with a low CO 2 partial pressure of 0.35 bar and presence of organic acid. It is planned to use mono ethylene glycol (MEG) to prevent hydrate formation. Organic acids may accumulate in the MEG cycle, and this effect was included when the experimental content of organic acids was selected. TLC basics Wet gas pipelines with stratified flow are susceptible to top of line corrosion (TLC) since the upper pipe section cannot be effectively protected by conventional corrosion inhibitors in the bulk aqueous phase. 1-7 As long as H 2 S is not present, the corrosion mode is CO 2 corrosion (Equation 1). Several models for predicting TLC rates have been developed and condensation rate and iron solubility are recognized as two important parameters. 1,8-10 The TLC model developed by Nyborg and Dugstad 1 is based on the corrosion rate being limited by the amount of iron that can be transported in the condensed water. 1-4 Therefore, the TLC rate is proportional to both the condensation rate and to the iron solubility of the condensed water (Equation 2). Since the precipitation of iron carbonate is kinetically slow, particularly at low temperatures, the model includes an empirical expression for supersaturation (Equation 3). H 2 CO 3 + Fe Fe 2+ + CO H 2 (1) CR = k R Cond C Fe S where CR is the corrosion rate (mm/y) (2) k is a constant (0.223 mm/y m²s/g kg/mmol), R Cond is the condensation rate (g/m²s), C Fe is iron solubility (mmol/kg) in the condensed water and S is the supersaturation ratio S = T where T is temperature in C (3) If organic acids are present in the pipeline, a fraction of them will be present in the gas phase and condense together with water and make the condensed water even more acidic (lower ph), as shown in Equation 4. RCOOH (g) RCOOH (aq) RCOO - (aq) + H + (aq) (4) where R is hydrogen (formic acid) or an alkene group. Lower ph means that the iron solubility increases and thus the TLC rate will also increase. It is therefore important that organic acids are included when TLC is evaluated. As top of line corrosion takes place, alkaline species (bicarbonate, carbonate) are produced, making the condensed water less acid with higher ph (Equation 1). The additional alkalinity can stimulate additional absorption of organic acids, since Equation 4 is shifted to the right. Consequently even more iron carbonate can be dissolved in the condensed water. The effect of organic acids on TLC has been discussed in several related conference papers. 3-5 It is generally accepted that the presence of organic acids increases the TLC rate

3 EXPERIMENTAL PROCEDURE Flow loop A gas circulating flow loop was used for the TLC testing. Schematic drawings and images of the loop setup are shown in Figure 1, Figure 2 and Figure 3. Moist gas was circulated from tank 2 (high pressure reservoir), through the test sections and back into tank 1 (low pressure reservoir) where a water/gas ejector system pumped the gas/liquid back to the high-pressure reservoir, tank 2. An ejector system ensured complete equilibrium between liquid and gas. Three test sections (section 1, section 2 and section 3) of 1.8 m long carbon steel pipes with 51 mm inner diameter were mounted in series, as illustrated in Figure 2. Note that only the results of section 1 are reported in the present work. To avoid corrosion on the bottom of the pipe, the bottom segment of the test pipe was painted (covering ca. 20 % of the internal surface area). The test sections were tilted slightly in the flow direction to direct the condensed water to the water sampling point. The condensation rate of each section was individually adjusted by an external cooling coil. A more detailed description of the loop and test system is given in a previous paper. 3 Test material The test sections were 1.8 m long seamless hot rolled carbon steel pipes. The outer diameter was 76 mm and the inner diameter 51 mm. The steel is designated S355J2H/E355+N with the chemical composition given in Table 1. The steel was normalised at 920 C followed by air cooling. Table 1: Chemical composition of the test sections. E = Electric furnace steelmarking process Schmelze / Heat No / No coulée Erschmelzungsart / Melt practice / Mode d elaboration : C % Si % Mn % P % S % Cu % Cr % Ni % Mo % V % N % Al % Nb % As % Sn % Ti % Co % Ca % Zr % B % W % CEV% J-Faktor Measurements and chemical analysis The condensation rate was measured by regular volumetric measurements of the condensed water on each test section. The condensed water was analysed for dissolved Fe 2+ (using a photospectrometer), organic acid content (using ion chromatography) and MEG content (using refraction index). NaCl (1g/kg) was added the loop liquid to monitor possible droplet carry-over from the tank. Cross sections of the exposed test sections (cut-outs from top of the line) were investigated with scanning electron microscope (SEM) and the chemical composition of the corrosion products was analysed by energy dispersive X-ray spectroscopy (EDS). Corrosion rate calculations Due to the massive size of the test sections it was not possible to obtain accurate direct mass loss measurements. The corrosion rate was therefore calculated as the sum of dissolved iron in the condensed water (Corrosion rate A) and the amount of iron remaining in the corrosion products on the steel surface (Corrosion rate B), as described in a previous paper. 3 The condensed water was collected and quantified at regular intervals. The iron concentration in the condensed water was analysed several times a week by a photospectrometric method. The painted area on each test section was accounted for in the calculation of corrosion rate A. 3

4 Figure 1: Schematic drawing of the TLC flow loop. Figure 2: Schematic drawing of test sections and collectors for condensed water. (a) Loop tank 1 (b) Test sections with insulation (c) External cooling coil Figure 3: Images of the flow loop. 4

5 Test conditions Table 2 gives an overview of the experimental parameters for the loop experiment. The temperature and organic acid content were varied, resulting in a combination of high temperature and high organic acid content (TLC1), high organic acid content and low temperature (TLC2) and high temperature and low organic acid content (TLC3). Table 2: Overview of experimental parameters. Parameter TLC1 TLC2 TLC3 Exposure time (days) Temperature in the loop tanks( C) CO 2 partial pressure (bar) Bulk MEG content (wt. %) Bulk formic acid (mmol/kg) Bulk acetic acid (mmol/kg) Gas flow velocity (m/s) Test material Carbon steel Carbon steel Carbon steel Chemical modelling MultiScale 1 software was used for calculating iron solubility in the condensed water. The measured temperature (average over the whole test section) and measured chemical composition (organic acids, MEG content etc.) and the applied CO 2 partial pressure was used as input values. RESULTS A summary of the experimental results is shown in Table 3. The TLC rates were 0.13 mm/y for TLC 1 but decreased to mm/y when the organic acid content was reduced (TLC3). The TLC rate of the low temperature experiment TLC2 was 0.11 mm/y even though the condensation rate was much lower than for TLC1. The concentration of dissolved iron (Fe 2+ ) in the condensed water dropped gradually during the experiments and approached a stable level after 5 10 days (Figure 4). This effect was most pronounced for TLC1 and TLC2, while the change was significantly less for TLC3. The concentration of organic acids followed essentially the same trend with initially high values that decreased with time (Figure 5). Analysis of chloride in the condensed water showed no significant carry-over of droplets from the loop tank. The exposed samples were mostly covered with a thin layer of corrosion product (up to 15 μm thickness) consisting of FeCO 3. The inlet-side of TLC1 had areas that were not covered with any corrosion products. The corrosion products were often cracked and porous. Localised corrosion attacks (15 80 μm deep pits) were also observed. SEM images of exposed test sections with corrosion products are shown in Figure 6 and a summary of the corrosion morphology is given in Table 4. The surface layer were 1 Trade name, see 5

6 Table 3: Summary of the experimental results. Parameter TLC1 TLC2 TLC3 Section inlet temperature ( C) Section temperature drop ( C) Condensation rate # (g/m²s) Condensed water composition (average values) MEG content (wt. %) Formic acid + formate(mmol/kg) Acetic acid + acetate (mmol/kg) Organic acids (mmol/kg) Dissolved Fe 2+ Average (mmol/kg) Plateau (mmol/kg) Surface film (mg/cm²) Film thickness (SEM) (μm) TLC rate from average Fe 2+ Corrosion rate A* (mm/y) Corrosion rate B* (mm/y) TLC-rate (mm/y) # Condensation rate reported as sum of water and MEG. Sum of formic acid + formate + acetic acid + acetate. * Corrosion rate A is based on dissolved iron in the condensed water. Corrosion rate B is based on iron present in the corrosion product on the sample surface. Fe2+ content (mmol/kg) TLC1 TLC2 TLC Exposure time (days) Figure 4: Content of dissolved Fe 2+ in the condensed water. 6

7 Formic acid + Formate (mmol/kg) TLC1 TLC2 TLC3 Acetic acid + Acetate (mmol/kg) TLC1 TLC2 TLC Exposure time (days) Exposure time (days) Figure 5: Content of formic acid + formate (left) and acetic acid + acetate (right). 7

8 (a) TLC1: High temperature and high organic acid (b) TLC2: Low temperature, high organic acid. (c) TLC3: High temperature, low organic acid. Figure 6: SEM images of exposed corrosion coupons (cross sections from the 12 o clock position) at low (left) and high (right) magnification. 8

9 Table 4: Properties of surface films (corrosion products) on exposed test sections. Thickness Constituents Morphology (μm) TLC FeCO 3 Mostly continuous surface layer, but only patches of corrosion products near pipe inlet. Corrosion products are porous/needles. Localized corrosion (20-80 μm deep). TLC FeCO 3 Continuous adherent film with pores. Sometimes with cracks or voids under the film. Initial steel surface visible. Traces of iron carbide from initial steel visible present in the film. Localized corrosion (15-30 μm deep). TLC FeCO 3 Thin continuous porous layer with voids. Localized corrosion attacks (30-50 μm) filled with corrosion products. DISCUSSION The experimental results showed that with a low CO 2 partial pressure of 0.35 bar, the TLC rate can be up to 0.06 mm/y under the conditions tested here, and up to 0.13 mm/y if organic acids are present. Both experiments with high organic acids (TLC1, TLC2) showed initially very high concentrations of Fe 2+ that decreased with time and reached a relatively stable level after a few days. This is related to the build-up of a partly protective surface layer of iron carbonate that reduced but did not stop top of line corrosion. This is further supported by the presence of iron carbonate films on the exposed steel surfaces (Figure 6). Thin but apparently protective film formed rapidly since the corrosion rate was low. The condensed water contained significant amount of organic acids, and the concentration was higher than what would be expected from chemical equilibrium with the bulk phase (condensed water without corrosion products would have essentially the same organic acid concentration as the aqueous bulk phase). This is most likely related to the alkaline corrosion products (Equation 5) that can react with the organic acids (Equation 6) and cause additional absorption of organic acids (Equation 7). Fe (s) + 2 H 2 CO 3 (aq) = Fe 2+ (aq) + 2 HCO - 3 (aq) + H 2 (g) (5) RCOOH (aq) + HCO - 3 (aq) RCOO - (aq) + H 2 CO 3 (aq) (6) RCOOH (g) RCOOH (aq) (7) Due to the reaction stoichiometry, one corroded iron specie (Fe 2+ ) produces two alkaline species (HCO 3 - ), and there is a good correlation between iron concentration and 2x organic acid concentration (Figure 7). This illustrates the importance of including organic acids in the TLC testing (and modelling). The concentration of organic acids in the gas phase is low and the organic acids will rapidly be depleted if they are not resupplied. However, TLC is usually most severe near the pipeline inlet, where the organic acids are not depleted. The question of depletion and possible resupply is therefore most relevant for the rest of the pipeline. Depletion of organic acids in the gas phase was also observed in the flow loop (results not shown here). It should also be noticed that MEG condensed together with water, but at a concentration that was less than the bulk content. Furthermore, it was rapidly depleted along the flow direction (results not shown) as also observed previously. 7 This indicates that MEG also will condense together with water in field pipelines, but without MEG resupply (e.g. by evaporation from the bulk phase) the MEG vapour will rapidly be depleted from the gas phase. Flow-enhanced droplet formation may increase MEG transport 9

10 to the gas phase, while the presence of an oil or condensate layer over the aqueous phase may reduce such transport. 4,15 The experimental results were compared with Nyborg and Dugstad s TLC model. 1 Chemical modelling was performed to calculate the condensed water chemistry and iron solubility (Table 5). The results are plotted in Figure 8, showing a good match for the case with low organic acids (TLC3), while the model is overpredicting with a factor of 3 for the high organic acid cases (TLC1, TLC2). The TLC model is conservative since it does not account for possible formation of protective surface films, but in this case with low CO 2 and high organic acid, the conservatism is too high. This could indicate that the supersaturation factor, an empirical relationship developed for a pure Fe CO 2 H 2 O system 1, may be affected by high concentrations of organic acids. The results of previous for previous TLC experiments carried out at 85 C with 10 bar CO 2 and high acetic acid (7-30 mmol/kg) 3 is also included in the comparison. For these experiments the model overpredicted with a factor of 1.2 to 3, further supporting the need for reviewing the effect of organic acids in the TLC model. Fe2+ content (mmol/kg) TLC1 TLC2 TLC3 TLC1 TLC2 TLC Exposure time (days) Total organic acids (mmol/kg) Figure 7: Comparison of measured Fe 2+ (solid lines) and measured organic acids (markers). Note the difference in scale height, the organic acids content is 2 x the Fe 2+ content. 10

11 Table 5: Input data for the chemical modelling used in the TLC model. TLC1 TLC2 TLC3 Temperature ( C) CO 2 partial pressure (bar) MEG content in condensed water (wt.%) Total organic acid in cond. water (mmol/kg) Fe 2+ solubility in cond. water* (mmol/kg) Supersaturation ratio Condensation rate (g/m²s) Modelled TLC-rate (mm/y) Experimental TLC rate (mm/y) * Chemical modelling software using measured composition as the composition of the condensed water Experimental TLC rate (mm/y) Linear 1:1 TLC1 TLC2 TLC3 Previous work Modelled TLC rate (mm/y) Figure 8: Comparison of modelled (x-axis) and experimental (y-axis) TLC rates. The previous TLC experiments (black markers) were carried out at 85 C with 10 bar CO 2 and 7-30 mmol/kg acetic acid in the condensed water. 3 11

12 CONCLUSIONS Three TLC flow experiments were carried out to simulate field pipeline conditions. The TLC rate varied significantly with the temperature/condensation rate and the concentration of organic acid. At high temperature (84 C, 0.13 g/m²s) the TLC rate was 0.13 mm/y, but it was reduced with almost 50 % when the organic acid content was reduced 80 %. This is related to the organic acids increasing the iron solubility in the condensed water. At lower temperature (56 C) and lower condensation rate (0.054 g/m²s) the TLC rate remained high at 0.11 mm/y since the iron solubility increases when the temperature decreases. Increased iron solubility was essentially compensating for reduced condensation rate. The experimental results were in good agreement with the modelled TLC rates for low organic acid concentrations, while the model was conservative with a factor about 3 for high amounts of organic acid. It should be noted that the model was developed primarily for cases without organic acid, and this might indicate a need for reviewing the model for cases with low CO 2 content and high amounts of organic acids. ACKNOWLEDGEMENTS The authors would like to thank Eni and Universal Pegasus International for the permission to publish the present work. REFERENCES 1. R. Nyborg, A. Dugstad, "Top of line corrosion and water condensation rates in wet gas pipelines," CORROSION/2007, paper no (Houston, TX: NACE International, 2007). 2. R. Nyborg, A. Dugstad, T.G. Martin, "Top of line corrosion with high CO2 and traces of H2S," CORROSION/2009, paper no (Houston, TX: NACE International, 2009). 3. G. Svenningsen, M. Foss, R. Nyborg, H. Fukagawa, "Top of line corrosion with high CO2 and organic acid," CORROSION/2013, paper no (Houston, TX: NACE International, 2013). 4. G. Svenningsen, R. Nyborg, "Modeling of top of line corrosion with organic acid and glycol," CORROSION/2014, paper no (Houston, TX: NACE International, 2014). 5. T.R. Andersen, A.M.K. Halvorsen, A. Valle, G.P. Kojen, A. Dugstad, "The influence of condensation rate and acetic acid concentration on TOL-Corrosion in multiphase pipelines," CORROSION/2007, paper no (Houston, TX: NACE International, 2007). 6. Y.M. Gunaltun, D. Larrey, "Correlation of cases of top of line corrosion with calculated water condensation rates," CORROSION/2000, paper no (Houston, TX: NACE International, 2000). 7. R. Nyborg, A. Dugstad, L. Lunde, "Top-of-the-line corrosion and distribution of glycol in a large wet gas pipeline," CORROSION/93, paper no. 77 (Houston, Texas: NACE International, 1993). 8. Z. Zhang, D. Hinkson, M. Singer, H. Wang, S. Nesic, "A mechanistic model of top of the line corrosion," CORROSION/2007, paper no (Houston, TX: NACE International, 2007). 12

13 9. U. Kaewpradap, M. Singer, S. Nesic, S. Punpruk, "Top of the line corrosion - Comparison of model predictions with field data," CORROSION/2012, paper no (Houston, TX: NACE International, 2012). 10. U. Kaewpradap, M. Singer, S. Nesic, S. Punpruk, "Comparison of model predictions and field data The case of top of the line corrosion," CORROSION/2015, paper no (Houston, TX: NACE International, 2015). 11. J. Amri, E. Gulbrandsen, R.P. Nogueira, "Role of acetic acid in CO2 top of the line corrosion of carbon steel," CORROSION/2011, paper no (Houston, TX: NACE International, 2011). 12. P.C. Okafor, S. Nesic, "Effect of acetic acid on CO2 corrosion of carbon steel in vapor-water twophase horizontal flow," Chemical Engineering Communications 194, 2 (2007): pp M. Singer, D. Hinkson, Z. Zhang, H. Wang, S. Nesic, "CO2 top-of-the-line corrosion in presence of acetic acid: A parametric study," Corrosion 69, 7 (2013): pp M. Singer, S. Nesic, Y. Gunaltun, "Top of the line corrosion in presence of acetic acid and carbon dioxide," CORROSION/2004, paper no (Houston, TX: NACE International, 2004). 15. R. Nyborg, A. Dugstad, L. Lunde, "The effect of gas velocity on glycol distribution and top-of-theline corrosion in large wet gas pipelines," 6th International Conference on Multi Phase Production (London, UK: Mechanical Engineering Publications, 1993). 13