Monday, 27 July. A Severe Top of the Line Corrosion Case Study Presented by: Ussama, PTTEP

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1 Schedule at a Glance The following technical program is correct at time of publishing. However, given the seniority of our speakers and the nature of their roles, speakers may subsequently substitute or remove themselves from the program. This is always regrettable, and we will always try to replace the speaker with a speaker with equivalent insight. 8:30 8:40 8:40 8:50 Monday, 27 July Welcome Speech Presented by: Marc Singer, TOL Conference Technical Chair Opening Speech Presented by: Michelle Lau, NACE East Asia and Pacific Area Director 8:50 9:00 Opening Ceremony 9:00 9:50 9:50-10:25 Keynote Presentation Managing Top of Line Corrosion: Just Take the Lead! Presented by: Michel Bonis, Total Designing for Top of Line Corrosion Management in Deepwater Subsea Gas Condensate Flowlines Presented by: Sivakumar Subramanian, Chevron 10:25 10:45 Break 10:45 11:20 11:20 11:55 11:55 12:30 A Severe Top of the Line Corrosion Case Study Presented by: Ussama, PTTEP TLC Study, Mitigation and Inspection in TEPI Presented by: Edi Sikumbang, TOTAL Success Story and Lesson Learn To Reduce Corrosion Rate by Corrosion Inhibitor Selection in Offshore Field Edyos Saleppang, Chevron 12:30 13:30 Lunch 13:30 14:05 14:05 14:40 14:40 15:15 Operational Challenge in Managing Top of Line Corrosion for 26 BOC - BOD Pipeline Presented by: Ajie Manggala Putra, Talisman 26 BOC - BOD Pipeline Replacement Presented by: Ajie Manggala Putra, Talisman Internal Corrosion Risk Assessment of Offshore Pipeline and TLC Analysis Presented by: Feng Cai, Safetech Research Institute 15:15 15:35 Break 15:35 16:10 16:10 16:45 Combined ILI Technology Approach for Monitoring Pipelines with Top of Line Corrosion and CRA Layer Presented by: Olaf Stawicki, Rosen NACE TCC International Initiative Presented by: Khlefa Esaklul, Occidental Oil and Gas Corp. 18:00 20:00 Welcome Dinner Top of the Line Corrosion Conference Final Program 10

2 9:00 9:50 9:50-10:25 Tuesday, 28 July Keynote Presentation Study of the Localized Nature of Top of the Line Corrosion Presented by: Marc Singer, Ohio University Modelling Top of the Line Corrosion in Gas with CO 2 and Organic Acid Presented by: Gaute Svenningsen, IFE 10:25 10:45 Break 10:45 11:20 11:20 11:55 11:55 12:30 Are Condensation Rate and Corrosion Rates Proportional in TLC? Presented by: Md Islam, Curtin University The Localized Corrosion Mechanism of X70 Steel in CO 2 Top-of-line Corrosion Environment Presented by: Yunan Zhang, Univ. of Sci. & Tech. Beijing An Innovative Design for Top of Line Corrosion & Assessment in Laboratory Presented by: Hesham Mahmoud Shehata, Enppi Engineering for the Petroleum and Process 12:30 13:30 Lunch 13:30 14:05 14:05 14:40 14:40 15:15 Effect of Monoethylene Glycol on Sweet Top of the Line Corrosion Presented by: Fernando Farelas, Ohio University The Inhibitive Effect of Mono Ethylene Glycol on Sweet Top of the Line Corrosion Presented by: Thunyaluk Pojtanabuntoeng, Curtin University Localized Top of the Line Corrosion in Marginally Sour Environments Presented by: Najmiddin Yaakob, Ohio University 15:15 15:35 Break 15:35 16:10 16:10 16:45 9:00 9:50 9:50-10:25 Sensitivity Analysis of TLC Mechanism Based on Segmented Pipeline Simulation Approach Presented by: Wong SY, PT. Synergy Engineering Methodology for Comparing Model Predictions with Field Data Special Case of Top of the Line Corrosion Presented by: Sandra Hernandez, Chevron Wednesday, 29 July Keynote Presentation Challenges Associated with the Development, Testing and Application of Top-of-Line Corrosion Inhibition Presented: Alyn Jenkins, MI-Swaco Enhanced Pipeline Integrity Through Proactive TOL Corrosion Mitigation Presented by: Laorta Thanachaiwiwat, Chevron 10:25 10:45 Break 10:45 11:20 11:20 11:55 Top of the Line Corrosion Inhibitor Development Presented by: Tong eak Pou, Ceca Inhibition Mechanisms for CO 2 Corrosion Mitigation by Amines at the Top-of-the-line Presented by: Zineb Belarbi, Ohio University 12:00 12:30 Closing Ceremony 11 Top of the Line Corrosion Conference Final Program

3 Technical Session Descriptions Monday, 27 July 8:30 8:40 Welcome Speech Presented by: Marc Singer, TOL Conference Technical Chair 8:40 8:50 Opening Speech Presented by: Michelle Lau, NACE East Asia and Pacific Area Director 8:50 9:00 Opening Ceremony 9:00 9:50 Keynote Presentation Managing Top of Line Corrosion: Just Take the Lead! Presented by: Michel Bonis, Total A young corrosion engineer working on a gas producing asset comes to face an on-going TLC issue on a wet gas pipeline in service for 3 years. At the same time he is questioned about the design of a new wet gas pipeline, potentially subjected to same TLC! My God: I know nothing on this TLC! Do you? Time to go to the literature and call few colleagues! An opportunity to introduce the main aspects of TLC through a series of questions that an Operator will certainly ask when facing such situation: Why did it occurred? What did we do wrong? What are the leading factors? How quick does it progresses? May it fail one day? When? What can we do to control this corrosion? Will it work well? How do we make sure it works? What if it does not? What do we do now for new pipelines? From these questions, TLC mechanisms, prediction rules, mitigation solutions and inspection/ monitoring means are covered by our Corrosion Engineer: Will he prove his leadership capabilities in this situation? 9:50-10:25 Designing for Top of Line Corrosion Management in Deepwater Subsea Gas Condensate Flowlines Presented by: Sivakumar Subramanian, Chevron Top of line corrosion (TOLC) risk has been assessed for subsea flowlines and subsea equipment in a deepwater gas condensate field. Stratified gas-liquid flow regime is expected in majority of the flowlines due to seafloor bathymetry, fluid velocities, and low in-situ volume fractions of liquid being produced. Planned subsea wellhead injection of a cocktail of hydrate inhibitor MEG and Film forming corrosion inhibitor (FFCI) is expected to be insufficient to protect the top of the flowline but sufficient to protect the bottom of the flowline and the risers connecting the flowlines to the continued on next page Top of the Line Corrosion Conference Final Program 12

4 floating production unit. Presence of organic acids in the flowstream from expected formation water composition and regenerated hydrate inhibitor MEG composition injected subsea contributes additionally to a heightened risk. This called into question the adequacy of the carbon steel basis of design for the flowlines and subsea equipment like flowline jumpers and PLETs. Through collaborative work between company subject matter experts (SMEs), external SMEs, and project team members, we were able to do an in-depth systematic modeling study of the risk posed and test solutions such as increased thickness of external coating (polypropylene) to mitigate the risk. This presentation will discuss the evolution of the TOLC risk assessment for the project since 2011, the engineering workflow adopted by the team to reduce conservatism, the rigor in understanding and defining model inputs, and the life of field approach used to determining cumulative metal loss. The conclusions of the in-depth studies support the continued use of carbon steel flowlines (instead of CRA based solutions) in the design basis with some modifications. 10:25 10:45 Break 10:45 11:20 A Severe Top of the Line Corrosion Case Study Presented by: Ussama, PTTEP Gas fields in the Gulf of Thailand have pipelines transporting multiphase wet gas containing corrosive agent. And several lines have been operating in stratified flow regimes at low gas velocity which leads to several Top of the Line Corrosion (TLC) cases. Bongkot field operated by PTTEP is one of those fields where TLC is a prominent issue. Majority of pipelines has been detected TLC by intelligent pigging. Two pipelines had failure history due to cold spot corrosion which occurs on small pipe surfaces where the water condensation rates are locally very high compared to the surrounding pipe in 2008 and Nevertheless, with highly severe TLC condition containing high inlet temperature, CO 2 content and operating in stratified flow regime since the production started-up, a developed TLC mitigation program could not sufficiently protect one of the previous leak pipelines. The line was reportedly leaked in In August 2013, pin hole leak was found. The leak point was located at 3 o clock between previous two clamps repair. The leak was repaired by installing PICCO clamp. At end of November 2013, another leak was reported at the same line. The ROV preliminary survey conducted immediately found two leaks located in the area of previous repairs. The leaks were also located at the 3 and 4 O clock position. The decision to stop production and replace the first 2 km section was considerably made. There was a concern whether the leak was internal or external corrosion. In May 2014, the replacement process was completed. The cut section for 100 m. was recovered for the root cause investigation. The investigation showed that the leak is obviously from internal corrosion. After cutting for further investigation, it was found that most of the significantly corroded features are located between 8-4 o clock (clockwise) positions. While bottom of the pipeline where corrosion inhibitor continuously injected was perfectly protected. The operating condition from the started-up was reviewed to determine the level of liquid in the pipeline. The results show low water gas ration (WGR) which indicate the low level of liquid for this pipeline. The root cause of this case was attributed to the water condensation in presence of high corrosive agents and low flow velocities not only the top part but also so the side of the pipeline where it was possible for water to condense. After the leaks, the full TLC mitigation and control programs below have been intensively developed: Batch treatment (BT) program Splash pig had been started since However, the frequency to control TLC development was not optimized. Nevertheless, due to the production constraint the BT frequency was hardly been followed. In 2013, the BT frequency was revised as recommended from Pipeline Integrity Management (PIM) study to maintain the pipeline integrity last long to the end of concession. The new BT frequency has been optimized. Volatile corrosion inhibitor (VCI) The efficiency of BT is questionable as it is hardly to follow recommended frequency. VCI has been studied to be an alternate TLC mitigation solution. PTTEP has been studied the possibility of using VCI since the first leak was detected in Currently, field trial for VCI efficiency and performance test 13 Top of the Line Corrosion Conference Final Program

5 has been conducted for selected sealines since April The field trial result by MFL pigging will be evaluated after 2 years (2015). TLC mattress installation pilot project the pilot project has been started since Firstly, the mattress was install externally on the cold spot or hot end areas to reduce the heat transfer rate between the pipe and outside seawater, attempting to minimize the TLC rate inside the pipe. To evaluate the mattress performance, temperature underneath the installed mattress has been surveyed. Overall temperature gain was observed over the insulated section. Reducing rapid temperature loss by convection in the pipeline horizontal section will reduce the overall water condensation rate which is the key to this mitigation technique. 11:20 11:55 TLC Study, Mitigation and Inspection in TEPI Presented by: Edi Sikumbang, TOTAL Total E&P Indonesie (TEPI) - since the project phase - had studied several pipelines prone to Top of line corrosion (TLC). Parameters determining TLC such as temperature difference between fluid and pipeline environment, water gas ratio (WGR), flow regime, water condensation rate (WCR) and fluids properties then continuously assessed during field operation phase. Based on the assessment result, the proper and economic TLC mitigation such as additional pipeline corrosion allowance, thermal insulation, pig cleaning-spray pigging or Volatile Corrosion Inhibitor (VCI) is selected. Monitoring of TLC rate and Mitigation effectiveness by intelligent pigging inspection is a part of the strategic efforts to control its rate, in conjunction with TLC mitigation i.e. regular pig cleaning & spray pigging and VCI. A series of intelligent pigging for TLC monitoring has been applied in TEPI for several specific pipelines. The presentation will show in general, TLC evolution in the A pipeline following its latest intelligent pigging inspection in Stabilization of TLC growth is observed generally with the decrease of the level of corrosion activity when compared to the previous intelligent pigging inspection. However, active TLC growth is still identified in certain points. 11:55 12:30 Success Story and Lesson Learn To Reduce Corrosion Rate by Corrosion Inhibitor Selection in Offshore Field Edyos Saleppang, Chevron Chevron Indonesia Company, which located in Kalimantan, has been in operation since early 1970 s. It has more than 150 pipelines, where 90% of them are located in offshore and one of it is 12 multiphase line Victor Platform to Sepinggan Production. Currently Victor platform production is 20,000 BLPD with an average of Basic Sediment & Water (BS&W) = 80% and Victor p/f is contributor 50% of total gross production from Sepinggan field. Based on In Line Inspection results by smart pigging execution on January 28, 2014 found that is mostly defects occur as internal corrosion and the deepest point are 71% at the bottom and 49% at the top of the line. Internal corrosion found on subsea pipeline due to presence of CO 2 when fluid from Victor p/f to Sepinggan Production is consists of gas, water, oil, and solid with CO % in phase gas. Refer to De Waard Milliams equation to predict corrosion rates can be determined CO 2 partial pressure (P CO 2 ); 30 Psi, it mean corrosion is most likely to occur. Meanwhile the corrosion rate refer to the corrosion monitoring by coupon reading with period from July 2013 to June 2014 is max 54 mpy equal to 1.37 mm/year on April 2014, so the remaining life or leaking probability will occur within 10 months with assumed corrosion rate is linear. As long as this period corrosion inhibitor (CI) type that have used is Single Amine (code KI-384) with history following as: Initial CI injection 15 GPD resulted corrosion rate mpy Increase of CI injection till 20 GPD resulted corrosion rate 7.37 mpy Increase of CI injection till 25 GPD resulted corrosion rate mpy After evaluate corrosion inhibitor treatment periodically we have decided to replace single amine type become double amine type (KI-3063) with initial injection 25 GPD on June 2014 resulted corrosion rate 0.18 mpy. After that we have reviewed and evaluated to decrease injection dosage 20 GPD on January 2015 result corrosion rate 0.15 mpy categorized as low corrosion rate refer to NACE 775. Based on this result we have performed to reduce corrosion rate continued on next page Top of the Line Corrosion Conference Final Program 14

6 from severe till low successfully. Key success of this method is to replace of corrosion inhibitor type from single amine to double amine and maintain of injection dosage regarding to optimize and determine effectiveness and efficiency of chemical inhibitor. 12:30 13:30 Lunch 13:30 14:05 Operational Challenge in Managing Top of Line Corrosion for 26 BOC - BOD Pipeline Presented by: Ajie Manggala Putra, Talisman 26 BOC BOD pipeline was designed to transport high temperature wet gas operating at C and 50 barg operating pressure. Along with high CO 2 level of 30% to 40%, this pipeline is exposed to a corrosive environment and presence of Top of Line Corrosion (TLC) was expected. Severe TLC was only confirmed from the 3rd Intelligent Pigging inspection in November Previous intelligent pigging in April 2009 and August 2010 provided inconclusive indication of TLC threat for this pipeline. Due to various constraints, TLC mitigation plan for this pipeline could not be executed at its highest level. Inline Inspection accuracy adds a challenge in term of monitoring the progress of TLC and assessment to the integrity of the pipeline requiring extra effort to be taken in order to have a reliable data and assessment result. This paper will provide an overview to Talisman Malaysia s experience in managing TLC in and maintaining the integrity of the 26 BOC BOD pipeline, including identified challenges, lesson learnt and room for improvement. 14:05 14:40 26 BOC - BOD Pipeline Replacement Presented by: Ajie Manggala Putra, Talisman 26 BOC BOD pipeline was designed to transport high temperature wet gas operating at C and 50 barg operating pressure. Along with high CO 2 level of 30% to 40%, this pipeline is exposed to a corrosive environment and presence of Top of Line Corrosion (TLC) was expected. Severe TLC was only confirmed from the 3rd Intelligent Pigging inspection in November Subsequent intelligent pigging confirmed the result of the 2013 Intelligent Pigging and based on the assessment the pipeline will fail much earlier than the original design life. Hence, it was decided to replace the subsea section of the pipeline. 24 Carbon steel pipeline with 75 mm MLPP heat insulation is selected for the new pipeline. This presentation will provide an overview to Talisman Malaysia s pipeline replacement project in establishing the design for the new pipeline recognizing the TLC issue in the existing pipeline. The design of the new pipeline takes various considerations including: TLC prediction along the design life of the pipeline, required TLC control / management plan, capability of regional pipeline contractors and previous experiences. 14:40 15:15 Internal Corrosion Risk Assessment of Offshore Pipeline and TLC Analysis Presented by: Feng Cai, Safetech Research Institute The internal corrosion risk assessment methods were applied to the offshore pipeline. Directly assessment methods including multiphase flow modeling and calculation were carried on as well as the field data analysis in order to assess the corrosion risks based on the pipeline integrity management strategy. The operational parameters and historical flow conditions were investigated based on data collection and validation. Typical top of line corrosion has been found in an offshore pipeline after inspection. The external environments of the pipeline were considered to determine the condensate status of the different sections of the pipeline. Top of line corrosion prediction and simulation experiments were also conducted to clarify the root cause of internal corrosion. 15 Top of the Line Corrosion Conference Final Program

7 15:15 15:35 Break 15:35 16:10 Combined ILI Technology Approach for Monitoring Pipelines with Top of Line Corrosion and CRA Layer Presented by: Olaf Stawicki, Rosen Pipelines serving the oil and gas industry for the transportation of crude products are designed to comply with the harsh conditions faced by operators in offshore environments. In particular, production and transmission pipelines supplying liquid, multi-phase or gaseous products put a broad variety of special design requirements to the operator. They usually comprise, but are not limited to, heavy wall thicknesses, multi-diameter character and completion in high water depths. Besides the mechanical configuration, the chemical composition of the medium and the operational conditions varying along the pipeline play a crucial role for the design and integrity of the offshore pipeline system. Transporting sour wet gas and depending on the temperature exchange with the subsea environment, pipeline made of standard carbon steel may be extremely susceptible to corrosive processes at its inside, which in turn represents both environmentally as well as economically a major risk for a reliable and safe pipeline operation. One important example is Top of the Line Corrosion (TLC) in wet gas lines due to condensation. Heavy walled lines, which are common in off-shore applications, are often used to allow a specified maximum corrosion growth rate over the life time of the structure. However, depending on environmental conditions, TLC can reveal corrosion growth rates of even up to several mm per year, therefore reducing the anticipated life-span of a pipeline dramatically without any possibility for potential life-time extension. The industry is addressing this issue through various means, e.g., employing a Corrosion Resistant Alloy (CRA) layer at critical positions of the pipeline where TLC is expected. These layers, connected mechanically or metallurgically to an outer carbon steel carrier, are usually made of stainless steel or nickel based alloys such as 625 or 825. These layers are thought to be resistant to the aggressive medium, but they can in generally also corrode under certain circumstances. Following an approach which complements the relative wall loss measurements of Magnetic Flux Leakage (MFL) with an Eddy Current (EC) technology, results are presented which show the benefits not only for detecting TLC in standard carbon steel pipe. The same approach can also be employed for monitoring anomalies in both the CRA layer and the outer carbon steel carrier. For pipelines without CRA layer, the EC approach provides a depth measurement of metal loss defects in terms of absolute figures that complements and assists the relative wall loss measurements of MFL for carbon steel pipes by increased distinction of individual pits in dense clusters due to a better lateral resolution of defect surface measurement. For pipelines with CRA layer, the EC approach complements MFL in the manner that the latter is not suitable for detecting metal loss in the non-ferrous CRA material, whereas EC is an ideal candidate for monitoring the conductive CRA layer for anomalies. The MFL technology is still used for monitoring the outer carbon steel carrier where EC is not applicable. 16:10 16:45 NACE TCC International Initiative Presented by: Khlefa Esaklul, Occidental Oil and Gas Corp. With over 300 technical committees, NACE is the leading voice in developing corrosion-related standards and reports that affect your industry. There is no better community to be part of than a committee the help companies: Increase work safety Implement risk assessment Cut costs to improve the bottom line Maintain proper maintenance and inspection effectively Preserve the longevity of products and infrastructure. Top of the Line Corrosion Conference Final Program 16

8 18:00 20:00 Welcome Dinner Tuesday, 28 July 9:00 9:50 Keynote Presentation Study of the Localized Nature of Top of the Line Corrosion Presented by: Marc Singer, Ohio University Top of the line corrosion is recognized as a major cause of pipeline failure all over the world and is the focus of intense research in term of mechanism understanding, prevention and prediction. Although more and more theoretical and experimental work is being performed on diverse aspects of top of the line corrosion, the localized nature of TLC is still not well understood. The corrosion features observed in the field can be so large than the corrosion process is often referred a localized uniform corrosion instead of a purely localized corrosion. In this sense, the theory developed for mesa attack may not be applicable for a top of the line corrosion and the galvanic effect promoting the pit growth may not occur. Instead, it is possible that the corrosion can be controlled by localized condensation leading to localized uniform corrosion. Tests were conducted in a flow loop equipped with a newly designed test section in order to improve the hydrodynamics of the test conditions. It involves a 316SS flat slab equipped with carbon steel sleeve. This setup has the advantages to expose a large steel surface of the corrosive environments, simulate more accurately the curvature of a field 20 or 30 ID pipe and to limit to a minimum the edge effects found with smaller sample. The tests conditions focused on the effect of temperature, condensation rate and acetic acid concentration. The main conclusions are listed below: The experimental setup using the steel insert is successful in recreating the effect of the water condensation rate, Pitting/mesa corrosion is strongly related to the level of condensation applied to the steel section, On the thermally insulated areas, localized corrosion is marginally observed but does not grow with time after the first months on exposure. The presence of acetic acid did lead to an increase in the severity of the corrosion attack. On the cooled section, pits still seem to be growing in depth with time and also form clusters. 9:50-10:25 Modelling Top of the Line Corrosion in Gas with CO 2 and Organic Acid Presented by: Gaute Svenningsen, IFE When top of the line corrosion (TLC) takes place the conditions are fundamentally different from corrosion in the bulk aqueous phase (BLC). Although the condensing aqueous phase and bulk aqueous phase are exposed to the same acid gases (CO 2, H 2 S and organic acids) they are chemically different. The bulk phase may have higher ph because it will often contain formation water with alkaline salts. In addition the bulk phase may have been chemically modified (ph stabilisation or corrosion inhibitor) to reduce the corrosivity. The condensing water is more acid (lower ph) since it does not contain alkaline salts, and it does not contain conventional corrosion inhibitors, both factors makes it a very corrosive ( hungry water ). Although the top of line corrosion products also are alkaline, this effect is to a large degree counteracted by the continuous renewal of fresh condensed water. Another important difference is that the volume of water per area of metal is significantly larger for BLC than for TLC. Previous work by Nyborg and Dugstad [1] has shown that the TLC rate is limited by the amount of iron that can dissolve in the condensing water. In other words, the TLC rate is limited by the condensation rate and by the iron carbonate solubility. However, precipitation of iron carbonate is a slow process, particularly at low temperatures, and the condensed water can be highly supersaturated before iron carbonate precipitation occurs. Thus the super 17 Top of the Line Corrosion Conference Final Program

9 saturation must also be accounted for when calculating the TLC rates. The possible formation of partly protective films is also an important aspect of the TLC process. If organic acids are present in the system they will be absorbed in the condensing water and make it even more acid [2]. This will increase the iron solubility and therefore also increase the TLC rate. This effect is particularly important for low CO 2 partial pressures where the acid contribution from carbonic acid is lower. Modelling of the effect of organic acid on the iron solubility in the condensed water and the top of line corrosion rate will be discussed in detail. 10:25 10:45 Break 10:45 11:20 Are Condensation Rate and Corrosion Rates Proportional in TLC? Presented by: Md Islam, Curtin University A new experimental setup for top-of-the-line corrosion (TLC) has been developed with unique facility of collecting the condensed liquid and monitoring the real surface temperature of the top-of-the-line. Surface temperature, gas temperature and condensation rate were the preliminary parameters to investigate TLC. The results demonstrate that the surface temperature is the main parameter controlling two primary reactions that determine TLC severity; i.e. iron dissolution and the iron carbonate precipitation. As a result, TLC rates remained relatively constant at low surface temperatures regardless of the water condensation rate. It could be noted that iron carbonate formation at surface temperatures around 35 C and below was not protective during the experimental duration. On the contrary, iron carbonate formed at higher surface temperatures (ca. 40 C) tended to be protective and, consequently, reduced the corrosion rates. Increasing of the gas temperature fostered the condensation rate to a greater extent but is less influential to TLC if the surface temperature is kept constant at low temperatures. However, at slightly elevated temperatures there is a marked effect of the condensation rate on the corrosion rate up to the point when a protective iron carbonate film starts to form. SEM and EDS study show that formation of protective iron carbonate started to form around surface temperatures of 40 C which reduced the corrosion rates. Thus TLC at low steel surface temperatures (below 40 C) is a likely risk. 11:20 11:55 The Localized Corrosion Mechanism of X70 Steel in CO 2 Top-of-line Corrosion Environment Presented by: Yunan Zhang, Univ. of Sci. & Tech. Beijing Corrosion behavior of X70 pipeline steel was studied in a high temperature and high pressure condensation autoclave, simulating the CO 2 TLC environment under static condition. A series of experiments were carried out at the test duration of 10 d, 20 d and 30 d. The temperatures of wet gas are respectively 25 C, 35 C and 45 C. The temperature of pipe is 5 C, and the CO 2 partial pressure is 0.8MPa. The corrosion rate was measured by weight loss method. Scanning Electron Microscope (SEM) was employed to analyze the surface morphology of corrosion scales. The development of localized corrosion was studied and the mechanism in TLC environment was discussed. The results indicated that the condensate droplets led to the localized corrosion with embossments around occurring on the corrosion scales of X70 steel in CO 2 gas environment and with increase of the gas temperature and test duration, the maximal depth of the pitting would remarkably increase. Top of the Line Corrosion Conference Final Program 18

10 11:55 12:30 An Innovative Design for Top of Line Corrosion & Assessment in Laboratory Presented by: Hesham Mahmoud Shehata, Enppi Engineering for the Petroleum and Process Designing a new experimental model used to compare between Top of the Line Corrosion (TLC) and Bottom of the Line Corrosion (BLC). The lid model is designed by using solid works software and manufactured by using 3D printing machine. Linear polarization resistance method is used to measure the corrosion rate for BLC samples, while weight loss method is used to measure TLC samples. Special TLC samples were designed (half pipe section). The influence of different parameters such as acetic acid concentration, condensation rate and bulk temperature are studied. The free acetic acid concentration will be varied from 0 to 1000 ppm ( ppm), with three different sets of temperature 50 Co, 70 Co and 90 Co. CO 2 partial pressure is constant for all experiments. Twelve tests are done for each acetic acid concentration for each temperature, each test runs for 24 hours. At the bottom of line, the corrosion rate is always greater than at the top of the line in order of magnitude. By Comparing the corrosion rate between Top of the line and Bottom of the line, it is found that BLC = 1/10 TLC. There is directly proportional relationship between acetic acid concentration and the corrosion rate on both BLC and TLC. 12:30 13:30 Lunch 13:30 14:05 Effect of Monoethylene Glycol on Sweet Top of the Line Corrosion Presented by: Fernando Farelas, Ohio University Monoethylene glycol (MEG) is a widely used hydrate inhibitor in wet gas pipelines that has shown decrease the corrosion rate of carbon steel pipelines. Therefore, it is important to determine the amount of MEG present at the top of the line. This work present a mechanistic water/meg co-condensation model in the presence of a noncondensing gas (CO 2 ) that could be used to predict the condensation rate and MEG concentration in the condensing phase. The model predictions were compared with loop test results showing good agreement. The results showed that the increase of the MEG content at the bottom of the line decreased the total condensation rate and increased the MEG content of condensing phase at the top of the line. However, this effect is visible only when the MEG content is higher than wt.% at the bottom. Long term corrosion experiment are also presented showing that the injection of 50 wt.% and 70 wt.% MEG at the bottom have a minimum effect on both general and localized corrosion resistance. On the other hand, 90 wt.% MEG decreased the top of the line corrosion rate significantly due to a decrease in condensation rate and increase of MEG in the condensing phase. 14:05 14:40 The Inhibitive Effect of Mono Ethylene Glycol on Sweet Top of the Line Corrosion Presented by: Thunyaluk Pojtanabuntoeng, Curtin University Top of the line corrosion is a result of condensation of water vapour during the transportation of wet gas. The condensed water is considered to be more corrosive than the bulk water at the bottom of the line because it is saturated with acid gases and contains no buffer. Mono ethylene glycol (MEG) is one of the preferred thermodynamic hydrate inhibitors which is injected into the pipelines. The indirect beneficial effect that MEG provides is the corrosion inhibition particularly for top of the line corrosion. Experimental investigation was carried out at high temperature (up to 120 C) and high partial pressure of CO 2 (up to 20 bar). MEG concentration was varied from 0 wt% to 90 wt.%. The results clearly demonstrated that MEG provided significant corrosion inhibition firstly by reducing the water condensation rate. Additionally, it affects various physico-chemical properties of the condensed liquid in favour of corrosion reduction. 19 Top of the Line Corrosion Conference Final Program

11 14:40 15:15 Localized Top of the Line Corrosion in Marginally Sour Environments Presented by: Najmiddin Yaakob, Ohio University Localized top of the line corrosion in highly sour environments in the presence of acetic has been reported. However, little has been published about the occurrence of localized corrosion in CO 2 environments with low H 2 S concentrations; such conditions are typically described as being marginally sour. This research presents a systematic study of the effect of low H 2 S concentrations on corrosion of an API 5L X65 carbon steel exposed to top of the line conditions. Special emphasis is given to the transition between sweet and sour corrosion and how it relates to localized corrosion. Experiments were performed at 1 bar total pressure in a CO 2 /H 2 S environment. The H 2 S partial pressure was varied from 0 to 0.15 mbar at two different gas temperatures (40 C and 60 C). Corrosion rate measurements and surface analyses revealed localized corrosion at H 2 S partial pressure lower than 0.08 mbar, being more severe at a gas temperature of 40 C. 15:15 15:35 Break 15:35 16:10 Sensitivity Analysis of TLC Mechanism Based on Segmented Pipeline Simulation Approach Presented by: Wong SY, PT. Synergy Engineering This presentation describes the TLC mechanisms in wide-range of production conditions, e.g. simultaneous presence of organic acid and sour gases, wet gas and multiphase flows, at different pressures and temperatures. Further sensitivity analysis is performed on the organic acid content, acid gases partial pressure, heat transfer coefficient and the subsequent condensation rate to assess their impacts to the magnitude of TLC. Steady state and dynamic flow simulators, e.g. PIPESIM and OLGA, coupled with the HYSYS process simulation program have been employed to provide the flow composition, fluid behavior and properties for each of the segmented block along the pipeline. The segmented simulation results are input to the commercially available TLC prediction models to yield the TLC rates, which have been compared with the application of the commercially available corrosion prediction packages based on the featured equidistant pipe-length or full-length analysis. 16:10 16:45 Methodology for Comparing Model Predictions with Field Data Special Case of Top of the Line Corrosion Presented by: Sandra Hernandez, Chevron Top of the Line Corrosion (TLC) is a serious concern for the oil and gas industry and has been the cause of numerous pipeline failures1-5. Many research projects have been developed in order to better understand the mechanisms and to develop accurate predictive tools for TLC6-10. The corrosion mechanisms implemented in most of the available TLC prediction models are mostly based on laboratory experimental data. Therefore, it is essential to validate the model s capabilities by using field data. A new approach in comparing model predictions with field data is proposed in this work. Information collected from a sweet field having experienced TLC issues was analyzed, processed, and then used as an input for the TLC predictive model to simulate the evolution of temperature, pressure, water condensation rates (WCR) and TLC rate along the pipeline. The simulation results were then compared with in-line inspection (ILI) data. Challenges encountered in the analysis of the information about the field conditions (inaccuracy and variability of production data) as well as the ILI data are discussed, and a coherent methodology for comparison with simulation results is proposed. Top of the Line Corrosion Conference Final Program 20

12 Wednesday, 29 July 9:00 9:50 Keynote Presentation Challenges Associated with the Development, Testing and Application of Top-of-Line Corrosion Inhibition Presented: Alyn Jenkins, MI-Swaco In multiphase carbon steel gas pipelines, there is a possible threat to the system integrity due to top-of-line corrosion (TLC). In wet gas pipelines, produced water has the potential to condense at the top of the pipeline as the temperature and pressure along the length of the pipeline decreases. If this happens, TLC will occur which can be very severe as the ph of the condensed water will be very low (< 5). In addition, insufficient inhibitor may have migrated to the condensed water from the bulk water phase or gas phase to provide adequate corrosion protection. Preventing TLC in multiphase systems with inhibitors provides numerous challenges. Inhibitors must be transported with the gas phase, then partition into the condensed water when necessary and form a protective barrier on the metal surface. A further challenge is the development and evaluation of inhibitors that can effectively mitigate preventing top-of-line corrosion. Traditional laboratory tests (kettle tests, autoclaves, flow loop, etc.) are not suitable for this purpose as they are designed to determine corrosion inhibitor performance in controlling corrosion in the bottom of line environment. Therefore, alternative TLC test methods are needed. In addition, corrosion inhibitors used to control bottom of line corrosion are not effective in preventing top-of-line corrosion. Conversely, inhibitors that mitigate TLC are not suitable for controlling bottom of line corrosion. Therefore, multiphase inhibitors are needed that will control corrosion occurring on the entire pipe surface. This paper details the challenges in developing top-of-line inhibitors and summarizes the work conducted to select a new top-of-line corrosion inhibitor for a specific field application in South East Asia. The paper also describes the development of new test methods suitable for assessing inhibitor performance under top-of-line conditions. Finally, the paper will discuss the issues that need to be overcome when applying top-of-line inhibitors in the field so effective mitigation can be achieved. 9:50-10:25 Enhanced Pipeline Integrity Through Proactive TOL Corrosion Mitigation Presented by: Laorta Thanachaiwiwat, Chevron Multi-phases Pipelines in the Gulf of Thailand operate in conditions that necessitate proactive corrosion monitoring and mitigation actions. Through a few decade of our pipeline operating experience journey, Top of Line Corrosion (TOL) caused by the carbon dioxide (CO 2 ) internal corrosion is one of the main contributing factors leading to this type of corrosion and potential leakage. Influence of temperature, gas velocity, flow pattern and the carbon dioxide (CO 2 ) concentration are the factors affecting the corrosion rate in multi-phases pipeline. Chevron studies indicate the areas of greatest risk of TOL corrosion in these pipelines occur in the first few kilometers of pipeline from its wellhead and around tie-in or mixing points, such as Wyes and Tees. To minimize corrosion in these multiphase, stratified flows, high temperature, high CO 2 pipelines, Chevron developed and implemented comprehensive corrosion mitigation program based on pipeline risk level to prevent premature loss of process containment. In addition to a conventional Corrosion Control and Monitoring Program (CCMP), Chevron puts in place the mitigation plan which includes pipeline risk assessments, pipeline in-line inspection (ILI) program, pipeline replacement plan and emergency pipeline repair plan using pipe clamp inventory management strategy. Also as part of our ongoing effort to enhance our pipeline integrity program, Chevron continues to do more trial and implementation of new chemical for corrosion inhibitor injection and batching program such as use of Volatile Corrosion Inhibitor (VCI), improvement of pipeline design, and other TOL corrosion mitigation strategies. As a result of this program, continuous improvements have enhanced pipeline integrity and safety of Chevron Thailand operations. 21 Top of the Line Corrosion Conference Final Program

13 10:25 10:45 Break 10:45 11:20 Top of the Line Corrosion Inhibitor Development Presented by: Tong eak Pou, Ceca 11:20 11:55 Inhibition Mechanisms for CO 2 Corrosion Mitigation by Amines at the Top-of-the-line Presented by: Zineb Belarbi, Ohio University Top-of-the-line corrosion (TLC) has the potential to lead to rapid loss of pipeline integrity. Furthermore, it presents unique challenges in relation to its mitigation. Volatile amine compounds are used as vapor phase corrosion inhibitors in packages for protecting steel against CO 2 corrosion. Therefore, it is important to understand how they mitigate CO 2 corrosion. The principal objective of this work is to investigate and understand the TLC inhibition mechanism in the presence of diethylamine (DEA) and morpholine. In order to determine possible interactions between the tested amines and the steel surface the charge thereon was investigated by determining the potential of zero charge (PZC) and the open circuit potential (OCP). The PZC was measured by means of electrochemical impedance spectroscopy (EIS) in a 1 wt.% NaCl electrolyte at different ph values. The possible inhibitive properties of DEA and morpholine were first tested at the bottom of the line by linear polarization resistance (LPR) and EIS. Weight loss and electrical resistance probes were used to measure the corrosion rate at the top-of-the-line. After experiments, the steel surface was characterized by scanning electronic microscopy (SEM) and energy-dispersive X-ray spectroscopy (EDS). The results were interpreted based on the surface charge and provided key information about the possible interactions between amines (DEA and morpholine) and the steel surface. Results obtained from weight loss, polarization, and impedance measurements are in good agreement. DEA and morpholine seem to affect the ph of the condensed water but do not have significant filming properties. 12:00 12:30 Closing Ceremony Top of the Line Corrosion Conference Final Program 22