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Management of top of Line Corrosion in wet gas lines Yves GUNALTUN Total S.A. DGEP/TDO/TEC. 2, Place de la Coupole 92078 Paris La Défense Cedex / France
[email protected]
Introduction Top of Line Corrosion (TLC) occurs in multiphase wet gas lines when water vapour contained in the gas phase condenses on the internal upper pipe wall. This happens due to external cooling by river water, seawater or cold air, if the pipe is not thermally insulated or buried at a reasonable depth. Furthermore, organic acids, if present in the produced gas, lower the pH of the condensed water (to below pH 4), giving rise to very high localised corrosion rates of up to 10 mm/year. As TLC occurs in wet gas lines operated in stratified flow, the corrosion inhibitor injected remains at the bottom of the line and is not able to protect the top of the line. At the time top-of-line was detected in the Field A lines in 1996, there was no method, technique or tool available on the market to predict, control and monitor this type of corrosion. Several R&D programmes had to be devised and implemented in parallel to investigate solutions, in order to maintain the integrity of the existing multiphase networks and to design the future transportation systems. Different entities of Total E&P, Total Research Centres, several companies and research institutes took part in these projects. The present article summarises the TLC problems experienced in pipelines of three gas fields in South East Asia, the actions taken and the techniques and tools developed for the management of TLC.
TLC in wet gas line – previous occurrences When TLC was detected in a line of Field A in 1996, after six years of operation, only two TLC cases had been reported in literature: one in 1960, by Elf on the Lacq field, the other in 1985 by Shell in Canada. In the latter case, it was attributed to the presence of H2S and to Indopipe – May 2006
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methanol injection. Neither of these explanations was valid for the Field A lines, where there was no H2S present and no methanol injected. TLC in the Field A lines was attributed to fast cooling of the gas by river water at locations where the pipes were subject to upheaval buckling. The thickness loss detected by MFL (Magnetic Flux Leakage) type intelligent pigging amounted to nearly 50% of the wall thickness (WT). In 1999, TLC was detected in the Field B lines, again after 6 years of service. The sealines were neither thermally insulated nor buried. The operating conditions were fairly similar to Field A. Again, the thickness loss detected by MFL type intelligent pigging was about 50 60% and the corrosion rate was about 1 to 2 mm/year. In 2001, two Field C lines were inspected after about one year in service and revealed severe TLC. They were not buried, except for the last 13 km. The first inspection results, by an MFL tool, revealed up to 72% thickness loss. Even though subsequent inspection results showed that the thickness losses were somewhat lower, around 50-55% of WT, the initial thickness losses were estimated to be several mm/month. On both the Field B and Field C sealines, TLC was detected along the first few kilometres from the wellhead platforms and was attributed to water dewing, subsequent to fast gas cooling by ambient seawater.
TLC management in wet gas lines All initiatives were oriented towards 4 major priorities that the company would be facing in a few years on three major gas fields: • • • •
understanding of the TLC mechanism; development of new techniques, tools and procedures for controlling TLC in the existing lines; development of new tools for the prediction and control of TLC, and for the design of lines for ongoing and future projects; development and tests of new monitoring and inspection tools to guarantee the integrity of the lines.
Understanding of the TLC mechanism Several studies were commenced in parallel to understand the mechanism of TLC and identify important parameters involved in the corrosion process. •
A preliminary assessment of the corrosion risk in the Filed B lines showed that CO2 corrosion was not the main cause of TLC and the presence of organic acids was suspected. Effectively, standard water analyses do not include analysis for organic acids and the samples taken from the Field B before field development were no exception. Water samples collected from Field B and then Field A wells were therefore analysed in a specialised laboratory in France where they showed significant amounts (an unusually high) of organic acid species (mainly acetic acid and, to a lesser extent, formic acid) in the produced water. Organic acids represented
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up to 3000 mg/l in the water from Field A, Field B and Field C. Generally, acetic acid concentrations in oil production systems are just a few hundred mg/l. •
A small size water condensation loop was constructed in the Correx laboratory at Saint Etienne (France) (specialised in corrosion studies), to investigate the role of organic acids and water condensation. The results confirmed the strong influence of these parameters, especially above 50°C. When organic acids are present, the corrosion is no longer of “uniform” type, but becomes “localised” (fig. 1), a much more critical form of corrosion. Moreover, for acetic acid, the corrosion rate is multiplied by a factor of 10 to 20 (compared to a pure CO2 system) when the temperature is increased from 50°C to 70°C. In addition, the presence of mill scale (the oxide layer formed during pipe manufacture) was found to exacerbate the initiation and development of the localised corrosion phenomena. Fig. 1: photo of TLC in a Field A line
Localised corrosion
•
A water condensation pilot was built at one of the Total E&P bases in South East Asia, to study the TLC mechanism and validate the results of the Correx laboratory.
•
Total developed a model (US 14 model) to calculate water condensation rates in the wet gas lines. The predictions of the model were matched against the inspection results from Field A and Field B lines in order to identify a threshold in water condensation rates below which the TLC rate is tolerable (fig. 2).
•
The TLC issue was then considered as part of the “Wet Schema” R&D programme. An R&D project was kicked off at Ohio University to develop a physical model for the prediction of TLC. A 4” condensation loop was built (fig. 3) for this purpose. Preliminary results confirmed the influence of the parameters mentioned above. During the first phase of the project, a semi-empirical model was developed for TLC prediction.
Finally, it was established that TLC is specific to hot wet gas lines operated in stratified flow, when they are subject to external cooling and especially to heat loss by convection (lines neither thermally insulated nor buried). The water condensation rate, temperature, and quantity of organic acids dissolved in the condensed water are the main parameters. Water analysis for organic acids is now part of standard practice in Total.
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Fig. 2: Predicted water condensation rates and thickness loss profile in a Field B line Water condensation rate (g/(m2.s)) 2.50
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Fig. 3: Condensing loop at Ohio University
Control of TLC in the existing pipelines Several actions have been taken to control TLC in the existing pipelines and also to prevent it in future pipelines. •
Local heat insulation was applied on the most corroding areas (detected by instrumented pig inspection) of the Field A and Field B lines by installing sand bags.
•
A corrosion inhibitor selection loop was built at CReG’s premises (Total Research Centre at Le Havre - France) to select filming type corrosion inhibitors for batch injection between two pigging runs. A water-soluble product with short contact time
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efficiency was selected (inhibitor should be able to pass into the water layer and film the surface in less than 2- 3 seconds during the pig movement). •
Field tests were conducted in the Field B and Field C lines to confirm the efficiency of the selected inhibitor. It was found that batch treatment is effective for about two to three weeks only.
•
The cooperation with CReG was then extended to the thermodynamic modelling of the Liquid (hydrocarbon)/Liquid (water)/ Gas system comprising various amounts of organic acids. It was carried out using the OLI/ESP thermodynamic package and aimed at assessing the composition of the water at the top of line conditions and the efficiency of neutralising amines such as MDEA. The calculations were used to evaluate the neutralising efficiency in Field C lines, where the produced water was mainly condensed water. The CReG study confirmed the feasibility of neutralising.
•
Preliminary tests carried out at the Correx laboratory in the condensing loop confirmed the possibility of neutralising organic acids by MDEA to reduce the TLC rate.
•
A field test was run in a Field C line and confirmed the CReG simulations and Correx results. Continuous injection of MDEA in the Field C lines started to bring TLC under control. Treatment efficiency was monitored by water analysis for iron, pH and calcium (to check the carbonate precipitation). The iron content in the water phase, collected at the line outlet, was reduced from 150 ppm to 20 ppm (concentration at the line inlet see figure 4). Fig. 4: Neutralising organic acids in a Field C line by MDEA injection pH
Fe (ppm)
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CReG thermodynamic modelling showed that MDEA injection was not a competitive option in the long term, if significant amounts of formation water were produced (this was the case for the Field A and Field B lines). Moreover, the implementation of batch treatment in Field A lines threw up a number of safety issues and entailed
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significant production loss. An R&D programme was then fielded to develop a new type of pig to control TLC. The idea was to use the inhibited liquid available at the bottom of the line to film the surface at the top of the line. The concept of “spray pig” was patented. Then, the decision was taken to develop the spray pig, called “TLCCPIG”, with TD Williamson at Tulsa. The project was financed by Total and PTTEP. After several loop tests at Tulsa and a field test in the Field B lines, this pig was adopted for batch treatments in gas lines (fig. 5). Fig. 5: Spray pig capable of projecting the inhibited bottom line liquid to top of line
TLC prevention and control in future pipelines While work was being done on the control of TLC in pipelines in service today, other actions were being fielded to prevent TLC in future ones. •
Total ran several simulations, considering different types of heat insulation coating and coating thickness, to bring the water condensation rates (inner wall surface of the upper half of the pipe) down to below the critical value based on comparison of condensation rates and inspection results from the Field A and Field B lines.
•
Where lines are buried to prevent pipe cooling by the external environment, simulations showed that there must be at least 50 cm of soil above the line.
•
After first inspection of Field C lines, the critical condensation rate was revised to a much lower value due to specific low pH. In order to validate this value, an R&D project was launched at IFE (Norway) using their condensation loop. It confirmed that, at this condensation rate, no TLC occurs in Field C conditions. The design of Field C lines was validated. The decision was taken to apply heat insulation coating and to bury the pipelines at a depth of 2 metres. The IFE tests also confirmed the Correx results that mill scale played an important role in the initiation of the localised corrosion.
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•
A new programme was set up at Ohio University to study TLC risk in the lines with pH control and in presence of H2S (application in sour gas lines). Recently this programme became a JIP when a number of other oil and gas companies joined it. The results showed that there is no risk of TLC if the corrosion is monitored by pH control. However, TLC can also occur in presence of H2S if the pH is not neutralised. The JIP is continuing work on this issue. It also covers the determination of critical velocities in the gas lines subject to TLC. A prediction model is under preparation.
•
For a new phase of Field C development, different types of heat insulation coatings and field joint coatings were evaluated and qualified.
•
Recent inspection results showed that TLC stabilises with time. The initial corrosion rate of 5 – 10 mm/year drops to less than 0.5 mm/year after 1 to 2 years of operation (figure 6). Another R&D project to understand the reasons for this stabilisation has started at IFE with a PhD student. The results will help to improve prediction of localised corrosion rates and evaluation of the remaining life of the lines affected by TLC. Figure 6: Evolution of pit depth/wall thickness ratio with time in Field C lines Pit depth / wall thickness
1 0.9 0.8 0.7 0.6 0.5 0.4 0.3 0.2 0.1
0 28-8-99
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In order to reduce CAPEX for the projects (eliminate heat insulation and line burial) and OPEX (injection of MDEA and batch treatments), an R&D project was started to develop volatile corrosion inhibitors. Cooperation with CECA (Arkema) has resulted in the identification of some promising molecules, and the tests carried out in the Correx condensing loop are very positive. A new chemical was formulated, combining the inhibitors for bottom line and top-of-line controls. After validation tests which are going on in the Ohio University condensing loop, field testing will start in the Field B and Field C lines.
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Monitoring of TLC and inspection of TLC-prone lines Monitoring of TLC Several types of treatment were proposed and applied, but evaluating the treatment efficiency was the weak point. Chemical analysis of water samples from the Field C lines was effective in monitoring the MDEA injection efficiency, but questionable for the batch treatment. In order to evaluate the risk of TLC and monitor the efficiency of the chemical treatment by batch, it was decided with the CReG to develop a condensing probe. In a cooperation study with Cormon (a company specialised in monitoring tools), a “cooled probe” was successfully developed to create a controlled water condensation rate on the resistive probe element and to measure the corrosion rate. The Cormon’s CEION signal treatment and technology was used for this purpose. The probe, patented by Cormon and Total, is extremely sensitive to metal loss and can indicate any change in the corrosion rate in less than one hour. The figure 7 shows the test results on Ohio condensing loop. Figure 7: Measurement of corrosion rate by a “cooled probe”
The probe has already been validated on the Ohio University condensing loop. It will be installed very soon on a pipe section on one of the Total refineries (condensing corrosion is also a problem in downstream operations), after which it will be field-tested on a Field B or Field C line. Inspection of lines prone to TLC Inspection tools used for the gas lines are generally based on the magnetic flux leakage (MFL) technique. The use of ultrasonic tools (UT) is limited (for practical reasons) to crosschecking or confirmation of the MFL results. In one 16” Field A gas line, the MFL tool reported metal losses of 60 to 77% of wall thickness, but crosschecking by UT showed metal losses of only 30%. The over-evaluation of thickness losses by MFL was confirmed by UT tools and also by visual inspection of
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repaired pipe sections in other lines of Field A and Field B. The inaccuracy was attributed to the shape of localised corrosion spot, which generally has uneven sharp edges. Without in-situ crosschecks, such over-evaluation could lead to misleading corrosion rate hypotheses, incorrect fitness for purpose assessment and therefore inappropriate decisions regarding the necessity for pipeline repair or derating. Several actions have been undertaken: •
For the inspection of Field B lines, PTTEP has developed, in collaboration with Dacon Inspection Services, a new UT tool called IRIS UT PIG to cross-check the MFL results.
•
A programme has commenced to compare the results of MFL tools, UT tools and visual inspection so as to understand the reasons for over-evaluation and to be able to calibrate these tools as appropriate. The programme was recently completed, and confirmed that the interpretation of inspection results for TLC-prone lines requires a new model, factoring in the shape of TLC features. Figure 8 shows the accuracy of two of the available tools (one MFL and one UT) on the market. Figure 8: Crosschecking of MFL and UT inspection results by C-Scan UT pig reported metal loss depth (% WT)
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Conclusions After seven years of efforts, the TLC risk can now be far more accurately predicted. Tools, techniques and chemicals are now available for prediction, prevention and control of TLC. A number of studies are still in progress regarding the H2S impact on TLC, critical velocity evaluation and stabilisation of TLC. The requirements for TLC prevention have recently been revised for two new projects. It was decided to reduce the thickness of heat insulation coating on the sealines, except doglegs, to
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prevent heat loss by convection. This solution could then be considered for other sealines and other projects, but we still lack information on heat insulation requirements for service with relatively high H2S. And if the efficiency of volatile corrosion inhibitors is confirmed by field tests, TLC would then be controlled as efficiently as bottom line corrosion in the near future. In this case heat insulation and batch treatment would not longer be required.
An example of cooperation Thanks to highly positive cooperation all round, most of the problems mentioned hereafter have been solved. The different collaborations to be noted involved several Total EP entities in head offices and in affiliates (Total E&P Indonésie and Total E&P Thailand), but also other operators (mainly PTTEP), Centre de Recherche de Gonfreville Total R&M (CReG), several chemical companies like CECA (which belong to ARKEMA) and Nalco, service companies such as OLI, external laboratories, universities and research institutes like Correx (Saint Etienne France), IFE (Norway), Ohio University (USA), companies specialised in developing monitoring and treatment tools such as Cormon (UK) and TD Williamson (Tulsa - USA), inspection companies like Rosen, PII, Dacon, heat insulation and pipe coating applicators such as Eupec and Bredero Shaw, and “dozens of others”. Total has, further, published, with its partners, about 15 papers on the theme. TLC is now considered as a major issue by Oil & Gas Industry and several major companies are taking part in JIPs on the subject.
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