corrosion nyborg 2005

8/12/2019 Corrosion Nyborg 2005

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Rolf Nyborg is Section Head forMultiphase Corrosion at the

Institute for Energy Technology(IFE) in Norway. He is also DeputyDepartment Head in the Materials

and Corrosion TechnologyDepartment at IFE. Mr Nyborg hasbeen working in corrosion research

at IFE for 20 years, and he hasbeen project manager for several

international joint industry projectson corrosion in oil and gas wells

and pipelines. He has also managedseveral corrosion projects for

individual oil companies and thechemical process industry. The

projects have included laboratorystudies, corrosion modelling andfield data evaluation. Mr Nyborghas an MSc in physics from the

Norwegian University of Science andTechnology in Trondheim.

a report byR o l f N y b o r g

Section Head, Multiphase Corrosion, Institute for Energy Technology (IFE)

Multiphase transport will have a major impact onoffshore development during the next decade. In thepast, emphasis was placed on processing the multiphasewell stream through separation on platforms close tothe wells. Drastic reductions in both investments andoperating costs can be achieved when unprocessed,

multiphase well streams can be transported over longer distances in carbon steel pipelines from subsea wells tomain platforms, existing installations on neighbouringfields or onshore processing facilities.

The pipeline costs are a considerable part of theinvestment in subsea projects, and for long-distance,large-diameter pipelines, they can become prohibi-tively high if the corrosivity of the fluid necessitates theuse of corrosion-resistant alloys instead of carbon steel.Better understanding and control of the corrosion of carbon steel can increase its application range andtherefore have a large economic impact.

The presence of carbon dioxide (CO 2), hydrogensulphide (H 2S) and free water can cause severecorrosion problems in oil and gas pipelines. Internalcorrosion in wells and pipelines is influenced bytemperature, CO 2 and H 2S content, water chemistry, flow velocity, oil or water wetting andcomposition and surface condition of the steel. Asmall change in one of these parameters can changethe corrosion rate considerably, due to changes in theproperties of the thin layer of corrosion products thataccumulates on the steel surface.

When corrosion products are not deposited on the

steel surface, very high corrosion rates of severalmillimetres per year can occur. The corrosion ratecan be reduced substantially under conditions whereiron carbonate (FeCO 3) can precipitate on the steelsurface and form a dense and protective corrosionproduct film. This occurs more easily at hightemperature or high pH in the water phase. WhenH 2S is present in addition to CO 2, iron sulphide(FeS) films are formed rather than FeCO 3, andprotective films can be formed at lower temperature,since FeS precipitates much easier than FeCO 3.

Localised corrosion with very high corrosion rates

can occur when the corrosion product film does not

give sufficient protection, and this is the most fearedtype of corrosion attack in oil and gas pipelines. Anexample of this type of localised corrosion attack in apipeline is shown in Figure 1. The line had been inoperation for several years without problems, butchanges in the well composition over time led to

more aggressive conditions, resulting in unacceptablyhigh corrosion rates. In order to control thecorrosion in pipelines, it is important to understandthe underlying corrosion mechanisms and be able topredict whether localised corrosion will be initiatedand how it can be prevented.

P r e d i c t i o n o f I n t e r n a lC o r r o s i o n i n P i p e l i n e s

Several prediction models have been developed for CO 2 corrosion of oil and gas pipelines. The modelsare correlated with different laboratory data and, insome cases, also with field data from oil companies.The models have very different approaches toaccounting for oil wetting and the effect of protectivecorrosion films, which can give large differences inbehaviour between the models. It is important tounderstand how the corrosion prediction modelshandle, particularly, the effects of oil wetting andprotective corrosion films when the models are usedfor corrosion evaluation of wells and pipelines.

In a joint industry project (JIP) at the Institute for Energy Technology (IFE), the different CO 2corrosion prediction models have been evaluated andcompared with actual field data gathered from the

participating oil companies. This project showed thatthe different models can give markedly differentcorrosion rate predictions for the same field case, andwhich models were most successful in their prediction varied considerably from case to case. It isnot possible to declare one or two models as better than the others. It is, however, important tounderstand the differences between the models inorder to interpret the predictions. In particular, theeffects of protective corrosion films and oil wettingare modelled quite differently in the various models,and these two effects may shift between very high andvery low predicted corrosion rates. There is inevitably

a high degree of uncertainty in these predictions, and

Controlling Internal Corrosion in Oil and Gas Pipelines

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low-flow areas such as tanks, drums and slug catchers.The estimated amount of corrosion products was 20t

the first year of operation. This was not regarded as acorrosion problem in the pipelines, but as a processproblem in the onshore processing plant. In order toreduce the amount of dissolved corrosion products inthe pipeline and avoid a costly rebuilding of the gasprocessing plant, the operator, Statoil, decided toreduce the corrosivity in the pipelines further byapplying the pH stabilisation technique.

The pH at the outlet of the pipelines prior to pHstabilisation was close to 6. Based on results fromlaboratory testing and calculations at the IFE, it wasdecided to increase the pH in the pipeline to 7.4.This was achieved by injecting a sodium hydroxide(NaOH) solution into the lean MEG tank. Theconcentration of dissolved iron, which has thepotential to form scale in the process equipment, wasreduced from approximately 100 parts per million(ppm) to less than 5ppm after six weeks, as shown inFigure 3 . This corresponds to a corrosion rate far below 0.1mm/year. Very little precipitation takesplace in the process system today, and the system hasbeen operated with success since the treatment wascarried out in 1997.

The main limitation of the pH stabilisationtechnique is that it cannot be used for pipelines

carrying large quantities of formation water, due tocarbonate scale formation close to the pipeline inletat the elevated pH. When the glycol is regenerated,the salts will accumulate in the regenerated glycol,which can also cause precipitation problems. Moredetailed knowledge of the kinetics of scaleprecipitation in glycol systems can lead to lessconservative evaluation of the application limits for the pH stabilisation technique.

A newly started JIP at the IFE is focused ondeveloping tools and knowledge for prediction of scale and particle formation in glycol systems for

long pipelines carrying unprocessed wet gas.

The pH stabilisation technique has been used mostlyfor wet gas pipelines without H 2S in the gas, but isnow being taken into use also for pipelines in thePersian Gulf, where there are considerable amountsof H 2S in addition to CO 2. There, the corrosion

product depositing on the surface will be FeS insteadof FeCO 3. These sulphide films have differentprotective properties to the FeCO 3 films forming insweet systems. Localised corrosion in the form of pitting is the critical factor in systems containingH 2S. The application limits for the pH stabilisationtechnique in wet gas pipelines containing highamounts of H 2S and CO 2 are being studied in anon-going JIP at the IFE.

U s e o f C o r r o s i o n I n h i b i t o r s

Due to the fact that the pH stabilisation technique

cannot be used for oil pipelines or gas condensatepipelines where large quantities of formation water are transported, injection of corrosion inhibitors isthe most used corrosion control method for suchpipelines. These are organic molecules that are addedto ppm levels and form surface layers that prevent thecorrosion reaction on the steel. Different inhibitorsare used depending on the actual conditions in eachpipeline. New inhibitors are continuously beingdeveloped to handle more aggressive conditions andcomply with more stringent environmentalregulations. At present, one of the largest challengesis to develop environmentally friendly corrosioninhibitors for high-temperature fields. Better understanding of the mechanisms for inhibition athigh temperatures and development of better testprocedures for inhibitors at high temperature are thefocus of a JIP starting at the IFE in 2005.

Selection and qualification of inhibitors in thelaboratory prior to implementation in the field isessential, and, most often, dedicated laboratoryexperiments will have to be performed withcandidate inhibitors for each field or pipeline. Anumber of factors may influence inhibition inmultiphase pipelines. Factors such as temperature,oil/water partitioning, water chemistry and flow

conditions have been widely studied. In the past, lessattention was given to factors such as thecomposition and microstructure of the steel, the typeof corrosion products formed on the steel surfaces,inhibitor adsorption on suspended particles in theproduced water and inhibitor accumulation onbubbles and oil/water droplets. Laboratoryexperiments at the IFE have shown that steelmicrostructure, corrosion products on the steelsurface and presence of very small clay particles or oil/water emulsions can strongly affect inhibitor performance. New test methods and equipment arebeing developed to account for the effects of

multiphase flow and steel surface conditions.

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Figure 3: Iron Content after pH Stabilisation of theTroll Pipelines

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50

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30 60 90 120 150Time/days

Injection of NaOH stopped

Injection rate of NaOH increasedInjection of NaOH started

Total ironDissolvediron

Fe /ppm2+

Fe2+ = ferrous iron, NaOH = sodium hydroxide.

corrosion nyborg 2005

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