ms20-02-158 rev 2

August 2013 Lloyd's Register AIS Page 2 of 9

Corrosion Rate Assessment Doc Number MS20-02-158 Rev 2

Note: Any comments or suggestions relating to this document should be passed to the custodian to allow full consideration at the time of the next review of this technical work instruction.

Revision Status

Issue/Rev Date Change Requests in this issue

0 First Issue of Document

1 16/07/12 Departmental name change from Integrity Services to Integrity Engineering Services ,Change in copyright date to 2012, , Minor amendments 4.4.3

2 22/07/13 MS20-02-150 reference removed use MS20-02-185 added corrosion mechanisms section 4.3. add theoretical starting point at 4.5



Process Flowchart

Identify Types of Corrosion for Assessment

Perform Corrosion Assessment Corrosion Rate Determination

Perform Corrosion Assessment Remaining Life Determination

Peer ReviewAgree Scope of Work and Responsibilities

Reporting

1. Application This procedure is for use by all Lloyds Register EMEA (LR) staff who undertake corrosion rate predictions on behalf of Energy Business Stream clients. This procedure is applicable when there is a requirement to perform a corrosion rate assessment, including determination of corrosion mechanisms, corrosion rate determination and remaining life determination.

2. Objective This procedure provides a consistent and auditable methodology to perform a corrosion rate assessment.

3. Responsibilities The Project Manager shall be responsible for the overall management of the corrosion rate assessment work scope. An appropriately authorised engineer (i.e. typically a Corrosion Engineer) shall be responsible for obtaining all relevant information from client/project team, performing the corrosion rate assessment and reporting any areas of concern with suitable recommendations. Any documentation that is to be issued to the client shall be subject to peer review by an appropriately authorised engineer, i.e. typically a Senior Corrosion Engineer. The main responsibilities and work flow pertaining to the corrosion rate assessment work scope is presented in the RACI chart below.



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8. Peer Review a i

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Responsible c Consulted i Informed

Report to be peer reviewed by an engineer with an appropriate competency/ authorisation category.

9. Delivery Deliver report either directly to client or via the LR project team, as appropriate.

a Accountable

1. Project Work Request

7. Reporting

2. Obtain Equipment/Pipework Register, details, etc.

5. Perform corrosion assessment - corrosion rate determination

3. Obtain Process Information

4. Obtain Materials Information

6. Perform corrosion assessment - remaining life determination

Prepare a written report detailing methodology, assumptions, conclusions, recommendations, etc.

Determine corrosion rates using accepted models or pertinent technical literature.

Process stream data should be obtained from client or project team.Materials data, GA drawings, piping specifications etc. should be obtained from client or project team.

Determine remaining life in accordance with LR procedures, if required.

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Pipework and equipment lists, mechanical details, drawings, etc. should be obtained from client or project team.

PWR to be raised by Project Manager for corrosion rate assessment

Work InstructionCorrosion Rate Assessment

MS20-02-158

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4. Method 4.1 General Corrosion rate assessments are most commonly required to support the activities of a semi quantitative corrosion risk assessment as described in LR work procedure MS20-02-185. Any deviation(s) from this procedure must have written authorisation from the Project Manager. A record of all changes must be held in the appropriate Project Reference File. Any changes specifically required by the client must be noted as such. 4.2 The Workscope The scope of the activity is to be clearly identified by the Project Manager at the beginning of the project. It is important that the scope is fully understood by members of the project team. Where the work is requested directly by a client (e.g. as consultancy), the scope of work must be agreed in writing. The workscope will typically involve predicting corrosion rates and possibly a remaining life for an item, a group of items or an entire process facility. This type of work is most commonly associated with hydrocarbon process systems and the utilities systems, including vendor packages. The following sections describe the steps required to perform a corrosion rate assessment and are presented in the order in which they should be performed. 4.3 Identification of Corrosion Mechanisms Prior to prediction of corrosion rates and determination of remaining life it is necessary to define the likely corrosion mechanisms e.g. CO2, H2S etc. along with the type of corrosion:

General, Pitting, Crevice, Galvanic, Environment induced cracking, Intergranular,

Of the above only General Corrosion and Pitting are measureable from inspection data and the rate predicted. This information can be used to identify inspection requirements upon completion of the assessment and may assist the project team, client and OIE's in subsequent decision-making. 4.3.1 General corrosion

Corrosion is a chemical reaction between the metal and its environment, Corrosion returns the metal to its combined state in chemical compounds that are similar or even identical to the minerals from which the metals were extracted. This is normally the preferred type of corrosion because it is predictable. 4.3.2 Pitting Pitting or localised attack in an otherwise resistant surface produces pitting, the pit may be deep, shallow or undercutting. Pitting share the same mechanism as crevice corrosion.


Corrosion Rate Assessment Doc Number MS20-02-158 Rev 2 4.3.3 Crevice

A crevice shields part of the surface, enhancing the formation of differential aeration and chloride concentration cells, both play a large role in the initiation and propagation of crevice corrosion as they do in pitting. 4.3.4 Galvanic Galvanic is where two dissimilar metals are coupled and one corrodes while the other is protected

4.3.5 Environment induced cracking There are three related but different types, Stress Corrosion Cracking (SCC), Corrosion Fatigue Cracking (CFC) and Hydrogen Induced Cracking (HIC). SCC normally occurs in alloys, stainless steels are susceptible to hot chlorides, brass in ammonia solutions and carbon steel in Nitrates. CFC occurs under cyclic stress in a corrosive environment HIC is caused by relatively low levels of hydrogen diffusing into alloy lattice when hydrogen evolves during corrosion, electro plating cleaning or pickling or cathodic protection. Molecular hydrogen gas can nucleate, generating sufficient internal pressure to deform and rupture metal locally

4.3.6 Intergranular Grain boundaries or adjacent regions become less corrosion resistant and preferential corrosion can be severe enough to drop grains out of the surface causing corrosion 4.4 Corrosion Rate Determination

This section details the method to be followed when determining the corrosion rate prediction model to be used. If the scope of work is large it is advisable to use an MS Access database to hold the asset inventory and data relating to mechanical properties, process fluids, operating conditions, etc. It is usually also appropriate to use the database to perform the relevant assessment calculations, i.e. in accordance with the methods described in the applicable standards, published papers or prediction models. The use of MS Access allows the assessment algorithms to be uniformly applied across all components in the scope of work and allows updates to be made efficiently. 4.4.1 CO2 Corrosion

There are various models available for prediction of CO2 corrosion rates. The most widely accepted model for CO2 corrosion rate predictions is that given by de Waard and Lotz (1) whilst a second model by de Waard, et al. (2), incorporates the effects of flow. BPs Cassandra spreadsheet (3) provides a freely-available tool that is based on this model but which incorporates a number of industry accepted modifications/improvements. An alternative model is provided by Norsok as described in their standard M-506 (4). Norsok freely provides an M-506 MS Excel spreadsheet and guidance documents that can be downloaded from their website.

4.4.2 O2 Corrosion



Oxygen corrosion rates can be predicted using the Oldfield, Swales and Todd prediction model (0). The model is based on the mass transfer effect of oxygen to the substrate surface in largely-deoxygenated waters (e.g. offshore water injection systems). As such, it is not applicable to seawater systems where the oxygen content is high. A second model by Berger & Hau (0) is also available and gives more realistic corrosion rate predictions for fluids which contain high concentrations of oxygen.



4.4.3 H2S Corrosion The Cassandra model allows the user to alter the calculated corrosion rate to account for the presence of H2S in the fluid. The BP guidance document which accompanies the model estimates the corrosivity of 1 mol% H2S to be comparable to 0.01 mol% CO2. In the spreadsheet, the effect is incorporated by adding the partial pressure H2S to the partial pressure CO2 in the calculation of pH (i.e. using the XLpH add-in) within the model. This approach typically results in H2S having a negligible effect on the overall corrosion rate. The use of Cassandra is therefore not recommended by LR for modelling CO2/ H2S systems. Nei et al. 2009 (7) provide a downloadable prediction model (8) which takes account of the presence of H2S and the FeS scale that is formed on the surface of the metal. The model identifies that the diffusion of H2S through the protective scale does not stop once the scale is formed and that corrosion of the substrate will continue but is affected by the mass transfer of H2S through the scale. This model provides predictive rates for CO2 and organic acid (e.g. acetic acid, etc.) corrosion and identifies how the rate will be affected (either positively and negatively) by the concentration of H2S in the fluid. 4.4.4 Other Forms of Corrosion Where corrosion is expected as a result of mechanisms other than CO2 and/or H2S, it is important to identify all corrosive species which may be present in the fluids. This will generally be achieved by discussion with the client, examination of the heat and mass balances, review of sampling reports/databases, etc. Where the corrosive species are not covered by the prediction models discussed above, the client may be able to provide guidance regarding published papers, assessment methodologies, etc. that are relevant to the specific process/conditions on their facility. Alternatively, a literature search should be performed to identify other relevant prediction models or general guidance on expected corrosion rates, i.e. based on the material types, fluids, etc. Typical sources of such information include ASM Handbooks, NACE conference papers and industry standards/recommended practices, e.g. API 581 contains clear guidance on how to predict corrosion rates in amine systems. 4.5 Validation of Predicted Rates

Where possible, corrosion rate predictions should be validated by comparison with measured corrosion rates, i.e. by review of existing inspection data, failure history, etc. In some cases, it may be appropriate to draw upon historical performance data from other assets. The validation of predicted corrosion rates is particularly valuable where the calculations have been made using methodologies that are not widely known, not supported by extensively-documented laboratory/field testing, etc. Assuming that the starting point is theoretical, you need to know the sample size and assign expected corrosion rates for that material and service. 4.6 Remaining Life Determination If required, the remaining life can be calculated using the predicted corrosion rate, in accordance with the requirements outlined in MS20-02-185 and the described in API 510 (0) and API 570 (0). Remaining life should be calculated from the date on which the wall thickness was measured (or from the commissioning date, if the nominal wall thickness is used in the absence of inspection data. Where appropriate, the remaining life may be presented to reflect the date of the report. In all cases, the report should clearly state the basis upon which the remaining life was calculated.



4.7 Reporting & Peer Review Reports shall be produced in a timely manner and reviewed by an appropriately competent engineer. Dependent on the extent of the scope of work, this peer review shall include either a sample or a full review of the input data, assessment methodology and results. The reporting style will be dependant on the scope of work and client requirements but will in general contain the input data, description of methodology followed and the results of the assessment, i.e. corrosion rates and possibly the remaining life.

5. References C. de Waard and U. Lotz, Prediction of CO2 Corrosion of Carbon Steel, Paper No. 69, NACE Corrosion 93, 1993. C. de Waard, U. Lotz and A. Dugstad, Influence of Liquid Flow Velocity on CO2 Corrosion: A Semi-Empirical Model, Paper No. 128, NACE Corrosion 95, 1995. A. Petersen, R. Chapman and B. Hedges, Corrosion Prediction with Cassandra, BP Upstream Technology Group, Sunbury, Report No. S/UTG/013/03, 2003. (G:\Groups\ETG\Corrosion\Cassandra training) NORSOK Standard M-506, CO2 Corrosion Rate Calculation Model, rev. 02, June 2005 Oldfield, J.W., Swales, G.L. and Todd, B. (1981). Corrosion of Metals in Deaerated Seawater, paper presented at NACE Middle East Corrosion Conference, Bahrain. Berger, F.P. and Hau, K.-F. (1977). Int. J. Heat and Mass Transfer, 20, 11851199. An open source mechanistic model for CO2/H2S corrosion of carbon steel, Srdjan Nei, Hui Li, Jing Huang and Dusan Sormaz, NACE paper 09572, 2009 http://www.corrosioncenter.ohiou.edu/freecorp API 510, Pressure Vessel Inspection Code: Maintenance Inspection, Rating, Repair, and Alteration, 9th Edition, American Petroleum Institute, 2006 API 570, Piping Inspection Code: In-service Inspection, Repair, and Alteration of Piping Systems, 3rd Edition, American Petroleum Institute, 2009

1. Application2. Objective3. Responsibilities 4. Method4.1 General4.2 The Workscope4.3 Identification of Corrosion Mechanisms4.3.1 General corrosion4.3.2 Pitting4.3.3 Crevice4.3.4 Galvanic4.3.5 Environment induced cracking4.3.6 Intergranular

4.4 Corrosion Rate Determination4.4.1 CO2 Corrosion4.4.2 O2 Corrosion4.4.3 H2S Corrosion4.4.4 Other Forms of Corrosion

4.5 Validation of Predicted Rates4.6 Remaining Life Determination4.7 Reporting & Peer Review

5. References

ms20-02-158 rev 2

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