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PROCESS

"DIRECT EXAMINATION INTERNAL PIPELINE CORROSION (ICDA)"

IRMS-P-75-23-00

ISSUE 0

Dandilion prepared by Engineering Ltda. Date Elabor. July 2011

Approved by F. Arrieta Date PASS. Sept. 2011

Authorized by J. González Date Implem. Nov. 2011

Procedure "Direct Examination of Internal Corrosion in Pipelines (ICDA)"

of 17 Edition: 3-P-75-23-00 SGIR

Change control

No.

Mod. Date

Mod. Scope Modification No. Page. Presented Approved

1. OBJECTIVE

Establish the activities through which Electrogas develop the tasks associated with the direct examinations of their pipelines to detect internal corrosion. This procedure does not apply to the pipeline.

It comprising internal corrosion chemical corrosion mechanisms and microbially influenced corrosion (MIC: microbiologically influenced corrosion).

2. SCOPE

The procedure is applied in the implementation activities of the inspection plan when the inspection is of direct type and when seeking to determine the extent of the threat of internal corrosion.

Activities associated with the direct examination for internal corrosion (ICDA) consists of four stages: 1) pre assessment and identification of ICDA regions, 2) indirect inspection, 3) determination of excavation sites and direct inspection of the pipeline, and 4) post evaluation and monitoring.

The results obtained by applying the ICDA method will be used to establish further actions to improve operational procedures and inform the process of analysis and decision of the inspection plan.

This procedure applies to the Operations and the wholeElectrogas Transportation System.

Charge Integrity Management is responsible for the smooth operation of the process, ensuring adequate staff training and participation associated with it. Responsible for the implementation of the procedure is the Chief Operating Officer.

Direct to detect internal corrosion examinations are carried out by a specialized service provider for this purpose.

twenty-one. Normative reference

This procedure complies with the following rules.



2.1.1. D.S. 280: "Safety Regulations for Transport and Gas Distribution Network "

Article 18.5: In the case of metal pipes they must be inspected, while in service with the methods laid down in the ANSI / ASME B31.8S Code - 2004, "Managing System Integrity of Gas Pipelines"

Article 20.7 d)The network integrity program must have the definition of methods for assessing integrity of networks and the procedures for their application.

Article 19: The results of the inspections of the pipes must be reported to the Superintendency, by the procedures established for this purpose.

2.1.2. 49CFR.192_Parte O - Gas Transmission Pipeline IntegrityManagement.

Section 192 921: How is the baseline assessment to be Conducted?

Letter a) Inspection methods: inspection methods may be one or more of the following:

- Tools for internal inspection (ILI) or any other able to detect corrosion or other threat. The ILI is performed according to ANSI / ASME Section 6.2 B31.8S; or

- Test pressure (PH), or

- Direct Examinations: ECDA or ICDA or SCCDA, or

- Another technology as the operator deliver an equivalent level of knowledge of the state of the pipelines.

Section 192 923: How is the direct assessment (DA) used and for what Threats?

Letter a) General: An operator can use DA as a primary method of inspection or to supplement other methods of inspection of Subpart O

Point b) primary Method: The operator can only use DA as primary inspection method to evaluate threats external corrosion (via ECD), internal corrosion (


means ICDA) and stress corrosion cracking (throughSCCDA).

The operator using ICDA as the primary method of evaluation must comply with the guidelines of 49 CFR

192 927 and ANSI / ASME B31.8S Section 6.4.2 and Appendix B2.

Letter c) Secondary Method: The operator using DA as a complementary method must have a plan that meets the requirements of an evaluation Confirmatory Direct 192,931.

Section 192 927: What are the requirements for using ICDA?

Letter a) Definition: ICDA is a process to identify along the pipeline locations where they could reside fluid or electrolyte (introduced into the system during normal operation or special conditions) and where internal corrosion is most likely to exist.

Letter b) General requirements: The ICDA applies only nominally dry pipelines transporting natural gas, this is a flow of gas which nominally does not contain any type of electrolyte.

Letter c) Plan ICDA: The operator must establish and follow a plan to develop the ICDA to cover the stages of pre assessment, identification of ICDA regions; definition of excavation sites and direct inspection of the pipeline, and post evaluation and monitoring.

2.1.3. ANSI / ASME B31.8S - Managing System Integrity of Gas Pipelines:

Section 6.4.2: Internal Corrosion Direct Assessment (ICDA) for internal corrosion threat.

The ICDA can be used to determine the integrity against the threat of internal corrosion of pipelines typically carry dry gas but may face specific situations where wet gas or water transport Liberty (or other electrolyte).

Investigating low or outstanding points along the pipeline delivered status information remaining product. If this lows not corrode, then the rest of the downstream duct is less


electrolytes likely to accumulate and therefore would be free of internal corrosion, requiring therefore any examination.

Internal corrosion is more likely in places where water accumulates first. To know this is necessary to know the behavior multi - phase of the product in the pipeline.

Direct checks are then made at points of potential accumulation of electrolytes. Inspections can be performed using X-rays or ultrasound to determine the remainder of the product thickness. Once you have identified the possible internal corrosion point the operator can use methods of monitoring (coupons, samples, ultrasonic sensors for real-time monitoring) to extend the period of reinspection by this threat.

For more information ICDA process should refer to Appendix B2 not mandatory.

3. RELATED DOCUMENTS

3.1. Rules:

D.S. 280_2010: Safety Regulations for Transport andGas Distribution Network.

49 CFR.192_2007: Minimum Standards Network SecurityGas.

ANSI / ASME B31.8S_2004: Pipeline Integrity Management

GRI 02-0057: "Internal Corrosion Direct Assessment of Gas Transmission Pipelines -Methodology" mandatory standard reference under 49 CFR 192 927,

Standard: SP NACE 0206 - 2006: "Internal Corrosion Direct Assessment Methodology for Pipelines Carrying Normally Dry Natural Gas".

3.2. procedures:

Procedure "Development and Upgrading Inspection Plan

Products "and

Procedure "Direct Networks Pipeline Inspections - Electrogas".

3.3. instructional:

Manual of Quality and Environment Electrogas S.A.,



Rules of order, hygiene and safety for Contractors

Electrogas S.A. and

Security Manual Electrogas S.A.,

4. TERMINOLOGY

Dry Gas: gas on its dew point without condensed liquids,

ICDA: Internal Corrosion Direct Assessment. Examination (inspection)

Direct internal corrosion of pipelines

MIC: Microbiologically influenced corrosion. Microbiologically influenced corrosion.

ICDA region: a portion of the product with a defined length. The length can be defined as any length between two points of entry of liquid.

SMYS: Specified Minimum Yield Stress. fluecnia minimum specified.

Location ICDA: are points or segments of the pipeline within a ICDA region where it is determined by this method, there may be an accumulation of fluid.

5. DESCRIPTION OF ACTIVITIES

5.1. GENERAL

This procedure describes the necessary procedure for the implementation of direct examination of internal pipeline corrosion activities.

The procedure applies whenever conditions are suspected to internal corrosion is active.

Such conditions should be established through analysis of the following information (ref ANSI / ASME B31.8S Annex A2.):

Analysis gas, liquid or solid, particularly H2S, CO2; O2, and chloride free water)

bacterial cultures results,

corrosion sensing elements: coupons, samples, etc.,

operating parameters, particularly pressure and flow rate, especially periods of low or no flow.

Evidence that internal corrosion has been the cause of past incidents,


Page 8 of 17 Edition: 3-P-75-23-00 SGIR

If it is proved that section analysis never contained water or other electrolyte and that there was no event due to internal corrosion, then the ICDA examination is not required.

In any case, this condition must be demonstrated with a predetermined frequency in such a way to ensure that the threat of internal corrosion is inactive.

Electrogas considered as a basis for applying this method the lines of the standards 49 CFR 192 927 letter c); ANSI / ASME B31.8S Annex B2, not mandatory and NACE SP0206.

Without limiting the foregoing may be used more detailed and / or variations to the above specifications according to the particular case that either analyze or own specifications ICDA service provider.

5.2 ACTIVITIES OF THE EXAMINATION ICDA

5.2.1 Pre assessment

5.2.1.1 Data Collection

At this stage you must collect and integrate the information needed to evaluate the feasibility of using the ICDA method to support the use of a particular model to identify the locations of possible accumulation of electrolytes (liquids) along the pipeline, identifying the ICDA regions, and potential entry points to the system liquid.

The minimum information required for analysis is:

i) Information provided in Asni / ASME 31.8S - A2:

- Year of installation, diameter, wall thickness;

- Information hydrostatic testing and direct inspections and past history of running,

- Analysis of gas, liquid or solid (including

H2S; CO2; O2; free and chloride) water,

- Results of bacterial cultures, devices

Corrosion Detection (coupons, samples, etc.),

- Operational parameters (especially pressure and speed, including periods of zero flow), and

- Level of operating voltages (% SMYS).



ii) Information to support the selection of the model identification points of fluid accumulation, among other: points of entry and exit of gas; location of all the low points of the pipeline loops, earrings, dead ends, valves, manifolds, traps, etc .; pipeline profile with sufficient detail to calculate the slope of each segment of the pipeline; the diameter of the pipeline and the range of expected speeds.

iii) historical operational data denounce abnormal operations, place of occurrence and consequences, particularly associated with income or formation fluids.

iv) information segments where unused cleaning pigs or where they may have deposited liquids.

5.2.1.2 Feasibility of using the ICDA

The operator must analyze the information collected to determine if the method is applicable or not. To do this, consider the following:

Usually the product should not contain any liquid

(Including glycols)

The product must not have been previously operating with a fluid where the ICDA is not applicable,

The product has no lining,

If history shows that pipeline internal corrosion exists or existed at the top of the pipeline the ICDA is not applicable,

The piggeo pipeline has affected the points of accumulation of fluid, so that the ICDA not predict the distribution of the liquid properly given this involvement,

The use of a corrosion inhibitor can affect the implementation of ICDA since the effectiveness of this may not be uniform,

The products containing accumulations of solids, sludge, scale, biofilm / biomass must be not evaluated using ICDA.



5.2.1.3 Identification of Regions ICDA

The operator must identify all ICDA regions. The ICDA regions extending from the point where it enters the fluid including the rest of the product (downstream) where internal corrosion may occur.

Income / expenses include fluid flow direction. For products having or have had bi-directional flow, ICDA regions should be established for each direction of flow and evaluated independently.

To define regions ICDA should also consider changes in process variables (such as temperature and pressure). These changes can be treated as:

- They generate a new region ICDA, or

- Do not create a new region ICDA but should be considered when calculating the critical angle

5.2.2 Indirect Inspection

5.2.2.1 Determination of the critical angle

In identifying segments the operator must use the model set out in GRI - 02-0057: "Internal Corrosion Direct Assessment of Gas Transmission Pipelines - Methodology". This model or equivalent are used to define the critical angle of the pipeline on which the liquid film can not be carried by the gas.

Electrogas defined as an alternative model to model GRI indicated above, the model set out in SP NACE 0206 - 2006: "Internal Corrosion Direct Assessment Methodology for Pipelines Carrying Normally Dry Natural Gas".

NACE 0206 SP model defines the critical angle (θ critical):

In which:



- Critical θ: critical angle over which the liquid is not transported by the gas flow,

- Ρl: liquid density,

- Ρg: gas density,

- G: acceleration of gravity,

- Did: inner diameter of the pipeline,

- Vg superficial gas velocity

- All parameters must be in units

consistent.

- Consideration should be given the compressibility factor (Z) in the calculation of the appropriate parameters.

The gas density is calculated as:

In which:

- Ρg: gas density,

- P: absolute pressure gas flow (MPag),

- MW: molecular weight of gas (assuming 100%

Methane: MW = 16 g / g-mol);

- Z: compressibility factor,

- R: universal gas constant: 8.314 Pa -

m3 / g-mol / K,

- T: Temperature of the gas flow (° K).

Electrogas use a simplification, less conservative, to calculate the superficial gas velocity (Vg) is:

The calculations must be performed for all the operational history of the pipeline and flow bi - directional in case it occurs or has occurred.

5.2.2.2 Determination of angles duct

Once the critical angles calculated torque different operational conditions, they must be compared with the different angles of the product (θi):



5.2.2.3 Identification locations ICDA

For those cases where θi ≥ θ critical, you have a possible point of accumulation of fluid, ie a location ICDA.

The ICDA locations are determined by the analysis of information from Step 1: pre evaluation and analysis of critical angles.

5.2.3 Identification locations excavation and direct inspection

5.2.3.1 Selection and prioritization of locations for excavation

The operator should identify the locations where ICDA greater possibility of internal corrosion exists. In this process the operator must identify at least two (2) locations to be excavated and inspected within each region ICDA.

One of the two (2) points to be inspected must necessarily be the lowest point of the ICDA locations and the following points should be a point closer to the bottom end of the ICDA region waters.

If the ICDA region there were higher angles the critical angle, then you must select the largest angle in the region. If it existed corrosion should check the next largest angle. If there were no corrosion should likewise verify the following for the validation of the method.

In each of these locations must perform direct inspection to determine whether or not internal corrosion, this is excavated and use any method to measure the loss of interior wall.



The method validation shall follow the guidelines of ANSI / ASME B31.8S Annex B2:

The operator must make at least two direct inspections in locations with accumulation points electrolyte (θi ≥ θ critical) determined in the above and where the angles are smaller than the critical angle (θi <θ critical). If these locations are found to be free from corrosion, then the method is confirmed safe.

Thus validation is effective when two successive direct inspection it is found that there is no corrosion. With this, all the ICDA region analyzed is accepted as free from the threat of corrosion.

5.2.3.2 Direct Inspection

Suitable measurement techniques for direct inspection are ultrasonic thickness measurements, x-rays, or the like, which must be performed according to written procedures on them and qualified personnel.

It should be particularly cautious if the longitudinal weld, the pipeline discovered, is at the bottom of it, that is at 06:00 Hrs.

5.2.3.3 Response

If there is corrosion on any of the locations inspected shall:

i) To assess the severity of the defect (remaining strength) and act accordingly.

You should use one of the following criteria to determine if the corrosion is found significant:

Corrosion is considered significant if the remaining wall thickness is less than the nominal minimum wall thickness, based on tolerance wall specified in the standard manufacturing,



An analysis of specific engineering which should consider prior metal loss and years of service of the pipeline,

Another technical criteria duly justified,

The criteria used to determine the number of inspections to be performed.

ii) Whenever loss of wall should be calculate the remaining strength of the product in those locations, using ASME B31G,

iii) As part of the direct examination ICDA in the process, make additional direct inspections of the ICDA region through the subdivision of the region into sub-regions, using the same methodology of this process, or verify the validity or not to use another method inspection method,

iv) To evaluate the potential for internal corrosion throughout the product similar to the ICDA certain characteristic regions, where this has been done only for a segment of the pipeline.

v) If generalized internal corrosion and internal corrosion is detected it is not in the bottom of the product, this is at 06:00 Hrs different locations, then you should re-evaluate the applicability of the ICDA method.

5.2.4 Post evaluation and monitoring

The ICDA plan should contain provisions for evaluating the effectiveness of the method and to monitor the segments where internal corrosion is detected.

i) Assessment of the effectiveness of the method

Within a period not exceeding one year the operator must evaluate the effectiveness of the method as a useful tool for addressing the threat of internal corrosion and determine whether a particular segment should be re evaluated in a shorter period than those established by the "Procedure Development Plan Update and Pipeline Inspection ".



If corrosion is found, then the method by which the critical angle must be re -rated estimated.

ii) Re assessment and continuous monitoring

It should be monitored on an ongoing basis all segments of the pipeline which is detected internal corrosion using techniques such as coupons, samples or ultrasound, which is extracted in liquid periodically the lows, and where chemically analyze these liquids looking for products corrosion.

You must set the frequency of monitoring and analyzing fluid based on all available integrity assessments and specific risk factors of each pipeline segment.

If the operator discovers evidence of corrosion products must:

- Carry out direct inspections downstream of the point where the electrolyte may have entered the pipeline, or

- Assess the segment using one of the other methods laid down in the inspection plan.

5.2.5 Records

Then the records to be stored and / or to generate in each of the steps of the method are detailed. All decisions taken during its development must be properly documented. Records must be maintained throughout the life of the product.

a) Documentation of the pre assessment

- All records supporting the information detailed in paragraph 5.3.1.1,.

- Methods and procedures used to integrate and analyze the information above,

- Characteristics and limits of each region ICDA,



b) Indirect Inspection

- Locations geo referenced the beginning and end of each region ICDA,

- Procedures for establishing the accuracy of the profiles of the pipeline,

c) direct inspections

- Information collected before and during excavation, plus information "procedure direct inspection" measurements metal loss, data used to investigate other locations susceptible to corrosion, data to estimate growth rate of corrosion includes,

- Activities planned mitigation,

- Description and rationale for the selection of additional locations or re prioritization

d) Post Evaluation

- The results and the method of calculation of remaining life, determining the maximum size of damage remaining, and calculation of the rate of corrosion,

- Determination, justification and validation period of re-evaluation (re-inspection)

- Criteria used to evaluate the effectiveness of the method and its results: criteria, data and information of the periodic evaluations.

5.2.6 Special Considerations

When first applied ICDA Direct Examination, should be considered more restrictive conditions than the minimum established by the method and then make them less demanding as experience is gained in the implementation of the method.

5.3 SAFETY AND ENVIRONMENT

All activities associated with the direct examination ICDA be made in order to minimize security risks to property and people, and environmental risks and for which guidelines apply:



Rules of order, hygiene and safety Contractors Electrogas S.A.,

Security Manual Electrogas S.A.,

Internal Inspection Service Pipe-normative internal environmental protection.

5.4 REPORT OF AUTHORITY

Once completed the direct examination report ICDA and established the plan of action, the results of the inspection to the competent authority, SEC or other be informed, in accordance with procedures established by it.

6 REGISTRATION OF QUALITY

The following documents are defined as quality records in order to provide pursuant to Clause 7.2 of ISO 9001: 2008.

These will be stored in accordance to what stated in the GER-P-

42-03-00-0 "Record Control".

FIRST NAME

CODE

LOCATION TYPE O FILE RETENTION TIME

ICDA Inspection Report

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