Integrity assessment methods adapted for stations, terminals

Dec. 20, 2004
Methods originally developed for pipeline integrity assessment have been adapted for station and terminal facilities.

Methods originally developed for pipeline integrity assessment have been adapted for station and terminal facilities. The methods include development and implementation of an integrity management plan, an inspection plan, and a fitness-for-service (FFS) assessment plan. These plans are based on accepted industry standards and implemented in accordance with accepted industry recommended practices.

Pipeline assessment and maintenance have received a great deal of attention in recent years. Most of this work, however, has concentrated on the transmission pipeline itself. Now the integrity of stations and terminals can be part of a total pipeline system integrity management program.

For example, Section 12 of American Petroleum Institute Standard 1160 provides guidance for integrity management of pump stations and terminals.1 This article shows how an integrity assessment approach has been developed for pipeline station and terminal facilities. The framework of the approach is risk based and is adapted from the one outlined in API Standard 1160.

Equipment inspections are implemented in accordance with accepted industry practices for pressure vessels, piping, and tanks, such as API 510,2 API 570,3 and API Standard 653.4 Defects and FFS also are assessed in accordance with accepted industry practices; typically, the three-level approach of API RP 579.5 NACE International's RP 0502 external corrosion direct assessment (ECDA) procedures are applied to underground equipment at station facilities.6

Three levels of FFS assessment are used to evaluate station facilities, excluding the pipeline itself. The assessment procedures become increasingly complex, costly, and accurate as the level of assessment increases from Level 1 to 3.

Level 1 typically is a screening analysis based on simplified, conservative guidelines and experience. Level 2 analysis is based on calculations made by simplified formulas and rules. Level 3 is a detailed analysis specifically tailored to the problem of interest.

A risk-based approach for aging facilities prioritizes inspection and mitigation schedules. That minimizes the inspection and operation costs of station facilities without jeopardizing equipment reliability and availability.

Equipment and systems typically covered in the assessment include station and facility programmable logic controller control systems, piping, piping connections, valves, tanks, pressure relief and protective devices, pumps, compressors, coatings, cathodic protection, separators, seals, and leak detection and containment devices.

Technical approach

Pipeline station and terminal facilities typically are assessed as shown in Fig. 1. This framework is adapted from that of API STD 1160.1 The first step is to gather, review, and integrate the relevant data on the facilities being evaluated. These data are then used to help make an initial risk assessment of the facilities and develop a baseline assessment plan.

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Inspection and mitigation activities then obtain additional data and, if necessary, modify operating parameters that affect equipment condition. The data are reviewed, updated, and integrated so that the risk assessment of the facilities can be updated and revised.

Finally, the inspection and mitigation plan is revised. The four steps in the loop periodically are repeated to maintain an active and up-to-date integrity-management program. The program also is evaluated to make sure reliability and safety goals are reached or exceeded.

As recommended by API RP 579, using the following guidelines implements three-level FFS assessments:5

  • Level 1 assessment performed by an inspector or engineer.
  • Level 2 assessment performed by an engineer.
  • Level 3 assessment performed by an expert engineer or by a team of engineers that includes at least one expert.

The assessments and required inspections should be carried out in a timely fashion. Some of the assessments and inspections are more critical than others, based on risk factors developed in integrity-management planning.

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Figs. 2 and 3 show the basic philosophy of API RP 579's three-level assessment approach.5 Fig. 2 illustrates the procedures applied to corrosion or local wall thinning. Fig. 3 illustrates the procedures applied to crack-like flaws. In addition to using the methods of API RP 579, the methods of BS 7910 can be applied to the evaluation of crack-like flaws.7

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Estimated remaining life (RL) is based on anticipated future operating conditions. Level 1 is relatively simple to apply and quite conservative. If equipment fails to satisfy Level 1 assessment, the more detailed and less conservative Level 2 assessment is applied. If equipment fails to satisfy Level 2 assessment, a very detailed, tailored Level 3 assessment is applied.

Level 1 analysis is based on design information, operating and maintenance records, and results of limited visual inspections. It is a conservative screening analysis that can be applied rapidly with minimal cost.

Level 2 analysis is based on the same information as Level 1, supplemented with additional basic inspection data and results of formula-based stress analysis. Level 3 analysis is based on the same information as Levels 1 and 2, supplemented with advanced inspection data, information from operational analysis, and results of detailed stress analysis—often finite-element analysis. The assessment becomes increasingly complex and costly as the level of analysis increases.

In a typical project, all of the station and terminal equipment will be subjected to a Level 1 assessment. Typically, some of the critical equipment will require Level 2 assessment, while only a few pieces of equipment may require Level 3 assessment. The first step in Level 3 assessment is to decide if repair or replacement is more economical than performing the assessment. Repair-or-replace decisions are also required for equipment that does not pass a Level 3 assessment.

The assessment process, inspection data, calculations, findings, conclusions, and recommendations are documented in detail so that analyses can be easily updated or repeated in the future. This type of work is often divided into two phases. Phase 1 involves Level 1 and Level 2 assessments and provides recommendations as to which Level 3 assessments, if any, should be undertaken. Phase 2 consists of Level 3 assessments, as required.

Following are the various FFS assessments.

Level 1

The first step in Level 1 assessment is to collect and review all required data. These data include:

  • Original equipment design analyses and drawings.
  • As-built equipment information and drawings.
  • Maintenance and repair-replacement history.
  • Operational history: pressures, temperatures, and environments.
  • Future operating conditions: pressures, temperatures, and environments.
  • Past inspection records, including positive verification of materials of construction.
  • Other data and measurements required for FFS assessment.

The data are evaluated to determine if they are sufficient for performing Level 1 assessment and to identify the probable material degradation mechanisms. Basic visual inspections obtain any missing data or verify questionable data. If sufficient data are available, Level 1 analysis is performed in accordance with the procedures of API RP 579, as applicable.5 If key data are missing or equipment does not pass Level 1 assessment, inspection techniques and sizing requirements for obtaining the data are recommended for Level 2 assessment.

The equipment and systems typically evaluated in this task are:

  • Piping and piping connections.
  • Valves.
  • Tanks.
  • Pressure relief and protective devices.
  • Pumps and compressors.
  • Coatings.
  • Cathodic protection.
  • Separators.
  • Seals and leak detection and containment.

These items are divided into critical and noncritical areas, based on the consequences of their failure to function properly in future service.

Level 2

In this task, information from Level 1 analyses determines the appropriate inspection methods for assessing the remaining life and FFS of the equipment. The inspection techniques and sizing requirements are determined in accordance with the following recommendations:

Data needed for FFS assessment.

Documents, procedures, and specifications needed to execute the inspection and Level 2 assessment are developed and integrated into the overall program. Results of the FFS assessment process are documented along with the inspection data and facility records. The information also includes any previous equipment and coating repairs.

Level 3

Detailed Level 3 assessments are performed, as required, based on the results of Level 2 assessments. Before any Level 3 assessment is undertaken, however, its cost and schedule are compared with the cost and schedule of equipment repair or replacement to make sure that a Level 3 assessment is warranted. The risk of not passing a Level 3 assessment is included in this cost-benefit analysis.

Level 3 assessments require specialized inspection for the material degradation mechanism of concern, possibly thermal analysis, detailed stress analysis, estimation or measurement of aged material properties, evaluation of the operating environment and process conditions, and prediction of minimum remaining life.

An appropriate team of experts, engineers, and inspectors performs these assessments.

Methods are recommended to remediate the type of degradation found if repairs are deemed necessary. Remediation is especially important when the rate of degradation is unpredictable or the minimum remaining life is predicted to be unacceptably low. For example, four methods of remediation are recommended for general or local corrosion:

  • The product stream may be physically changed.
  • Protective linings or coatings may be employed.
  • Water or chemicals may be injected into the product to modify the environment or metal surface.
  • Weld overlays of similar material may be applied in accordance with the applicable codes.

ECDA

External corrosion direct assessment (ECDA) methodology, a tool developed for pipeline integrity management,6 has proven useful for pipeline and piping segments that are not readily accessible for in-line inspection or hydrostatic pressure testing.

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The method helps keep external corrosion defects from growing large enough to affect the structural integrity of underground pipelines. It can be adapted to managing the integrity of underground piping in stations and terminals, excluding the transmission pipeline itself.

ECDA integrates data from direct field inspections and aboveground field measurements with pipeline or piping physical characteristics and operating history to provide a measure of the current condition of the overall system. The information on current condition is then compared with the requirements for maintaining structural integrity.

ECDA is implemented in four steps:

1. Preassessment. Historic and current data are collected and evaluated to determine if ECDA is feasible, to define assessment regions, and to select tools for indirect inspection. These data typically are in design, construction, operations, maintenance, and inspection records.

2. Indirect inspection. Aboveground and-or surface inspections identify coating holidays, other anomalies, and areas of past or current external corrosion. At least two inspection tools are used for reliability.

3. Direct examination. Analysis of data from Step 2 indicates sites for excavation and direct examination of the pipe surface. Data from the examinations are combined with those obtained previously and the effect of external corrosion is assessed. Coating performance, defect repairs, and mitigation are also evaluated.

4. Postassessment. Evaluation of data from Steps 1 through 3 indicates the effectiveness of the ECDA process and establishes intervals for reassessment.

Table 2 of RP0502 lists five types of tools that can be used in indirect inspection:6

  • Close-interval survey (CIS).
  • Current voltage gradient surveys (ACVG and DCVG).
  • Pearson.
  • Electromagnetic.
  • AC current attenuation surveys.

Table 2 of RP0502 lists conditions to which these tools may or may not apply. Important conditions to consider in stations and terminals include stray currents, nearby metallic structures, roads, and paved areas.

Once defects are identified, characterized, and quantified, their effect on integrity, FFS, and remaining life is evaluated with the procedures described previously.

Example application

An operator conducts a review of equipment at a station and identifies a section of piping with more than 40% external wall loss. The risk analysis indicates that this area of local wall loss should be evaluated to determine the action required. The following information is collected:

  • Because the pipe is made of Grade 359 steel, the specified minimum yield strength (SMYS) is 359 MPa.
  • The nominal diameter (D) is 610 mm (24 in.).
  • The nominal wall thickness (t) is 12.7 mm (0.5 in.).
  • The maximum operating pressure (MAOP) is 7,470 kPa (1,000 psi).
  • There is no other significant loading on the piping.
  • The design factor (Fd) is 0.50.
  • The distance to the nearest major structural discontinuity (Lmsd) is 3.5 m.
  • Because action was taken to eliminate the corrosion problem that caused the wall loss, the future corrosion allowance (FCA) is zero.
  • The allowable remaining strength factor (RSFa) is 0.90 based the recommendation in paragraph 2.4.2.2.d of API RP 579.5

Inspection of the area of wall loss reveals no groove-like flaw.

The remaining pipe wall thickness in the thinned area is measured with a 10 by 10 mm grid; Table 1 shows the results. The area extended 40 mm in the longitudinal (L) direction and 90 mm in the circumferential (C) direction. Thus, 5 measurements were made along each longitudinal grid line, and 10 measurements along each circumferential grid line.

The Level 1 procedures for assessment of general metal loss in Section 4 of API RP 579 were applied as follows:

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Step 1: Compute the minimum required WT for circumferential (hoop) and longitudinal (axial) stress (Equations 1 and 2; see Equations box).

The minimum required thickness (tmin) = 12.7 mm.

Step 2: Determine the minimum measured wall thickness (tmm). The data in Table 1 show that tmm = 5.90 mm.

Step 3: Determine the length for thickness averaging (L). First, compute the remaining thickness ratio (Rt) and Q parameter (Equations 3, 4a, 4b, and 4c).

Step 4: Determine the longitudinal extent of the area of wall loss (s). From Table 1, s = 40 mm.

Step 5: Since s = 40 ≤ L = 46.7, the flaw is acceptable, provided that the criteria of paragraphs 5.4.2.2.d and 5.4.2.2.g of API RP 579 are satisfied.

Check the three criteria for longitudinal extent of metal loss (s) in paragraph 5.4.2.2.d (Equations 5a, 5b, and 5c).

Check the criterion for circumferential extent of metal loss (c) in Paragraph 5.4.2.2.g (Equation 6).

From Fig. 5.7 of API RP 579, Rt must be greater than 0.2 for c/D ≤ 0.348 for an acceptable circumferential extent of local metal loss. Since c/D = 0.148 < 0.348 and R = 0.465 > 0.2, the circumferential extent of metal loss is acceptable.

Because the above Level 1 screening analysis shows that the local metal loss is acceptable, no further analysis is required. This analysis applies to pressure loading only. If other loads are present, such as pipe-bending loads, more detailed Level 2 or Level 3 analyses would be required.

Also, this analysis applies only if the amount of fatigue loading is less than 150 cycles or satisfies the screening procedure of Paragraph B.5.4 of API RP 579. A fatigue analysis must be performed if the amount of cyclic loading is significant by this screening procedure.

References

1. American Petroleum Institute, "Managing System Integrity for Hazardous Liquid Pipelines," API Standard 1160, 2001, Washington.

2. American Petroleum Institute, "Pressure Vessel Inspection Code: Maintenance Inspection, Rating, Repair and Alteration," API 510, Eighth Edition, 1997, Washington.

3. American Petroleum Institute, "Piping Inspection Code: Inspection, Repair, Alteration, and Rerating of In-Service Piping Systems," API 570, Second Edition, 1998,Washington.

4. American Petroleum Institute, "Tank Inspection, Repair, Alteration, and Reconstruction," API Standard 653, Third Edition, 2001, Washington.

5. American Petroleum Institute, "Fitness-For-Service," API Recommended Practice 579, 2000, Washington.

6. NACE International, "Pipeline External Corrosion Direct Assessment Methodology," NACE Recommended Practice 0502, 2002, Houston.

7. British Standards Institution, "Guide on methods for assessing the acceptability of flaws in metallic structures," BS 7910, 1999, London.

Based on a presentation to the 5th International Pipeline Conference (ASME), Oct. 4-8, 2004, Calgary.

The Authors

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Carl E. Jaske ([email protected]) is senior group leader at CC Technologies Services Inc., Dublin, Ohio. He holds a BS in general engineering and mathematics and an MS in theoretical and applied mechanics from the University of Illinois. He received a PhD in metallurgical engineering from Ohio State University. Jaske is an ASME Fellow and past chair of both the ASME Pressure Vessels and Piping Division and ASME Pipeline Systems Division. He has served on ASME Code subgroups and organizing committees of ASME, JSME, ASM, and EPRI conferences. He served on the working group that developed API Standard 1160, and he is an associate editor of the Journal of Pressure Vessel Technology.

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Aida Lopez-Garrity (alopez @cctechnologies.com) recently joined CC Technologies Services Inc. as a principal engineer and manager of facilities integrity. Previously, she was a senior corrosion engineer for Trans-Canada PipeLines Ltd., Calgary; the Pembina and Peace pipelines, Calgary; and PDVSA, Caracas, Venezuela. Lopez-Garrity graduated from Imperial College-University of London, with a degree in metallurgical engineering, and she holds an MS in corrosion science and engineering from University of Manchester Institute of Technology. She is the chairman of NACE Specific Technology Group STG 035 on "Oil and Gas Pipelines, Tanks and Well Casings," chairman of NACE Task Group TG 247 on "Liquid Epoxy Coatings for External Repair, Rehabilitation and Weld Joints on Buried Steel Pipelines," past chairman of NACE Task Group TG 014 on "Pipeline External Corrosion Direct Assessment Methodology," and vice-chair of the NACE Corrosion 2003 Direct Assessment Symposium.