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FAQ

FAQ

Aging Assets. Necessity for Inspections, Maintenance and Integrity Assurance.

Many oil, gas and petrochemical plants have already reached an advanced age. The continued operation of older assets is still possible but the risk of accidents and unplanned stoppages is increasing and therefore one of the biggest challenges of ageing assets.

In the following, we have compiled and answered our most frequently asked questions.

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How many days before the turnaround is the inspection team expected to be at site?

A core team consisting of a project manager, corrosion engineer and technical clerk shall be available at the plant at least 7-10 days prior to turnaround. This gives the team the opportunity to hold discussions and plan accordingly for the upcoming turnaround inspections. They can also consider the critical items based on the historic data available from the customer`s asset integrity team.

Do inspectors need special certificates for new technologies to detect CUI? Are there any further training / qualifications TUV Rheinland offers?

For Pulsed Eddy Current using SONOPEC, we provide in-house trainings for the technicians.

As basic qualification, the technician needs to be level II qualified as per ASNT SNT-TC-1A, ANSI CP-105, EN ISO 9712 and other nationally recognized procedures and guidelines for NDT personnel qualification and certification. For more details visit https://www.tuv.com/world/en/advanced-ndt-training-courses.html

What are the qualification requirements for a plant inspector?

API offers certification for pressure vessel inspectors, piping inspectors, tank inspectors etc, through their individual certification program. As an industry practice, we prefer an API 510 inspector with minimum 8 years of experience in plants for conducting inspection activities during turnarounds for pressure equipment, and API 653 certified individuals with storage tank experience for any tank inspection jobs (especially floating roof storage tanks).

Is an inspection of an old plant still cost-efficient?

A turnaround lasting only a few weeks might cost the equivalent of an entire year’s maintenance budget for an old plant. However, safety is an inherent enabler of productivity. If a shutdown is properly executed then it enables higher plant efficiency as well as reduction in unexpected troubles during operations.

Is it cost-effective to use permanent sensors for monitoring corrosion during a short period of time compared to taking measurements manually?

The permanent corrosion monitoring sensors will certainly be an effective solution to monitor the corrosion behaviour during a long time period. Due to the costs of the sensors it might not be the most cost effective option for an operator as one-off project. However, the costs can be significantly reduced if purchasing and installation of the sensors are outsourced to an inspection company. We can re-use the sensors on other projects and will charge clients only for the time period they need the sensors. Also, the operator will save time and costs training its own staff in how to install the sensors and will avoid the costs of purchasing the necessary software licenses.

What is the lifespan of the corrosion sensors?

There are many types of corrosion sensors available on the market and the battery life varies from one manufacturer to another. The most important, however, is that the battery life will strongly depend on the frequency of the measurements you wish to take. In general, you should expect the sensor to last for at least 5 years with the measurement frequency once per day.

What is the minimum pipe diameter for permanent corrosion monitoring and what are the operating temperatures?

Using the standard sensors – min diameter is 3 inches. However, we can install sensors on the pipes up to 2 inches at high temperatures and even up to 1 inch at normal temperatures. This will require some additional adjustment of the probes but it is possible to install permanent corrosion monitoring sensors to the piping as thin as 1 inch diameter. As for the temperature range, we use the corrosion sensors that operate between -180 °C (-290 °F) up to 600 °C (1100 °F)

By coating equipment, is it possible to extend the service life?

External coating can prevent the effects of atmospheric corrosion up to a certain point. If the only damage affecting the equipment is atmospheric corrosion, then the lifetime of the equipment (pressure vessel) can be extended based on the renewal / maintenance of the coating and ultrasonic thickness checks. However, coating should not be the only consideration when deciding about the life extension of pressure vessel.

What will be minimum frequency for conducting RLA (Remnant Life Assessment)? Is it required to conduct Metallurgical Replica (in-situ) during RLA (Remnant Life Assessment) always? What is the minimum frequency for turnaround / plant shutdown?

Remaining Life Assessment (RLA) is an attempt to measure and predict the residual life of equipment for replacement or repair planning. In RLA multiple nondestructive and metallurgical tests such as in situ-replica are done for obtaining accurate measurement of thickness and dimensions, and for finding any anomalies according to the expected damage mechanisms.

The shutdown frequency is determined based on various factors. One of the most important factors is the current age of the plan. Critical tasks require the highest priority. However, for many oil and gas operators/end users, the frequency of major turnarounds is generally 3 - 4 years or less. Extending intervals between shutdowns is the real challenge. This has been further heightened by the disappointing slide in oil prices and the pandemic, which has led to a reduction in resources in the past months.

What are the results of the RLA study?

This approach focuses on qualitative and quantitative methods to precisely estimate the remaining life of equipment subject to cumulative degradation.

The RLA study should at least provide answers to the following questions:

  1. Is it likely that the equipment will be fit-for-service during its remaining and extended operating life? (API RP 579, ASME FFS-1)
  2. What changes must to be made before it can enter the life extension period?
  3. What additional integrity measures and plant management improvements are necessary in order to provide adequate assurance of integrity during the period of extension?

On which studies and facts is the asset life extension based?

Asset life extension is based on several factors, including but not limited to results of studies such as: Fitness for Service (FFS), Finite Element Modelling (FEM) analysis, Remnant Life Assessments (RLA), Engineering Critical Assessments (ECA), failure analysis, and creep testing, among others.

An OSG specialist will be added to the team if requested by the customer. Typically, we do not shouldering the responsibility of the Occupational Safety and Health (OSH) specialist.

During the shutdown, the focus is on static pressure containment parts or, in parallel, inspection and maintenance of rotating equipment. What else is also implemented? Is the OEM mainly involved in that?

In our experience, for the rotating equipment, the inspection, maintenance and repair is covered by a long term service contract by the OEM directly or by its authorized representative. However, we support the OEM or its representative by providing NDE (like UT, PAUT, PT, MT etc.) during turnaround.

Are cranes and lifting equipment included in the integrity assessment? Should such a test be carried out under the supervision and involvement of a competent person for lifting equipment who knows the load cycle and working mechanism?

Cranes and lifting equipment are always part of integrity assessment. However, cranes and lifting equipment do not require plant shutdowns for inspection. A competent inspector / examiner will check this at fixed interval periods depending on the national / international regulations.

Is there any methodology to understand / inspect the integrity of cathodic protection of pipings and storage tanks used for LPG?

Preventing corrosion and protecting underground tanks from corrosion is easily achieved by the use of two commonly applied protection methods: external coating and cathodic protection.

These two methods are complementary and should be used in conjunction with the other. The effectiveness of cathodic protection of a tank under embankment can only be based on measurements of "instant OFF" potentials. "ON" potentials routine measurements are only aimed at detecting possible operational problems.

How do you calculate the amount of the sensor needed to install in one piece of equipment, for example a storage tank?

The Wireless Corrosion Monitoring System is installed at various locations in the CML/TML (Condition Monitoring Locations/Thickness Monitoring Locations) and is recommended by corrosion/materials engineers. Each systems is based on materials of construction, operating conditions and active damage mechanisms.

Do you have more questions? Don't hesitate to ask our experts for Asset Integrity Management.

To reach your AIM get in touch with our experts. We support you.

To reach your AIM get in touch with our experts. We support you.