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Latest News & Articles from FIMS International

February 2023, Calgary – Alberta

We are delighted to announce that FIMS International company had successfully passed the ISO certification audit and obtained full certification in both Quality and Environmental Management system. We are proud of such achievements and continue to deliver our Structural Integrity & Corrosion Management Services with top quality and efficient support to our clients to achieve safe & reliable operations of their assets and operations.

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November 2022 –

Corrosion Monitoring in the Petroleum Industry – A Comparative Assessment Options:

Intrusive Corrosion Monitoring techniques rely on entry into a pipeline. With proper design, construction, and retrieval it is generally possible to conduct intrusive monitoring while produced fluids are flowing.
Pigging or In Line Inspection – An inspection probe called an intelligent pig is launched into a pipeline while produced fluids are flowing. Pipelines must be equipped with special entry ports – namely Launchers and Receivers- in order for pigging to be conducted. Once launched, intelligent pigs are able to use nondestructive examination techniques inside the pipeline to provide evidence of corrosion erosion and cracking. Intelligent pigs can perform UT, Magnetic flux leakage testing, and take measurements including pipeline diameter, curvature, bends, and temperature.
The advantages of pigging are direct measurements taken from inside a running pipeline. The pig also has the effect of cleaning scale, wax, and debris from the line. A disadvantage is that launchers and receivers have to either be existing pieces of kit on that pipeline or retrofitted during a turnaround. Another disadvantage is the risk of a pig getting stuck in a pipeline. This is a consideration especially in systems that are prone to scaling or wax deposition.
Coupons- Corrosion Coupons are inserted into a flowline to measure the corrosion rate. Corrosion coupons typically are composed of the same metallurgy as the pipe. Metal loss can be observed upon coupon retrieval and calculations can be performed to determine the metal loss of the production piping. An advantage of the use of corrosion coupons is that they show observable metal loss. A disadvantage is that if incorrectly placed, they may indicate a corrosion rate that differs from the reality of the actual system. It is important to have an expert understanding of the likely locations of corrosion within a system before installing coupons.
Probes- Corrosion Probes use electrical resistance to monitor the corrosion within a system. Unlike corrosion coupons and pigs, they are able to remain continuously inside the pipe and are not subject to removal. They are also able to provide continuous, real time data. The advantage of corrosion probes is that they provide real time, continuous data without the need for removal. The disadvantage they share with corrosion coupons is that they must be correctly placed in order to depict the most accurate corrosion data.
Non-Intrusive Corrosion Monitoring Techniques are conducted on the external surface of pipes and vessels.
Ultrasonic Testing (UT)- UT involves the use of an ultrasound to measure wall thickness and is a very common monitoring technique in the Oil & Gas World. These measurements can vary from single point measurements, to Ultrasonic phased array systems, to inline UT monitoring. UT works best when baseline wall thickness measurements are taken and compared with UT results that are taken at specific intervals in specific locations based on the nature of the production system and produced fluids. The advantage of UT is that it is very commonly used within the Oil & Gas Industry and it is a fairly easy matter to obtain trained UT technicians. It is important to obtain baseline UT data prior to commissioning the system, and to designate appropriate corrosion monitoring locations based on the expected types and locations of corrosion for each system. UT inspection must also be done at regular intervals to maintain a complete dataset. Even so, a disadvantage of UT is that it does not provide continuous real time data.
Radiographic Testing (RT)- RT is another commonly used method of monitoring corrosion. RT involves the use of X-rays to determine the amount of corrosion within a pipeline. This can be accomplished with either X-Ray films or by using Digital Radiography. In both cases, RT is most appropriate over small areas of small-bore pipe. RT is also useful in observing Corrosion Under Insulation without removing the insulation for visual inspection. The advantage of RT is that it is very commonly used within the Oil & Gas Industry and it is a fairly easy matter to obtain trained UT technicians. It is important to obtain baseline RT data prior to commissioning the system, and to designate appropriate corrosion monitoring locations based on the expected types and locations of corrosion for each system. RT inspection must also be done at regular intervals to maintain a complete dataset. Even so, a disadvantage of RT is that it does not provide continuous real time data. RT is also limited by the area it is able to cover and is therefore best used for small-bore pipe and small areas of concern.
Field Signature Method (FSM)- FSM involves the use of an electrical current to measure the voltage drop between sensor pins in a given area of monitored pipe. This signature drop can be compared to measurements taken during the lifetime of the field to calculate a real time corrosion rate. It is useful for remote operations requiring continuous non-intrusive corrosion monitoring. The advantages of FSM are that it is ideal for remote unmanned fields and that it provides continuous real time data. The disadvantage is that installation may be expensive.

FIMS Materials, Corrosion, and Inspection expert engineers are ready to identify likely corrosion hot spots and select and perform the most appropriate and effective corrosion monitoring surveys for any asset.

This article was originally written by Shelly Gallender – Integrity Principal Engineer at FIMS International
For support and information email us at: contact@fimsinternational.com

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September 2021

Materials Selection for Internal Corrosion Control in Oil & Gas Production Facilities

Materials Selection is the first step in the development of a corrosion management plan for an oil & gas production project. One must understand the most likely sources of corrosion and cracking in a system to choose the right materials.
CO2, H2S, O2, and microbes in production fluids indicate that internal corrosion and cracking are likely. When CO2 is the predominant corrodent in process fluids, the oil is referred to as sweet. Fluids with a partial pressure of H2S greater than 0.05 psi are considered sour. Oxygen and microbes are generally found in fields undergoing waterflood. It is important to note that the presence of microbes (Sulfate Reducing Bacteria called SRBs) can cause a field to turn sour in addition to contributing to generalized corrosion.
Carbon steel is the base material of choice for most oilfield projects. CO2, O2, and Microbiologically induced corrosion may be managed by including an appropriate amount of corrosion allowance in combination with injection of a corrosion inhibitor. The corrosion allowance (typically 3-6 mm) is determined from the design life, predicted corrosion rate, and corrosion inhibitor availability of a system.
Higher corrosion rates and/or long design life may drive a project to select a more robust material (stainless steel or corrosion resistant alloy) for vulnerable system components. Upgrading a project’s metallurgy comes with additional expense as well as new potential degradation mechanisms that must be considered. Stainless Steel is subject to cracking at temperatures above 140F, and many of the CRAs come with fabrication and welding challenges. A mixed metal system may also be subject to galvanic corrosion. Another concern is that corrosion may be pushed down the line away from corrosion resistant areas to areas of bare carbon steel.
Materials selection is a powerful way to combat corrosion, but it must be performed in a thoughtful and thorough way by experienced professionals.
The integrity engineers at FIMS will be more than happy to guide a project in the selection of the ideal materials to provide corrosion protection and asset integrity through the lifetime of a facility.

This article was written by Shelly Gallender – Integrity Principal Engineer at FIMS International
For support and information email us at: contact@fimsinternational.com

October 2020

FIMS International is proud to support one of its important client KBR. As FIMS International was chosen to be the specialist support company in the filed of Cathodic Protection. Click here For more information