iicorr Ltd

Monitoring Technology

What area does an FSM instrument cover?

A) The instrumented area = Approximately 1-2 * Diameter of pipeline B) Physical extension Approximately 5-6 * Diameter of pipeline

How do you know where to place an FSM station on a long pipeline?

A corrosion profiling program, CorPos, estimates the corrosion rates along the pipeline. Based on the result, the position(s) can be selected.

How many FSM stations do you need on a 50 km long flowline?

An engineering study is needed to find out how many stations are needed, but a combination of corrosion modelling, one or more high sensitive probes and one FSM at a critical location is a common configuration.

How often do you need to replace the battery package?

5-10 years, dependent of how often you load the data. If a cable connection is possible, it is recommended.

What is the current/power supply to the unit?

Battery, cable, solar cells

How often do you take measurements?

Dependent of the type of power feed, but once a day is common for normal corrosion monitoring. You may increase the frequency if changes are detected. Higher frequency gives higher (short term) sensitivity, but may require cable power feed

Is the current/power continuously on?

No, only when measuring, approximately 2min./measuring

What type of communication can you accept?

(hydroacoustic, cable) RS - 232 C 15m RS - 422 300m RS - 485 300m CorrOcean Fieldbus 300m

How can the use of intelligent pigging be reduced when you are installing an FSM on your pipe?

With on-line monitoring you are able to optimise the use of intelligent pigging so that it is only used to assess changes you know are taking place. On-line monitoring provides both real time data and historical data, and may also lead to a decision to rely on monitoring, modelling and smart pigs (instrumented cleaning pigs) and forgo intelligent pigging altogether.

You say you can use data from one FSM station to calibrate your prediction tool for corrosion attacks - how is this possible?

FSM measurements will give you a report of how the condition is on one area of the pipe. Engineering studies as preparations for placement and reliability to FSM will give the trend for the whole pipe. When the results coincide, your confidence in the results increases.

In a subsea bend or pipe, changes in the temperature will influence the elongation of the component. How will this influence the readings from FSM ?

Compensations for temperature changes are included in the calculations, and temperature sensors are also included in the system. You will typically see results change during temperature transients (shut-down) and then resume at the same level afterwards. This does not normally interfere with detecting corrosion trends.

What are the benefits with a combined system of FSM and HSER probe?

HSER will give you a more detailed and earlier warning for general corrosion because the sensitivity is higher. FSM measures local corrosion, cracks and pitting, and more direct and long-term influence on the pipe. FSM measures also material loss on the pipewall (erosion). These two systems together gives you a total monitoring system and will give you a better confidence in the system.

Can FSM be used on other alloys than carbon steel?

Yes, all metallic materials

Can you identify the type of corrosion (general corrosion or pitting corrosion)?

Yes.

What is the sensitivity of FSM - please quantify for different thickness?

0.1% of pipe wall thickness.

Solids & Erosion Monitoring

What are the benefits of the service?

We provide the complete package to detect, quantify, analyse and report solids production and erosion development to allow you to maintain control and reduce risk with confidence.

What do you see as the limitations of your system?

Most clients that have had experience of alternative acoustic systems invariably encounter areas where the acoustic data is questionable, whether this is as a result of not picking up solids that were produced, results affected by acoustic noise or problems associated with multiphase or liquid flow. There are definite questions on the reliability of acoustic alternatives in these areas.

These problems have not been experienced with the inline system and the results of this type of system have never really been questioned.

Issues of concern that have been raised in respect to the inline system relate to probe lifetime and cost of consumables.

Probe lifetime for well test applications is very dependent on what solids are produced and at what velocities.

Where safety and rig time are concerned this should not be an issue. In a recent head to head between the inline and acoustic systems, the inline system warned of a potential loss of containment, whilst the acoustic did not detect any solids production (and if it had it wouldn't have quantified the erosion). The client did not know which way to turn and therefore carried on. Within a matter of minutes of the probe being depleted there was a LOC incident, along with the related safety issue and shut in. The cost of the probe was minimal compared to rig time lost, disruption of the test procedures and the potential safety issues.

In production phases the probe element thickness is calculated as a result of the expected lifetime of the field / well and the allowable erosion rate. If metal loss increases significantly and no remedial action is taken, the probe may deplete over time but this would be the least of the clients' worries.

Q. Do you sell the system and train client personnel?

No, we do not sell the system, although we may look at long term lease. It is a service that we provide and the added value comes from the experience, knowledge and judgment of the engineer.

Q. Why are the probes so expensive?

The probes are not expensive, LOC, safety issues and uncertain data with which to make decisions are.