corrosion monitoring solution for amine units - · pdf file3 permasense ltd, century house,...

1 Permasense Ltd, Century House, 100 Station Road, Horsham, RH13 5UZ, UK www.permasense.com [email protected] +44 20 3002 3672

1. Overview of the amine absorption/regeneration process

Hydrogen sulphide (H2S) and carbon dioxide (CO2) removal from process streams and from natural gas

is a necessary quality control step to meet final product sales specifications and to comply with

environmental emission limits.

These acidic contaminants are typically removed with aqueous mixtures of alkanol-amines and/or

alkylalkanol-amines (amine) in a regenerable process. The handling of acidic process streams and rich

amine (amine that is highly loaded with H2S/CO2) solutions will always result in corrosion by nature of

these compounds. Accelerated corrosion episodes and potential leaks and failures can lead to

unplanned outages, which can severely impact the plant revenues.

Acid gas is removed from the gas stream or liquid process stream by counter-current reactive

absorption with a lean aqueous amine solution in a multistage absorber tower at feed gas pressure.

Hydrocarbons and other non-reactive dissolved gases are recovered from the aqueous amine solution

by pressure reduction in a flash tank. Based on amine solution chemistry, acid gas removal from the

rich amine solution is performed at elevated temperatures by counter-current steam stripping. This

is the amine regeneration step. Stripping steam, which is used for both heating and acid gas dilution,

is contacted with the rich amine in a multistage regenerator tower operated at low pressure. A

reboiler is fed with the bottoms of the regenerator tower below the steam stripping section to

minimize water usage. The acid gas is separated from the condensed water in the overhead reflux

drum. The lean/rich amine heat exchanger minimises the energy consumption of the amine

regeneration tower. The hot/lean solution is pumped from the bottoms of the regenerator tower

through the lean/rich amine heat exchanger, the lean amine cooler and a filter system before being

recycled back to the top of the absorber tower.

2. Overview of corrosion issues within amine units Amine systems are subject to corrosion by both carbon dioxide and hydrogen sulphide in the vapour

phase, in the amine solution, and in the regenerator reflux, as well as amine degradation products in

the amine solution. In refineries specifically, amine systems suffer from corrosion by several

components not generally found in natural and synthesis gases, such as ammonia, hydrogen cyanide,

and organic acids, some of which will accumulate at various points around the refinery amine system.

There are several key variables for assessing the potential for amine unit corrosion, which makes

corrosion predictions without online monitoring very complex:

− Acid gas loading

− Velocity and wall shear stress

Corrosion monitoring solution for amine units


− Temperature

− Impurities and heat stable amine salts

− CO2 to H2S ratio

− Choice of amine-type

Figure 1: Amine unit process flow diagram showing high risk corrosion areas

Figure 1, above, shows the predicted variation of corrosion rates for carbon steel with amine acid gas

loading and velocity. This shows that, as would be expected, high rich amine H2S loading combined

with high velocity results in higher corrosion rates.

The simplified process flow diagram in Figure 2 gives a general overview of areas of an amine unit

most prone to corrosion and fouling:

Figure 2: Amine unit process flow diagram showing high risk corrosion areas

As shown, corrosion in amine plants can be divided into two types:

o Wet acid gas corrosion of carbon steel from the reaction of CO2 and H2S with iron through a

thin liquid film;

o Amine solution corrosion of carbon steel in the presence of aqueous amine.


Non-insulated amine absorbers are subject to water vapour condensation. With very low levels of H2S

being present with the CO2, carbonic acid can form resulting in accelerated corrosion rates with carbon

steel, especially in the vapour space at the bottom of the absorber.

Sediments (for example, iron-based corrosion products) in the process stream erode the inlet nozzle

and accumulate in the flash tank, which can increase the risk of under deposit corrosion.

In the lean/rich amine heat exchanger, two-phase flow can occur from aqueous solution boiling and/or

acid gas stripping due to insufficient back pressure on the rich stream. Rapid thinning of metal

surfaces and excessive vibration can occur in both plate frame and shell and tube lean/rich amine heat

exchanger. The counter-current flow design maximizes heat recovery, but also has consequences for

corrosion. When the rich amine solution is fed through the tube side to prevent fouling, it is more

likely that bubbles will be formed at the top of the shell than if lean amine solution was routed tube-

side. Non-condensable gases, such as air and hydrocarbons, accumulate in the shell and prevent the

amine solution from wetting metal surfaces. In applications where CO2 is the only acid gas or where

H2S levels are very low in the regenerated amine solution, carbon steel surfaces not wetted by the

amine solution are susceptible to carbonic acid attack wherever water vapour condenses.

Another common problem with regenerator inlets is the formation of a two-phase feed, which results

in erosion of the vessel wall opposite the feed point and the carryover of liquid droplets in the vapour

stream leaving the regenerator.

Reboiler feed pressure is an important design parameter to facilitate two phase-flow in the correct

stages of the reboiler. Asymmetrical flow conditions and flow obstacles like traditional intrusive

corrosion monitoring have been proven to cause increased turbulence in the high velocity vapour flow

and accelerated erosion onto the metal surfaces further downstream.

Sheer rates, turbulence and steam velocities are also key for corrosion and erosion control in the

overhead condenser and accumulator section. Vapours impinging onto downstream metal surfaces

can result in erosion of the equipment wall and any iron sulphide passivation layer can be easily

removed, leaving surfaces bare for further corrosion attack.

There is also potential for corrosion caused by heat-stable salts in amine treating units. Heat stable

salts are the reaction products of the amine with strong acid compounds (like CO2). These are usually

introduced with make-up water and the feed gas stream, or generated within the unit by chemical

reaction with other contaminants, such as O2, CO, cyanides and SO2. Heat stable salts are non-

regenerable at the process conditions used in the regenerator tower, so they accumulate in the amine

throughout the plant, causing significant corrosion. The corrosion products themselves, iron sulphide

and iron carbonate are entrained in the circulating amine as solid particles, which can cause other

operational difficulties such as foaming, fouling and emulsions. This impedes the reliability of the

amine unit in terms of operation, throughput, treatment capacity and absorption capability.

3. Commercial impact of amine unit shutdowns

Like sour water strippers, amine units are one of the forgotten ‘workhorses’ of process plant – most

of the time, while the amine absorption and regeneration system operates satisfactorily, it needs little

attention and minimal focus from the plant operators and engineers. However, a failure in the amine

system can cause a major problem for operations, unless there is adequate redundancy of amine

treating available – ultimately, this could result in a full plant shutdown while repairs are carried out.


In many instances, capital cost constraints during the original plant construction, from capacity

expansion projects or, specifically in refining, from clean fuels projects, have resulted in a lack of spare

capacity or redundancy in the amine facilities at many plants. Some plants operate with multiple

parallel amine regeneration trains to enable parts of the amine system to be shut down for

maintenance for a period of time – but this is not always the case – especially on offshore production

facilities where space and weight is limited. In the refining industry, increasing severity of operation

of hydrotreating units driven by ever-lower sulphur specifications of finished gasoline, jet fuel and

diesel has increased the pressure on the amine absorption and regeneration system, and the quantity

of H2S has increased as a result. In some cases, the original facilities are being operated at significantly

higher processing rates and amine H2S loading than the original design, as a means of conserving

capital from an upgrading project budget.

In turn, this trend has limited the flexibility that the processing facility has to shut down the amine

system for repairs in the event of a corrosion-induced leak, as the risk of H2S gas evolution from amine

solution means it is not safe practice to store rich amine.

Without storage for rich amine, the facility is forced to limit the H2S load on the amine system by, for

example:

• Change of feedstock (heavy, high sulphur crudes changed to light, lower sulphur and more

expensive feeds),

• Reduced production rate (lower natural gas feed rate to a gas processing platform or onshore

plant) or,

• Change of production mode (yielding high sulphur, raw gasoil to storage for later reprocessing,

rather than producing ultra-low sulphur, high value diesel).

Lower H2S production during an amine system outage can also result in difficulties in the operation of

downstream sulphur recovery units, which can be temperamental to wide changes in gas feed rate,

resulting in plugging of the reactor tubes or of the dip legs into liquid sulphur storage tanks.

Continued operation without adequate amine capacity also risks violating the facility gaseous

emissions quality limits, which could result in enforcement orders and/or greater scrutiny of the

facility operations by the local and/or national regulators.

The commercial impact of an amine system outage on a given plant will depend on the type of plant,

its specific configuration and the feed quality, but is often significant.

In a refinery, on an assumption that an amine system outage would constrain total refinery throughput

by an average of only 10% for a 5 day period while repairs were effected. Using a representative

refining margin of $7/bbl, the impact on a refinery of 200,000 bpd capacity would be $0.7 Million plus

the costs of the repair. Repairs could be, for example, tube sheet replacement for the amine

regenerator rich/lean exchanger, which is at high risk of corrosion and could be of the order of $0.3

Million fully installed. It could therefore be anticipated that an unplanned 5 day shutdown of an amine

regeneration train in a refinery (even with some degree of redundant capacity) could cost in excess of

$1 Million in lost production.

In a large gas processing plant of 500 MMSCFD capacity, a reduction in throughput by, for example,

25%, due to an unplanned amine system outage, with a prevailing natural gas sales value of

$3/MMBTU (Henry Hub average quotation from 2014 to 2016), would result in a loss of revenue of

approximately $400,000 for a 5 day outage, plus the cost of repairs, which could easily take the total

lost opportunity value to $0.6 Million.


4. Permasense sensors build confidence in safe and reliable amine

unit operations

Permasense continuous wall thickness measurement sensors are designed to be robust to all industrial

environments and ideally suited to monitor corrosion in the highest risk areas of amine units. The

sensors communicate wirelessly with a central gateway which delivers the data direct to the desk of

the integrity or operations engineer, avoiding the need to visit the unit to make or collect

measurements.

The monitoring data enables engineers to reliably determine if corrosion is taking place within the

equipment, supporting the management of the unit integrity between planned shutdowns. This data

is particularly valuable in understanding the correlation between corrosion rates and changes in

feedstock and process conditions, particularly due to short term upsets, minimises the risk of leaks

and enables better forecasting of equipment retirement.

Permasense systems support the optimisation of corrosion prevention and mitigation strategies, as

well as delivering data to enable justification of metallurgy upgrade decisions to corrosion resistant

alloys.

5. Permasense solution for high-risk locations for amine systems

The diagram below (Figure 3) shows an outline of a typical Permasense corrosion monitoring system

for an amine unit:

Figure 3: Outline monitoring locations for amine units

Potential monitoring locations are indicated in Figure 3. A typical installation would comprise

approximately 20 monitoring locations, with 2-4 sensors per location.


Temperature resistance - Sensors can be supplied with three waveguide lengths: 100mm, 300mm and

500mm. For many locations within the amine system, 100mm waveguide sensors, providing

temperature resistance up to 150˚C (300˚F) will be suitable. Higher temperature locations, such as

near to the regenerator reboiler, standard 300mm waveguide sensors will be required (with

temperature resistance up to 600˚C (1100˚F).

Figure 4: 100mm short waveguide sensor on clamp assembly

Metallurgies - Sensors can be mounted on a full range of materials including carbon and cast carbon

steel, chrome steels (1% Cr (5130), P5, P9), duplex, P265GH (430-161), 1.4571 (316Ti), P295GH

(17Mn4), Monel, HR120, Inconel, Incoloy and Hastelloy.

Sensor mounting methods - Stud mounting, using the drawn arc method, offers the greatest flexibility

in choice of monitoring locations. Studs can be welded on to live piping and in hazardous areas, e.g.

by employing friction stud welding.

Figure 5: Stud mounted sensor installation

When welding is not permissible or possible due to material restrictions, Permasense can supply

clamps in a variety of diameters up to 40", and for towers and vessels, custom-built mounting saddles,

which can enable magnetic attachment to vessel shells or they can be affixed using epoxy where non-

magnetic materials are present.


Figure 6: Epoxy adhesive saddle for sensor mounting

Figure 7: Clamp assembly for sensor mounting

Figure 8: Magnetic saddle assembly for sensor mounting

6. Introducing the Permasense ET210 sensor model

Permasense has recently introduced the ET210 sensor for lower temperature applications (up to 120

°C (250 °F)) making it ideal for most areas of an amine system. This sensor uses specially designed

very low power EMAT technology which enables measurement of the metal thickness through


external corrosion protection coatings, up to 1mm thick, without any damage. The very low power

requirement enables EMAT-based technology to be permanently deployed in Zone 0 intrinsic safety

rated areas of the plant for the first time. Each sensor is attached to the outside of the equipment

via an integral magnet, which along with WirelessHART protocol compliant communications and

battery power makes the installation very quick and convenient. A secondary plastic strap secures

the sensor in place, as shown in Figure 9, and a steel lanyard is connected through the sensor body

to provide total protection against falling. The measurement location requires light surface

preparation prior to sensor mounting, such as wire brush and light emery paper. Hence, each sensor

can be installed in just a few minutes.

ET210 sensors can easily be mounted in circumferential arrays, as shown in Figure 10, to monitor

localised corrosion attack mechanisms.

Figure 9: ET210 sensor. Non-intrusive, no paint removal

required, magnetic mounting with lightweight securing strap

Figure 10: Circumferential array of

ET210 sensors

7. Example deployment

Case study - A European refiner operated four parallel amine trains – each with a similar configuration

and employing real-time corrosion monitoring at key locations using Permasense sensor technology.

Figure 11: Extract of the customer’s amine system P&ID


The following trends show the Permasense data for one of the sensors mounted on the amine

regenerator for each train, numbered 1-4, over the period July 2012 to July 2014.

While it is clear that there is no/little corrosion activity in amine trains 1-3, there is significant corrosion

attack at the same location in amine train 4, measured at 1 mm/year (40 mpy).

The Permasense data enabled the plant corrosion engineer to clearly demonstrate the difference in

performance across the four trains to operations/technical staff, who carried out further

investigations. It was discovered that, due to the non-uniform line-up of acid gas streams from the

various upstream units, train 4 feed gas had a much higher CO2 content than the other 3 trains. It was

then possible to change feed gas routings to share the high CO2 acid gas across all four trains to limit

the corrosive effect.


Conclusions:

1. The Permasense data identified a corrosion issue in train 4 that would not otherwise have

been expected, or detected until the next shutdown (or following an equipment leak, if

earlier).

2. The lifetime of the Train 4 amine unit has been extended by many years, resulting in a

significant net cost saving for the customer, from deferred equipment retirement and

replacement costs while avoiding risk of an unplanned outage.

3. This case study also demonstrates the effectiveness of the Permasense data, in combination

with process data, to provide a concrete basis and common language for troubleshooting

across the Process-Technical/Operations and Integrity Management/Corrosion/Inspection

functions and to enable process changes to be made to mitigate corrosion.

Contact:

For further information, please contact us by email at [email protected] or by telephone as

follows:

HEAD OFFICE

+44 20 3002 3672

ABERDEEN OFFICE

+44 122 462 8258

AMERICAS OFFICE (TX)

+1 713 425 6359

ASIA OFFICE (KL)

+60 3 6200 0788

corrosion monitoring solution for amine units - · pdf file3 permasense ltd, century house,...

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