astham Refinery Limited is

a company owned 50

percent by Shell U.K.

Limited and 50 percent by

AB Nynas Limited. It oper-

ates a distillation unit established in

1966 and designed to run on heavy

naphthenic crude. In 1989 the unit was

expanded to provide a capacity of 1.2

million tonnes per year.

Assistant editor of JPCL Europe, Dan

Mobbs interviewed engineering man-

ager Andy Smith to find out how coat-

ing maintenance is handled at

Eastham Oil Refinery in Cheshire’s

Ellesmere Port, England.

Dan Mobbs: How do you begin

planning a maintenance-painting

program for a refinery?

Andy Smith: We try and paint as

much as the budget allows. We have

started a program where we allocate x-

22 JPCL Annual Bonus Issue / August 2014 / paintsquare.com

By Dan Mobbs

COATING MAINTENANCE AT AN OIL REFINERYamount each year to be utilized on

maintenance of either pipelines or

tanks. We inspect the plant to deter-

mine what the main problems are that

need to be addressed. We don’t allocate

one piece of plant every year and look

at just that.

For instance when we do a tank out-

age, and we take about five tanks out

each year to do some major repair work

or checks, we would paint the tank only

if there were any obvious pipes or sup-

ports or degradation concerns. But we

don’t say every five years, “We’re going

to go around and paint again.”

DM: You’re currently undertaking a

program to move pipe supports and

use an engineering wrap to extend

service life. What is the progress of

this?

AS: It’s a requirement by the Health and

Safety Executive [HSE, UK] to establish

more in-depth written schemes and pro-

cedures for examination of every piece of

plant. Basically some of our dock lines sit

directly on supports without shoes

attached, which can cause problems.

These lines can be in good or satisfactory

condition until they reach the support,

where you can find more localized wear

due to corrosion and erosion.

In the past, if we found issues on

these lines, we would have to cut the

Annual Bonus Issue

East

ham

Oil

Refin

ery,

UK.

All

phot

os: D

an M

obbs

paintsquare.com / August 2014 / JPCL Annual Bonus Issue 23

24 JPCL Annual Bonus Issue / August 2014 / paintsquare.com

corroded pipe out and put a spool piece

in. This is a big issue for us because

we’ve got an 1,800-metre line down to

the QE2 docks where we load and

unload material from tankers. It’s not a

piggable line, so we have to empty the

line of something like 150 tonnes of

product and then clean the line before

we can weld. This can create problems

on the docks, as ships are coming and

going and we have to stop hot work. I

discovered, however, a company in

Aberdeen that has a composite-wrap

repair material that, depending upon the

amount of work needed on the line, can

give between 15 and 20 years warranty.

They also take responsibility for the life

of the line, and they’ve established this

with the HSE.

What I decided to do was cut away

the old support, then put in a new sup-

port and shoe up the pipe to provide a

better support about a metre further

along the line. This exposed where the

corrosion on these dock lines was. We

checked and double checked that the

results we got from the inspection were

indicative of what you’d get from an

ultrasonic test, which they were, and we

found 11 areas that had a problem with

corrosion due to a loss of wall thickness.

The company came in and did the

wraps on the dock lines, and we made

significant savings in terms of the repairs

against the spool maintenance. This

enabled the API 570-qualified inspector

to upgrade his original report regarding

the pipeline’s life expectancy.

DM: Many refineries of a certain

age suffer with dissimilar metal

corrosion. Is this something affect-

ing your facility? And if so, how do

you manage it?

AS: This plant was built 40 to 50 years

ago and was constructed with a short-

term view that it wasn’t going to be

here that long. They put stainless-steel

pipes in a lot of areas, but then the

flanges were carbon steel. That’s the

problem I’ve got now — carbon steel

flanges on stainless lines.

Our plant runs at such a high tempera-

ture that you can’t do inspection apart

from during shutdown, which we do for

four weeks in January. During the last two

shutdowns, the whole of the naphtha line

through the plant and the entire light gas

oil (LGO) line were inspected, as they’re

the two critical lines. We have isometric

drawings for the whole line highlighting

every single flange, valve and drain point;

which the inspector uses in the examina-

tion. It doesn’t take long to get the inspec-

tor’s report and photos back, so if there’s

a major concern, we order a repair and go

stainless-to-stainless.

There were no significant findings on

the LGO line. One flange was risk-

assessed and deemed it could wait until

the next shutdown. Over the next five

years, every single pipeline in this plant

will be checked and inspected. Any area

of major concern will be repaired and

areas of minor concern will be checked

visually on an annual basis to assess

degradation.

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DM: Fitness-for-purpose studies on

the on-site storage tanks are cur-

rently being undertaken. Tell me

about that.

AS: We inspect tanks to EEMUA 159

[Above-ground storage tanks – a guide to

inspection, maintenance and repair pub-

lished by the Engineering Equipment &

Materials Users’ Association] which is the

specification put together a few years ago

combining both American Petroleum

Institute and British standards. We’ve car-

ried out about 50 tank inspections in 11

years, because when I came here I was-

n’t convinced about the quality of the

existing reports, so we put in an inspec-

tion regime.

Actually, this year we are coming to the

end of inspecting every single tank, but

all the inspections we are doing now,

including on pipes, are remaining-life

processes. The inspectors will calculate a

remaining life based on corrosion aspects

at the plant, and from that we can devel-

op what the inspection criteria will be. So

one tank on our log might be six years

until the next inspection and one might

be 15, which is very different from the

old days, when we would say, “It’s a

crude tank; we’ll check it every 10 years.”

Everything is now dependent upon

inspection criteria, and that’s what has

changed really in the last two years.

We’ve invested a considerable sum

over the last 10 years on tanks, modifi-

cations, and repairs. For example, we

started using a new thermal-insulating,

two- to three-mm-thick coating that

takes away the requirement for insula-

tion, on the roofs of a lot of our bitu-

men and distillate tanks.

Another example is the refurbishing of

two old tanks, situated on the banks of

the River Mersey, that store crude oil at

about 70 C. Insulation is damaged by

wind and water, which can cause huge

corrosion problems. We’ve stripped the

insulation off them already, and we’ll be

shot-blasting them clean, then using the

insulated coating, which is much cheap-

er than insulating and we can get a

good aesthetic finish.

DM: Risk-based inspections, site-

wide surveys of the paint, and

recording the condition of each

asset to meet HSE requirements

can be a major undertaking. How is

this handled at Eastham?

Everything we do on site is very

detailed and takes a lot of time to pro-

duce the necessary documents — as

well as a lot of investment. The para-

meters are continually changing.

In terms of engineering and mainte-

nance, it’s all about making everything

fit for purpose, and the only way you

can do that is identify — as we do —

the degradation mechanisms on each

piece of equipment. For instance, at

certain temperatures, erosion or abra-

sion might be occurring on some of

the lines. At higher temperatures it

could be naphthenic corrosion or sul-

phidation, so the first thing we have

to do is identify where the plant could

fail.

We identify the degradation mecha-

nism of each line, mark this on the iso-

metric drawings, and tag up and num-

ber every valve and flange. We then

inspect on the basis of the different

corrosion mechanisms, which means

doing different kinds of inspection.

One of the major jobs I’m tied up

with is going to take considerable time

from start to finish. The naphtha line

has been broken down into four areas.

The inspector has a written scheme of

examination for that piece of plant,

which tells him the drawing number,

inspection frequency, where the line is,

what it’s made of, temperatures, pres-

sures, what the required inspection

area is and what type of inspection

needs to be done. It’s a lengthy task.

We have completed the degradation

analyses, all the procedures have been

redone, and the written schemes of

examination are ongoing for a number

of plant items. We have time constraints

on completing the inspections during

shutdown, simply because of the tem-

peratures of the line. We simply can’t do

inspections all 52 weeks of the year.

26 JPCL Annual Bonus Issue / August 2014 / paintsquare.com

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susceptible to naphthenic corrosion

and sulphidation. We still have a lot of

other carbon steel that we’re repeatedly

measuring and monitoring, and if we

find a problem piece then we’ll cut it

out and replace it. That is principally

our view: over a period of time, most

pieces of plant and equipment will be

changed to stainless steel, but again

we’re not going to go on a knee-jerk

reaction and change everything for the

sake of it, as this new inspection criteria

will identify when it’s becoming critical.

We’ll know that it’s going to last for

three to four years, for example, and

then we can plan replacements well in

advance. Our procedure now is to

inspect, assess risk, and then determine

when we will review, repair, or replace.

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DM: What would you say the most

critical parts of the refinery are in

terms of corrosion problems and

how are they protected?

AS: The most critical pipelines are

those above 200 C and less than 330

C, because that’s almost the breeding

ground for naphthenic acid corrosion

(caused by oxidation of naphtha) and

sulphidation, which are the higher-end

degradation mechanisms. With naph-

thenic corrosion you could have a 200-

metre piece of line that looks perfect,

but in fact you could have a wormhole

straight through the line.

We’re replacing a lot of the original

carbon steel with stainless as we go, as

the basic 316 stainless grade is less

Annual Bonus Issue

We changed a significant amount of

heat exchangers, fin fans, and pipes to

stainless steel over the last 12 years.

When I first came here, people were

doing inspections ad nauseam. Now

we’ve expanded the inspection to five

or six techniques, all specific to what-

ever piece of plant we’re doing.

Because the inspections are more

detailed, we are actually reducing the

rate of inspections.

There are three major heating units

here at Eastham, which were always

difficult and expensive to inspect.

Ultrasonic testing was used to carry

out the inspections, which gave a lim-

ited amount of results, but then we

came across a company from The

Netherlands that carried out inspec-

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paintsquare.com / August 2014 / JPCL Annual Bonus Issue 29

tions by intelligent pig and we have

used this method for the last two

years. Not only did it give us 100-per-

cent inspection of the tubes, it also

cleared any potential fouling that could

have been building up. The cost for

carrying out this inspection has proved

economical, not only because it gives

us a full picture of the pipework, but

now we don’t have to go in the heater

every 12 months; it’s now every five

years, so the savings we’ve made are

huge.

There are a lot of inspections to be

carried out, and because we’re now

doing it right, it gives us the confidence

to expand the inspection regimes.

Although the initial inspection cost is

high, long term it’s more economical.

DM: What are the specifications for

the surface preparation and coat-

ing of the different areas?

AS: I don’t specify any surface prepara-

tion, but leave it to the coating people

to prepare accordingly for the coating

they are applying. When we’re doing a

tank with the aforementioned thermal-

insulating coating for example, they

might water-wash and bristle brush

and give me a 10-year guarantee. Even

if it were a specialist coating, I would

still leave it to them and wouldn’t

specify what they need to do. All I’m

interested in is how much it’s costing

and what the guarantee is. That’s their

criteria. JPCL