Volume 6 Preprint 7
New Developments in the Use of Chemicals for Pipeline Corrosion Control
Keywords: Corrosion, pipeline, gas, monitoring, inspection, inhibitor, foamer, environment
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Volume 6 Paper C011
New Developments in the Use of Chemicals for
Pipeline Corrosion Control
Baker Petrolite, Kirkby Bank Road, Knowsley Industrial Park, Liverpool
L33 7SY, UK
Advances are continually being made in the corrosion management of
pipelines, in particular gas production pipelines. Flow simulation
models can be developed which allow for changing conditions at
particular areas of a pipeline. Corrosion rate trends can be correlated
with these simultaneously changing process conditions. It is shown
how water hold-up, and its consequent effects, can be overcome by
chemical means. Recent developments in corrosion monitoring and
inspection techniques that have led to improvements in the way
pipelines can be monitored for corrosion are assessed. New
developments are also described in the way corrosion inhibitors are
evaluated for their environmental acceptability.
Keywords: Corrosion, pipeline, gas, monitoring, inspection, inhibitor,
Corrosion is a serious problem with pipelines, both from an internal
and external point of view. In the present case consideration is given
to the effects of internal corrosion in gas pipelines. For the safe and
reliable operation of gas systems it is important to detect the location
and quantify the amount of internal corrosion that occurs before
significant damage occurs.
Pipeline failures often occur due to pitting corrosion. This will be a
problem if corrosive water collects in traps and there is no provision
for chemical treatment. For example, with gas transmission systems
the primary location for corrosion to occur is where water coalesces
and collects in low spots.
Corrosion in gas pipelines
With gas pipeline systems the rate of gas flow is not constant over
time. Initially in the life of a field there are typically high production
volumes. However, both hydrocarbon production and velocity
decrease with time. These lower velocities lead to settling of water
and solids in stagnant areas. Corrosion in pipelines can result from
these changes in production conditions occurring with time.
Internal corrosion is a major cause of pipeline failure, and can
approach 50% of all incidents . Pipeline failure is frequently due to
pitting, a form of localised corrosion. Actual pipeline failure rates
depend on the pitting rate and the wall thickness . Attempting to
determine specific pipeline locations that represent an integrity threat
is better than applying a corrosion rate to an entire line length. If the
locations along a pipeline length most likely to accumulate water have
not corroded then other locations less likely to accumulate water are
unlikely to have suffered serious corrosion .
The actual control of internal corrosion is a vital part of any pipeline
integrity management system. Knowledge of the operating conditions
together with monitoring of the liquid and solids content can help to
determine the locations of highest risk for internal corrosion. Once
the highest risk sections of pipeline are identified remediation
strategies can be developed including removal of liquids and solids
even if the line cannot be pigged. In addition corrosion inhibition can
be used to control internal corrosion.
Water hold-up in gas pipelines
Water accumulation in gas gathering systems cause significant
reductions in cross sectional area. The quantity of deposits and liquid
hold-up present is a strong indicator of the potential that internal
corrosion is occurring.
The measured corrosion rates can be related to liquid hold up. In gas
transmission systems, the component which would be a liquid is
present normally only as a mist or dispersion within the gas phase.
Liquid phases are seen only when system upsets occur though this
happens relatively frequently. With gas gathering systems liquid holdup is generally present.
A corrosive environment within a pipeline segment is created when the
shear forces applied by the gas phase on the aqueous phase are
insufficient to carry the water over a region of upward inclination. The
gas-liquid shear forces are insufficient to overcome the gravitational
forces and move the water. When this occurs water accumulates on
the up-dip region of the pipeline segment . A localised water
fraction as high as 50% of the cross-sectional area of the pipeline can
occur and be sustained within the up-dip inclination for up to several
thousand feet in length. These water accumulations cause significant
pressure drops in gathering systems.
Modelling can be used to both predict when water hold up occurs and
to measure the amount of liquid. Flow modelling can be used to
predict the locations at which water will coalesce, separate and collect.
Flow modelling can also be used to determine the amount of water
hold-up already present in the line.
Detailed examination of locations along a pipeline where water first
builds up provides information about the remaining length of the pipe.
Corrosion is most likely (and may be the most severe) where water first
It has been observed in some low-flow segments that changes in the
inclination angle of less than 1 degree (and as little as 0.25 degrees)
can be sufficient to cause significant water accumulations. Stagnant
water traps will form if the pipeline is inclined above a certain critical
angle. The first pipe inclination equal to or greater than the critical
angle has the greatest opportunity for internal corrosion due to the
probability for liquid hold-up . Evaluation techniques must be
applied to verify the pipe integrity at this point. In one example it was
determined that an angle of 3.34° was the critical angle for water holdup .
The critical angle is very sensitive to changes in flow rate and
pressure. For example, it was noted that there was a slight flow rate
drop associated with delivery stations along a particular line. To
account for this change in flow rate and associated pressure drop the
pipeline was segmented based on the operating conditions. For each
section an associated critical angle was calculated. This angle was
then compared with the inclination angle. Locations were deemed to
be at risk where the inclination angle exceeded the critical angle of the
pipeline. The first location where the critical angle was exceeded was
assumed to have the highest risk. This data was compared with inline inspection data to help quantify the internal corrosion
Knowledge of the operating conditions along the entire length of the
pipeline will help the assessment of internal corrosion. This includes
elevation profile (for water accumulation), low spots and diameter
changes. This is in addition to pressure, temperature, flow rates and
gas composition (especially CO2, H2S and water levels).
Inspection and Monitoring
It is very important that an accurate record of any upsets that might
affect the corrosive conditions within the specified pipeline is
maintained by the operator. For pipelines with limited historical
information an in-line inspection tool could be considered to establish
a baseline assessment of the internal condition of the pipe.
In-line inspection surveys with the use of intelligent pigs can be used
to determine the internal corrosion condition of natural gas pipelines.
These can be moved through the pipeline either by tether or by the
use of product flow. Intelligent pigs are used to survey the corrosion
damage within a pipeline using ultra sonic or magnetic flux leakage
methods of detection. In most cases magnetic flux leakage tools are
used for gas pipelines [7, 8]. They are used to detect and measure the
effects of localised corrosion including pits and even cracks [9, 10].
Solids and deposits are frequently overlooked as a part of a monitoring
programme but all solids collected from a pipeline need to be
identified, catalogued and tracked .
It is normally recommended that at least two techniques be used to
Weight loss coupons and probes if possible should be located at those
areas which are the most representative of the highest risk of internal
corrosion. However, retrieval of the coupons or probes is an important
issue. Often it is not possible to gain access to some of the areas of
pipelines potentially most at risk from corrosion. Coupons provide a
long term average measurement of the corrosion rate and can give a
visible indication if localised corrosion or deposits are occurring.
Electrochemical probes will give instantaneous estimates of corrosion
rates. Electrical resistance probes will give an average corrosion rate
over a period of time.
New methods of corrosion monitoring include those of non-intrusive
techniques for monitoring corrosion. For example, one technique
involves inducing an electric current and monitoring the changes in
the corresponding electrical field pattern in the pipe wall . These
may be due to metal loss from general corrosion, pitting or erosion or
other phenomena (e.g. cracks). Sensing pins/electrodes are
distributed in an array over the area to be monitored to detect changes
in the electrical field pattern. The electrical potential map derived is
proportional to the change in wall thickness. The sensitivity of the
technique is typically 0.5% of the remaining wall thickness (for general
High-resolution electrical resistance techniques also have been
developed . These should allow accurate corrosion rate
determinations to be undertaken more quickly. The technique would
not require a conductive water phase. The sensor possesses a high
signal to noise ratio, potentially enabling resolution down to +/- 5
ppm for a 1 mm thick element.
Mitigation of corrosion
A chemical inhibition programme can be used to minimise the
corrosion rate. This is especially the case when free water is
continuously present or solids and liquids cannot be removed. A
corrosion inhibitor is applied to the line to reduce the corrosion rate
by at least 90% (often much higher). Laboratory testing and pipeline
corrosion rate monitoring are used to determine the effectiveness of a
corrosion inhibition programme. For continuous injection into the
system the corrosion inhibitor can be injected via an injection quill.
Corrosion inhibitor application in pipelines can also be by batch or
slug application. In a batch application the inhibitor is placed between
two pigs. In lines which can not be pigged a slug of chemical is
pumped into the line and the operating flow is used to deliver the
corrosion inhibitor. Such treatments are performed on a regular basis.
If water or solids are present in a pipeline in low spots the water can
be removed by a simple pigging operation. If a pipeline cannot be
pigged, hold-up or solids may be removed in some cases depending
on operating conditions by the application of a chemical cleaner or
Foamers will entrain liquids into the gas phase to form a ‘mist’ which
will be carried through with the gas phase. Cleaners will help suspend
solid deposits into a liquid phase.
If liquid water is flowing freely through the system an inhibition
programme will be required to minimise internal corrosion.
Field study – Removal of liquid hold-up
A sub-sea gas well had not been producing the predicted volumes of
gas and the gas gathering line was operating at increased pressures.
The production conditions in the line were modelled and
representative fluid samples collected. The accumulation of liquids in
the flow line was found to be the cause of the problem. Owing to the
water hold-up and the increased pressures in the line the corrosion
rates in the system had also increased. The pipeline ran ten miles
uphill between the wellhead and the platform. The line produced 0.2
MMSCMD gas and 57.6 cubic metres of water per day.
Mechanical removal of the liquids was not possible but a chemical
solution was cost effective and was investigated. A rigorous screening
process was used to select the proper chemical to remove the
accumulated liquids from the flow line by application at the wellhead.
The treatment by the foamer was at a rate of 7.5 litres per day and the
gas production rate was increased by 38% with no upsets (Figure 1).
The corrosion rates were also expected to have decreased due to the
decrease in system pressure and free water. The system experienced
a decrease in pressure of more than 10 bar.
Gas production optimisation
Gas production (MMSCMD)
Figure 1. Foamer injection started after 16th day. The gas
production optimisation occurred during removal of water in the
line and decreased corrosion rates
Recent changes in environmental policy
Much emphasis has been put on making oilfield chemicals more
responsive to the surrounding environment in recent years. Changes
in environmental regulations over the years have led to ever more
stringent environmental criteria which chemicals must face. At the
same time these environmental criteria have gradually become more
precise in nature, with specific, but representative, organisms being
To prevent the pollution of the NE Atlantic from land-based and
offshore sources a means of control was devised over the use and
discharge of offshore chemicals. A European body was set to develop
and adopt a Harmonised Mandatory Control Scheme (HMCS).
A new HMCS has been in force in the UK since August 2002. This is
operated as a discharge permit system. The main components of the
HMCS are a pre-screening scheme and a revised harmonized offshore
chemical notification format (which contains environmental property
information). This data is used in new software to assess the
environmental properties. The software evaluation is called CHARM
(Chemical Hazard Assessment and Risk Management). Chemicals such
as corrosion inhibitors used on offshore platforms must comply with
this process. In most cases in the UK this has replaced the Offshore
Chemical Notification Scheme (OCNS) procedure.
Initially the pre-screening is undertaken on the chemical components.
The chemical must possess biodegradability greater than 20%.
there must then be compliance with two out of three of the following
properties: for toxicity the EC50 should be greater then 10 mg/l, for
bio-accumulation the Log Pow less than 3 (or molecular weight greater
then 600) or biodegradability greater than 60%. If a component fails
pre-screening it will be flagged for substitution.
The process then uses CHARM software as a decision-support tool. It
involves the calculation of a Hazard Quotient (HQ). The HQ is
calculated using values from the environmental properties of the
chemical such as toxicity, the % of component in the product and the
expected product dose rate (specific to the water or total fluids).
These new protocols present a challenge to the selection and use of
corrosion inhibitors. However, not only are there corrosion inhibitors
which can be used under the new (or the old) schemes but rapid
developments have been taking place which allow the deployment of
new chemicals that are more environmentally friendly in nature. These
have been found to possess inhibition performance at least as good as
the more traditional inhibitor chemistries previously used.
The specific locations where internal corrosion is most likely to be a
threat to the integrity of pipelines need to be determined. Modelling
those areas where severe corrosion occurs due to water hold-up will
help this process. This will enable appropriate monitoring, inspection
and mitigation to be carried out before failures occur.
Corrosion control can be helped by procedures such as removal of
liquid hold-up and chemical means including corrosion inhibitors as
well as the use of foamers and cleaners.
Pipeline inspection and monitoring is essential to help maintain the
integrity of the equipment. Some improvements in the way pipelines
can be monitored for corrosion have been outlined.
Corrosion inhibitors are being developed which offer high levels of
protection whilst at the same time having a much reduced effect on
the environment in terms of their toxicological, biodegradation and
The author expresses his thanks to Baker Petrolite for permission to
present this paper. The author also wishes to record his thanks to his
colleagues, in particular W.Y.Mok, for their technical contributions.
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