Nace sp0499 2007 (1)

Standard Practice
Corrosion Control and Monitoring in
Seawater Injection Systems
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© 2013, NACE International
SP0499-2012
(formerly TM0299-99)
Item No. 21237
Copyright NACE International
Provided by IHS under license with NACE Licensee=University of Alberta/5966844001, User=trert, rtyrtyrty
Not for Resale, 03/04/2015 09:38:26 MST
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SP0499-2012
NACE International i
_________________________________________________________________________
Foreword
This NACE standard practice provides guidance in controlling and monitoring for corrosion,
bacteria, and water quality to corrosion engineers, field corrosion, production, technical, and
operating personnel, and others involved in corrosion control of seawater injection systems. This
standard includes descriptions of equipment and practices for controlling and monitoring corrosion
in seawater injection systems.
This standard was originally adapted from a report produced by the former Corrosion Engineering
Association (CEA), which operated in the United Kingdom under the auspices of NACE
International and the Institute of Corrosion (ICorr).
(1)
The standard was developed as a test method
(TM) in 1999 by Task Group (TG) T-1D-47, a component of Unit Committee T-1D, “Corrosion
Monitoring and Control of Corrosion Environments in Petroleum Production Operations,” and
revised in 2007 and 2011 by TG 345, “Corrosion Monitoring in Seawater Injection Systems:
Review of NACE Standard TM0299-99.” During the 2007 revision, the TG decided to change the
designation of the standard from a TM to a standard practice (SP). TG 345 is administered by
Specific Technology Group (STG) 31, “Oil and Gas Production—Corrosion and Scale Inhibition.”
This standard is issued by NACE International under the auspices of STG 31.
In NACE standards, the terms shall, must, should, and may are used in accordance with the
definitions of these terms in the NACE Publications Style Manual. The terms shall and must are used
to state a requirement, and are considered mandatory. The term should is used to state something
good and is recommended, but is not considered mandatory. The term may is used to state
something considered optional.
_________________________________________________________________________
(1)
Institute of Corrosion (ICorr), Corrosion House, Vimy Court, Leighton Buzzard, Bedfordshire LU7 1FG, United Kingdom.
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SP0499-2012
ii NACE International
_________________________________________________________________________
Standard Practice
Corrosion Control and Monitoring in
Seawater Injection Systems
Contents
1. General.......................................................................................................................... 1
2. The Need for Corrosion Control .................................................................................... 2
3. Corrosion Control in Seawater Injection Systems......................................................... 2
4. Monitoring of Seawater Injection Systems.................................................................... 4
5. Materials Selection for Seawater Injection Systems ..................................................... 9
References........................................................................................................................ 10
Bibliography ...................................................................................................................... 11
TABLES
Table 1: Recommendations for Injection System Materials.............................................. 10
FIGURES
Figure 1: Layout of a typical water injection system ........................................................... 1
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NACE International 1
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Section 1: General
1.1 This standard covers aspects of corrosion control and monitoring in seawater injection systems.
1.2 Most seawater injection systems rely on coatings, liners, plastics, composite materials, and corrosion-resistant alloys (CRAs)
to overcome potential corrosion problems prior to deoxygenation. The practices in this standard concentrate more on controlling
and monitoring corrosion in facilities downstream from deoxygenation, but also address some of the aspects relevant to selection
of appropriate mitigation and control methods for upstream service conditions. The standard also addresses materials selection
for seawater injection systems.
1.3 This standard presents practices for controlling and monitoring corrosion in seawater injection systems. However, many of
these practices may be applied to other types of water injection systems, such as:
(a) Systems for reinjection of produced water;
(b) Aquifer-sourced water injection systems; and
(c) River or surface water injection systems.
1.4 Figure 1 shows a typical layout of a water injection system—in this case, an offshore application. The purpose of Figure 1 is
to show equipment items typically associated with water injection systems and common fluid treatments and monitoring types and
locations. It does not show all items of equipment or all possible fluid treatments or monitoring types that can be used in water
injection systems.
Figure 1: Layout of a typical water injection system, indicating recommended chemical treatment locations
and monitoring points.
Seawater lift pump
Deaerator tower
Coarse filters Fine filters Injection pumps
Booster pumps
Seawater lift caisson
Injection
discharge header
Flowlines
(1)
(2)
(3) (4)
(3)
(5)
(6)
(7)
(8)
(9)
(9) (9) (9) (9)
(10)
(10) (10) (10)
Key to Figure:
(1) Addition of chlorine/electrochlorination
(2) Addition of filtration agents
(3) Chlorine monitoring upstream and downstream of deaerator
(4) Injection of organic biocide
(5) Galvanic probe
(6) pH, oxygen and residual oxygen scavenger monitoring
(7) Monitoring of suspended solids, sessile and planktonic bacteria
(8) Oxygen monitoring downstream of injection pumps
(9) Probes/coupons/bioprobes on injection discharge header and flowlines
(10) Wellhead monitoring of flowrate, temperature and pressure
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2 NACE International
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Section 2: The Need for Corrosion Control
2.1 The importance of controlling corrosion damage in the carbon steel (CS) pipework of a seawater injection system to ensure
the integrity of topside and downhole equipment and minimize system operating and maintenance costs is widely recognized.
2.2 Equally important is a requirement to avoid reservoir formation blockage by corrosion by-products and bacterial debris in
seawater injection wells. In oil fields in which recovery of reserves is from a formation with permeabilities of a few millidarcies,
(2)
this requirement can influence the acceptable level of corrosion and the methods of monitoring and control. Corrosion products
(e.g., iron oxide and sulfide) and bacterial biomass have caused considerable damage, even in formations with high permeability.
2.3 The necessary corrosion control strategy is largely dictated by whether the major intent is to control corrosion damage or to
minimize formation damage. Therefore, the overall philosophy of operation should be system-specific. When considering
corrosion in seawater injection systems, the effect of velocity and entrained solids should also be considered. In addition to
technical considerations, the corrosion control philosophy may also be dictated by environmental considerations or regulatory
requirements, particularly regarding allowable chemical treatments.
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Section 3: Corrosion Control in Seawater Injection Systems
3.1 Corrosion in seawater injection systems is usually caused by the presence of oxygen, bacteria, or concentration cells from
solids in the seawater.
3.2 Deaeration (i.e., removal of dissolved oxygen) should be used to control oxygen corrosion in seawater injection systems.
3.2.1 Mechanical deaeration of the seawater is usually achieved by passing production gas through the seawater in an
exchange tower, or by vacuum deaeration in a tower.
3.2.2 When production gas stripping is used, the corrosiveness of the stripping gas is a factor that may require special
attention, particularly when the carbon dioxide (CO2) in the produced gas dissolves to form a corrosive solution, or when
produced or fuel gas contains hydrogen sulfide (H2S) or sulfur dioxide (SO2).
3.2.3 Mechanical deaeration alone may not be efficient enough to reduce the oxygen concentration to a level at which the
corrosiveness of the seawater is acceptable.
3.2.4 In addition to the long-established system of gas stripping and oxygen scavenging in a tower (see Figure 1),
commercial methods that are more compact and are well-suited to applications in which space is at a premium have become
available. Such systems differ from conventional larger gas stripping towers in that they use a recirculating nitrogen stream
as the stripping medium, which is then regenerated for further use. The use of chemicals for oxygen removal may be
reduced or eliminated by the use of such units, depending on the ultimate water quality required. In such systems, there is
often a resultant reduction in pH, and this should be considered when selecting materials for construction of equipment
downstream from such units.
3.3 An oxygen scavenger, such as ammonium or sodium bisulfite, shall be added to the seawater after mechanical deaeration to
ensure adequate oxygen removal to control corrosion by oxygen.
3.3.1 The type and quality of the oxygen scavenger used is a key factor.
3.3.1.1 Sodium sulfite, a dry powder, must be dissolved in water and is not very soluble. The solution, being dilute,
reacts quickly with atmospheric oxygen if stored in an open container exposed to air.
3.3.1.2 Ammonium bisulfite and sodium bisulfite, manufactured in liquid form and not required to be dissolved in water
prior to injection, are more convenient to use. These are concentrated solutions and are not as sensitive to air exposure.
Ammonium bisulfite is the more concentrated of the two and is somewhat more resistant to degradation from exposure
to air. However, both of these materials should be stored to eliminate or minimize exposure to air.
(2)
Millidarcy: 0.001 darcy—unit of measure of permeability; from Petroleum Engineer’s Handbook (Richardson, TX: Society of Petroleum
Engineers, 1987).
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3.3.2 Oxygen scavengers require time to react with the oxygen, and the part of the system immediately downstream from
the scavenger injection point may not be totally protected against oxygen corrosion.
3.3.3 The rate of reaction of the scavenger with oxygen depends on several factors, including the formulation of the oxygen
scavenger, the pH, the presence of interfering ions such as sulfide and calcium, and the temperature. Some oxygen
scavengers can be catalyzed (e.g., bisulfites by the addition of cobalt [15 parts per billion (ppb) of 2% cobalt chloride
solution]) to speed up the reaction. Addition of the catalyst separately has been found to have the most beneficial results in
speeding up reaction time. The presence of H2S can slow reaction rates and interferes with catalysts.
3.3.4 In some systems, there has been evidence to suggest that excessive amounts of oxygen scavengers above those
required to stoichiometrically remove oxygen can lead to an increase in the corrosion rate.
3.3.5 There have been suggestions that oxygen scavengers may undergo a chemical reaction under some circumstances,
producing H2S in small quantities, and this could affect the corrosion rate under actual system conditions. This theory is
based on the results of laboratory tests. This view is currently not widely supported. Greater quantities of sulfide may
potentially be released in the system as a result of the activity of sulfate-reducing bacteria (SRB).
3.4 Both aerobic and anaerobic bacteria are normally present in seawater and can become active in different parts of the
injection system.
3.4.1 Oxidizing biocides (primarily chlorine [Cl2], although bromine [Br2] has a similar effect) should be used for control of
microorganisms in the aerobic part of the seawater injection system (i.e., upstream from oxygen removal). Cl2 can be
generated by electrolysis from seawater, added via a gaseous source, or injected as an aqueous solution of sodium
hypochlorite (NaOCl) or chlorine dioxide (ClO2).
3.4.1.1 Chlorine is an oxidizing agent and tends to increase the corrosiveness of seawater in most situations.
Therefore, the Cl2 concentration at the generation plant should be controlled, and the addition of Cl2 should be precisely
metered so that the amount injected does not exceed the Cl2 demand. Excess Cl2 present after deaeration may
increase the corrosiveness of the seawater and/or cause pitting corrosion in the part of the system that is not
constructed of material resistant to seawater under oxidizing conditions. As an oxidizing agent, excess Cl2 increases the
oxygen scavenger requirement.
3.4.1.2 The part of the system upstream from oxygen removal is usually constructed of materials such as duplex
stainless steels (SSs) that are resistant to seawater containing oxygen and low concentrations of oxidizing biocides. To
ensure that this resistance is maintained, precautions should be taken to prevent local accumulation of Cl2, especially
under shutdown conditions.
3.4.1.3 Aerobic bacteria upstream from deaeration are normally controlled by Cl2 additions. Anaerobic bacteria can be
controlled to an extent by Cl2 injection. However, SRB are resistant to oxidizing biocides and can still flourish in many
places in seawater injection systems.
3.4.2 Organic biocides should be used to control anaerobic bacteria in the seawater injection system downstream from the
deaerators, where monitoring has shown there is a potential problem. Care should be taken when selecting suitable
biocides. In addition to their own effectiveness as biocides, they should be considered as part of the overall chemical cocktail
in the water injection system. Incorrect selection of biocide can cause compatibility issues with other chemicals, particularly
oxygen scavengers. In some cases in the field, compatibility issues have been severe enough to warrant switching off
oxygen scavengers during biocide injection and vice versa, resulting in less than optimum treatment of the water injection
system. Experienced chemical treatment companies with appropriate documented testing should be consulted to ensure
that a fully compatible range of chemicals can be specified.
3.5 Solids in the seawater should be removed or reduced to a minimum if required to reduce corrosion in the injection system.
Corrosion may occur under deposits, which can generate oxygen concentration cells. Solids present in the seawater may also
cause erosion-corrosion, particularly at bends or restrictions in the system.
3.5.1 Filtration of the seawater is commonly used to reduce solids in the injection system, which can form deposits in the
bottom of injection lines and set up concentration cells and harbor bacteria. Filtration agents such as ferric chloride and/or
polyelectrolytes are often added to the seawater to aid filtration.
3.5.1.1 Care should be taken to avoid excessive dosage of ferric chloride that can increase corrosion in the seawater
injection system.
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Section 4: Monitoring of Seawater Injection Systems
4.1 Corrosion in seawater injection systems should be monitored using probes (such as linear polarization resistance [LPR],
electrical resistance [ER], or galvanic probes) and corrosion coupons installed on the common discharge header between the
final-stage pumps and the injection wells. If there are particular concerns (e.g., regarding flow effects), flow lines to individual
injection wells should also be monitored.
4.1.1 Injection systems operate at high pressure, so safety is a concern. Equipment installation and use must conform to
sound engineering design and safe operating practice to avoid the potential safety hazards associated with system pressure.
4.2 The location of monitoring facilities varies according to the design of the particular system and information requirements
based on the local corrosion problems in the injection system or the chemical treatment program, as dictated by the monitoring
and corrosion-control philosophy.
4.2.1 Corrosion-monitoring and oxygen-measurement devices should be located downstream from water injection pumps,
where oxygen ingress may occur as a result of faulty pump seals.
4.2.2 Monitoring devices intended to reveal problems caused by the activity of SRB in a seawater injection system should be
located further downstream, such as in the flow line immediately upstream from the seawater injection wells.
4.2.3 In locating corrosion-monitoring facilities close to injection wellheads, consideration must be given to factors such as
the relative flow rate to different wells and the location of choke valves or orifice plates. Although in most cases seawater
injection wells might be expected to be under pressure at the wellhead, sometimes the wellhead is under vacuum, in which
case the monitoring device location may require additional evaluation.
4.2.4 Turbulence because of close proximity (particularly downstream) to chokes, orifices, tee-pieces, bends, and other flow
disruption sources can create high shear conditions. Monitoring devices should be located 5 to 10 pipe diameters away, if
possible. Monitoring devices may also be mounted close to the turbulence-inducing source to evaluate shear stress effects
rather than in locations with little or no shear stress.
4.3 Corrosion-Monitoring Devices
At least two monitoring devices should be located at each corrosion-monitoring point. Normally, one of these should be a
corrosion coupon set, and the second should be a corrosion-rate measuring probe. Device geometry (e.g., element types) may
have an effect on corrosion rate information obtained, and thus may influence any relative assessment of data.
The orientation of obtrusive monitoring devices and position across pipe flow can influence the quality of data obtained and
should be considered at the design stage. For example, if devices are exposed close to the pipe wall, the variable rheological
conditions, particularly around an access fitting, may adversely influence the data quality. Therefore, devices should be located
away from the pipe wall, tee-pieces, access fittings, and bends, unless specific effects associated with velocity or turbulence are
being monitored.
4.3.1 Corrosion Coupons
4.3.1.1 76 mm (3.0 in) long strip coupons are the type most commonly used in seawater injection systems. They are
usually installed in pairs, with the face parallel to the flow.
4.3.1.2 The coupon should be made from the same specification of material as the injection system being monitored.
4.3.1.3 Flush-disc coupons, although possibly offering a better insight into pipe wall corrosion, are insensitive relative to
strip coupons in detecting changes in system operation (e.g., corrosion from oxygen), and therefore should not be used
alone unless the sole purpose is to investigate pipe wall corrosion rates.
4.3.1.4 Cylindrical or rod-type coupons are used in some installations. They are reliable and may not be subject to
edge effects (strip coupons sometimes corrode badly at an edge as a result of metal-working stress or velocity effects).
They also can be used in a multiplace fitting so time studies of corrosion rates can be made. In many cases, however,
corrosion morphology cannot be detected with rod-type coupons.
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4.3.1.5 Coupon exposure times should be evaluated to find the optimal exposure for proper monitoring. The exposure
time of the coupon should normally be one to three months, depending on system requirements. The exposure time
should be dictated by the severity of corrosion and/or system velocity.
4.3.1.5.1 Too short an exposure time (e.g., less than one month) is likely to yield a result higher than a true
average corrosion rate during the period of exposure.
4.3.1.5.2 A freshly exposed, clean metal surface initially corrodes faster. A minimum exposure period of
approximately one month reduces the influence of the initial period on the overall mass loss.
4.3.1.5.3 When the mass loss is small, any error is likely to be magnified. A short exposure period may not
adequately demonstrate deposit growth trends, concentration, or other effects that might require more time to
develop.
4.3.1.5.4 Too long an exposure time (e.g., longer than three months) might provide information at intervals too
infrequent to be of use in controlling the process or the effectiveness of the chemical additives.
4.3.1.6 The use of a multiple-coupon device, such as a multichuck fitting, should be considered, and coupons should be
pulled at different intervals to determine whether corrosion is occurring and to optimize future exposure intervals.
4.3.1.7 Corrosion-monitoring data obtained from installations mounted on top of the line can be contaminated by effects
from entrained gas, oily matter, or deposits such as iron sulfide (FeS). Gas may break out, causing loss of contact
between the coupon and water. Oily matter and deposits may coat the coupon and isolate it from the water. Bottom-of-
the-line installations can be affected by erosion caused by sludges, sand, or silt in high-velocity systems, or by deposits
in low-velocity systems. In most cases, the effect of erosion is most noticeable when coupons are mounted toward the
bottom of the line. In situations in which SRB are active, bottom-of-the-line installation may be more indicative of their
effects.
4.3.1.7.1 Sand or silt may affect not only the results, but also the life of the monitoring installation. Access fitting
threads can be progressively worn by abrasive solids in bottom-mounted locations unless special precautions, such
as back-flush attachments on the retriever, are used.
4.3.1.7.2 Bottom-of-the-line sampling may be particularly useful when there are problems caused by abrasive
solids.
4.3.1.8 Other factors to consider when locating monitoring installations include the position of coupons. Occasionally,
coupons are mounted across the pipe wall itself or in sample traps that may be influenced by the flow effects and the
anticipated corrosion mechanisms. Shear stress generated by flow can remove protective scale.
4.3.1.8.1 Similar shear stress effects may be observed if coupons are installed immediately downstream from a
valve or bend because of flow disturbance. Generally, the distance from either side of a bend where flow distortion
is assumed to have decreased sufficiently to eliminate shear stress effects is approximately 5 to 10 times the pipe
diameter.
4.3.1.9 Localized corrosion effects may be visible on corrosion coupons after exposure. These include edge effects at
either the leading edge (impingement), the trailing edge (cavitation), under coupon insulation or elastic band (crevice
corrosion), or on the face of the coupon (various types of pitting or selective attack). Pitting morphology is usually more
obvious on strip coupons than on rod-type coupons unless it is obscured by velocity effects.
4.3.1.10 Observations made at the time the coupons are removed from the system should be recorded and used to
complement a more detailed deposit analysis carried out later. Certain spot tests may give information that will not be
available after the deposits have been oxidized by the atmosphere. Photographs taken at a field laboratory prior to
testing and photographs of coupons following testing provide valuable records.
4.3.1.11 Various methods of surface preparation before exposure are used for strip or cylindrical corrosion coupons.
The most commonly used method involves grit or glass-bead abrasive blasting to a specified finish. Alternatives include
grinding, which some operators prefer to use because of the ease with which pitting corrosion can be visually detected.
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4.3.2 Electrochemical Probes
4.3.2.1 LPR probes are particularly helpful for identifying upsets involving fluid contamination, process changes, or
chemical treatments in water injection systems. They are valuable for assessing effects of chemical additives such as
corrosion inhibitors.
4.3.2.2 Electrical shorting caused by corrosion deposit build-up on LPR probes is particularly associated with flush-type
probes, or pin electrode-type probes with a short spacing between electrodes. Additionally, flush-type probes have a flat
surface on which deposits can more easily develop to form a bridge.
4.3.2.2.1 The problem of deposit build-up is also dependent on the type of deposits that can induce pitting
corrosion by setting up concentration cells underneath the deposits, and it is more frequently associated with
systems in which deposits tend to consist predominantly of FeS. If possible, to reduce fouling in these systems, the
probe should not be located in the six o’clock position.
4.3.2.2.2 Experience has shown that pitting corrosion, as well as variations in the oxygen concentration, may be
indicated by noisy readings from electrochemical monitoring devices. Instruments and software written specifically
for evaluation of noise that can be used for in-depth studies are available. A polarization curve or potentiodynamic
scan can be run and evaluated for pitting potential, as indicated by hysteresis of the curve (i.e., the intercept of the
anodic back scan with the cathodic curve can be used to predict pitting tendency). Particular care shall be taken in
the application and interpretation of such methods beyond that required for the standard LPR approach.
4.3.2.3 The time taken for a probe to stabilize after installation varies, but typically, it is less than 48 hours. In most
cases, the probes stabilize in a few hours. Stabilization occurs more quickly if a set procedure is followed for activating
the electrodes (e.g., in a weak acid solution [such as 5% sulfuric acid] for 5 to 10 minutes).
4.3.2.4 Probe results reflect changes in the process or chemical treatments. When the response becomes sluggish or
the readings approach zero or rise rapidly off-scale, probe maintenance shall be performed and new electrodes should
be installed.
4.3.2.5 LPR probes are very susceptible to fouling by deposits such as FeS, sand, waxes, scales, and oil that can affect
the accuracy of the readings.
4.3.2.6 In some cases, LPR probes will need maintenance or replacement after one to two months because of
electrode shorting, deposit build-up, or sluggish or erratic behavior. In other clean systems, probes can function
correctly for much longer periods. Probes should be regularly inspected until a suitable life pattern can be established
for the particular service conditions.
4.3.2.7 Because LPR probes can respond rapidly to changes in the system, single LPR readings taken at infrequent
intervals should not be considered reliable. Spot readings offer little or no benefit over ER probe readings (see
Paragraph 4.3.3.1). Results taken more frequently are more beneficial in establishing the corrosion status of a system.
The LPR reading is not the actual corrosion rate if localized corrosion takes place or if an incorrect Stern-Geary constant
is used. The LPR probe should be calibrated by measuring the Tafel constants to get the correct Stern-Geary constant.
4.3.2.8 Continuous automatic monitoring of LPR probes has particular advantages. Small-amplitude current
voltammetry gives an instantaneous corrosion rate record that can be plotted and variations in corrosion rate can be
seen clearly. Care should be taken to select appropriate voltage settings and scan rates for the most reliable results.
4.3.3 ER Probes
4.3.3.1 ER probes offer an alternative method of monitoring. These probes monitor the increase in electrical resistance
of a metal wire or strip as it corrodes, and the data can be plotted for corrosion trends. ER probes are often adopted as
a crosscheck for LPR probes. ER probes are often used because of the difficulties in maintenance necessary for LPR
probes (ER probes require only minimal maintenance). ER probes are effective in seawater injection systems in which
fouling of electrodes may render the LPR probe ineffective very quickly, making the LPR technique impractical to use in
some systems.
4.3.3.2 The ER technique has one major shortcoming―if the system being monitored is sour, the formation of FeS
and/or other conductive scales can increase the effective cross section of the metal loop and render the measurement
inaccurate. Another potential problem with the use of ER probes is the reading stability if temperature fluctuations are
apparent in the system. Accurate readings can only be obtained if the sensing element is at the same temperature as
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the reference element, which is sometimes located at the opposite end of the probe body. Experience has shown that in
a liquid phase, it takes five minutes for probes to have stabilized sufficiently to allow credible data to be accumulated.
Such temperature effects tend to be of less concern in water injection systems.
4.3.3.3 A number of element shapes for ER probes are available, the most commonly preferred one being the tubular
element. This element provides a better insight into the average metal loss and it is also used in areas of severe
corrosion, in which thicker elements are needed to give a reasonable probe life. Wire element probes are also used,
which, because of the rapid reduction in cross-sectional area, quickly detect the onset or progress of pitting corrosion.
4.3.3.4 Although the amount of data obtained from an ER probe is restricted when compared to data obtained from LPR
probes, the correct element selection offers long probe life with minimum maintenance, thereby allowing cost-effective
monitoring.
4.3.4 Galvanic Probes
4.3.4.1 Galvanic probes are often selected as a support probe technique. They do not allow the measurement of
corrosion directly, but they can indicate the presence of an oxidizing species. Galvanic probes have been shown to be
very responsive to dissolved oxygen in a system and, in this respect, are a valuable tool to detect oxygen entry, although
they do not measure oxygen content. These probes are especially useful when commissioning, optimizing, or
troubleshooting seawater injection systems as well as monitoring high-pressure systems.
4.3.4.2 In galvanic probes, two replaceable pin electrodes, one of which is steel and the other brass, are generally
used, and these are inserted directly into the seawater stream. Other metallic couples can be used for specific galvanic
corrosion studies.
4.3.4.3 Galvanic probes should be used downstream from deaerator tower/residence tower locations to help control
tower operation and oxygen scavenger injection. In these locations, galvanic probes have been used successfully as a
means to detect the presence of residual Cl2 and changes in Cl2 content when the oxygen levels are under strict control.
4.3.4.4 Experience has shown that electrode fouling can result in a sluggish response, from either accumulation of
corrosion product or process fouling. Consequently, galvanic probe electrodes shall be cleaned regularly to obtain good
performance. Process fouling can be minimized by positioning probes downstream from filters.
4.4 Seawater Chemistry Measurements
4.4.1 Water chemistry measurements should be used to complement online corrosion rate monitoring. The reasons for high
corrosion rate excursions may sometimes be associated with inadequate removal of oxygen, poor biological control, plant
malfunctions, oxygen ingress, and excessive addition of chemicals used to control corrosion, scale, or microorganisms. For
example, bisulfite or excess Cl2 increases corrosiveness. Changes in injection water composition caused by switching
sources from a reservoir to a supply well, or disposal of a tank of produced water along with the regular injection water, can
change the water chemistry.
4.4.2 Dissolved Oxygen
4.4.2.1 Oxygen content of the injection water should be routinely monitored. For example, oxygen measurement can
supplement corrosion-monitoring devices located downstream from water injection pumps, where oxygen ingress may
occur as a result of faulty pump seals.
4.4.2.1.1 The concentration of unreacted oxygen scavenger can be determined by means of sulfite residual tests.
However, the results obtained using the standard procedure, based on reaction with iodine, are likely to be affected
by sulfides if they are present.
4.4.2.1.2 The addition of oxygen scavenger is usually monitored by checking the dissolved oxygen concentration of
the seawater at suitable locations downstream from the oxygen scavenger injection point, by corrosion rate
measurements, or by a combination of these.
4.4.2.2 Monitoring dissolved oxygen in the seawater can be carried out by an electrochemical (polarographic)
technique, a chemical method, or by colorimetric ampoules.
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4.4.2.2.1 The polarographic technique is the most sensitive and the only one currently available that allows
concentrations of oxygen as low as 1 ppb to be continuously recorded on a chart. The technique uses a sensing
element that consists of a gold cathode and silver anode immersed in an electrolyte.
4.4.2.2.1.1 The seawater sample is allowed to pass against a thin membrane (usually polytetrafluorethylene
[PTFE]), through which the oxygen passes to react electrochemically in the sensing element, thereby allowing
a direct measurement of dissolved oxygen present. The sensing elements should be calibrated routinely by
properly trained technicians.
4.4.2.2.1.2 The silver anode can be poisoned by sulfite and sulfide ions. However, H2S-insensitive versions
of these instruments are available. If poisoning occurs, the sensing element should be restored to full
sensitivity by following the manufacturer’s electrode-cleaning procedure.
4.4.2.2.1.3 The sensing element should be placed in a flowthrough or sidestream arrangement connected to
a sampling point. The length of tubing connecting the sampling point to the flowthrough sensing element
should be as short as possible. Sample flow rates are slow (approximately 50 mL/min), and residence time of
the water in the sample line should be minimized to prevent inaccurate measurement because of consumption
of oxygen in the sample line through corrosion processes or further reaction with oxygen scavenger added.
Leakage in any joints upstream from the sensing element shall be avoided.
4.4.2.2.2 Chemical techniques have been found to give less consistent results than the polarographic method,
although these techniques are still widely used in industrial water treatment. These techniques, however, are time-
consuming.
4.4.2.2.3 Ampoules based on color chemistry are commonly used for oilfield waterflood monitoring and are much
easier to use than a conventional titration procedure. However, they can suffer interference either from poor water
clarity or by reaction with the oxidizing agents (e.g., Cl2) or reducing agents (e.g., sulfites, bisulfites, and sulfides).
4.4.3 Bacteria and Biocide
4.4.3.1 In many seawater injection systems, no monitoring is carried out to verify that aerobic bacteria are being
controlled; it is assumed that a certain Cl2 residual ensures that aerobic bacteria are under control.
4.4.3.1.1 Oxidizing biocides such as Cl2 can be analyzed by several techniques, some of which are affected by the
presence of other oxidizing or reducing agents. In most cases, the control of Cl2 injection is based on the
assumption that the Cl2 demand of the water is fairly constant, and that the rate of Cl2 injection and its concentration
as injected are also fairly constant. Therefore, online monitoring of Cl2 residual is not normally considered
necessary, and control can be based on spot checks using various comparator methods.
4.4.3.1.2 Online analyzers for Cl2 and other oxidizing biocides are available; these generally use colorimetric
technology.
4.4.3.1.3 Monitoring of residual Cl2 content has often been used to give an indication of the effectiveness of
chlorination. The perceived logic behind such monitoring is that if an excess of Cl2 is detected, the required amount
of Cl2 must have been used in effectively reducing biological activity. This is only indirect evidence, and must be
confirmed by monitoring biological activity also.
4.4.3.2 Monitoring of the seawater injection system for corrosion associated with anaerobic bacteria and for determining
effectiveness of biocide treatment should be considered.
4.4.3.2.1 NACE Standard TM0194
1
provides detailed procedures for field monitoring of bacterial growth in oil and
gas systems.
4.4.3.2.2 Other monitoring techniques that can provide relevant information include corrosion coupons, biofilm
probes, and chemical analysis for dissolved sulfides. All of these methods have been used, but industry
preferences vary.
4.4.3.2.3 A current trend is to place more emphasis on biofilm probes, which are designed to sample sessile
bacteria. These are bacteria that grow on the metal surface under any other deposits and that may be least
exposed to bactericide treatment.
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4.4.3.2.4 Chemical analysis to determine concentrations of the biocide may be desirable. Monitoring of both
continuous and slug or batch treatment should be included to optimize biocide addition.
4.4.4 Seawater pH
4.4.4.1 Seawater pH readings should be taken routinely on an injection system incorporating produced gas stripping.
Ideally, continuous-reading probes contained within a sidestream arrangement should be used. The alternative method
of grab sampling may be used, especially as a crosscheck to a continuous-reading probe.
4.4.4.2 High-pressure pH probes that can be inserted directly into a pressurized system have been developed. There
has been little performance feedback to date on which to base recommendations regarding the use of these probes.
4.5 Solids
4.5.1 Physical tests using membrane filter tests and particle counters, such as suspended solids content and particle size,
counts, and distribution, should be used when corrosion products might have an adverse effect on injection water quality (see
NACE Standard TM0173
2
for guidance).
_________________________________________________________________________
Section 5: Materials Selection for Seawater Injection Systems
5.1 ASM
(3)
Metals Handbook
3
contains useful guidance on corrosion mechanisms and mitigation measures in water injection
systems, including materials selection.
5.2 For secondary oil recovery, seawater may be pumped back down into the well. The raw seawater should be treated at the
intake with Cl2 or hypochlorite and pumped up with lift pumps. The early pumps were made from austenitic cast iron with duplex
SS shafts. Some of the austenitic cast-iron impellers suffered corrosion, but the shafts were not attacked. The impellers as well
as the shaft are now typically made from duplex SS.
4
5.3 The seawater should be filtered and treated before injection to avoid souring the field. It also should be deaerated to prevent
corrosion. Stainless steels are resistant to pitting and crevice corrosion in deaerated seawater, even if hot. After treatment and
deaeration, CS pipe may be used, but SS should be used where velocities are high (e.g., in pumps, valves, and reducers). At the
high pressures involved, duplex SSs are often used for larger components because their higher strength can reduce weight.
Seawater injection pumps have typically been made from UNS
(4)
S41000 (410 SS), UNS S31600 (316 SS), and UNS S31800
(318 SS), which have generally been satisfactory. However, there has been a gradual trend toward using proprietary duplex SSs,
such as UNS S32550 (alloy 255) and UNS S32760 (ASTM
(5)
A 240
5
or A 988
6
), for injection duty to avoid corrosion and to reduce
weight.
7
5.4 If sweet seawater (i.e., not containing H2S) is deaerated to less than 20 ppb oxygen, velocities are low, and SRB are
controlled, CS may be used for injection. If these conditions cannot be met, more corrosion-resistant materials, such as those
used in sour seawater service, should be used.
8
5.5 Injection water may be deaerated seawater, raw untreated seawater, or produced water. The Norsk Sokkels
Konkuranseposisjon (NORSOK)
(6)
evaluation of corrosiveness for deaerated injection seawater is, for conventional deaeration,
based on a maximum operating temperature of 30 °C (86 °F) and the following oxygen equivalent (oxygen equivalent = ppb
oxygen + 0.3 [ppb free Cl2]) levels:
 50 ppb for 90% of operation time; and
 200 ppb for 10% of operation time, noncontinuous.
5.6 If the specified oxygen equivalent is above 50 ppb or the temperature is greater than 30 °C (86 °F) for normal operation,
material selection shall be subject to special evaluation.
(3)
ASM International (ASM), 9639 Kinsman Road, Materials Park, OH 44073-0002.
(4)
Unified Numbering System for Metals and Alloys (UNS). UNS numbers are listed in Metals & Alloys in the Unified Numbering System, 10th
ed. (Warrendale, PA: SAE International and West Conshohocken, PA: ASTM International, 2004).
(5)
ASTM International (ASTM), 100 Barr Harbor Dr., West Conshohocken, PA 19428-2959.
(6)
NORSOK standards are developed by the Norwegian petroleum industry. They are administered and published by Standards Norway,
Strandveien 18, PO Box 242, N-1326 Lysaker, Norway.
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5.7 NORSOK recommendations for tubing and liner materials are shown in Table 1.
9
Table 1: Recommendations for Injection System Materials
Injection water Tubing and liner Completion equipment
(When different from tubing/liner)
Deaerated seawater Low-alloy steel UNS N09925 (alloy 925), UNS N07718
(alloy 718)
22Cr or 25Cr duplex SS
Raw seawater Low-alloy steel with glass-reinforced
plastic (GRP) or other liner
Unlined low-alloy steel for short design
life
Titanium (with design limitations)
Titanium (with design limitations)
Produced and aquifer water Low-alloy steel
Low-alloy steel with GRP or other liner
13Cr (provided oxygen < 10 ppb)
22Cr duplex SS, UNS N07718, UNS
N09925 (provided oxygen < 20 ppb).
13Cr (with limits as for tubing for this
service)
5.8 For CS submarine injection flow lines, the minimum corrosion allowance shall be 3.0 mm (0.12 in). In injection water
systems in which alternating deaerated seawater, produced water, aquifer water, and/or gas could flow through the systems, the
material selection must allow for this. All components that may contact injection water or back-flowing fluids must be resistant to
the well-treating chemicals and well-stimulating chemicals. For CS piping, the maximum flow velocity shall be 6 m/s (20 ft/s).
9
5.9 The most common injection water for onshore oil and gas production is produced water. This often contains high
concentrations of ions and dissolved gases (e.g., chlorides, bicarbonates, sulfates, CO2, and H2S). Many materials have been
used for injection piping handling produced water, with differing degrees of success. Solid GRP piping with threaded connections
has been used successfully in this type of application. UNS S31600 (316 SS), UNS S31803 (alloy 2205), and internally coated
CS have been used for wellhead tie-ins, headers, meter runs, waterway crossings, or other high-traffic areas. CS with an internal
cement lining (dense ASTM C 150
10
Type III pozzolana cement) has an expected life of 20 years, with some repair work likely at
joints. CS with an internal high-density polyethylene (HDPE) lining is expected to last 25 years. CS with shop-applied coating
(e.g., modified baked phenolic) used together with chemical treatment can be expected to last approximately seven years. Bare
CS, even with inhibitor and/or biocide treated water, has a life expectancy of approximately five years (typically 2 to 7 years)
before repairs are needed.
11
_________________________________________________________________________
References
1. NACE Standard TM0194 (latest revision), “Field Monitoring of Bacterial Growth in Oil and Gas Systems” (Houston, TX:
NACE).
2. NACE Standard TM0173 (latest revision), “Methods for Determining Quality of Subsurface Injection Water Using Membrane
Filters” (Houston, TX: NACE).
3. ASM Metals Handbook, “Corrosion: Environments and Industries,” Volume 13C (Materials Park, Ohio: ASM International,
2006), pp. 922-962.
4. G. Payne, “Material Failures in North Sea Water Injection Systems,” CORROSION/93, paper no. 66 (Houston, TX: NACE,
1993), pp. 1-8.
5. ASTM A 240/A 240M (latest revision), “Standard Specification for Chromium and Chromium-Nickel Stainless Steel Plate,
Sheet, and Strip for Pressure Vessels and for General Applications” (West Conshohocken, PA: ASTM).
6. ASTM A 988/A 988M (latest revision), “Standard Specification for Hot Isostatically-Pressed Stainless Steel Flanges, Fittings,
Valves, and Parts for High Temperature Service” (West Conshohocken, PA: ASTM).
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7. G.L. Swales, B. Todd, “Nickel-Containing Alloy Piping for Offshore Oil and Gas Production,” presented at the 28th Annual
Conference of Metallurgists of the Canadian Institute of Mining, Metallurgy, and Petroleum
(7)
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August 20-24, 1989 (Montreal, QC: CIM, 1989).
8. C.C. Patton, “Corrosion Control of Water Injection Systems,” MP 32, 8 (1993): pp. 46-49.
9. NORSOK Standard M-001 (latest revision), “Materials Selection” (Lysaker, Norway: NORSOK).
10. ASTM C 150 (latest revision), “Standard Specification for Portland Cement” (West Conshohocken, PA: ASTM).
11. R.J. Franco, “Materials Selection for Produced Water Injection Piping,” MP 34, 1 (1995): pp. 47-50.
_________________________________________________________________________
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SP0499-2012
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SP0499-2012
NACE International
ISBN 1-57590-083-1
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