600 Corrosion Inhibitors
Author: C.D. (Charles) Buscemi
Abstract
This section discusses the use of corrosion inhibitors in various environments. It
also provides a guide for the use of polysulfide corrosion inhibitors and a guide to
evaluating corrosion inhibitors in the laboratory.
Chevron Corporation
Contents
Page
610
Downstream Inhibitors
600-3
611
Passivators
612
Filmers
613
Anti-corrosives
614
Inhibitor Selection
615
How to Apply Inhibitors
616
Monitoring Techniques
620
Corrosion Inhibitors in Oil and Gas Production
621
Factors Influencing Oilfield Corrosion
622
Characteristics of Corrosion Inhibitors
623
Corrosion Inhibition in Oil and Gas Wells
624
Corrosion Inhibition in Water Injection Systems
625
Internal Corrosion Control Of Pipelines
626
Laboratory Testing of Corrosion Inhibitors
627
Monitoring Results of Inhibitor Use in the Field
628
Chemistry of Corrosion Inhibitors
630
Use of Polysulfide Corrosion Inhibitors
631
Polysulfide Chemistry
633
How to Increase Effectiveness of Polysulfide Corrosion Inhibitors
634
Troubleshooting
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635
Survey Results
640
How to Evaluate a Corrosion Inhibitor for Use in Oil Fields
641
The Electrochemical Corrosion Process
642
Factors That Affect Corrosion
643
Types of Corrosion Inhibitors
644
Treatment Methods
645
Laboratory Test Methods
646
Field Condition and System Analysis
647
Selecting Corrosion Inhibitors
648
Selecting a Laboratory Test Method
650
References
600-51
600-60
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610 Downstream Inhibitors
Inhibitors retard corrosion by forming a barrier between metal and a corrosive
agent. They allow us to use carbon steel in corrosive services without linings, coatings, or other expensive protection. We use them in applications from well drilling
to product storage and transport. This section covers uses downstream of the
producing field gathering system. For applications in oil and gas production, see
Section 620.
We classify inhibitors as passivators and filmers. Passivators are inorganic, watersoluble compounds that promote formation of protective metal oxide or sulfide
films. Filmers are organic inhibitors that coat metal surfaces with a protective film.
They are either water-soluble hydrocarbon-dispersible or hydrocarbon-soluble.
Acid neutralizers and oxygen scavengers are organic and inorganic compounds
often found in corrosion prevention programs and commonly associated with inhibitors. Because they combat corrosion by changing the chemistry of the corrosive
agent, they are more accurately described as anti-corrosives and are dealt with only
briefly here. Where inhibitors and anti-corrosives are part of the same corrosion
prevention scheme, we refer the reader to the appropriate chapter of this manual for
an in-depth discussion of usage.
Section 610 is organized by inhibitor and type of anti-corrosive to give a broad view
of the types of chemicals used for corrosion control. Figure 600-1 shows what
inhibitors are used in plants. Each section explains the basic concepts of inhibition,
the types of inhibitors used, where they are used, and how they are applied. For
greater detail on the application of the inhibitors in specific plants, see Volume 2 of
this manual.
611 Passivators
Passivators include polysulfides, chromates, nitrites, thiocyanates, and oxides of
vanadium, arsenic, and antimony. They work by promoting the formation of oxide
or sulfide diffusion barriers to separate the metal from its corrosive environment.
Common applications of passivators include polysulfides in wet hydrocarbon
streams containing cyanide or ammonium bisulfide, chromates and nitrites in
cooling water systems, and the heavy metal oxides in gas processing plants. Each of
these passivators is discussed in greater detail below.
Ammonium and Sodium Polysulfides (APS & NPS)
APS and NPS are used to control corrosion and hydrogen blistering in fluid catalytic crackers (FCC), sour water strippers and waste water treatment plants,
cokers, hydrotreaters, and amine plants. In cyanide-containing systems, polysulfides react with the cyanide ion to form noncorrosive thiocyanate. This prevents
corrosion by keeping cyanide from reacting with the steel to form soluble iron
cyanide. Because cyanides also promote diffusion of atomic hydrogen into steel,
polysulfides inhibit hydrogen blistering. In systems containing ammonium bisulfide, polysulfides decrease corrosion by promoting formation of a stable protective
sulfide scale.
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Product Storage
Product Transport
Mothballing Plants
Cooling Systems
Steam Generation
H2S Removal MEA/DEA
CO2 Removal MDEA
X
CO2 Removal MEA
X
CO2 Removal Carbonate
Sour H2O Strippers
X
WWT Plants
Hydro-treaters
X
Glycol Units
FCC Units
Coker Units
Type
Catalytic Reformers
Corrosion Inhibitors in Process Plants
Crude Units
Fig. 600-1
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X
X
X
X
X
Passivators
APS/NPS
X
(1)
Vanadium
X
X
1
Arsenic
X
X
1
Antimony
X
X
1
Thiocyanate
X
X
1
Chromate
1
Nitrite
1
X
X
X
X
Filmers
Amines
X
X
X
X
X
X
Oils
X
Precipitation
Phosphate
X
Neutralizers
Amines
X
Na-Phosphate
X
X
X
Caustic (NaOH)
X
Ammonia
X
X
X
Scavengers
Sulfite
X
X
Hydrazine
X
X
(1) Passivators not recommended
In FCC units, polysulfides are used in the fractionator overhead and light ends
recovery systems. In sour water strippers, they are injected ahead of the overhead
condenser. In waste water treatment plants, they are injected ahead of the ammonia
stripper overhead condenser. In hydrotreaters, they are injected ahead of the aircooled heat exchangers in the reactor effluent system to combat ammonium bisulfide corrosion.
In refinery H2S removal amine plants, polysulfide is also injected in the regenerator overhead ahead of the overhead condensers. Here, H 2S and ammonia concentrate to form corrosive levels of ammonium bisulfide. Without polysulfide, cyanide
in the feed (formed in other refinery process units) can interfere with the formation
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of a protective iron sulfide scale and lead to increased corrosion. In producing field
gas plants there is no cyanide, so polysulfide injection is unnecessary.
For more information on polysulfide injection, refer to Section 630 of this manual.
Thiocyanate and the Heavy Metal Oxides
Gas processing plants use thiocyanate or the oxides of vanadium and arsenic to
passivate equipment. Gas plants remove CO2, H2S, or both from natural gas and
process gasses (hydrogen and ammonia). As carrier fluids, gas plants use potassium
carbonate, the amines (MEA, DEA, and MDEA), or proprietary solvents.
CO2-removal units using potassium carbonate solvent (Benfield and Catacarb
plants) experience severe corrosion and require a passivating inhibitor. Not only is
the wet CO2 corrosive, but the carbonate solvent itself is also highly aggressive. The
Company uses metavanadate inhibitors in these plants. These oxidative inhibitors
only promote protective scale formation in their highest oxidation state. Thus,
reducing compounds like H2S in small amounts make inhibitors less effective.
Some processes use periodic air blowing (Catacarb) or chemical additions to oxidize
a reduced inhibitor back to its highest and most effective oxidation state. In large
concentrations, H2S retards corrosion by promoting formation of protective sulfide
scale. The critical concentration level at which H2S becomes beneficial is not accurately known but is believed to be in the 500-to-1000 ppm range. Oxidative inhibitors are corrosive to copper alloys such as Monel and 70/30 Cu-Ni.
CO2-removal units using MEA solvent need inhibitors to protect stainless steel
reboiler tubes and the hotter carbon steel equipment in the plant, such as rich/lean
exchangers. The reboilers represent a highly corrosive service. Although the mechanism is not well understood, amine degradation products are corrosive. MEA-type
CO2 plants use arsenic, thiocyanate, and antimony inhibitors. As with metavanadate, these passivating inhibitors can only promote protective scales in their highest
oxidation state and are adversely affected by small amounts of H2S.
CO2-removal units using MDEA solvent do not use passivators because corrosion is
low, providing oxygen contamination is controlled. MDEA is highly susceptible to
oxygen contamination. It forms degradation products that can be more corrosive
than MEA that is similarly contaminated.
H2S-removal plants that use amine solvents do not require inhibitors because the
amine is not corrosive. When inhibitors are used, it is either as a component of a
proprietary solvent package or because the solvent is loaded past theoretical H2S
absorption capacity and corrosive bisulfide ion (HS) is present.
Chromates and Nitrites
Cooling water systems represent an important use of passivators. Closed systems
use chromate or nitrite passivators, with the more environmentally acceptable nitrite
now coming into wider use. These inhibitors are typically slug fed and used at high
dosages (500–10,000 ppm). Heavy metal passivators like chromate once dominated
inhibitor use in open recirculating systems (those with cooling towers). Such inhibitors are less costly and easier to control than others, but they are being phased out in
favor of more environmentally acceptable passivators like phosphate. For more
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extensive coverage of these subjects, see Sections 2200 and 2400 of the Heat
Exchanger and Cooling Tower Manual.
Another application of these passivators is in plant mothballing to protect against
corrosion of water-packed idle equipment. For more guidance on these techniques,
refer to Section 810, “Mothballing.”
612 Filmers
Filmers are typically organic amine compounds with a polar amine or fatty acid
group at one end. The polar end attaches to the metal surface and the organic molecule forms a protective barrier or film. Hydrocarbons from the process often reinforce this film by attaching to the organic end of the molecule. But compatibility
with the particular service should be checked, because some hydrocarbons can wash
inhibitor films away, and some are sensitive to low-pH aqueous systems. Filmers
have also been found to foul equipment, reduce heat transfer, and impact product
specifications. Filmers are used in relatively small amounts compared to other
inhibitors and corrosion control chemicals. Unlike most barrier systems such as
coatings, they are self-healing. The most common use of filmers in downstream
applications is discussed in the following paragraphs.
Most filmer applications are in process units, product transportation and storage
systems, and steam condensate systems. Refinery crude unit overhead systems
represent the most common use of filmers in process units. Here, filming amines are
used along with neutralizers (ammonia or amines) to control corrosion of equipment by dilute hydrochloric acid. For an in-depth analysis of this corrosion problem
and the methods (including inhibitor use) used to combat it, see Section 3100 of this
manual, “Crude Distillation Units.”
Another use of filmers in process units is as a substitute for polysulfide in FCC
fractionator overhead systems that contain low levels of cyanide. Check with a
materials engineer when taking this approach. Filmers will not prevent hydrogen
blistering, which can be severe if cyanide concentrations are too high.
In refined product systems, the aim of an inhibitor program is to minimize product
contamination from corrosion products as well as metal loss. Dissolved water is the
principal corrosive agent in these systems. Both water-soluble inorganic
anti-corrosives and oil-soluble organic filmers have been used to protect product
systems from corrosion. Both are effective, but filmers offer more protection and are
preferred. Systems protected with organic filmers are clean and rust-free. Metal loss
has been found to drop by 98 to 99% compared to unprotected material and product
cloudiness is reduced. Filmers also tend to reduce the friction factor for pumping
fluids.
Organic filmers are not without their problems. Some products desorb or wash away
these inhibitors. This not only removes protection, but may also contaminate the
product. Inhibitors that work by chemisorption (attaching themselves to surfaces
chemically) are more resistant to this than those that attach themselves by physical
adsorption. Use of chemisorbed inhibitors allows us to run some systems intermittently with uninhibited products and still get adequate corrosion protection. The
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inhibitor film is replenished when inhibitor-carrying product is re-introduced into
the system.
Filmers are also used in steam condensate systems to protect against CO2 corrosion. However, the films can adversely affect heat transfer in boilers, potentially
overheating and failing tubes, when the condensate is used as boiler feedwater. For
more information on steam condensate treatment, see Section 740 of this manual,
“Corrosion in Steam Condensate Systems.”
Organic filmers (oils, greases, and Chevron Rust Preventive) have been applied to
idle equipment as protection against atmospheric corrosion. The use of filmers in
plant mothballing is covered in more detail in Section 810.
613 Anti-corrosives
These materials include ammonia, the inorganic neutralizers [such as sodium
hydroxide (caustic), sodium carbonate (soda ash) and sodium phosphate], neutralizing amines, and oxygen scavengers (hydrazine and sulfite et al.). They work by
neutralizing or removing (scavenging) the corrodent and are often used with inhibitors to form a comprehensive corrosion control program. Note that polysulfide
passivators are also often used to remove cyanides, and therefore can be considered
anti-corrosives too. Because they react stoichiometrically with the corrodent, anticorrosives are usually required in large amounts. Common applications are crude
unit overheads, reformer catalyst regenerations, and boiler and steam condensate
systems.
Anti-corrosives are used in many processing plant applications. The largest uses are
organic neutralizing amines in crude unit overhead systems and amines (MEA,
DEA, and TEA) in glycol extraction units and glycol gas dehydration units. In
the latter case, corrosion can occur if the glycol solvent decomposes into organic
acids. In catalytic reformers, morpholine is a common neutralizing amine used to
control hydrochloric acid corrosion during regeneration of chlorided catalyst.
Steam generation systems use oxygen scavengers and neutralizers in their water
treatment programs. Oxygen scavengers are usually hydrazine or other amine-based
compounds that are added downstream of the deaerator to remove residual oxygen
from the boiler feedwater. Oxygen causes pitting in steam generation systems.
Neutralizers also protect steam condensate systems from wet CO2 corrosion.
Vendors formulate condensate treatments with compounds of differing volatility to
protect all parts of the system, not just that section where the first condensate forms.
Systems with ultra-clean water, such as those using demineralizers, often don't need
condensate treatment because they don't contain the bicarbonate from which CO2
forms. Have your water treatment vendor verify the need for condensate treatment
in your system with corrosion data and steam studies. More information on condensate treatment is available in Section 740.
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614 Inhibitor Selection
The corrosion mechanism, chemical nature of the corrodent, and system metallurgy
are important factors in inhibitor selection. Consider the following points:
•
Is the corrosive organic or aqueous? Is it high or low pH?
•
What's the best carrier medium for the inhibitor? Should it be oil or water
soluble?
•
Must the inhibitor be volatile to protect all parts of the system?
•
Will it foul equipment or be too easily desorbed (washed away) by the process?
•
Are there metals in the system that an inhibitor could damage?
•
Will the inhibitor affect the process or the product?
•
Is the cost of corrosion less than the cost of treating?
•
Do environmental regulations limit use of inhibitors?
These questions illustrate some key qualities of inhibitors. Solubility is very important. Inhibitors must get to where they are needed, yet not foul or be washed away
too easily. Improper selection of inhibitors can make things worse. Some neutralizers and other alkaline compounds can corrode or crack copper alloys if overdosed. Some inhibitors seriously affect processes high in particulates (gas plants) by
promoting foaming. This may, therefore, require anti-foaming agents. Environmental regulations now limit levels of many elements (chromium and zinc, for
example) that are active ingredients in some popular inhibitors. So, environmental
compatibility must be checked.
Before choosing an inhibitor, investigate how similar services are inhibited. Then
look for applicable experience. Make sure you can measure effectiveness of the
inhibitor. Seek help from the experts, looking first within the Company. Before
relying on the vendors, be sure that your application is not one which the Company
knows more about or insists on having a vote on (i.e., finished product additives).
615 How to Apply Inhibitors
The method of inhibitor application is very important, and all aspects need to be
considered carefully. For uses other than the condensing services discussed below,
application methods may require special attention. For help, consult the CRTC
Materials and Equipment Engineering Unit and the CRTC Fuels Group Process
Advisors.
For best results, inhibitors should be injected continuously through a quill or nozzle.
Injection is often accomplished with a positive displacement pump. For very high
flow rate situations (such as the Richmond RLOP where flow rates reach roughly
60 GPM), restriction orifices are the preferred water injection method. Some inhibitors are used neat (undiluted), but most are diluted in mix tanks or blended with slip
streams.
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When applying an inhibitor program, consider the effect of common problems such
as underdosing inhibitor, system leaks and contamination, and treating old, previously uninhibited systems. Underdosing can be worse than using no inhibitor at all.
This is especially true for passivators where insufficient inhibitor produces incomplete barriers that can promote rapid localized corrosion or pitting.
System leaks or contamination can introduce compounds that reduce an inhibitor’s
effectiveness. H2S, for example, reduces chromates and the strong oxidizing inhibitors of gas processing plants, limiting their effectiveness. The surfactant or detergent properties of some inhibitors can cause process contamination or fouling in old
equipment by removing old corrosion scales. Initially, inhibitors should be added
slowly to these plants.
Passivators
For information on the application of passivators, refer to the particular chapters
dealing with the inhibitor:
Polysulfides—Section 630, “Use of Polysulfide Corrosion Inhibitors”
Thiocyanate and heavy metal oxides—Section 3700, “Acid Gas Removal Plants”
Chromates and nitrites—Sections 2200 and 2400 of the Heat Exchanger and
Cooling Tower Manual
Filmers
Continuously feed these inhibitors to maintain films in good repair. The size of the
surface area to be protected can be used as a guideline to help determine the amount
of filmer to inject. In practice, however, the appropriate level of filmer to inject
often requires empirical (trial and error) techniques.
For best results, use in combination with neutralizers (ammonia or neutralizing
amines) if low pH is the cause of corrosion gas in crude unit overhead systems, and
keep oxygen out of the process. Oxygen reduces filmer effectiveness and promotes
fouling. Systems that are multi-phase or high in particulates may require agents to
reduce emulsion and foaming caused by these high surface activity filming
inhibitors.
Filmers can lead to fouling problems and therefore should be applied with caution.
Anti-corrosives
Of the anti-corrosives (neutralizers and oxygen scavengers) neutralizers alone will
be discussed.
The two most important considerations in using neutralizers are pH control and
volatility. In some systems, pH needs to be controlled to 7.5 maximum to prevent
cracking and minimize corrosion of copper alloys. But many neutralizers are so
strongly alkaline that such control is difficult. Continuous pH recorders and monitors are helpful in proper pH control. To protect copper alloys, use intermediate
molecular weight neutralizing amines to increase pH at a controlled rate, or add an
azole copper-alloy corrosion inhibitor to your neutralizer.
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A neutralizer’s volatility determines how well it will distribute itself throughout a
system. It is characterized by a distribution ratio of the amount dissolved in the
vapor divided by the amount in the liquid phase. For large systems with a wide
range of condensation conditions, use mixes of neutralizers with differing distribution ratios to ensure adequate coverage. A detailed discussion of the application of
neutralizers to fractionator overheads can be found in Section 3100 of this manual.
616 Monitoring Techniques
(See Section 500 for more details on these techniques.)
Most inhibitors are sold to the user on faith. Effective monitoring therefore, is very
important. Typical methods measure corrosion rates, pH, hydrogen evolution, inhibitor residuals, or corrosion product contamination of process or water streams.
Vendors also offer proprietary field evaluation units that measure any or all of these;
however, their units are primarily used to evaluate neutralizers.
Corrosion rates are measured with coupons, corrosion probes, or both. Coupons are
lab-prepared metal strips (short length removable pipe spools work, too) that are
weighed before and after exposure to provide long-term average corrosion rates. For
useful data, exposure time should be at least 30 days. Drawbacks of this method are
that corrosion information is not instantaneously or continuously supplied and
coupons do not see heat transfer which can be critical to corrosivity. Coupons, as
well as probes which are discussed next, are able to monitor corrosion in one location only. Corrosion can still occur in a system due to different local conditions at a
point away from where the coupons are placed, despite little corrosion occurring on
the coupon. Proper coupon placement is important to ensure monitoring of worst
case conditions.
Corrosion probes use electrical measurements to determine corrosion rates. The two
types, electrical resistance and linear polarization, produce data much faster than
coupons. Electrical resistance probes measure increases in resistance caused by
decreases in the cross-sectional area of a wire or tube exposed to the process. The
exposed wire should be of the same material you are studying in the system.
Although useful for measuring general corrosion, probes do not accurately measure
localized corrosion (pitting). Linear polarization probes give instantaneous readings
and are useful for optimizing corrosion control programs, including inhibitor injection rates. Some types also detect pitting. However, the linear polarization devices
do not work in mixed phase or non-aqueous systems.
Probes can sometimes give erratic readings in turbulent zones such as in the top of a
column or in a reboiler outlet line. Linear polarization probes are especially prone to
this. The CRTC Materials and Equipment Engineering Unit is available for consultation on corrosion monitoring.
Hydrogen probes are another useful method of monitoring inhibitor effectiveness in
sour water streams. These probes measure hydrogen evolved as a result of corrosion. They can be used in cyanide-containing systems to detect hydrogen blistering
and the effectiveness of the polysulfide injection program. However, Company
experience with this technique has not been outstanding.
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Other monitoring methods include measuring pH and testing process streams for
corrosion products. System water pH is an indication of neutralizer performance and
helps operators protect copper alloys against excessive neutralizer injection.
Testing for corrosion products can give qualitative or quantitative measures of effectiveness. Simple evaluations can sometimes be made by just examining the color of
a process or water stream or measuring the amount of material that collects in a
filter. It is important to allow some time after introducing an inhibitor before using
these methods because an inhibitor’s detergent properties may initially skew results,
making them appear worse than they really are.
Iron content is not necessarily a good indicator of corrosion. Under normal conditions, iron solubility is low and most corrosion product remains in the equipment. It
is only at very low pH conditions, where the corrosion product is completely
soluble, that iron content is a true measure of corrosion.
Try to use at least two different monitoring techniques to verify results.
620 Corrosion Inhibitors in Oil and Gas Production
This section discusses the factors that cause oilfield corrosion, describes inhibitors
used to control corrosion, and discusses their application to oil and gas production
as well as water injection systems. This is background information for engineers and
technologists responsible for working with chemical vendors to select and maintain
cost-effective chemical treatment programs. A brief discussion of the chemistry of
inhibitors is also included. Information for this section relies heavily on P. J. Stone’s
chapter in Volume 13 of the ASM Metals Handbook, 9th edition (Reference [6]).
The Metals Handbook contains a more detailed treatment of this subject, particularly the chemistry of inhibitors, and references for further reading.
621 Factors Influencing Oilfield Corrosion
Corrosion in oilfield operations is normally caused by one or more of the following
species in the produced or injected water:
•
•
•
•
Carbon dioxide (CO2) and other acids
Hydrogen sulfide (H2S)
Oxygen (O2)
Bacteria
Two designations commonly used in the oil patch are “sweet” corrosion and “sour”
corrosion. Sweet corrosion is caused by CO2, as well as formic acid, acetic acid, and
other short-chain acids, in the absence of H2S. When measurable H2S is present, the
corrosion that occurs is called sour corrosion.
Temperature Effects
In general, greater well depth corresponds to higher bottom hole temperature—as
high as 400°F in deep reservoirs. Elevated temperatures accelerate corrosion reactions much as they do other chemical reactions. Furthermore, the higher the
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temperature, the harder it is to prevent corrosion with corrosion inhibitors, which
can break down and lose effectiveness at elevated temperatures.
Water Content
For corrosion to occur water must be present. The corrosivity of the water is determined by the amount of CO2, H2S, other acids, O2, etc., dissolved in the water
(typically a high-chloride brine), and by the temperature.
Up to a certain point at least, corrosivity increases with the percentage of water in
the produced liquid (the water cut). With some exceptions, oil wells with water cuts
of less than 30% to 40% are not very corrosive, because the water is well emulsified and does not wet the surface of the steel. Above 30% to 40% water cut, the
water separates out sufficiently to wet the metal surface and allow corrosion to take
place. The point at which water begins to wet the steel surface depends on the characteristics of the oil and the water. The 30% to 40% water cut is only a rough guideline and can vary markedly from field to field.
Gas wells have no similar water cut rule of thumb. They have only a small amount
of liquid hydrocarbon to prevent water from wetting the metal surface; therefore,
corrosion can occur in gas wells at much lower water cuts than in a typical oil well.
Well Pressure
Increased well pressure raises the water solubility of acid gases (i.e., CO2, H2S),
increasing the corrosivity of the water. Bottom hole pressures exceeding 20,000 psi
are occasionally encountered.
Carbon dioxide partial pressure is often related to corrosivity as follows:
•
•
•
A partial pressure of CO2 below 7 psi is generally noncorrosive.
A partial pressure of CO2 between 7 psi and 30 psi may indicate corrosion.
A partial pressure of CO2 above 30 psi usually indicates severe corrosion.
This guideline originally was applied to gas-condensate wells. Although it is still
widely accepted, there are many exceptions.
No similar rules of thumb relate H2S partial pressure to corrosivity. CO2 generally
has a greater impact on corrosivity than H2S; however, since they are usually found
together, it is difficult to separate their effects.
Oxygen Content
Problems resulting from oxygen are more prevalent in water injection systems than
in producing wells. However, it is important to be cautious about introduction of
oxygen into producing wells, for instance, by injection of a nondeaerated chemical.
In water injection systems, oxygen may be present in the supply water when the
water source is surface or shallow ground water. Sea water is commonly used in
near-shore or offshore fields and usually contains approximately 8 ppm dissolved
oxygen. Oxygen can also get into closed water handling systems through
non-gas-blanketed holding tanks, open vents, or thief hatches of water holding
tanks, as well as around the shaft on the suction side of centrifugal transfer pumps.
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Crude oil or diesel oil blankets on the water surface in tanks do not stop oxygen
from contaminating the water.
Bacteria
Although it occasionally occurs in production systems, bacteria corrosion, which is
sometimes referred to as microbiologically-induced corrosion (MIC), is more
commonly a problem in =water injection systems. Sulfate-reducing bacteria (SRB)
reduce sulfate ions (SO4 ) to H2S, often converting a noncorrosive source water
into an aggressively corrosive water. Changes in the biological environment, such as
in temperature, velocity, pressure, shielding debris (in the bottom of tanks), deposits
(organic and inorganic), and nutrients, cause bacteria to grow. Changes in temperature can increase SRB growth from zero to high levels. The practice that appears to
cause the greatest bacterial growth is transporting the water to a surface holding
tank having many static areas and letting the water warm up or cool to 100 ± 10°F.
SRB and other bacteria also produce tubercles or biomass that can cause plugging
and impede or prevent the use of biocides to rid the system of bacteria. In many
cases SRB have produced enough H2S to turn a sweet surface system sour, and are
suspected to have caused reservoirs to change from sweet to sour. The injection of
sea water into offshore fields has probably been the worst offender in introducing
SRB into a production system.
Erosion and Abrasion
Many wells in geologically young formations produce fine sand along with the
fluids. This fine sand may remove inhibitor films, protective corrosion product
layers, or metal, depending on the velocity of the fluids. Also, this fine sand may be
a primary cause of equipment failure in artificially lifted wells. Sand control, a
process of permanently preventing movement of fine sand particles from the formation, is often necessary for good corrosion inhibition.
Cyclic Loading, Stress, and Wear
Corrosion inhibitors have been specially formulated to help reduce corrosion
fatigue caused by cyclic loading, which is typical of sucker rod operation. However,
corrosion inhibitors are generally not relied upon to prevent stress corrosion
cracking or sulfide stress cracking. (See Sections 420 and 452.) Because most oil
wells are not perfectly vertical holes, wear of tubing by rods becomes a problem in
rod-pumped wells that are highly deviated or crooked. Rod guides are sometimes
effective in controlling wear.
622 Characteristics of Corrosion Inhibitors
Organic corrosion inhibitors are generally film-forming amines and their salts. Inorganic inhibitors are not effective. The three classifications of inhibitors are cathodic,
anodic, and cathodic-anodic. They generally inhibit corrosion by adsorbing at the
metal/solution interface. This points out the importance of having clean metal
surfaces. Inhibitors often will not get through old scale deposits on the metal
surface.
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Pour Point
Because inhibitors are usually stored and used outdoors, they must remain liquid at
low temperatures. A pour point of -20°F is usually required. Some locations may
have an even lower pour point requirement (-40° to -50°F). The required pour point
often dictates the solvent system of a particular inhibitor.
Solubility
The solubility of the inhibitors is dictated by the intended use. By their nature,
however, inhibitors cannot be truly soluble in either hydrocarbons or water; their
degree of dispersibility is more descriptive of their behavior.
Emulsion Tendencies
Inhibitor treatments have often resulted in emulsions of the hydrocarbons and water
that are extremely difficult to break. In some cases, the emulsions resulting from
inhibitor treatments are so viscous that the surface separation equipment is literally
plugged up by the emulsion. While emulsion-breaker chemicals can be added to
formulations in small amounts, it is best that each product be tested in the
crude/water mix in which it is to be used, to assure it does not cause an emulsion to
form.
623 Corrosion Inhibition in Oil and Gas Wells
Oil wells, which produce liquid hydrocarbons and water, can be divided into two
types: flowing wells, which have a natural flow of hydrocarbons and water to the
surface, and artificially lifted wells, which require some form of pump. The latter
type includes:
•
Rod-pumped wells, which use a positive displacement downhole pump
connected to the surface by sucker rods.
•
Gas-lifted wells, in which gas is injected at some point downhole to lighten the
fluid and cause flow.
•
Submersible-pumped wells, which use electrical multistage centrifugal pumps
placed near the bottom of the well.
•
Hydraulically-pumped wells, which use positive displacement pumps driven
hydraulically by oil or water from a surface motor and pump.
Gas Wells. Most gas wells flow naturally. These include dry gas wells, which
produce significant quantities of liquid hydrocarbons, liquid petroleum gas (LPG),
and methane at high pressures from high-temperature reservoirs. Along with the
gas, varying amounts of condensed reservoir water (low content of Cl - and other
dissolved species) and free reservoir water (high content of Cl- and other dissolved
species) are produced.
The characteristics of oil and gas wells vary widely from field to field. Consequently, there are a large number of organic corrosion inhibitors available with
varying characteristics. Some of the factors that need to be considered in choosing
the most cost-effective inhibitor include water volume, bottom hole temperature and
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pressure, well depth, completion design, and the inhibitor’s pour point, solubility,
and emulsion tendency.
Batch Treatment—Pumping Wells. Corrosion problems in rod-pumped wells are
directly related to the production volume and water content of the wells. Severe
corrosion is evidenced by excessive rod, pump, and tubing failures. Pitting corrosion, which is accelerated by the presence of CO2, or CO2 and H2S, reduces rod life
by leading to corrosion fatigue failures.
The most common treatment for rod-pumped wells is batch treatment with a pump
truck, which flushes the inhibitor down the annulus with produced fluids or water,
and follows with further flushing with the same fluids. The well continues pumping
during this operation.
The following provisions will contribute to the success of the batch treatment:
•
Circulation of high-volume wells is often necessary to achieve adequate inhibitor coverage.
•
In high gas-oil ratio (GOR) wells, it may be necessary to isolate the annulus for
approximately 2 hours after treatment to allow the inhibitor slug to fall.
•
Calculation of inhibitor volume based on the frequency of treatment and fluid
production is an accepted procedure. This calculated inhibitor concentration is
generally maintained at 25 to 35 ppm of the total fluid produced.
•
The correct minimum overflush must be determined.
Batch Treatment—Flowing Wells. Batch treatment of flowing gas or oil wells may
be effective at low fluid production volumes. Treatment is accomplished by
pumping a 10% solution of inhibitor in hydrocarbons or water into the well, then
shutting in the well long enough for the inhibitor solution to fall to the bottom of the
well. Because the liquid fluid level is unknown, the depth to which the inhibitor
solution will fall is unknown; consequently, the results of the application are difficult to predict.
A more positive approach to batch treating is full tubing displacement. This is
accomplished by pumping a solution into the well and displacing the solution to the
bottom of the well with a calculated volume of water or hydrocarbon. However,
there is some risk of stopping (killing) the well production by doing this. Another
approach is to displace the inhibitor solution with an inert gas, such as nitrogen.
Nitrogen is less likely than water or hydrocarbon to stop the flow of the well.
Batch Treatment—Frequency. How frequently an oil or gas field performs batch
treatment depends on local guidelines. These guidelines are volume of inhibitor per
treatment, volume of flush, and treatment frequency. Guidelines are generally based
on barrels of fluid produced per day (BFPD). Automatic computer-controlled chemical injectors are available for batch treating.
Squeeze Treatment. Squeeze treating is the injection of inhibitor directly into the
producing formation. It is applicable to all oil and gas wells with sufficiently porous
and permeable producing zones. It results in essentially continuous treatment if the
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inhibitor will adsorb rapidly onto sand and desorb slowly into produced fluids from
the producing sand.
An example of the squeeze treatment technique is to mix one or two 55-gallon
drums of inhibitor with 10 to 20 barrels of diesel oil or kerosene. The inhibitor solution is displaced to the bottom of the well, and an overflush of 200 to 500 barrels or
more of oil or brine is then used to push the inhibitor into the formation. This technique often leads to continuous feedback lasting anywhere from 3 months to 2
years.
Squeeze treatment has the following advantages: it works on wells with high fluid
levels, the frequency of treatment is drastically lower than with batch or continuous
treating, it is more reliable than some batch methods, and it treats the entire length
of the tubing. However, squeeze treating is not recommended for wells with
mechanical problems, such as suspected tubing or casing leaks, because the inhibitor may exit through the leak rather than reaching the intended area in the
formation.
The major concern with squeeze treating is the possibility of plugging of the formation. Various sandstone formations differ in adsorption and plugging characteristics,
and the limestone behaves quite differently from sandstone.
In a unique variation of the formation squeeze, the corrosion inhibitor/hydrocarbon
diluent is atomized with an inert gas, such as nitrogen, and displaced down the
tubing and into the formation with the same inert gas. Longer squeeze life and better
inhibition have been claimed. The method is advantageous in wells with low bottom
hole pressures because the low density of the nitrogen makes it easier to resume
production in such wells.
Continuous Treatment. This method is accomplished by a chemical-proportioning
pump that operates constantly. In artificially lifted wells, except gas-lifted wells, a
small quantity of inhibitor is continuously injected into the annulus with a portion of
the produced fluid. This technique is known as slip-stream flushing. After an initial
treatment of several gallons of inhibitor, inhibitor is continuously injected in order
to maintain an inhibitor concentration of typically 25 ppm to 100 ppm in the
produced fluid. The mechanical setup for continuous treatment in rod-pumped and
submersible-pumped wells without packers is simple, because the annulus is open to
the tubing.
In gas-lifted wells, the dry gas may cause the solvent to be stripped from the inhibitor, resulting in gunking of the inhibitor and plugging of the system. A system for
inhibiting gas-lifted wells is described in Reference [7].
Continuous treatment requires a person to maintain the equipment and adjust equipment settings. In addition, local environmental restrictions can make it difficult and
costly to store chemicals at the wellhead.
Continuous treatment of flowing oil and gas wells requires certain types of well
completions, as follows:
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•
Fig. 600-2
600 Corrosion Inhibitors
Dual completion, either concentric or parallel Figure 600-2). In this completion technique, two separate strings of tubing are run in the same hole and may
or may not be the same size.
Corrosion Inhibitor Injection with Dual Completion Designs
Concentric and parallel string dual completion designs.The "kill"
string can be used for continuous corrosion inhibitor injection.
•
Capillary or small-bore treating tube (Figure 600-3) requires a string of
continuous, small-diameter tubing strapped to the outside of the production
tubing. This type of completion provides excellent inhibitor injection control
with superior results. Disadvantages are the cost and the mechanical
difficulties.
Before initiating this method of treating, lab tests should be conducted to ensure
the chemical is totally soluble and won't plug the injection line. Filters are used
on the surface to protect the injection line against plugging. The injection line
should have at least a 0.25-inch O.D.
Chevron Corporation
•
Sidepocket mandrel chemical injection valve (Figure 600-4). The annulus is
filled with liquid inhibitor solution, and continuous injection on the surface is
used to apply pressure to the annulus so that the injection valve opens. Mechanical difficulties with the valve and the stability of the inhibitor solution are
disadvantages. There can be significant costs associated with filling the annulus
with inhibitor initially and with each subsequent injection valve replacement.
•
A low-cost continuous method for marginal gas wells involves perforating the
tubing above the packer, filling the annulus with an inhibitor solution and then
continuously pumping inhibitor solution into the annulus at the surface. This is
similar to the chemical injection valve completion in Figure 600-4, except that
perforations exist above the packer, rather than a valve.
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Fig. 600-3
Corrosion Prevention and Metallurgy Manual
Downhole Chemical Treating Tube
Fig. 600-4
Sidepocket Mandrel Chemical Injection
Valve
Capillary treating tube used for continuous
injection of corrosion inhibitor.
•
Packerless completion (Figure 600-5). No downhole valves are involved, but
inhibitor solution stability must be considered. In a packerless completion with
high bottom-hole temperatures, continuous treatment is generally selected when
production rates are such that the expected treatment life of batch treatments is
economically prohibitive.
Fig. 600-5
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Treatment with High-density Corrosion Inhibitors. Most liquid inhibitors have a
density of 7.6 to 8.2 lb/gal. High-density liquid corrosion inhibitors are formulations that have been coupled with weighting agents. Their high density (10 lb/gal)
and their immiscibility with hydrocarbons and water enable them to fall through
static columns of hydrocarbons. Frequent small-volume batch treatments are typically used. Some applications for these unique inhibitors are high fluid level
pumping wells as well as gas wells.
The weighting agent in high-density inhibitors is often zinc chloride (ZnCl2), which
may precipitate as zinc sulfide (ZnS) or zinc oxide (ZnO) when applied to some
wells. The precipitation problem may become apparent in the form of plugging of
downhole equipment and/or failure of the inhibitor to reach a desired point. Other
forms of weighted inhibitors, such as solid sticks, are also available. More detailed
information on liquid weighted inhibitors, including fall rates, is available in References [8], [9], and [10].
624 Corrosion Inhibition in Water Injection Systems
Corrosion in water injection systems is inhibited by protecting surface gathering
lines and tanks for recycling produced water, water-treating equipment, and the
surface lines and downhole tubing of injection wells. The primary causes of corrosion in waterfloods are oxygen contamination and the acidity of the water.
Mechanical Oxygen Stripping
The following mechanical methods are primarily used to remove oxygen from water
with a high oxygen content, such as sea water:
•
Countercurrent gas-stripping towers. The simplest and most economical
method if large amounts of natural gas are available at low cost.
•
Vacuum towers. Used where insufficient gas is available.
•
Obtaining water from deep sources. For example, lifting sea water from a
depth of 100 feet by gas-lift or pumping. This method is only suitable where it
is known that sea water from a given depth has sufficiently low oxygen content.
Usually, mechanical methods do not reduce oxygen sufficiently, and chemical
oxygen scavengers must be injected downstream of the mechanical oxygen stripping equipment to remove the last traces of oxygen.
Chemical Oxygen Scavengers
Oxygen scavenging is the removal of oxygen by chemical reaction. Oxygen scavengers can reduce the oxygen content of the water to less than 10 ppb, a level that is
considered insignificant from a corrosivity standpoint. Oxygen scavengers
generally require a catalyst to achieve oxygen removal to the 10-ppb level. The
most commonly used oxygen scavengers are:
=
•
Chevron Corporation
The sulfite ion (SO3 ). This may come from sulfur dioxide (SO2) gas generated on the site, from solutions of sodium sulfite (Na2SO3) or sodium bisulfite
(NaHSO3), or from a solution of ammonium bisulfite (NH4HSO3). Ammo-
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nium bisulfite is the most commonly used because of its stability in storage and
its ability to exist as a highly concentrated liquid solution. Solutions containing
60 to 70% NH4HSO3 are commercially available.
=
The reaction of oxygen with SO3 oxygen scavengers requires an initiating
step: very small additions (ppm) of transition metal
ions, such as cobalt or
=
nickel, are needed to catalyze the reaction. SO3 oxygen scavengers are typically purchased in this catalyzed condition so that the oxygen will be removed
within an acceptable period of time (usually a few minutes). Noncatalyzed
sulfite scavengers take a much longer time to react, subjecting all the metal
parts downstream of the injection point to corrosion until the reaction has
lowered the oxygen content sufficiently.
Interferences with the reaction may cause the rate of the reaction or its degree
of completion to be unsatisfactory. The cause of such interference should be
investigated. The most common problem is deactivation of the catalyst. All
transition metals are not equally effective, and pH affects the various possible
metal ions differently. In waters containing sulfide, the catalyst can be precipitated as an insoluble solid or complexed with a chelating agent such as ethylenediamine tetraacetic acid (EDTA). In both cases, the catalyst is rendered
inactive.
Though the least convenient to use because it is a powder that must be mixed,
cobalt-catalyzed sodium sulfite is the most efficient oxygen scavenger of these
three sulfite types and is effective in both acid and alkaline pH waters. Catalyzed ammonium bisulfite is most effective at pH 9.5 or greater.
•
Hydrazine. Practical only at elevated temperatures, hydrazine is typically used
in boilers and steam generators.
•
Sodium hydrosulfite (NaHSO2). Recommended for scavenging oxygen in
polymer flood enhanced recovery
= applications because it causes much less
polymer degradation than SO3 . However, NaHSO2 is very unstable in solution and requires storage as a solid and daily solution preparation.
Oxygen corrosion control requires particular attention in water used for cyclic steam
injection and steam floods. Corrosion and other water-treating problems in steam
injection systems are discussed in Reference [11].
Organic Corrosion Inhibitors
The same acids that cause corrosion problems in the production system
(e.g., carbonic acid from CO2) can carry through the injection water.
Most corrosion inhibitors designed for acidic corrosion are film-forming amine
salts. Water-soluble or dispersible modifications of these materials can be used in
waterflood applications. The system must be free of oxygen contamination for these
materials to be effective. Therefore, the above materials are sometimes used with
oxygen scavengers.
An inhibitor's film-forming ability and stability are determined by a combination of
factors. The conflict between solubility and film stability is a basic obstacle in
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formulating inhibitors for waterfloods; molecular changes that promote water solubility tend to decrease filming ability. Compatibility or solubility of injected water is
important to prevent plugging of low-permeability reservoirs.
The same inhibitors used for producing wells have been extended or modified for
use in waterfloods. The required concentration of inhibitor, however, is drastically
increased because of the absence of the hydrocarbon phase. For example, addition
of a hydrocarbon phase to sour brine can lower the inhibitor required for the same
level of inhibition from 25 ppm to 5 ppm. Field experience shows that the presence
of hydrocarbons aids film formation and persistence. Unfortunately, this benefit is
not available in a water injection system.
In some situations, as when the volume of water to be treated is small, oxygen
removal may not be practical. Organic inhibitors are available that will help control
corrosion in these situations. Consult with chemical suppliers for details.
H2S Effects
H2S causes many more handling and corrosion problems in injection water than
CO2 or short-chain acids do. The primary reason for this is that iron sulfide (FeS),
the product of H2S corrosion, is very insoluble. FeS deposits itself on downstream
equipment, plugs injection wells, and causes difficulties in oil-water separation. No
known scale inhibitor prevents the precipitation of FeS. However, proper corrosion
inhibition can prevent FeS from forming in the first place.
Alternative Piping Materials
Use of oxygen removal and organic corrosion inhibitors can be avoided if, instead
of carbon steel, alternative piping materials are used, such as plastic-lined or
cement-lined steel, corrosion resistant alloys, fiberglass-reinforced plastic, or other
nonmetals.
Control of Bacteria Corrosion
Solutions to bacteria corrosion problems include avoiding static or dead areas in the
initial design stage, keeping the system clean, and using a bactericide.
Cleaning of the surface system requires removal of settled solids in tankage and
separation vessels. Tanks left uncleaned may contain 4 to 6 feet of solids and sludge
after 5 to 10 years of operation. Cleaning frequency should be determined by the
rate of solids deposit. In some cases this may be quarterly and in others it may be
annually.
Transmission and gathering lines can be kept clean by regular pigging, the most
effective method of controlling bacteria corrosion. Where economics permit, pig
traps and launchers should be designed into gathering systems to allow removal of
liquids in low places along the line. Pigs can also be used to remove bacteria colonies which have become established along the pipe wall. Care must be taken not to
damage internal plastic coated lines when pigging.
Bactericides are chemicals that kill or control microorganisms. Many of these chemicals are surface-active cationic materials that can have compatibility problems with
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anionic chemicals such as scale inhibitors; therefore, care must be exercised when
injecting multiple chemicals.
It is easier to kill bacteria initially than to try to clean up a contaminated system.
Care must be exercised to ensure safe handling of biocides, since they are generally
toxic and some are known carcinogens. Proper procedures must also be followed in
handling and disposal of water containing biocide.
625 Internal Corrosion Control Of Pipelines
The factors that affect corrosion in oil, gas, and product pipelines are the same as
those that affect oil and gas wells, i.e., water content, CO2, H2S, O2, pressure, and
temperature. All are important, but the effects of flow patterns and fluid velocity are
especially significant in pipelines. These not only influence the severity of corrosion, but also dictate its location.
Corrosion in product pipelines arises because petroleum products carry water in
solution. The amount of water dissolved in a product is dependent on temperature.
For example, as shown in Figure 600-6, gasoline saturated with water at 110°F
contains about 4 gal/1000 bbl dissolved water.
Fig. 600-6
Solubility of Water in Gasoline
°F
Solubility
Gal/1000 Bbl
40
1.8
50
2.1
60
2.4
70
2.7
80
3.0
90
3.3
100
3.6
110
4.0
Gasoline and other liquid products can be introduced into a pipeline that is as warm
as 110°F. Others can be introduced at 140°F. Normal pipeline temperatures range
from 40°F to 75°F, the reduced solubility of water at the lower temperatures can
result in precipitation of about 80% of the dissolved water. When a product is introduced into the pipeline at 110°F and then cooled to 40°F, the solubility drops from
4 gal/1000 RRL dissolved water to 1.8 gal/1000 bbl.
Oxygen comes from the dissolved air in the product and its solubility varies by
product. For example, the oxygen solubilty in crude oil can be 30 times higher than
in water.
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Dry natural gas pipelines are not immune from corrosion. Traces of the glycol used
for dehydration are introduced to the line by carry over in the form of vapor or
spray. Even the best operated glycol dehydration systems will introduce about
0.1 gallon of wet glycol per mmcf gas into the line in normal use.
As shown in Figure 600-7, the glycol will be in equilibrium with the water in the
gas depending on the temperature and pressure of the system. Decreasing temperature increases the water content of the glycol and, therefore, its corrosivity. Chlorides, oxygen, and sulfur can significantly accelerate this corrosion.
Fig. 600-7
The Effect of NaCl and Elemental Sulfur on the Corrosion Behavior of Steel
Specimens Semi-submerged in Glycol
Determining the Possibility of Corrosion
Flow patterns and fluid velocities significantly affect corrosion in pipelines. Furthermore, the flow of two and three phase fluids is very complex. For the purposes of
simplification, the following discussion is based on these assumptions:
Chevron Corporation
•
The system is in continuous operation.
•
Water carried by the line is corrosive.
•
Neither paraffin nor water deposited scale is present.
•
A flow change from laminar (stratified) to turbulent (mixed) occurs at a
velocity between 3½ to 7 ft/sec in a phase system.
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•
At water cuts >25%, water is the external phase.
•
Wet gas can contain 5 bbl or less liquid per mmcf.
•
Flow in a wet gas system becomes the spray or mist pattern at 25 ft/sec or
more.
Figure 600-8 shows a method to calculate the approximate velocity in the pipeline
carrying both liquid and gas. See API RP 14E, Recommended Practice for Design
and Installation of Offshore Production Platform Piping Systems, for a detailed
description.
Fig. 600-8
Approximate Velocities in Pipeline Operations
MSCFD × °R
Cubic Feet of Gas/Second = ------------------------------P × 3060
BWPD + BOPD
Cubic Feet of Liquid/Second = ----------------------------------15400
Cubic Feet o f Gas ⁄ Sec + Cubic Feet of Liquid ⁄ Sec
Velocity (Ft/Sec) = Velocity (Ft ⁄ Sec ) = ----------------------------------------------------------------------------------------------------------------------------Cross Sectional Area of Pipe in Square Feet
where:
MSCFD = Gas/Day in 1000’s of Cubic Feet
°R = °F + 460°
P = Pipeline Operating Pressure in psi
BWPD = Barrels of Water per Day
BOPD = Barrels of Oil per Day
Pipeline Specification Liquids.
Figure 600-9 shows flow patterns in a pipeline carrying pipeline specification oil.
Flow patterns of other liquid product lines are similar. Basic Sediment and Water
(BS&W) content ranges from trace to 2%.
Flow patterns assume continuous operation, and water is “free” rather than emulsified. Periods of intermittent operation allow water to fall out, and it may not be
“picked” up again when operation resumes.
Flow type 1 is for a velocity from 0 to 3½ ft/sec. Water falls to the bottom of the
pipe, accumulates in semi-stagnant pools at low spots, and flows from the pools as
slugs. Corrosion is probable especially at the low spots.
Flow type 2 is for velocities between 3½ and 7 ft/sec. The fluid flow is in transition
so the water drop-out will be a function of the fluid's specific gravity, water cut,
viscosity, and velocity.
Unless water hold-up can be proven, assume the same conditions as flow pattern 1.
Corrosion is probable especially in the low spots.
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Fig. 600-9
600 Corrosion Inhibitors
Flow Patterns for Lines Carrying Pipeline Specification Oil
Flow type 3 is for velocities greater than 7 ft/sec. Flow is turbulent with all the
water entrained in the fluid. Corrosion is not likely unless flow is intermittent.
Figure 600-10 shows the flow patterns for lines carrying oil with BS&W content
from 3% and up.
Natural Gas Pipelines
Figure 600-11 shows flow patterns for natural gas pipelines with up to 5 bbl liquid
per mmcf gas. Even dehydrated gas pipelines can contain corrosive liquids such as
water or water/glycol mixtures. The presence of acid gases such as CO2 and H2S
significantly accelerate corrosion, as do any oxygen and/or sulfur, which can be
extremely serious.
Flow type 1 is for velocities up to 7½ ft/sec. All liquid drops from the gas stream,
flows to low spots, and accumulates in semi-stagnant pools. As a pool increases in
size, the cross sectional area decreases, increasing the velocity. The pool becomes
turbulent, moves up-dip, and eventually a slug of liquid is stripped from the pool
and moves downstream. The remainder of the pool moves back to the bottom and
the cycle repeats.
Severe corrosion is probable in the bottom and downstream of the low spots.
Moderate corrosion is probable in a narrow flow path along the bottom of the line.
Flow type 2 is for a velocity of 7½ to 15 ft/sec. Most of the liquid drops out of the
gas, flows along the bottom, and accumulates in turbulent pools on the up hill side
of the low spots in the line. Slugs of liquid are stripped from the pools and move
downstream. The smaller drops are carried in a minor spray flow and wet the pipe
wall.
Severe corrosion is probable at the uphill sides of the low spots. Moderate corrosion is probable in a narrow liquid flow path along the line bottom. Mild corrosion
is probable on the remainder of the pipe wall.
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Fig. 600-10 Flow Patterns for Field Flowlines, Gathering Lines, etc.
Corrosion Prevention and Metallurgy Manual
Fig. 600-11 Flow Patterns in Wet - Gas Pipelines with
Up to 5 Bbls Liquids Per MMSCF
Flow type 3 is for velocities between 15 and 25 ft/sec. Water drops out of the gas
stream and forms a continuous flowing stream along the bottom of the line. Some
accumulation occurs on the up hill sides of the low spots. Small slugs of water are
stripped off and carried downstream. Water droplets are also carried in a continuous
spray and deposited alternately onto and stripped from the pipe wall.
Severe corrosion is probable in the continuous flowing stream zone and on the
uphill sides of the low spots. Moderate corrosion is probable over the remainder of
the pipe wall.
Flow type 4 is for velocities greater than 25 ft/sec. All water remains in the spray
and is continuously deposited onto and stripped from the pipe wall.
Corrosion is probable over the entire pipe wall with the severity dependent on the
corrosivity of the water. At very high velocities, erosion corrosion is possible.
Treatment of Pipelines
Cleaning the pipeline is the first step in an effective corrosion program. The corrosion under deposits can be severe. Furthermore, most film-forming amine-type
inhibitors are not selective in what they film. Corrosion deposits, scale, and sand
will be coated and affect the performance of the program. In old systems where the
velocity is low and severe corrosion has occurred on the bottom of the line, cleaning
is mandatory.
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Basically, there are three types of inhibitor treatment programs for pipelines:
•
Periodically coat the inside of the pipeline with a tenacious film-forming
inhibitor. Apply a diluted inhibitor solution between two pigs or by a batch or
slug type treatment. The preferred velocity is 2 to 3 ft/sec, with a maximum of
5 ft/sec. As shown in Figure 600-12, inhibitor volumes are based on a “desired
film thickness” and are usually from 1 to 3 gallons/diameter inch/mile.
Fig. 600-12 Inhibitor Volume Requirements for Batching Filming Treatment
For 2.0 mil film
•
Gallons of inhibitor per mile of pipe = 6.92 x pipe diameter in inches
For 1.0 mil film
•
Gallons of inhibitor per mile of pipe = 3.46 x pipe diameter in inches
For 0.5 mil film
•
•
Gallons of inhibitor per mile of pipe = 1.73 x pipe diameter in inches
Continuously inject a water or oil soluble inhibitor into the line. The amount
depends on the severity of the corrosion, monitoring, and on product contamination limitations, for example jet fuel and the WISM test.
Historically, most pipeline failures caused by internal corrosion occur in the
bottoms of the lines, especially in the low spots. The most effective treatment is
an inhibitor that moves through the lines and partition into the water wherever
it accumulates and wets the pipe.
The corrosion inhibitor must be preferentially soluble or dispersible in the
water even though a large volume of hydrocarbon is present.
The test results in Figure 600-13 show how 5 inhibitors perform in constant
concentration wheel tests. The partitioning test was done after fluids were
mixed with a hydrocarbon and the water phase are allowed to separate. The
data in this table show the percent protection of tests with corrosion inhibitors
compared to corrosion tests with no inhibitor added.
Fig. 600-13 Comparison of Corrosion Inhibitors by Constant Concentration Test and
Partitioning Test
Percent Protection
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Inhibitors
Constant Concentration Test
Partitioning Test
A
94.7
24.5
B
93.7
80.9
C
98.7
36.0
D
94.5
91.9
E
96.2
83.1
E
96.2
83.1
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•
Corrosion Prevention and Metallurgy Manual
Periodically batch a water soluble-dispersible inhibitor into the line. The
amounts depend on the severity of corrosion, product contamination limitations, and experience with the inhibitor.
Monitoring Corrosion
Corrosion monitoring is used to determine system corrosiveness as well as the
effectiveness of corrosion control procedures. Monitoring techniques range from
visual examination to complex electrochemical polarization or electromagnetic
techniques and are usually classified as direct or indirect. The following methods
can be used to monitor corrosion rates and inhibitor effectiveness:
•
Indirect
Weight-loss Coupons
Electrical Probes
Galvanic Probe
Hydrogen Probe
Water Chemistry
•
Direct
Visual inspection
Test Spools
Ultra-Sonic Inspection
Calipers
Radiography
Indirect Procedures
Indirect procedures are widely used to monitor corrosion and corrosion control
programs in pipe lines.
Weight Loss Coupons. Weight loss coupons are the most common form of monitoring in the oilfield. Preweighed metal coupons are exposed a minimum of 15 days
or longer-depending on the expected corrosion rate and the corrosion rate
calculated from the metal loss. They can be any shape such as disks, strips, and rods
and out of the same alloy as the system.
Coupons are cheap compared to other forms of monitoring but they have the
following disadvantage.
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•
Coupons must be located in areas where water is present, and where corrosion
is occurring.
•
They are usually inserted perpendicular to the flow direction and, thus, produce
a different corrosion rate behavior.
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•
They must be exposed long enough to produce measurable corrosion.
•
The system must be shut down for replacement.
Electrical Probes. Electrical probes instantly measure a corrosion rate and eliminate the need to shut down the system. A more extensive discussion of electrical
probes is given in Section 520.
The common probe types are the electrical resistance and linear polarization probes.
The three most popular are the Corrosometer and Corrator (Rohrback Instruments)
probes, and the PAIR probe (Petrolite Corp.)
The CORROSOMETER, (shown in Figure 600-14) is an electrical resistance
probe utilizing a wire loop inserted into the system and allowed to corrode. The
resistance of the loop is proportional to the cross-sectional area. As the area is
reduced by corrosion, the increase in resistance can be measured and the corrosion
rate calculated at any time. Figure 600-15 shows a typical data plot.
Fig. 600-14 CORROSOMETER® Electrical Resistance Meter, Schematic of Instrument.
(Courtesy of Rohrback Cosasco Systems, Inc.)
The probe does not have to be in a continuous water phase. However, several factors
affect corrosometer probe measurements.
Chevron Corporation
•
The probes are perpendicular to the flowstream, producing different corrosion
circumstances than the pipe wall experiences.
•
In sour systems a tenacious film of iron sulfide can form on the sensing
element. The film stifles further corrosion and provides erroneously low corrosion rate data.
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Fig. 600-15 Typical Corrosometer Probe Data (Courtesy of Rohrback Cosasco Systems, Inc.)
•
The wire may perforate near the body of the probe due to pitting corrosion.
This causes an extremely high initial corrosion rate and renders the probe
useless.
Both the CORRATER and PAIR probes use the linear polarization method to
measure the corrosion rate. In this method, a voltage difference is created between
two electrodes emersed in an electrolyte, and the resulting current flow is measured.
This current is proportional to the corrosion rate. The difference between the two
probes determines how changes system resistivity. As shown in Figure 600-16, the
CORRATOR uses 2 electrodes, and the PAIR uses 3.
Corrosion rates measured by the two-electrode CORRATOR must be corrected for
the resistivity of the test solution, while those measured by the three electrode PAIR
probe need not be corrected. The corrosion rates measured by both instruments are
real time (instantaneous rates occurring at the time of the measurement).
The linear polarization method has two major disadvantages.
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Fig. 600-16 Two Probe and Three Probe Linear Polarization Methods to Measure Corrosion Rate
•
The lack of a continuous high conductivity fluid between the electrodes makes
it ineffective in hydrocarbon streams where little water is present or relatively
dry gas streams.
•
Erroneous readings or no readings may occur if corrosion products or solids
bridge the electrodes.
The PAIR probe can used for polarization studies when coupled with a potentiometric device. The CORRATOR cannot.
Hydrogen Probes. Hydrogen probes obtain comparative corrosion rate data in sour
systems. They are available from several manufacturers and can range from the
simple, as shown in Figure 600-17, to the complex.
Though they are used in sour systems, studies have shown that a hydrogen probe
can detect corrosion in systems containing as little as 1 ppm H2S. Hydrogen probe
data, as shown in Figure 600-18, usually does not correlate with other corrosion rate
data obtained from coupons or electric probes. Also oxygen can interfere with probe
sensitivity.
Galvanic Probes are simple, inexpensive devices that measure changes in the
corrosivity of an electrolyte. A galvanic probe consists of two dissimilar metals
which generate an electrical current when immersed in an electrolyte. The current is
measured by a meter or a recorder.
System variables such as temperature, velocity, pH, oxygen, salinity, or the presence of an inhibitor cause a change in system corrosivity, which is inducted by a
change in current. Galvanic probes, like hydrogen probes, are useful.
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Fig. 600-17 Typical Internal Hydrogen Pressure Probe
Water Chemistry. Iron concentrations are the most common form of corrosion
monitoring by water analysis. Any change in a base line value shows a change in
the system corrosion rate. Several factors affect iron concentrations used to monitor
corrosion:
•
•
•
•
•
•
Iron concentrations are usually not reliable for sour systems.
Oxygen contamination can cause iron precipitation.
Some subsurface waters contain soluble iron.
Volume fluctuations influence iron concentrations.
Corrosion type (e.g. pitting) influence interpretation.
The analysis must be substantiated with other corrosion monitoring techniques.
Direct Procedures
Direct procedures are the most reliable methods for detecting and monitoring the
corrosion damage process.
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Fig. 600-18 Correlation of Hydrogen Probe Pressure Change With Coupon Corrosion Rate for
Several Wells
Visual Inspection is necessary at system locations that are susceptible to accelerated attack. These are welds, seams, and transition pieces or vessels not easily monitored by other methods. There are several disadvantages to the procedure.
•
Can be time consuming.
•
Frequently requires extensive cleaning
•
Usually requires a system shutdown.
•
Requires an expert inspector. Visual inspection without substantiating measurement is a matter of judgment.
•
Selection of inspection location is critical.
Test Spools are usually installed in a bypass loop and may or may not contain other
monitoring equipment. If one or more of the indirect methods is being used, the test
spool can be used to verify measurements. Test spools are usually constructed of the
same materials as the system monitored.
The major disadvantages are expense and that a test spool must be installed where
corrosion will occur.
Ultrasonic Inspection techniques use ultrasonic sound waves to measure metal
thickness. The technique is very useful for monitoring the progress of general,
uniform corrosion. Carefully measured baseline data is required. These are the
major limitations.
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•
Surfaces must be clean in order to obtain effective transducer/specimen
coupling.
•
Interpretation requires a trained operator.
•
Transducer orientation is important for reproducibility
•
Transducer must be in direct contact to detect the damage; pitting damage is
difficult to detect.
Calipers include mechanical and electronic tools.
An example of an electronic tool is an instrumented pig that induces an electromagnetic field in the pipe as it moves through the line. The pig can detect measurable
changes in this field caused by discontinuities such as pits or holes. Another type
measures wall thickness by ultrasonic techniques.
There are also mechanical pipeline calipers available that are significantly less
expensive than the electronic calipers. However, these calipers only detect internal
damage.
Radiography is used extensively to inspect the internal integrity of structural parts
and material. It sees through solid materials. The penetrating radiations used are
generally from two sources: x-ray and gamma ray. X-rays are usually generated by
man-made electronic equipment while gamma rays are emitted by radioactive materials or isotopes.
The method has many of the same disadvantages as ultrasonics, as well as the
following:
•
•
Interpretation requires a trained operator.
Source orientation is critical for reproducibility.
626 Laboratory Testing of Corrosion Inhibitors
Many testing methods designed to simulate field conditions have been reported, but
only a few of these methods survive, and none has become a standard test.
Film Persistence Wheel Test. The end user of corrosion inhibitors often specifies a
laboratory test that the inhibitor must pass before a field trial or purchase is considered. Since the wheel test is commonly the one specified, many inhibitors are
formulated to pass it. Unfortunately, it has been found that inhibitors can be formulated to pass the wheel test, but they fail to prevent corrosion in the field. For this
reason, some operating locations do field trials and skip the wheel test.
After 25 years of use and many series of multilaboratory comparative inhibitor tests,
no consensus has been reached on a standardized version of the wheel test. A wheel
test procedure (not a standard) is described in Reference [12].
The wheel test is a dynamic test in which synthetic or field fluids including inhibitors are placed in a 7-ounce beverage bottle containing a metal coupon. The bottle
and its contents are purged with N2, followed by CO2 or H2S, and the bottle is
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capped. The bottles are then agitated for approximately 1 hour by securing them to
the circumference of a wheel and rotating the wheel. After the first agitation period,
the coupons are transferred to a rinse bottle containing fluids with no inhibitor and
again agitated. The coupons are then transferred to another bottle containing only
corrosive fluids (no inhibitor) and agitated for a longer time, usually 24 hours. The
metal coupon is then removed and cleaned, and the weight loss is measured.
Section 640 provides a more detailed explanation of the criteria for choosing a
specific inhibitor and how to test its effectiveness in the laboratory.
The maximum safe temperature for the wheel test is 180°F; however,
high-temperature versions have been constructed. Temperatures of 300°F to 400°F
and pressures of several thousand pounds per square inch are achieved using highalloy pressure cylinders.
Static Test. In this test, coupons are exposed in fluids for about 1 week, with and
without inhibitors, and evaluated on a weight-loss basis. Another static inhibitor
screening test consists of short-term static exposure in field fluids containing inhibitor, followed by immersion in a copper ion solution to determine filming ability.
627 Monitoring Results of Inhibitor Use in the Field
The following methods are used to monitor corrosion rates and inhibitor
effectiveness:
•
•
•
•
•
•
•
•
Corrosion coupons
Spools, pup joints, and pony rods
Iron counts
Resistance probes
Electrochemical methods such as LPR (linear polarization resistance) probes
Caliper surveys
Copper ion displacement
Radioactive tracer methods
Vendors can help in setting up and maintaining monitoring programs. To select the
most cost-effective inhibitor treatment program, particularly for topsides equipment, vendors commonly use an instrumented side-stream flow loop to evaluate the
performance of candidate inhibitors over a range of injection rates. Comparison of
performance of the various vendors' chemicals in the actual field environment will
help in selecting the most cost-effective treatment program.
Plant tests can be used as an alternative to side-stream testing, particularly where the
volume to be treated does not exceed about 60,000 bbl/day.
Reference [13] describes a corrosion fatigue testing apparatus for field-testing
corrosion inhibitors that are specially formulated to prevent corrosion fatigue of
sucker rods.
Bacteria corrosion is addressed in several references. Reference [14] discusses a
method of enumerating bacteria. Reference [15] gives a quick field method for
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enumerating total bacteria and studying the effect of bactericides. Reference [16]
contains a method of studying biofilms and the effect of bactericides on them. A
rating system for evaluating bacterial problems in waterfloods is given in
Reference [17].
628 Chemistry of Corrosion Inhibitors
Many inhibitor formulations are available. However, most of these inhibitors are
produced from only a few basic types of starting molecules. Fatty acids and some
form of basic nitrogen-containing precursor are the principal sources of active
ingredients.
The first proprietary organic inhibitors were fatty imidazolines made from byproduct fatty acids and polyethylene amines. The molecules produced from these
products were dissolved in hydrocarbon solvent or water-alcohol-base solvent,
depending on whether they were further reacted. Typical further reactions were
salted with acetic acid (CH3COOH) or quaternized with a short-chain alkyl chloride. Highly corrosive wells required daily batch treatments with these early
inhibitors.
The inhibitors currently in use are generally more complex mixtures or reaction
products that have been formulated to meet the demands of a very competitive
industry. The amines or cationic molecules used today are often neutralized with an
organic acid or quaternized to achieve a final basic product. In approximately 70%
of the inhibitor formulations used, the choice of the acid or anionic molecule is
critical to the performance of the final product. Also, a mixture of acids is sometimes used to obtain a desired property.
More details on chemistry are available in Reference [6].
Bactericides. The most common surface-active bactericides are dimethyl coco
amine quaternized with methyl chloride; coco diamine acetate, benzoate, or adipate;
3-alkoxy* -2hydroxy-n-propyl trimethylammonium chloride (where * denotes a
linear primary alcohol, C12-C15); and dimethyl coco amine quaternized with
2,2-dichloro-diethyl ether. The most common nonsurface-active bactericides are
formaldehyde, glutaraldehyde acrolein, chlorine dioxide (ClO2), chlorine, sodium
hypochlorite (NaOCl), isothiazolone, dibromonitrile proionamide, and sodium
dimethyldithiocarbamate. The use of formaldehyde is discouraged because it is a
known carcinogen.
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630 Use of Polysulfide Corrosion Inhibitors
Corrosion of refinery equipment by cyanides (CN-) and bisulfide ions (HS-) can be
reduced through use of an efficient polysulfide injection system. This section
summarizes Chevron’s current guidelines for effective application of polysulfide
inhibitor systems for refinery process plants. Much of the information given here
was developed during surveys conducted in 1988 [3] and 1996 [24].
631 Polysulfide Chemistry
Two types of polysulfide, ammonium polysulfide (APS) and sodium polysulfide
(NPS), are available to inhibit corrosion. NPS (Na2Sx) is more stable than APS
((NH4)2Sx), but is reported to be less reactive with cyanides than APS [18].
Ammonium polysulfide is available in two different strengths as shown in
Figure 600-19. A typical sodium polysulfide composition is given in Figure 600-20.
The amount of free sulfur available for reaction with cyanides varies from one grade
of polysulfide to another. The chemical vendor can provide a current analysis.
Fig. 600-19 Ammonium Polysulfide Chemistry
Characteristics
Chevron Corporation
Strength 1
KC-2045 Refinery Grade
(1994)
Strength 2
KC-2040 Refinery Grade
(1994)
Active Sulfur (Wt. %)
(“0” Valence S)
36% Min.
32% Min.
(NH4)2Sx
55%
49%
NH4OH
31%
33%
Free H2O
14%
18%
Total Nitrogen (Wt %)
20% Min.
20% Min.
Total Sulfur (Wt %)
45% Min.
40% Min.
Specific Gravity at 25°C
1.15–1.17
1.13–1.15
B.P.
100°F
100°F
Freeze Point
10–15°F
10–15°F
pH
10.5–11.5
10.5–11.5
Total NH3 in Product (Wt %)
24.3%
24.3%
Color/Odor
Ruby-Red Liquid With
Strong NH3 Odor
Ruby-Red Liquid With
Strong NH3 Odor
Comments:
In a Fire, Produces H2S,
NH3, NOx, SO2
In a Fire, Produces H2S,
NH3, NOx, SO2
Per operator experience,
APS is difficult to pump
< 40°F
Per operator experience,
APS is difficult to pump
< 40°F
(x = 1 - 4)
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As of October 1996, the current cost of KC-2045 APS was $295 per ton or about
$1.42/gal., plus shipping (FOB Stockton, California, or Pasadena, Texas).
Tessenderlo Kerley is the sole supplier of ammonium polysulfide, which is
produced primarily for the fertilizer industry. The current contact is:
Tessenderlo Kerley, Inc.
Brian Jones, Vice President
2801 West Osborn Road
Phoenix, Arizona 85017
Tel: 602-889-8300
Fax: 602-889-8430
Email: im-info@tkinet.com
Fig. 600-20 Sodium Polysulfide Chemistry by Manufacturer
Kerley Chemicals
February 1993
Characteristics
Morton International
February 1993
Formula
Na2S5
Na2S3.8
Molecular Wt. %
206
167.6
Free Sulfur min. Wt. %
14.5% min.
Free Sulfur Typical Wt. %
17.4%
0 Typical
Na2Sx
(x=5) 29%
(x=3.8) 20%
(Na2S) Sodium Sulfide
(11.8% typ.) 13.5% max.
(Na2S203) Sodium Thiosulfate
(12.2% typ.) 14% max.
3%
Spec. Gravity at 60°F
1.33
1.23
Freeze Pt.
32°F
Color/Odor
Red-orange
Viscosity @ 60°F
7.5 cp
—
Comments:
Made from sulfur and
caustic soda.
—
—
—
—
Red-orange
APS is the more commonly used. Either type can be used for most applications, but
APS is highly favored over NPS in FCCU applications to simplify downstream sour
water treating.
FCCU applications typically produce a large volume stream of sour water
containing residual polysulfide. Sour water containing APS can be steam stripped to
reduce both NH3 and H2S down to low levels (less than 50 ppm). Water containing
residual NPS must either be acidified to remove sulfides, or oxidized to convert
sulfides to sulfates. Given a choice, most refineries prefer simple steam stripping
over acidified stripping to avoid corrosion from acid handling. Some refineries, on
the other hand, can accept small volume streams containing NPS into their overall
sour water system without seriously affecting effluent quality.
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632 How Polysulfide Inhibits Corrosion
Polysulfide is typically used in FCCs, cokers, and WWT ammonia stripper overheads to counteract cyanides, and added to wash water in hydrotreaters to reduce
corrosion in reactor effluent air coolers.
Polysulfide mitigates corrosion or cracking in three ways:
1.
Polysulfide reacts with cyanides to form harmless thiocyanates and thus
neutralize their damaging effects.
2.
Polysulfide promotes the formation of a more adherent, protective sulfide scale,
converting FeS to FeS2.
3.
Polysulfide inhibits the bisulfide reaction with iron.
Polysulfide Reacts With Cyanides to Neutralize Their Damaging Effects
Free cyanides break down protective iron sulfide scales to form ferrocyanide and
sulfide ions:
FeS + 6CN- → Fe(CN)6-4 + S-2
(Eq. 600-1)
The reaction exposes bare metal to the process stream. Newly exposed metal again
forms a sulfide scale which is subsequently damaged by cyanides, leading to
continued loss of metal thickness, and in some cases, hydrogen blistering.
Polysulfide inhibits the reaction of cyanides (CN-) with sulfide scales and direct
reaction with iron, by reacting with CN- to form harmless thiocyanate (SCN-):
CN- + Sx-2 (Polysulfide) → SCN- (Thiocyanate) + Sx-1 -2
(Eq. 600-2)
However, polysulfide does not stop corrosion, and hydrogen evolution continues at
rates dependent on the protectiveness of the iron sulfide corrosion products.
Polysulfide Promotes the Formation of a More Adherent, Protective
Sulfide Scale
Polysulfide reacts with FeS to form the “higher order” sulfide FeS2. FeS is formed
by reaction of carbon steel with the bisulfide HS - ion and is a loose, semi-protective
scale which is eroded away in turbulent or high-velocity streams. FeS is also subject
to reaction with cyanides, which break down the scale and expose fresh metal to the
corrosive environment.
FeS2 differs from FeS in that it is a hard, adherent scale which is not easily eroded
away by turbulence and velocity, and is also more resistant to attack by cyanides.
The reaction of polysulfide with the nonadherent FeS scale to form FeS2 proceeds
as:
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FeS (Loose Scale) + Sx-2 (Polysulfide) → FeS2 (Hard Scale) + Sx-1-2
(Eq. 600-3)
where the Sx-2 is the reactive part of the (NH4)2Sx molecule, and “x” can vary from
1 to 4.
Polysulfide Inhibits the Bisulfide Reaction with Iron
The third beneficial way in which polysulfide acts in overhead systems is to reduce
hydrogen blistering and wet H2S cracking. Bisulfide ions react with iron in the steel
to form sulfide, sulfur ions, and hydrogen:
Fe + 2HS- → FeS + S- + 2Ho (Undesirable Reaction)
(Eq. 600-4)
Since sulfur inhibits the recombination of atomic hydrogen to hydrogen gas,
H atoms diffuse into the steel and cause hydrogen blistering and weld cracking. By
reacting with iron to form sulfide scale, the polysulfide, either ammonium or
sodium, reduces both creation of atomic hydrogen and sulfur ions. Polysulfide
(whether sodium or ammonia based) inhibits this reaction.
There is also some evidence that ammonium thiocyanate inhibits corrosion.
The reaction in Equation 600-4 can only occur if both an anodic half reaction and a
cathodic half reaction are free to proceed:
Fe → Fe+2 + 2e- (Anodic Half Reaction)
(Eq. 600-5)
and
2HS- + 2e- → 2Ho + 2 S-2 (Cathodic Half Reaction)
(Eq. 600-6)
The two electrons freed at the anode are needed at the cathode to turn bisulfide ions
into hydrogen atoms and sulfur ions. Polysulfide, instead, robs those two electrons
in the following reaction:
Sx-2 + 2e- → Sx-1-2 + S-2
(Eq. 600-7)
and stops Equation 600-6 from proceeding. Without the atomic hydrogen created in
Equation 600-6, the diffusion of hydrogen into steel is limited; and the risk of
cracking and blistering is sharply reduced.
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633 How to Increase Effectiveness of Polysulfide Corrosion Inhibitors
Polysulfide injection systems depend on certain critical factors for success. These
factors are:
•
•
•
•
•
•
injection water chemistry and pH
oxygen exclusion
temperature of operation
injection quantity and location
periodic monitoring
use of reliable and efficient pumps
Injection Water Chemistry and pH
Of major importance to the effectiveness of the injection system are the chemistry,
pH, and temperature of the injection water and process stream into which the
polysulfide is added. Any condition resulting in the precipitation of elemental sulfur
leads to plugging in the polysulfide system. APS readily decomposes to ammonia,
H2S, and elemental sulfur if the following conditions are not met by the injection
and process streams:
1.
Oxygen must be kept under 15 ppb (wt.). Oxygen converts polysulfide to
sulfur.
2.
pH should be at least 8.5 (at least 8.0 for NPS), which assures enough excess
ammonia will be in solution, and that polysulfide remains stable.
3.
Fe should be no more than 1 ppm.
4.
Optimally, at least 50 ppm H2S (by weight) should be in solution.
Reducing H2S leads to deficiency of S-2 and will cause sulfur precipitation.
In order to meet these guidelines, Chevron recommends that polysulfide be injected
into sour wash water whenever possible. If stripped sour water must be used, it
should be checked regularly for H 2S content, and it must be oxygen-free. If H2S
content is less than 5 ppm, its use will likely lead to plugging of equipment with
elemental sulfur. The use of condensate or boiler feed water is not recommended.
Both are likely to contain traces of oxygen, be deficient in H2S, and be insufficiently alkaline.
It is important to inject the polysulfide into plenty of water. If the dilution water
boils off, the polysulfide will decompose, leaving vapor lines clogged with solids.
Ammonia may also vaporize out of solution, causing decomposition of the polysulfide and precipitation of sulfur. Excessive vaporization is most easily avoided by
adding large amounts of wash water.
Keep Oxygen Content and Temperatures Low
If sulfur precipitates out of the polysulfide solution either in storage or in equipment, oxygen content should be checked. Sources of oxygen include defective
packing and mechanical seals, leaking injection pumps, and break tanks which are
not inert-gas-blanketed. Likewise, while in storage, polysulfide solution must be
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blanketed, preferably by nitrogen, to prevent oxygen pickup. Polysulfide will
decompose and precipitate sulfur if stored in a drum or tank left open to air.
Although it is commonly used, oil blanketing is not as effective as nitrogen, since
oxygen can dissolve through the oil layer and into the polysulfide. A nitrogen
system can be expensive and harder to maintain than oil blanketing, but a nitrogen
blanket should be added if plugging problems persist.
Even in an oxygen-free storage environment, polysulfide is difficult to pump
< 40°F. In cold climates, insulation of the storage tank and piping may be necessary.
At elevated temperatures NH3 vapor pressure and evaporation control solubility. As
NH3 evaporates from the solution, polysulfide becomes less soluble until it crystallizes, and as NH3 continues to evaporate, the polysulfide breaks down to sulfur.
Aqueous ammonia can be used to resolublize crystallized APS.
The process stream temperature after polysulfide/water injection, should be not
hotter than 325° F. As the stream temperature exceeds 250°F, the solution begins
decomposing to ammonia, hydrogen sulfide, and elemental sulfur.
Use Proper Injection Methods, Quantities, and Locations
Equipment most susceptible to cyanide corrosion is shown in Figures 600-21
through 600-24. To fight corrosion in these areas:
1.
Use the proper quantities of polysulfide and wash water, inject polysulfide in
more than one location where appropriate, and use an injection quill with holes
drilled or a spray nozzle where the polysulfide/water enters the process stream.
2.
Use plenty of wash water to fully dilute corrodents, absorb salts and acid gases,
and avoid excessive vaporization. At least 25% of the wash water should
remain unvaporized throughout the piping and equipment to be protected.
3.
For units other than FCCs and Cokers, a common rule of thumb is to use at
least five times the stoichiometric equivalent of polysulfide needed to react
fully with cyanides. In plants where cyanide content is not significant, e.g.,
hydroprocessing plants, the guideline is to add 10 ppm of polysulfide (by
weight) into the injection water to reduce bisulfide corrosion.
For FCCs and cokers, add the stoichiometric amount of polysulfide needed to
react with cyanides (based on the amount of active sulfur in the solution), plus
enough to give 10–15 ppmw in the sour water further downstream of the injection point.
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4.
Inject polysulfide at the locations shown in Figures 600-25 through 600-28.
5.
Wherever possible, avoid recirculation of partially spent polysulfide—add a
fresh injection point instead. This is usually a concern for FCC and Coker overheads where a “parallel cascade” system is preferred over “reverse cascade”.
This helps reduce chances for recirculating contaminants in the overhead
system. See Figure 600-29. The advantages of having a single polysulfide
injection pump seldom outweigh the disadvantages of the reverse cascade
system.
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Use an injection quill with holes drilled, or one with a spray nozzle tip, spray
nozzle, or capped quill to maximize contact of polysulfide with the process
stream. References [3] and [24] show quills and nozzles which are being used
successfully in some plants. Spray nozzles give better contacting of polysulfide
with the process stream, but require that the nozzle be retractable, since it is
more susceptible to plugging.
Fig. 600-21 Hydroprocessing Units—Areas Most Susceptible to Aqueous Corrosion
Fig. 600-22 Coker Units—Areas Most Susceptible to Aqueous Corrosion
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Fig. 600-23 Waste Water Treatment, Sour Water Stripper, Sour Water Concentrator, and Amine Units—Areas Most
Susceptible to Aqueous Corrosion
Fig. 600-24 FCC Units—Areas Most Susceptible to Aqueous Corrosion
El Segundo only
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Fig. 600-25 Hydroprocessing Units—Location of Most Effective Polysulfide Injection Point
Fig. 600-26 Coker Units—Locations for Polysulfide Injection and Hydrogen Probes
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Fig. 600-27 Waste Water Treatment, Sour Water Stripper, Sour Water Concentrator, and Amine Units—Locations for
Polysulfide Injection
Fig. 600-28 FCC Units—Locations for Polysulfide Injection and Hydrogen Probes in FCC Units
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Fig. 600-29 Cascade Water Wash
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Monitor the Process Stream Chemistry
Hydrogen probes and monitoring of pH, H2S, O2, and CN- content in the process
stream or effluent water allows for early detection of problems and time to make
corrections before severe corrosion results.
While H2S concentration is certainly high enough in sour wash water, stripped sour
water or boiler feed water should always be tested for H2S content. Although it is
not quantitative, a lead acetate test for the existence of H2S is quick and
inexpensive.
If plugging problems arise, check for oxygen. Oxygen is the primary reason for
sulfur clogging of pumps and lines.
Even in smoothly running FCC and coker units, monitoring of hydrogen activity
and testing for cyanides should be performed regularly. Hydrogen activity is most
readily monitored through the use of probes, typically measured once per week.
Probes should be installed wherever blistering and weld cracking is common such
as in intercooler and aftercooler piping, and in the vapor zones of reflux drums,
interstage k. o. drum, and the de-ethanizer. Figure 3200-19 in Section 3200 of the
Corrosion Prevention and Metallurgy Manual describes recommended practices for
FCC overhead units. Figure 3200-19 includes recommended monitoring frequencies for sour water and for hydrogen probes.
The ferric chloride spot test is a quick qualitative test for cyanides performed in the
field to ensure that all free cyanide is being reacted with. In this test, a few drops of
sample water are placed on filter paper and allowed to dry. A drop of ferric chloride
(FeCl3) solution is then allowed to run into the sample spot. A deep Prussian blue
color should not appear as the two spots overlap. The blue color is evidence of
ferrocyanide (Fe(CN6)2-) which forms as a reaction product if CN- is present.
Although the color test is not quantitative, a positive reading means all of the CN- is
not being reacted with polysulfide. A red spot may appear. This is evidence of
harmless SCN-.
A few plants currently use the FeCl3 test. Failure to perform even a simple qualitative test like this one may lead to a plant not injecting enough polysulfide to react
with all the free CN-. Details about the FeCl3 test are available from the FCC
Process Advisor.
In the field, the accepted method for checking for residual polysulfide is to compare
prepared samples of potassium chromate to the drawn sour water. The color of the
samples corresponds to sour water with known ppm levels of polysulfide. Alternatively, a photograph of potassium chromate samples can be used for comparison.
At some refineries, a yellow color is either visually observed in effluent water or
measured via spectral absorption. This method is not foolproof. The yellow color
which suggests the existence of polysulfides in solution can also be due to corrosion products.
One way to know whether it is a valid indicator is to shut off the polysulfide injection entirely, allow the system to reach equilibrium (which could take several hours
in large plants), and then check the water color. If it remains yellow, then color is
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not an appropriate way to check for polysulfide in that system. If it changes color,
then a combination of color check and FeCl3 spot test is the best, easy way to
determine if enough polysulfide is being injected into that system. For more accurate results, the recommended field method for quantifying polysulfide is the spectrophotometer method “Plant Method A-48”. There is also a laboratory method
available from CRTC’s Analytical Unit that gives the best results, but it is not suitable for field use.
Use Reliable and Efficient Pumps
There should be at least one reliable pump and one pump spare for the polysulfide
system. Most plants have three to four pumps.
In the 1988 survey [3], some refineries who used air driven pumps such as the Williams Occilomatic air pump, complained that they were not reliable. The recommendation after that survey was to use the Milton Roy diaphragm pump because, at
Pascagoula, this pump was more reliable than the Williams air pump for pumping
polysulfide. The air pumps allow for the chance of air leakage into the system—air
can leak past the piston seal and into the water.
Diaphragm pumps at Richmond plugged after 6 months use. Richmond now uses
Pulsar Pulsafeeder pumps.
At various times, the Hills, Milton Roy, Williams Occilomatic, and Pulsafeeder
have reportedly performed poorly. The main point is that each location should find a
reliable set of pumps and maintain them properly so that pump problems do not
cause polysulfide injection system downtime.
Pump Sizing for Cyanide Environments. It is important to choose a pump with a
wide capacity range to deal with changing refinery conditions. In order for polysulfide to be effective, the operator must know the quantities of cyanide, and must add
more than enough polysulfide to stoichiometrically neutralize the cyanide. The
reason for this requirement is that complete reaction of the two species is impossible, considering the short contact times within the equipment. The required
steps are:
1.
Determine amount of cyanide in the system
2.
Determine the amount of polysulfide required
3.
Select the pump to operate between 50% and 100% of capacity
To determine the amount of polysulfide required for FCC and coker overheads, use
the method shown in Figure 600-30. Note that it is also important to know how
much net sour water is flowing from your system. It is important to choose a pump
with a wide capacity range (to deal with changing refinery conditions), as well as
one which can be used most frequently between 50% and 100% of capacity
In the design example choose a pump with a maximum capacity of 18 × 2 = 36 gpd,
so the pump operates at 50% of capacity. However, if designing for twice the
normal flow requires purchase of the next size larger pump, consider dropping the
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maximum design flow to 133% of normal, so the normal flow rate is 75% of
capacity; this may allow for a smaller pump.
Fig. 600-30 Sample Calculations for Ammonium Polysulfide Needed for Total Cyanide
Calculate stoichiometric amount of active sulfur required to react with cyanide in the fractionator overhead, assuming 36 weight % active sulfur:
(NH4)2Sx + NH4CN ⇔ (NH4)2Sx-1 + NH4CNS
S (32 mw) + CN- (26 mw) ⇔ SCN- (Thiocyanate)
Since 32/26 = 1.23, then 1.23 lb of “active” sulfur is required per pound of cyanide.
Provide enough additional polysulfide to maintain 10 ppmw active sulfur in the net sour
water from the unit.
1. Polysulfide Consumed for an assumed cyanide rate of 2 lb/hr:(1)
( 1 lb Solution )
( 1 Gal. Solution )
( 2.0 lb CN - ) ( 1.23 lb active S )
---------------------------- × ------------------------------------ × ------------------------------------ × ----------------------------------------------1 Hr
( 0.36 lb active S ) ( 1.16 ) ( 8.3 )lb Solution
lb CN 24 Hr
1 Day
Gal. APS Solution Consumed
Day
× ------------- = 17 -------------------------------------------------------------------2. Polysulfide in Net Sour Water (10 ppmw)
1 lb Solution
( 20 Gal. Water ) 1440 Min. ( 8.3 lb Water ) 10 lb active S
------------------------------------- × ---------------------- × --------------------------------- × ------------------------------- × ----------------------------------1 Gal. Water
1 Min.
1 Day
10 6 lb Water 0.36 lb active S
1 Gal. Solution
( 1.16 ) ( 8.3 )lb Solution
Gal. APS Solution
Day
× --------------------------------------------------- = 0.7 ------------------------------------------Total Polysulfide Solution Required = (1+2) ≈ 18 Gal. APS Solution /Day, so that pump
operates at about 50% of capacity choose a pump with a maximum capacity of 36 Gal/Day.
(1) Typically 0.5 to 5.0 lb/Hr of CN- is produced in an FCC overhead system.
Pump Sizing for Other Environments. In applications where cyanide is not
important, (such as hydrotreater effluent air coolers) a concentration of about 10
ppm of polysulfide in the wash water stream will inhibit other forms of corrosion
including reduction of bisulfide ion corrosion. In this case, the amount of polysulfide to add depends on the amount of wash water flow to the equipment. Our guideline is that 25 GPM of wash water requires 1.5 gallons per day of 20–30% weight
active sulfur in polysulfide solution. This solution can be diluted to allow higher
rates (if desired) for better injection pump operation.
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634 Troubleshooting
Following is a list of common problems with polysulfide injection systems, which
can lead to corrosion, blistering, weld cracking, and plugging.
Corrosion, Blistering, Cracking
•
•
•
•
•
•
Not enough polysulfide added; pump too small
Oxygen present (decomposition of polysulfide)
pH, H2S, NH3 too low (decomposition of polysulfide)
Injection water vaporizing upstream (insufficient water; lines too hot)
Vaporization of NH3 out of hot injection water
Inadequate mixing of polysulfide solution with the process stream
Pump, Gage, and Line Plugging
•
•
•
•
Oxygen present (check for leaks, and adequate inert gas tank blanketing)
pH, H2S, NH3 too low (maintain 8.5 pH for APS and 8.0 for NPS)
Injection water vaporizing upstream
Vaporization of NH3 out of hot injection water
635 Survey Results
Details of a survey conducted in 1988 for all types of plants using polysulfide are
found in Reference [3]. Survey responses came from a total of 26 plants, including
six FCCU (Richmond, Philadelphia, El Segundo, Pascagoula, Port Arthur, and El
Paso), twelve hydroprocessing units, and eight sour water stripper, sour water
concentrator, and amine regenerator units.
Another survey conducted in 1996 focused on FCC overhead systems; details are
contained in Reference [24]. These references are available in CRTC’s Materials
Engineering files.
640 How to Evaluate a Corrosion Inhibitor for Use in Oil Fields
This section describes how to evaluate a corrosion inhibitor for use in oil fields. To
achieve good field results, it's important to carry out a carefully designed evaluation
of all aspects of the production system and the methods that can be used to prevent
corrosion.
The evaluation process includes a thorough understanding of electrochemical corrosion and the factors that affect it, types of corrosion inhibitors, treatment methods,
and an analysis of conditions in the production system that cause corrosion. Based
on this information, you can conduct laboratory tests to select an inhibitor. In
general, products that perform well in the laboratory will also perform well in the
field.
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641 The Electrochemical Corrosion Process
Corrosion involves the conversion of metal into non-metallic corrosion products. It
is an electrochemical process that occurs in oilfields when water is present. During
the corrosion process, an electric current flows and sets up a current. The resulting
electrical circuit consists of three parts: an anode, a cathode, and an electrolyte. The
combination of the anode, cathode, and the electrolyte is called a corrosion cell.
•
Anode. The anode is the area of the corrosion cell on the metal surface where
metal loss occurs. Here metal atoms lose electrons and dissolve or go into solution as metal ions with positive charge. The electron loss is called oxidation.
The electrons left behind travel through the metal to the cathode.
•
Cathode. The cathode is the area of the corrosion cell on the metal surface that
does not dissolve. It is the site of the other chemical reactions necessary for
corrosion to occur. The electrons left behind at the anode by the oxidation of
the metal travel to the cathode and are consumed there by an oxidizing agent
present in the water. (An oxidizing agent is a chemical reactant that consumes
electrons.) A typical reaction is with hydrogen ions. The consumption of electrons is called reduction.
•
Electrolyte. The electrolyte is a solution that conducts electricity. In the
oilfield, the electrolyte is a water solution of a substance that forms ions. For
example, common salt when dissolved in water breaks-up or ionizes into
sodium ions and chloride ions. Electrical conduction is by the movement of
ions. The more ions, the better the conductance. The electrolyte must be in
contact with or wet the metal surface.
642 Factors That Affect Corrosion
In any laboratory evaluation, consider the main factors that affect the corrosion
reaction.
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•
Electrolyte Conductivity. The electrolyte conductivity has a direct effect on
the corrosion rate and the amount of metal that dissolves. For example, distilled
water is not very conductive and is not very corrosive. However, salt water is
very conductive and can be very corrosive.
•
pH. The corrosion rate of steel usually increases as the pH decreases. As the
pH decreases, the amount of hydrogen ions in solution increases. The more
hydrogen ions, the more electrons can be consumed at the cathode.
•
Dissolved Gases. Dissolved gases are the primary cause of most corrosion
problems in the oilfield. Oxygen, carbon dioxide, and/or hydrogen sulfide
dissolved in water drastically increase its corrosivity.
•
Temperature. Corrosion rates generally increase with increasing temperature
in closed systems. However, the solubility of the dissolved gases decreases with
increasing temperature and will lower the corrosion rates in open systems
where the gases can boil off.
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•
Pressure. Pressure increases the solubility of the dissolved gases and the corrosion rate.
•
Velocity. Corrosion rates usually increase with increasing flow rate.
643 Types of Corrosion Inhibitors
To inhibit corrosion, impair the reactions at the anode or cathode or both, or eliminate the contact between the electrolyte and the metal surface. Most inhibitors form
a film on the metal surface. Some form an invisible, thin film only a few molecules
thick. Others form a visible, thick film that coats the metal isolating it from the electrolyte. Still others form film in combination with the corrosion products.
Another way to impair corrosion is passivation. Passivation occurs when an inhibitor forms a very thin, unstable film either at the anode or the cathode and lowers the
reaction rate at that site. Those that form the film at the anode are called anodic
inhibitors; those that form the film at the cathode are called cathodic inhibitors.
The inhibitors most widely used to protect oil and gas production equipment and
pipelines are the cathodic and mixed organic types that function by forming film.
Inhibitor Classification
Liquid inhibitors are primarily classified as follows:
•
Solubility or dispersibility in oil and water (filming ability).
•
Organic or inorganic. Most inhibitors used in oilfields and pipelines are liquid,
organic mixtures.
Inhibitor dispersibility is important because it affects how the inhibitor is used and
where it will be effective. Many treating techniques require diluting the inhibitor in
a solvent before application.
Film persistency is a function of the dispersibility of the inhibitor. Inhibitors that
have a high degree of solubility in oil or water most often exhibit poor film persistency. However, many of the relatively insoluble inhibitors that show good film
persistency do not produce good inhibition in low concentrations. The more soluble
products generally exhibit better inhibition in low, constant concentration
applications.
644 Treatment Methods
In Wells
To apply corrosion inhibitors in oil and gas wells, lay down an inhibitor film and
replenish it periodically (batch treatment), continuously (continuous treatment), or a
combination of the two.
The batch treatment techniques include the following:
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•
Tubing Displacement. Used primarily for wells with a packer and for gas lift
wells. Treatment lasts from one week to several months, depending on the
system treated.
•
Standard Batch. Pumping wells are frequently treated by batching the inhibitor into he annular space and circulating to the bottom by by-passing production to the annulus or flushed by means of a treating truck.
Sometimes the wells are left to circulate the inhibitor down the annulus, up the
tubing, and back down the annulus. In other instances, it is circulated only
enough of flushed to carry a water dispersible or soluble inhibitor through the
oil column above the pump. Wells do not truly circulate until the fluid column
builds up to equal the bottom hole pressure or the well is pumped off.
Non-water dispersible inhibitors (heavy filmers) require some circulation.
Disperse or dilute and flush highly water-dispersible or soluble inhibitors with
about 1 bbl brine or fresh water for each 1000 ft. of tubing. Circulate, if
required.
Treatment frequency depends on production. It varies from every two to three
days (more than 350 bfpd) to once every month (less than 50 bfpd).
You can also treat gas wells equipped with packers by the standard batch technique. Lubricate one or two drums of a film-forming inhibitor, neat or diluted,
into the tubing and allow it to fall to the bottom. This usually requires abut one
hour of shut-in time for each 1500 ft. of tubing.
•
Continuous Treatment. Introduce the inhibitor on a continuous basis so that
the concentration is maintained at the required level. The concentration will
vary depending on the severity of the corrosion.
In Flowlines/Pipelines
The first step in an effective corrosion program is to clean the pipeline. Most film
forming amine type inhibitors do not film selectively. Film coats corrosion deposits,
scale, and sand and affects the performance of the program. In old systems where
the velocity is low and severe corrosion has occurred on the bottom of the line,
cleaning is mandatory.
Three types of inhibitor treatment programs are available for flowlines/pipelines.
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•
Periodically coat the inside of the pipeline with a tenacious film-forming
inhibitor. Apply a diluted inhibitor solution between two pigs or use a batch or
slug type treatment.
•
Continuously inject a water or oil soluble inhibitor into the line.
•
Periodically batch a water soluble-dispersible inhibitor into the line and maintain the required concentration in the water.
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645 Laboratory Test Methods
It’s important to consider the capabilities of laboratory test methods and evaluate
their advantages and disadvantages.
The Wheel Test
The wheel test is named after the primary piece of equipment used in the procedure. The wheel, or test oven, allows the rotation of bottles containing test fluids
saturated with CO2 and/or H2S, metallic coupons, and corrosion inhibitors at a
specific temperature for a specified time period.
Compare the metal loss of the coupons in the inhibited fluids with the metal loss of
the coupons from uninhibited fluids, or blanks. Report the results as the per cent
protection provided by the inhibitors, and/or as corrosion rates expressed in mils per
year (mpy).
Generally, there are two types of wheel tests:
•
Constant Concentration or Continuous. Evaluates inhibitors for continuous
injections such as water soluble inhibitors
•
Film Persistent. Evaluates inhibitors for batch treatment, tubing displacement,
or wherever corrosion inhibitor film life is important.
The wheel test is simple and allows the evaluation of several variable effects on
corrosion inhibitor performance: temperature, time, concentration, and to a small
degree, the acid gas composition. The wheel test also allows the evaluation of a
large number of inhibitors relatively quickly.
Test results have a low variability of less than 4% only if the average per cent
protection is in the range of 95% to 100%. The variation can double if the results
drop to 90% average per cent protection. Do not base the selection of inhibitors on a
single test. Differentiation among several inhibitors is not possible even at 95%
protection if the differences in per cent protection are 4% or less.
Pipelines, tubing, and production equipment usually do not fail because of general,
uniform corrosion. The most typical failure mechanism is pitting. In a system where
the failure mechanism is known to be pitting, a wheel test is not relevant unless
pitting attack occurs on the blanks and is prevented by the inhibitor.
Other drawbacks include the chemistry of the test fluids, lack of velocity effects,
and time dependency of inhibitor performance on time.
Linear Polarization Resistance (LPR)
Linear polarization resistance is an electrochemical technique used to measure the
corrosion rate of a test specimen. The rate is usually expressed in mils per year
(mpy). The technique is very fast, and is often called instantaneous. The name
comes from the term polarization resistance, dE/dI, which is the slope of the plot of
the polarization potential versus current. The dE is the millivolts potential the test
specimen is displaced or polarized from the corrosion potential in either the
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cathodic or anodic direction. The dI in milliamps is the current generated by the
displacement.
The polarization resistance is related to the corrosion current, Icor. Icor is equal to
the current generated in the anodic and cathodic reactions of the corrosion cell. The
corrosion rate can be calculated from Icor.
See Section 625 – Indirect Procedures for a more detailed discussion of Linear
Polarization Resistance measurement devices.
A discussion of LPR applications follows.
Kettle Test. An adaptation of the LPR technique for high and low pressure and
temperature applications. The kettle is a one liter resin kettle equipped with an LPR
probe, mechanical stirrer, gas sparge tube, and a heating mantle. You can add other
equipment such as a pH probe, ion selective electrode, or a sampler.
Advantages: The kettle overcomes many of the disadvantages of the wheel test such
as limited corrodant (CO2/H2S), reproducibility, time dependence of corrosion rates,
and velocity. However, to be useful the test electrodes must be in a conductive solution to limit the use of a hydrocarbon phase.
Disadvantages: One of the major disadvantages is that the equipment requirements
prevent the screening of a large number of inhibitors in relative short period of time
as compared with the wheel test.
Flowing. Flow systems attempt to duplicate system flowing velocity, or shear.
Advantages: Flow systems provide test fluids of constant composition.
Disadvantages: The cost of the system, size, and a limited number of inhibitors can
be evaluated. Relevancy is questionable because of the shape and orientation of the
test specimen. Using LPR instead of weight loss coupons restricts the amount of the
hydrocarbon phase.
Rotating Electrode. This technique attempts to duplicate the effects of fluid flow
by rotating the test electrode at various speeds in the electrolyte rather than flowing
the electrolyte past the electrode.
Advantages: It is used to study film life at different velocities and shear.
Disadvantages: The present systems are temperature- and pressure-limited, but can
achieve speeds in excess of 10,000 rpm and velocities exceeding 15 fps.
Autoclave
This term generally applies to any corrosion inhibitor laboratory test done at
temperatures and pressures higher than can be achieved in glassware, and usually in
a corrosion resistant metal test cell or cells. Temperature and pressure are limited
only by the materials of construction. The test can be static or stirred. Pipe autoclaves can be mounted on a wheel and run like a wheel test.
Autoclaves allow the use of large excesses of acid gases that maintain the corrosivity of the test fluids. In a normal wheel test, the acid gases are in such low
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concentrations, that they are consumed, allowing the pH to raise and reduce the
corrosivity. The major disadvantages are cost and their complexity. Also, high
temperature, high pressure testing is hazardous.
646 Field Condition and System Analysis
To define the problem, analyze the system. Answer these questions before defining
an effective mitigation program or establishing meaningful values for the various
parameters of an laboratory evaluation. Where is the corrosion occurring? What is
causing it?
Determine the following:
Chevron Corporation
•
System Temperature. Determine the temperature especially at the location of
the problem and also any extremes to which the inhibitor may be exposed, both
internally and externally. Internally, temperature can affect stability, solubility,
as well as ability to protect. Externally, inhibitors can separate if exposed to
temperatures at the pour point or exposed to high temperatures where solvent
light ends boil off.
•
Volumes and Types of Fluids. Consider BOPD, BWPD, BCPD, GOR,
MMCFD, etc.
•
pH. Measure the pH at the location of the problem as well as the extremes. This
is important not only for inhibitor performance, but also for its affect on, for
example, inhibitor stability or foaming tendencies.
•
Pressure. Measure the pressure at the problem as well as the extremes. Pressure can affect inhibitor performance. If there are large pressure drops, for
example, across control valves or into a separator, the product must be checked
for any foaming or emulsion tendencies.
•
Acid Gases. Determine the amount of CO2 and H2S.
•
Oxygen. Measure the amount of oxygen. Forty ppb can be significant.
•
Water Analysis. Measure pH, temperature, pressure, dissolved acid gases,
oxygen and bicarbonates when the sample is taken.
•
System Design and Components. Use process and instrument diagrams
(P&ID). If none are available, make sketches showing major equipment, flow
direction changes, monitoring points, separators, treaters, etc.
•
Environment. Consider environmental factors. Where will the chemical ultimately reside? If it is in the disposal water, what is the concentration limit?
•
System Limitations. Determine whether the treatment method has system limitations. For example, is the bottom hole pressure of the well sufficient to allow
a full tubing displacement, or can the flowline be pigged?
•
Downstream Processing. Does downstream processing place limits on the type
of chemicals that can be used? For example, one type of membrane sweetening
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system cannot tolerate the polynuclear aromatics found in many inhibitor
solvents.
647 Selecting Corrosion Inhibitors
Make a preliminary decision on how to treat the corrosion problem based on the
system analysis and the determination of where and what is causing the corrosion.
For example, if the problem is downhole in a gas well, you might consider whether
the tubing will displace or squeeze, and find out if treating string is available for
continuous treatment.
After the method is selected, define what physical properties of the inhibitor are
required. For example, if the batch treatment method is selected, the inhibitor must
be a film former. However, before any type of corrosion test is run, evaluate the
following inhibitor properties.
•
Solubility/Dispersibilty. The inhibitor must be sufficiently dispersible or
soluble in the diluent to be used at the required concentration. The diluent can
be lease crude, condensate, diesel, or produced water.
•
Thermal Stability. The inhibitor must not decompose or react further at the
maximum temperature to which it will be exposed. It must not gunk.
•
Emulsion Tendencies. The large concentration of inhibitor used should not
cause emulsion problems in the system. Test it at several representative
concentrations.
•
Foaming Tendencies. Especially in gas treating systems and separators, the
inhibitor should not cause foaming in amine or glycol treating systems or liquid
separation equipment.
•
Compatibility. Will the inhibitor be compatible with other treating chemicals
used elsewhere in the system or will they together cause foaming, gunk, emulsion, or reduced effectiveness?
If the corrosion problem is in a wet gas or oil line and continuous treatment is
selected, use a water soluble or highly water-dispersible inhibitor. Run the same
tests as above in addition to the following:
August 1999
•
The Solubility/Dispersibility. Include the produced water in the test. The
water solubility or dispersibility of many inhibitors, such as the quats (quaternary amines), are affected by the TDS (total dissolved solids) and/or temperature of the water.
•
Partitioning. If the flowing velocity is low, water will collect in low spots and
tend to remain stagnant. The most severe corrosion is likely to occur here.
Select inhibitors that have a high degree of water solubility or dispersibility and
partition to the water to provide protection in these areas.
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In dry gas lines, the inhibitor solvent can be stripped, resulting in a viscosity
increase and reduced distribution or gunk. Consider these properties also:
•
Pour Point. Is the inhibitor pumpable at the lowest temperature to which it
will be exposed. Unfortunately, a pour point does not tell any thing about
pumpability.
•
Environmental. Is the chemical safe to use? For example, does disposable
water have a concentration limitation?
648 Selecting a Laboratory Test Method
Before selecting a laboratory test method, consider system limitations and parameters that affect the corrosion problem. For example, you would not use a conventional wheel test in a well where temperature exceeds 220°F, contains 20% CO2,
and produces 20 mmcfd. Nor would you use the Hastelloy C, 15,000 psi autoclave
for a 100°F, 10 bpd rod pumped well.
Following are acceptable parameters for laboratory test methods.
Conventional Wheel Test (Temperature less than 180°F)
•
•
•
•
•
Rod Pumped Wells
Low Velocity, low pressure lines
Flowing Oil Wells
Water disposal wells - continuous injection
ESP wells
High Temperature/High Pressure Pipe Autoclave
•
•
•
•
Same as conventional wheel test when the temperature exceeds 180°F
For gas condensate wells
When the effect of acid gas composition on inhibitor performance is desired
To minimize the changes in corrosivity of the test fluid due to acid gas
consumption
LPR - Kettle (less than 180°F and less than 10% hydrocarbon)
•
•
•
•
•
•
Filming rate studies
Test automation, e.g., data recording
Minimize the changes in corrosion caused by consumption of acid gas
Velocity effects that are hard to calculate
Parameter variation effects, e.g., temperature
Protective film formation (Iron Carbonate)
LPR - Flow
•
•
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Same as LPR - Kettle
Pressure effects, depending on materials of construction
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LPR - Rotating
•
•
Same as LPR Kettle
Velocity/shear effects
Autoclave - Stirred, Weight Loss Coupons
•
•
•
•
•
Velocity effects that are hard to calculate
Pressure
Temperature
Inhibitor stability
High acid gas composition
Autoclave - Stirred, LPR
•
•
Same as Autoclave - Stirred, Weight Loss Coupons
Same as LPR - Kettle
As discussed previously, the test methods overlap in their capabilities and have
advantages and disadvantages. The wheel test is simple. The autoclave tests are not.
But the autoclaves allow higher temperatures and pressures than the glassware tests
as well as allowing the use of specific acid gas compositions.
The LPR methods allow automation and constant fluid composition tests as well as
the measurement of instantaneous instead of average corrosion rates. Autoclave and
kettle methods allow velocity effects to be studied, but not in the detail that a
rotating electrode system is capable of.
Some conditions in the field cannot be duplicated in the laboratory. Others may be
overlooked in the design of an evaluation. For these reasons, a laboratory evaluation must be confirmed by a field evaluation.
650 References
August 1999
1.
Betz Handbook of Industrial Water Conditioning, 8th Edition, Betz
Laboratories Inc., 1980.
2.
The Nalco Water Handbook, 2nd Edition, Nalco Chemical Co., Inc., 1988.
3.
C. D. Buscemi, “Polysulfide Corrosion Inhibitor Application Guide,” Materials
Division File 20.10.18.80.15, September 30, 1988.
4.
R. L. Piehl, “MDEA Conversion,” Materials Division File 75.16.31.1,
September 28, 1987.
5.
M. R. Barusch, L. G. Haskell, R. L. Piehl, “Control of Internal Corrosion of
Petroleum Products Pipelines With Oil Soluble Inhibitors,” Corrosion,
pp. 158–166, March, 1959.
6.
P. J. Stone, “Corrosion Inhibitors for Oil and Gas Production,” ASM Metals
Handbook, 9th Edition, Vol 13, 1987, p. 478.
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7.
D. H. Mutti, J. E. Atwood, C. R. LaFayette and A. O. Landrum, “Corrosion
Control of Gas-Lift Well Tubulars by Continuous Inhibitor Injection into the
Gas-Lift Gas Stream,” Paper 5612, presented at the 50th Annual Meeting,
Society of Petroleum Engineers, Dallas, TX, 1975.
8.
G. B. Farquhar, M. J. Michnick, and R. R. Annand, “Tracer Experiments
During Batch Treatment of Gas Wells With Corrosion Inhibitors,” Mater. Prot.
and Perform., Vol 10 (No. 8), Aug. 1971, pp. 41–45.
9.
C. C. Patton, D. A. Deemer, and H. M. Hillard, Jr., “Field Study of Fall RateOilwell Liquid Inhibitor Effectiveness,” Mater. Perform., Vol 9 (No. 2),
Feb. 1970, pp. 37–41.
10. C. O. Bundrant, “High Density Corrosion Inhibitors Simplify Oil Well Treatments,” Mater. Perform., Vol 8 (No. 9) Sept. 1969, pp. 53–55.
11. N. G. Haseltine and C. M. Beeson, “Steam Injection Systems and Their Corrosion Problems,” Mater. Perform., Vol 4 (No. 10), 1965. pp. 57.
12. B. F. Davis, “Wheel Test Method Used for Evaluating of Film Persistent Inhibitors for Oilfield Applications,” NACE Publication 1D182, Item 54238, Mater.
Perform., Vol 21 (No. 12), Dec. 1982, pp. 45–47.
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Chevron Corporation
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Corrosion Prevention and Metallurgy Manual
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August 1999
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