Brine Compatibility with metal
Transcript of Brine Compatibility with metal
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F O R M A T E B R I N E S C O M P A T I B I L I T Y W I T H M E T A L S
Formate BrinesCompatibility with Metals
Authored by Siv Howard,Formate Brines Consultant
Reviewed by Derek Milliams,Advanced Corrosion Management Services
Frank Dean,Ion Science
Commissioned by Cabot Specialty Fluids
This document reports accurate and reliable information to the best of our knowledge.
Neither the author nor the reviewers assume any obligation or liability for the use of the information presented herein.
December 2006
Photo: Courtesy of Sandvik
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Contents
Purpose and Scope 3
Acknowledgements 3
Summary 3
1 Introduction to Formate Brines 42 Introduction to Oilfield Corrosion 4
2.1 Types of Corrosion 4
2.2 Types of CRAs and how they are chosen 5
3 HPHT Field Experience 6
4 What Makes Formates less Corrosive than Other Brines? 7
5 The Carbonate/Bicarbonate pH Buffer in Formate Brines 7
5.1 How the Carbonate/Bicarbonate Buffer Works 7
5.2 Buffer Protection against CO2(H2S) influx 8
6 Corrosion in Formate Brines in the Absence of Corrosive Gases 10
7 Corrosion in Formate Brines Contaminated with CO2 12
7.1 CO2Corrosion 12
7.1.1 CO2Corrosion of C-Steel 13
7.1.2 CO2Corrosion of 13Cr Steel 14
7.1.3 CO2Corrosion of Higher Alloy Steels 16
7.1.4 CO2Corrosion Rates 16
7.2 Impact of CO2on SCC 19
7.2.1 Testing by Hydro Corporate Research Centre 19
7.2.2 Testing by Statoil at Centro Sviluppo Materiali 20
8 Corrosion in Formate Brines Contaminated withH2S 21
8.1 Impact ofH2Son General and Pitting Corrosion 21
8.2 Impact ofH2Son SCC and SSC 21
8.2.1 Sulfide Stress Cracking (SSC) of Carbon and Low Alloy steels 21
8.2.2 Cracking of CRAs in H2SContaining Environments 22
8.2.3 High-Temperature Testing by CAPCIS 22
8.2.4 High-Temperature Testing by Statoil at Centro Sviluppo Materiali 24 8.2.5 Low-Temperature Testing by CAPCIS 24
8.3 Use ofH2SScavengers in Formate Brines 25
9 Corrosion in Formate Brines Contaminated with O2 26
9.1 Impact of O2on SCC 26
9.1.1 Testing by Hydro Research 26
9.1.2 Testing by CAPCIS 27
9.1.3 Testing by Statoil at Centro Sviluppo Materiali 28
9.2 Use ofO2Scavengers in Formate Brines 28
10 Catalytic Decomposition of Formates a Laboratory Phenomenon 29
11 Hydrogen Embrittlement of Metallic Materials in Formate Brines 30
11.1 Hydrogen Embrittlement 30
11.2 Sources of Hydrogen 30
11.2.1 Hydrogen Charging from Galvanic Coupling 30
11.2.2 Hydrogen Charging from Formate Decomposition 30
11.3 Field Evidence Totals Elgin Wells G1 and G3 31
12 Avoid Pitfalls in the Laboratory! 32
13 Avoid Pitfalls in the Field! 33
13.1 Four Simple Rules for Avoiding Corrosion in Formate Brines 33
13.2 Examples of Incorrect Use 33
References 35
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Purpose and Scope
Cabot Specialty Fluids (CSF) is in the process of writing a
formate technical manual. This manual will cover formate
brines and their application in well construction operations:
chemical and physical properties, compatibilities and
interactions, applications, and Health, Safety and
Environmental aspects. While preparing the manual, CSF
has received numerous enquiries for information about the
corrosion characteristics of formates. In response, CSF
decided to commission a seperate review on metal
compatibility of formate brines. The outcome of this review is
reported in this document. The report includes some basic
corrosion theory, a review of laboratory test results with
formate brines, best practice procedures for testing formates,
advice on the proper field use of formates, and some
examples of improper use of formates in the field.
Acknowledgements
Some of the experimental work described in this document
was undertaken for CSF by Hydro Research and CAPCIS
Ltd. Other sources of information have been SPE and NACE
papers, and personal communication from corrosion
researchers and consultants.
In addition to the two reviewers Frank Dean, Ion Science, and
Derek Milliams, Advanced Corrosion Management Services,
I want to thank the following people for their valuable
contributions and advice: Peter Rhodes (Consultant), Salah
Mahmoud of MTL Engineering, John Herce of MTL Engineering,
Neal Magri of Technip Offshore, Inc., and Mike Billingham of
CAPCIS.
In addition, I want to thank Cabot Specialty Fluids for
supporting the preparation of this review, and especially John
Downs for his valuable technical contributions and editing.
Summary
The corrosivity of formate brines used in drilling, completion,
workover, and packer fluids for HPHT wells has been
thoroughly investigated over the past few years. One of the
drivers for this activity has been a spate of costly well
integrity failures that have been reported after operators have
used the traditional high-density halide completion brines.
Laboratory and field experience has shown that buffered
formate brines are considerably less corrosive than other
brines at high temperatures, even after exposure to large
influxes of acid gas.
Over the past 10 years, formate brines have been used in
more than 130 HPHT well construction operations where
they have been exposed to temperatures of up to 216C /
420F and pressures of up to 117.2 MPa / 17,000 psi.
There is no record of any corrosion incidents being caused
by buffered and correctly formulated formate brines under
these demanding conditions.
The low corrosivity of the formate brines is attributed to the
benign properties of the brine itself. Formate brines have a
naturally alkaline pH and can be buffered with carbonate/
bicarbonate buffers to maintain a favorable pH even after
large influxes of acid gas. As a matter of fact, it has been
shown that the pH in buffered formate brine never drops
below about 66.5 when contacted by acid reservoir gases.
Formate brines contain very low levels of halide ions, and are
thereby free of the corrosion problems commonly associated
with halides such as pitting and stress corrosion cracking.
Even with a significant level of chloride contamination, formate
brines have been shown to outperform uncontaminated
bromide brines. And last but not least, the formate ion is an
anti-oxidant, which limits the need for adding oxygen
scavengers, and avoids the problems that can occur when
these scavengers become depleted.
With the growing awareness of the shortcomings of the
halide brines, it is expected that formate brines will have an
increasingly important role in future HPHT well construction
operations.
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1 Introduction toFormate Brines
High-density formate brines have been available to the
industry for use in drilling, completion, workover, and packer
fluids since the mid 1990s. This family of non-corrosive,
high-density, monovalent brines offers clear advantages over
the traditional halide family of brines in that their use is not
just limited to completion and packer fluids, but includes
solids-free drilling fluids, which offer exceptionally good flow
characteristics over the whole density range.
The primary uses for formate brines over the past 10 years
have been in demanding applications where conventional
drilling and completion fluids have not been able to meet the
required performance specifications. The applications where
formate brines have been used include:
HPHT completions and workovers to provide
compatibility with completion materials and reservoir
HPHT drilling to avoid well control problems anddifferential sticking
Reservoir drilling and completion to improve production
Narrow bore and extended reach drilling to improve
circulation hydraulics
Shale drilling to minimize environmental impact
Cesium formate, the highest density brine in the formate
family, has proven to be an excellent replacement for the
traditional high-density zinc bromide brine, and is now the
high-density completion fluid of first choice in the North Sea.
To date, cesium formate has been used in more than 130
HPHT well operations, at temperatures as high as 216C /
420F, at pressures up to 117 MPa / 17,000 psi and in the
presence of corrosive gases such asCO2, H2S, and O2.
Indeed, field experience has shown that formate brines have
given operators the ability to drill and complete challenging
HPHT wells with a degree of success, economy, and security
that would have been difficult to achieve using conventional
fluids.
Field experience has also shown that buffered, uninhibited
formate brines exhibit low corrosivity towards all types of
steel tubulars used in well construction and production
operations, even when contaminated with corrosive gases
and chlorides. This compatibility with carbon and low alloy and
stainless steel goods has been an important consideration forthe oil companies who have chosen formate brines for use in
their HPHT well constructions.
2 Introduction toOilfield Corrosion
2.1 Types of Corrosion
The aqueous corrosion of metals involves two electro-chemical
reaction zones in close proximity: a cathodic reaction zone, in
which electrons are taken from the metal to reduce a reactant
(e.g. protons, water, or oxygen) in an electrolyte(often a
solution of salts) which is in contact with the metal, and an
anodicreaction zone, in which the metal is oxidized
(corroded), liberating electrons into the metal. Electrons move
through the metal from the anodic to cathodic zone
balancing the electro-chemical reactions. The effects of
corrosion most commonly encountered in the sub-surface
oilfield environment fall broadly into the following categories:
General corrosion:General corrosion is a relatively slow
process where the metal loss is relatively uniform over the
exposed surfaces and typically occurs over long time scales.
Carbon steel and low alloy steels are particularly susceptible
to general corrosion in acid environments.
Pitting corrosion:Pits are typically millimeter-sized zones of
anodic corrosion commonly associated with high chloride
concentrations in solution. Pitting commences with the
localized breakdown of a passivating scale on a metal. This
exposes small areas of oxidizable metal. Chloride preferentially
migrates to these local anodic zones, and assists in removal
of anodically oxidized metal, to form pits. The metal surface
outside the pits is cathodic and supports the reduction of, for
example, dissolved oxygen from the electrolyte. Pitting
corrosion is characterized by a high cathodic to anodic area
ratio. Metal dissolution is confined to pits that deepen much
faster than the rate of average wall loss associated with
general corrosion.
Stress Corrosion Cracking (SCC) is a destructive and fast-
acting effect of corrosion that can cause catastrophic failure
of Corrosion Resistant Alloy (CRA) oilfield tubulars and
equipment, sometimes within a matter of days. SCC cracks
develop from local defects in the surface oxide film, often
from sites of active pitting corrosion. For SCC to occur, tensile
stresses in the material are required in addition to the presence
of a corrosive environment and a susceptible material (Figure 1).
Increasing stress, temperature, and concentration of, for
example, halide ions, together with corrosive oilfield gases,
increase the risk of metal failure from SCC.
Figure 1Factors required for stress corrosion cracking (SCC).
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Hydrogen damage is a term used to refer to a variety of
deleterious phenomena for example SSC, SOHIC, HIC, and
hydrogen embrittlement which affect metals when they
contain atomic (diffusible) hydrogen. The causes are broadly
two-fold. Either the hydrogen is dissolved into the metal at
high temperature (the higher the temperature, the less specific
the source of hydrogen has to be) then the metal is rapidly
cooled to a low temperature leading to hydrogen over-
saturation, or the hydrogen enters the steel directly at a low
temperature (less than about 100C / 212F) due to corrosion
involving hydrogen promoters, the most important oilfield
hydrogen promoter being hydrogen sulfide.
Sulfide Stress Cracking (SSC) occurs during corrosion of steel
under tensile stress in the presence of water and hydrogen
sulfide. It is generally accepted that SSC is in part caused by the
promotion of hydrogen entry into the steel by hydrogen sulfide.
This causes steel embrittlement which, under tensile stress,
causes the steel to crack. High strength carbon and low alloy
steels and hard weld zones are particularly prone to SSC.
Hydrogen Induced Cracking (HIC) occurs in carbon and
low alloy steels, when atomic hydrogen diffuses into the steel
and then combines to form molecular hydrogen, particularly
in the vicinity of steel inclusions, such as manganese sulfide.
The build up of hydrogen pressure at inclusions leads to the
formation of planar cracks. The linking of these cracks, internally
or to the surface of the steel, results in Step Wise Cracking
(SWC) that can destroy the integrity of the component. Near
the surface of the steel the cracks can lead to the formation of
blisters. HIC damage is more common in components made
from rolled plate than in those made from seamless material.
HIC generally occurs at temperatures below 100C / 212F
and in the presence of certain corrodants called hydrogen
promoters, such as hydrogen sulfide. No externally applied
stress is needed for the formation of HIC.
Stress oriented hydrogen induced cracks (SOHIC) is
related to SSC and HIC/SWC. In SOHIC, staggered small
cracks are formed approximately perpendicular to the
principal stress (residual or applied) resulting in a ladder-like
crack array linking (sometimes small) pre-existing HIC cracks.
The mode of cracking can be categorized as SSC caused by
a combination of external stress and the local straining
around hydrogen induced cracks.
Hydrogen Embrittlement (HE) of metals, particularly of high
alloy steels, is the physical result of high levels of hydrogen
uptake into the metal. Hydrogen is much more soluble
and diffusible in metals at high temperatures than at low
temperatures (defined as below 100C / 212F). Embrittlement,
therefore, normally occurs as a consequence of corrosion at
high temperature, followed by sufficiently rapid cooling of the
metal to entrap the hydrogen at low temperature. It may also
result from intense hydrogen entry due to corrosion at low
temperature in the presence of a hydrogen promoter.
2.2 Types of CRAs and how they are chosen
Well engineers select the metallurgy of their sub-surface tubulars
according to the composition of the produced fluids/gases and
the downhole temperature profile. If there is any risk of CO2
production during the lifetime of the well they will tend to select
Corrosion Resistant Alloy (CRA) steels that contain chromium,
nickel, and sometimes molybdenum. High downhole tempera-
tures and the presence of H2Sand Cl-necessitate the selection
of more expensive CRAs with high alloy metal content. Given
the high cost of the types of CRA tubulars being used in HPHT
wells and the cost of a well intervention and loss of productionif the material should fail, it is important to maximize their life
expectancy. The cost of a rig for an offshore HPHT well
intervention can run into several million dollars and the waiting
time for both the rig and new CRA material might be up to a
year. It is therefore particularly important that the integrity and
life expectancy of the tubulars is not compromised by adverse
interactions with completion, workover, and packer fluids.
Table 1 lists some CRAs commonly used in tubulars. The
recommended temperature ranges for the various CRAs vary
between the OTG producers, and no universally accepted
limits exist. The temperature limits shown in Table 1 are taken
from the Sumitomo selection guide [1] and apply when CO2is
present. The recommended applicability limits of the alloys in
Table 1 are also dependent upon chloride concentration and,
when present, upon the levels of H2S.
There are also quite a few austenitic alloysthat, because of their
corrosion resistance properties, are commonly used in well
applications. These alloys are characterized by their high content
of chromium and nickel. They are mainly used as material for
packers, safety valves, hangers, etc. In some cases they can be
sensitive to hydrogen embrittlement and other forms of attack
often associated with H2S. The industry standard for sour service
materials [2] provides more information on the sensitivity of
austenitic and other corrosion resistant alloys to this common
contaminant of oil and gas production environments.
Table 1 Martensitic and Duplex steels commonly used in oilfield tubulars. The application limits apply in the presence of CO2and are
further restricted by the level of CO2, H2S, and Cl-[1].
Group Name Cr % Ni % Mo %General application limit
[C] [F]
Martensitic
13Cr 13 -- --
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3 HPHT Field Experience
Over the last 10 years formate brines have been used in more
than 130 HPHT applications at downhole temperatures as high
as 216C / 420F and at pressures up to 117 MPa / 17,000 psi.
Since their first use in HPHT wells, there have been no
corrosion incidents caused by formate brines when used
according to the guidelines described in this document.
Table 2 HPHT field experience with formate brines provided by CSF over the past seven years.
BP Rhum3/29a
ShellShearwater
MarathonBraemar
BPDevenick
TotalElgin/
Franklin
StatoilHuldra
No. of wells 3 6 1 1 10 6
HydrocarbonGas
condensateGas
condensateGas
condensateGas
condensateGas
condensateGas
condensate
Max. tempC 149 182 135 146 204 149
F 300 360 275 295 400 300
Completion material CRA S13Cr 25Cr 13Cr 13Cr 25Cr S13Cr
Liner material CRA S13Cr 25Cr 22Cr VM110 P110 S13Cr
Packer material CRA 718 718 718 718 718 718
Brine density g/cm3 2.00 2.20 2.05 2.20 1.80 1.85 1.60 1.65 2.10 2.20 1.85 1.95
Reservoir pressureMPa 84.8 105.6 74.4 72.4 115.3 67.5
psi 12,300 15,320 10,800 10,500 16,720 9,790
CO2 % 5 3 6.5 3.5 4 4
H2S ppm 5 10 20 2.5 5 20 50 10 14
Exposure time days 250 65 7 90 1.6 yrs 45
ApplicationPerforationCompletionWorkover
Well killCT
WorkoverPerforation
WorkoverPerforation
DrillCompletion
WorkoverCompletion
CTWell kill
Perforation
DrillingCompletion
Screens
StatoilKvitebjrn
StatoilKristin
BP
High IslandA-5
DevonWest
Cameron165 A-7, A-8
DevonWest
Cameron575 A-3
Walter O&G
Mobile Bay862
No. of wells 7 to date 7 to date 1 1 1 1
HydrocarbonGas
condensateGas
condensateGas
Gascondensate
Gas Gas
Max. tempC 155 171 163 149 135 216
F 311 340 325 300 275 420
Completion material CRA S13Cr S13Cr S13Cr 13Cr 13Cr G-3
Liner material CRA 13Cr S13Cr S13Cr 13Cr 13Cr G-3
Packer Material 718 718 718 718 718 718 G-3
Brine density g/cm3 2.00 2.06 2.09 2.13 2.11 1.03 1.142.11
1.49 packer
Reservoir pressureMPa 81 90 99 80 74 129
psi 11,700 13,000 14,359 11,650 10,731 18,767CO2 % 2 3 3.5 5 3 3 10
H2S ppm Max 10 12 17 12 5 5 100
Exposure time days 57 574
3 yrs packer2 and 1.3 yrs 1.4 yrs
201.5 yrs packer
Application
DrillingCompletion
ScreensLiners
DrillingCompletion
Screens
Well killCompletion
PackerPacker Packer
Well killCompletion
Packer
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4 What Makes Formates lessCorrosive than Other Brines?
There are several features of formate brines that make them
inherently less corrosive than other brines used by the oil
industry.
Halide-fee
Conventional halide brines (NaCl, KCl, NaBr, CaCl2, CaBr2,
ZnBr2, and their blends), and particularly chlorides, are known
to promote several forms of corrosion. Localized corrosion,
such as pitting and SCC are promoted in halide environments,
and the severity increases with increased halide concentration.
Even after contamination with moderate levels of chloride
ions (Cl-), formate brines still retain their non-corrosive
characteristics in most applications.
Antioxidant
Oxidants, such as O2are known to cause corrosion
problems. The formate ion is a well-known antioxidant or free
radical scavenger, used in many industrial and medicalapplications.
Favorable alkaline pH
Formate salts dissolved in water exhibit a naturally favorable
pH (8-10).
In non-oxygenated solutions, corrosivity is determined in part
by pH. The lower the pH, the greater the tendency for
corrosion. In addition, pH determines the stability/solubility of
corrosion scales.
Traditional high-density halide brines typically have pH values
of between 2 and 6 (depending on the type of halide) and are
therefore naturally more corrosive than formate brines.
Compatibility with Carbonate-based pH buffer
The only truly reliable protection against corrosion from acid
gas (CO2and H2S) is to pre-treat the receiving brine with a
carbonate/bicarbonate buffer. The buffer not only helps to
maintain the brine pH in the safe alkaline zone but also
promotes metal passivation.
Traditional high density completion and packer fluids based
on divalent halide brines (CaCl2, CaBr2, ZnBr2) cannot be
buffered because even small amounts of added carbonate/
bicarbonate buffer are precipitated out. Carbonate/bicarbonate
buffers are soluble in formate brines, and can be formulatedto make fluids that remain pH stable in the face of quite large
influxes of CO2.
In order to fully understand how the buffer in the formate
brine enhances the corrosion protection provided by the
formate brine itself, one first needs to understand how this
buffer works and how it reacts to influxes of common acid
gases such as CO2and H2S.
5 The Carbonate/BicarbonatepH Buffer in Formate Brines
Formate brines provided for field applications should be
buffered by the addition of potassium or sodium carbonate
and potassium or sodium bicarbonate. Typical recommended
levels are 6 to 12 lb/bbl of potassium carbonate or a blend of
potassium carbonate and potassium bicarbonate. The main
purpose of this buffer is to provide an alkaline pH and to
prevent the pH from fluctuating as a consequence of acid or
base influxes into the brine. The buffer also plays a very
important part in encouraging the formation of the high quality
protective carbonate film on the steel surfaces.
5.1 How the Carbonate/Bicarbonate Buffer Works
A pH buffered solution is defined as a solution that resists a
change in its pH when hydrogen ions (H+) or hydroxide ions
(OH-) are added. The ability to resist changes in pH comes
about by the buffers ability to consume hydrogen ions (H+)
and/or hydroxide ions (OH-).
The carbonate/bicarbonate buffer system provides strong
buffering at two different pH levels:
Higher buffer level at pH = 10.2
(1)
where = 10.2
At pH = 10.2 ( ) the buffered solution contains the same
amount of carbonate ( ) and bicarbonate ( ).
Lower buffer level at pH = 6.35
(2)
where
= 6.35
At pH = 6.35 ( ) the buffered solution contains the
same amount of bicarbonate ( ) and carbonic
acid ( ).
The exact levels of and
will vary somewhat with
brine concentration, temperature, and pressure.
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Figure 2 demonstrates how the carbonate buffer works when
a strong acid is added. The carbonate will react with added
acid until all the carbonate is consumed. As long as there is
still carbonate left in the solution, the pH will remain high,
around the higher buffer level = 10.21. As soon as the
carbonate is consumed, the pH will drop down to the lower
buffer level where it will remain as long as bicarbonate is
available to react with the added acid and be converted to
carbonic acid. In order for the pH to drop down below this
second buffer level, an acid would need to be added that is
stronger than the carbonic acid that is formed. As any CO2
gas influx into the buffered solution will dissolve and be
converted to carbonic acid, a CO2influx is therefore not
capable of pulling the pH much below this second buffer
level.
5.2 Buffer Protection against CO2(H2S) influx
The major cause of acidification of conventional completion
brines is influx of carbon dioxide gas (CO2) into the wellbore:
(3)
(4)
(5)
Depending on the pH in the brine system, the dissolved CO2
will remain in the brine as either carbonic acid (H2CO3) or
bicarbonate (HCO3-) according to the equation 5. This is
demonstrated in Figure 3. As more CO2gas enters into the
brine, the carbonic acid concentration builds up and the pH
drops and allows unbuffered brines to acidify.
The three different brine systems in Figure 3 will react in the
following way to a CO2influx:
Conventional divalent halide brinescannot be buffered
with carbonate/bicarbonate because the corresponding
metal carbonate (CaCO3, ZnCO3) will precipitate out of
solution resulting in the formation of solids in the clear
packer/completion fluid. These divalent brines have a
naturally low pH (26) and the influx of CO2will, dependent
on the partial pressure of CO2, further lower the pH. The
CO2will largely be converted to carbonic acid, which is
very corrosive.
Buffered formate brinesare capable of buffering large
amounts of CO2. Unless the influx is unusually large, the
brine will maintain a pH (at around the upper buffer level)
which is high enough to prevent carbonic acid being
present in the fluid. With a large influx of CO2, the pH will
drop down to the lower buffer level (pH = 6.35) where it will
stabilize. Measurements of pH in formate brines exposed
to various amounts of CO2have confirmed that the pH
never drops below 66.5. This pH is still close to neutral,
meaning that this brine system cannot be acidified toany great extent by exposure to CO2.
Unbuffered formate brines: The pH of these brine
systems behaves very much like halide brines when
exposed to CO2gas. However, they do have a higher initial
pH, and the pH drop will be limited as the formate brine is
a buffer in itself (pKa= 3.75). If there is any chance of an
acid gas influx, the use of unbuffered formate brines is not
recommended.
Figure 2The pH of water buffered with carbonate as a function of added strong acid (H+). The x-axis shows the fraction of the bufferthat is consumed by the added acid. As can be seen, carbonate will buffer twice, first at pH pKa2= 10.2 (upper buffer level) and then at
pH = pKa1= 6.35 (lower buffer level). If the added acid is carbonic acid (from CO2influx), the pH can never drop much below pKa1.
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Influx of CO2into a wellbore is often accompanied by
hydrogen sulfide (H2S). H2Sis a very weak acid with a pKa1at
around 7. H2Scorrosion is generally suppressed in alkaline
scenarios by the formation of non-soluble sulfide films.
Therefore sustained corrosion by hydrogen sulfide in the
presence of buffered formate brines is unlikely to occur.
In order to get the full benefit of the carbonate/bicarbonate
buffer in the formate brine, both the buffer level and buffer
capacity need to be maintained during field use. Over-
treatment with potassium carbonate is most often not a
problem.
Figure 3 pH as function of CO2influx in a typical halide brine, an unbuffered formate brine, and a buffered formate brine.
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Table 3General corrosion rates of C-steel in formate brines.
FluidDensity pH
(diluted1:10)
Temp. days P-110 C-110 Q-125
s.g. ppg C F mm/y MPY mm/y MPY mm/y MPY
NaFo 1.26 10.5 10.0 163 325 7 0.008 0.3
CsFo 12.0 163 325 7 0.000 0.0
CsFo + 5%KCl 2.18 18.2 10.5 177 350 40 0.076 3.0 0.065 1.0 0.051 2.0
CsFo 12.0 177 350 7 0.003 0.1CsFo 10.0 191 375 ? 0.005 0.2
CsFo 10.0 204 400 17 0.008 0.3
CsFo 1.94 16.2 218 425 30 0.177 7.0
Table 4General corrosion rates of CRAs in formate brines.
FluidDensity pH
(diluted1:10)
Temp. days 13CrModified
13Cr22Cr 25Cr
s.g. ppg C F mm/y MPY mm/y MPY mm/y MPY mm/y MPY
KFo 1.26 10.5 9.8 66 150 30 0 0 0 0
KFo1.57 13.1 9.8 66 150 30 0 0 0 0
NaFo 1.26 10.5 10.0 163 325 7 0 0.0 0 0.0
CsKFo
+ 3 g/L Cl-1.95 16.2 10.4 165 329 30 0.01 0.39
KFo 1.26 10.5 9.8 185 365 30 0 0 0 0
KFo 1.57 13.1 9.8 185 365 30 0.043 1.7 0 0
CsFo 10.0 191 375 ? 0 0.0 0.03 1
CsFo 10.0 204 400 17 0.003 0.1 0.03 1
CsFo 204 400 7 0.076 3
CsFo 1.94 16.2 218 425 30 9.25 364 0.41 16
Shaded area = outside the operating envelope of the specific CRA
6 Corrosion in Formate Brines inthe Absence of Corrosive Gases
In the absence of corrosive gasses and within the operating
envelope of the specific metal (as defined in Table 1 and its
associated text), formate brines are essentially non-corrosive to
all forms of steels used in oil and gas well construction, even
when contaminated with chloride ions. Table 3 and Table 4 list
general corrosion rates for a variety of formate brines at
temperatures up to 218C / 425F, collected from various
published and unpublished sources [3].
The general corrosion rates of C-steel and CRAs in formate
brines are negligible regardless of the temperature. Localized
corrosion and SCC have never been observed. The use of
corrosion inhibitors in formate brines is neither necessary nor
recommended.
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Corrosion comparison:
Cesium formate brine versus zinc bromide brine
Traditional high-density halide brines are known to cause or
facilitate pitting corrosion due to their low pH and high
content of halide ions (Cl-, Br-). A comparative corrosion test
[4] has been carried out at 204C / 400F with C-steel
exposed to a high density cesium formate brine and in a
blend of zinc bromide and calcium bromide brines, both with
a density of 2.18 s.g. / 18.2 ppg. The mixed bromide brine
was tested with and without a corrosion inhibitor. The testing
was carried out in 100 mL C-steel pressure vessels. The
corrosion of the walls of the vessels was determined by
measuring the weight loss of the vessels after 12 days of
exposure to the brines. The results are shown in Table 5. The
CaBr2/ZnBr2brine promoted severe localized corrosion at the
interface between the liquid and vapor. The presence of a
corrosion inhibitor marginally reduced the general corrosion
rate but seemed to amplify the localized corrosion. The
weight loss of C-steel in the bromide brine was found to be
about 100 times higher than in the uninhibited formate brine
and the depth of the localized metal corrosion in the bromidewas about 1,000 times higher than in formate. No significant
localized corrosion or pitting corrosion and only negligible
general corrosion was experienced in the formate brine.
Pressure build-up in the headspace of the test vessels was
monitored in these tests, and the bromide brine was shown
to create higher pressures at 204C / 400F than the formate
brine. The pressure build-up with the bromide brine, resulting
from the evolution of hydrogen gas, is thought to have been
caused by the corrosion reactions.
Table 5General and localized corrosion on C-steel (P-110)
exposed to inhibited and uninhibited calcium/zinc bromide and
cesium formate brines at 204C / 400F.
Test Fluid
Generalcorrosion
rate
Rate ofmaximum
penetration
mm/y MPY mm/y MPY
Uninhibited CaBr2/ZnBr2 0.84 33 7.72 304
Inhibited CaBr2/ZnBr2 0.66 26 13.1 517
Csformate 0.008 0.3
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formic acid, a stronger acid (one with a lower pKa) would
need to be introduced. An example of this would be
hydrochloric acid (HCl). The presence of a very small amount
of formic acid has actually proven to be a benefit in promoting
the formation of iron carbonate films that protect steel
surfaces against CO2 corrosion [7].
It is important to keep in mind that the main purpose of the
buffer provided in formate brines is to maintain a high pH so
that CO2corrosion is prevented. In a realistic field situation the
likelihood that a buffered formate brine would ever receive a
CO2gas influx large enough to overwhelm the buffer is low.
(Figure 3). Traditional high-density halide-based brines do not
have this advantage, and CO2corrosion will commence after
even a minor influx of CO2.
Even if a CO2influx is sufficient enough to overwhelm the
carbonate component of the powerful pH buffer,a protective
iron carbonate layer will form much faster and much more
efficientlyin a buffered formate than in other high density
completion brines. Here is why:
Both carbonic acid and formic acid are known to be corrosive
to C-steel and lower alloyed steels and to some CRAs, such
as 13Cr, at elevated temperatures. The corrosion takes place
according to the following mechanisms, respectively:
(12)
and to a lesser extent;
(13)
Ferrous iron liberated by these reactions builds up in solution
and eventually reaches a level at which the solubility of iron
carbonate is exceeded locally on the corroding surface.
Further corrosion will then cause the build-up of an iron
carbonate layer on the steel surface:
(14)
Alternatively or additionally to the formation of this iron
carbonate layer a magnetite (Fe3O4) layer can be formed.
Both the iron carbonate and the magnetite films are known to
be extremely efficient in inhibiting further corrosion.
Factors that will influence the quality of the film are [7]:
Volume to surface ratio. The ratio between the solution
volume and the area of steel exposed to the fluid. This is
not a variable in an annular well environment, and it is
therefore important to accurately reproduce this in a
laboratory test environment. 24 mL/cm2is an acceptable
range. Using higher ratios will generate misleading
corrosion predictions. As an example, increasing this ratio
by a factor of 10 (typical ratio used for corrosion testing =
20 mL/cm2), has been shown to double the measured
corrosion rate of 13Cr steel at 120C.
Amount of carbonate in the uid.The build-up of iron
carbonate depends on the solubility product of iron
carbonate. This means that as more carbonate ions are
present in the fluid, the less dissolved iron (corrosion
product) is needed to saturate the fluid close to the metal
surface and start film formation.
Rate of initial corrosion.A high rate of corrosion
immediately before the iron carbonate layer forms is
known to increase the quality of the layer.
Buffered formate brines that are exposed to a large amount
of CO2form a higher quality protective layer than other
acidified completion brines because they provide both a
higher amount of carbonate (see bullet point 2 above effect
of buffer) and a higher rate of initial corrosion (see bullet point
3 above the additional small amounts of formic acid seem
not only to slightly increase the initial high corrosion rate but
also to significantly further promote the formation of the iron
carbonate layer).
7.1.1 CO2Corrosion of C-SteelIf the carbonate component of the buffer in a formate brine is
overwhelmed by CO2influx, the pH will start decreasing and
CO2corrosion will take place according to Equations 12 and 13.
An initial period of high general corrosion will be experienced
prior to the build-up of the protective iron carbonate layer.
For C-steel this initial phase of high rates of general corrosion
is readily measured by short-term weight loss tests. There are
cases in the oilfield literature where exaggerated and
misleading CO2corrosion rates have been reported with
formates as a consequence of measuring the short-term
weight loss and then extrapolating this rate linearly over time
to create annual corrosion figures. It has therefore been
advised [6][7] not to use standard short-term weight loss
methods to predict long-term CO2corrosion rates for C-steel
in formate brines.
Compared with halide brines, formate brines have been
shown to be much less aggressive to C-steel, even in tests
where high CO2additions have decreased the pH to the
lower buffer level [8]. Figure 4 shows photos of 1.5 mm thick
C-steel coupons that have been exposed to 1.53 s.g. / 12.8
ppg calcium bromide and potassium formate brines acidified
with CO2at temperatures varying between 120C / 248F and
180C / 356F [7]. The coupon to the left shows severe
localized corrosion attacks on the coupon that was exposed
to the bromide brine, and the coupon to the right shows that
only general corrosion has taken place in the potassiumformate brine. A SEM photo of an iron carbonate layer
formed on C-steel in a formate brine is shown in Figure 5.
The film is very dense, of thickness 5 to 20 m. By comparison,
the surface layer that was formed in the calcium bromide
brine was found to be of a duplex structure with a thickness
of 100 to 200 m. Table 6 shows weight loss data and actual
local corrosion rates for the same coupons. Adding a
commonly used corrosion inhibitor to the bromide brine did
not improve the performance or stop the localized corrosion.
No additional chloride was added to the brines used in these
tests.
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Table 6 Average corrosion rate and rate of the deepest attack
for C-steel in 1.53 s.g. / 12.8 ppg bromide brine and buffered
KFo brine exposed to a large CO2influx. The experiments were
commenced at 120C / 248F, with an excursion to and from
180C / 356F [7].
Fluid
Corrosion rate
Average rate Deepest attack
mm/y MPY mm/y MPY
CaBr2 0.39 15.4 >8.71) >3421)
CaBr2inhibited
0.34 13.4 >8.71) >3421)
KFo 0.30 11.8 --- ---
1) Perforated, i.e. attack > coupon thickness = 1.5 mm
Real-time corrosion rates for C-steel in various formate and
bromide brines exposed to a large amount of CO2are shown
in the plot in Figure 6. This plot is based on Linear Polarization
Resistance (LPR) measurements that have been calibrated
against weight loss. As can be seen, a protective layer wasformed on the metal surfaces exposed to the formate brines
within the first 2030 hours of exposure to CO2. The scatter in
the bromide data during the initial period with high corrosion
rates indicates that localized corrosion was taking place.
7.1.2 CO2Corrosion of 13Cr Steel
13Cr steel has been shown to behave in a similar manner to
C-steel when exposed to formate brines that have received a
large influx of CO2. A protective layer is formed during a short
initial period of high general corrosion activity.
As with C-steel, formate brines in which the pH has been
substantially decreased to the lower buffer level by a large
influx of CO2appear to be much less aggressive towards
13Cr than acidified halide brines. Figure 7 (see left-hand
photo) shows severe localized corrosion of a 13Cr steel
coupon exposed to calcium bromide brine acidified with CO2
at temperatures varying from 120C / 248F to 180C / 356F.
A 13Cr coupon exposed to formate brine under the same
test conditions shows only general corrosion (see right-hand
photo in same figure). Weight loss corrosion rates for the
same coupons are shown in Table 7 along with the maximum
depths of pits caused by localized corrosion.
A SEM photo of the film formed in the formate brine is shown
in Figure 8. This film is thicker (100 m) than the one seen on
C-steel, and the film quality and ability to inhibit corrosion are
not quite as good.
Figure 4 C-steel test specimens after exposure to inhibited
calcium bromide and potassium formate (both 1.53 s.g. / 12.8
ppg) with a large CO2influx at 120C / 248F, with an excursion
to and from 180C / 356F [7]. Severe localized corrosion
attacks are seen in the calcium bromide brine. The potassium
formate brine only caused general corrosion. (The CO2influxwas large enough to overwhelm the upper buffer level and drop
the pH to the lower buffer level in the formate brines.)
Figure 5 SEM photo of iron carbonate protective layer formed
on C-steel in a potassium/cesium formate brine where pH was
pulled down to the lower buffer level by a large influx of CO2.
The thickness of the layer is about 5-20 m.
CaBr2 K formate
Corrosion
film
C-steel
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Figure 6 LPR plot showing initial corrosion of C-steel in potassium formate potassium/cesium formate and calcium bromide brines at
various temperatures. All brines were exposed to a large CO2influx. The time scale starts from the time of acidification with CO2. An initial
short period of high corrosion rates can be seen in the formate brines before the protective iron carbonate layers are formed. No distinct
peak can be seen in the bromide brines. The corrosion inhibitor in the bromide brine appears to have no impact on the CO2corrosion.
Figure 7 13Cr test specimens after exposure to inhibited
bromide (1.53 s.g. / 12.8 ppg) and potassium formate (1.53 s.g. /12.8 ppg) with a large influx of CO2where pH had been pulled
down to the lower buffer level. Severe localized corrosion
attacks are seen in the calcium bromide brine. The potassium
formate brine only caused general corrosion.
Figure 8 SEM photo of iron carbonate protective layer formed
on 13Cr in potassium/cesium formate brine where pH waspulled down to the lower buffer level by a large influx of CO2.
The thickness is about 50100 m.
CaBr2 K formate
Corrosion
film
13Cr
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7.1.3 CO2Corrosion of Higher Alloy Steels
A protective layer also forms on the surfaces of higher alloy
steels in the formate brines where the higher buffer level has
been overwhelmed by a massive influx of CO2(Figure 9 for22Cr). The layers formed on these metals are of the thicker
variety (about 50100m). In spite of the slightly lower quality
of these films, the corrosion rates are very low due to the
resistance of these metals to both carbonic acid and formic
acid. No signs of pitting corrosion have been observed in any
of these materials exposed to buffered formate brines even
with a large amount of CO2influx.
Figure 9 SEM photo of iron carbonate protective layer formed
on 22Cr in a potassium/cesium formate brine where pH was
pulled down to the lower buffer level by a large influx of CO2.
The thickness of the layer is about 50100 m.
7.1.4 CO2Corrosion Rates
General corrosion rates in formate brines as a function of
temperature and level of CO2influx are shown in Figure 10 to
Figure 14 for C-steel, 13Cr, modified13Cr (1Mo and 2Mo),22Cr, and 25Cr respectively. The data are taken from various
sources [6][7][8][9][10][11]. The data points represent
measurements done with and without H2Sin the headspace
and with and without chloride contamination in the formate
brine. Neither H2Snor chloride contamination appear to have
any significant impact on the CO2corrosion rates. For C-steel
and 13Cr steel, only the corrosion rates that were determined
by LPR or long term (30 days) weight loss tests have been
included. These are the true corrosion rates at which the
system will stabilize over time, and are not heavily inuenced
by the short-duration high corrosion rates that are measured
before the protective layer is formed. Rates that are known to
have been measured with unrealistic volume-to-surface
ratios are also excluded.
For Alloy 718 (not plotted), the measured corrosion rates are
negligible, in the order of 0.035 mm/y / 1.4 MPY after
overwhelming the buffer with CO2.
When using measured CO2corrosion rates for formate
brines, which have been measured after the buffer has been
overwhelmed; one would need to consider the timing aspect
of these rates.
Buffered FORMATE BRINES do not allow corrosion of downhole components unless and until the carbonate buffering
effects are overcome. This will normally take an extended period, or it might never happen during the life of
the well. When, due to CO2influx, the pH does drop to a point where corrosion can occur the formation of a
protective iron carbonate layer is promoted, particularly on carbon steels, and pitting of CRAs is not seen.
Influx of CO2into HALIDE BRINES causes an immediate (further) drop in pH and increased corrosion occurs. The
formation of a protective iron carbonate layer on carbon steels is hindered or prevented and the pitting of CRAs
promoted by the presence of halide ions.
Table 7 Average corrosion rate (weight loss) and corrosion rate for the deepest attack for 13Cr-steel in the two 1.53 s.g. / 12.8 ppg
bromide brines, the 1.53 s.g. / 12.8 ppg potassium formate brine, and the 1.70 s.g. / 14.2 ppg potassium/cesium formate brine.
Fluid Temp [C] days
Corrosion rate
Average rate At deepest attack
mm/y MPY mm/y MPY
CaBr2 120 1801) 62 0.061 2.4 2.1 83
CaBr2-inhibited 120 1801) 62 0.055 2.2 2.6 103
KFo 120 1801) 50 0.72 28.3 --- ---
KCsFo 150 34 0.249 9.8 --- ---
KCsFo 175 34 0.119 4.7 --- ---
1) These tests were run at 120C / 248F, with a quick ramp-up to 180C / 356F and down again after 1,000 hours in the bromides and 700 hours in theformates.
Corrosion
film
22Cr
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Figure 10 Measured general corrosion rates for C-steel in buffered formate brines with various levels of CO2influx and in some cases
H2S. Most rates are taken from long term LPR plots. Formate brines contaminated with chloride are also included. (See Figure 3; an
intact buffer is considered to correspond to a pH of about 9.5 and above.) No localized/pitting corrosion has been reported in any of
these tests.
Figure 11 Measured general corrosion rates for 13Cr in buffered formate brines with various levels of CO2influx and in some cases H2S.
Most rates are taken from long term LPR plots. Formate brines contaminated with chloride are also included. (See Figure 3; an intact
buffer is considered to correspond to a pH of about 9.5 and above.) No localized/pitting corrosion has been reported in any of these tests.
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Figure 12 Measured general corrosion rates for modified 13Cr (1Mo and 2Mo) in buffered formate brines with various levels of CO2influx and
in some cases H2S. Most rates are taken from long term LPR plots. Formate brines contaminated with chloride are also included. (See Figure 3;
an intact buffer is considered to correspond to a pH of about 9.5 and above.) No localized/pitting corrosion has been reported in any of these
tests, apart from a couple of tests reported by Statoil and CSM [11] where the brine was contaminated with a very high level of chloride.
Figure 13 Measured general corrosion rates for 22Cr in buffered formate brines with various levels of CO2influx and in some cases H2S.
Most rates are taken from long term LPR plots. Formate brines contaminated with chloride are also included. (See Figure 3; an intact buffer
is considered to correspond to a pH of about 9.5 and above.) No localized/pitting corrosion has been reported in any of these tests.
Figure 14 Measured general corrosion rates for 25Cr in buffered formate brines with various levels of CO2influx and in some cases H2S.
Most rates are taken from long term LPR plots. Formate brines contaminated with chloride are also included. (See Figure 3; an intact buffer
is considered to correspond to a pH of about 9.5 and above.) No localized/pitting corrosion has been reported in any of these tests.
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7.2 Impact of CO2on SCC
Until quite recently, it was widely believed that SCC of CRAs in
completion and packer fluids was only likely to be a problem if
the fluid was contaminated with oxygen and contained some
chloride. Recently, new laboratory data emerged, suggesting
that some CRAs were also susceptible to SCC in bromide
brines containing no added chlorides [5]. This discovery was
soon followed by the revelation that SCC of CRAs could take
place in oxygen-free bromide brines contaminated with CO2[12].
SCC has never been experienced with formate brines in the
field. In the laboratory, SCC has never been experienced in
30-day tests in the presence of CO2. Only limited evidence of
SCC has been experienced in modified 13Cr steel at an
extended test period or with presence of H2S. Extensive SCC
testing has been carried out on formate brines by two research
groups: Hydro Corporate Research Centre in Norway [12] and
Centro Sviluppo Materiali SpA in Italy [10][11].
7.2.1 Testing by Hydro Corporate Research Centre
Hydro Research tested CRAs for SCC after exposure tobuffered 1.7 s.g. / 14.2 ppg potassium/cesium formate brine.
They used the U-bends and C-rings, pre-stressed to yield
method. A 1.7 s.g. / 14.2 ppg calcium bromide brine was
included in the testing for comparison. Both brine types were
contaminated with 1% Cl-. No oxygen scavengers or
corrosion inhibitors were added to either brine. The fluids
were tested at 160C / 320F over a period of three months
with visual inspection after each month. Testing was done
with 1 MPa / 145 psi CO2in the headspace, which immediately
overwhelmed the upper buffer level (the carbonate portion) of
the carbonate/bicarbonate buffer in the formate brine and
allowed pH to drop to the second buffer level. The CRAs that
were tested included triplicate specimens of modified 13Cr-1Mo,
Duplex 22Cr, and Super Duplex 25Cr.
The metal coupons were galvanically coupled to the loading
bolts (C-276) and stressed to beyond yield. All oxygen was
thoroughly removed by flushing at least 6 times with 1 MPa /
145 psi of test gas before testing and after each inspection.
All of the test metal samples were inspected with an optical
microscope after the first and second months. At the end of the
exposure period the crack patterns in the specimens that had
failed were studied in cross-section under an optical
microscope.
Table 8 shows the test results. At the end of the 3-month test
period none of the metal samples exposed to the formate
brine showed any signs of stress corrosion cracking. In the
bromide brine, both modified 13Cr-1Mo and Duplex 22Cr
showed signs of cracking after only 1 month, and Super
Duplex 25Cr showed evidence of cracks at the initiation
stage in the third month. This clearly demonstrates that under
the conditions used in this test program, oxygen is not
required for SCC to take place in bromide brines; the
presence of CO2is enough.
To our knowledge, there are no additives that can prevent the
SCC failures in the halide brines containing CO2. No additives
are currently available to scavenge CO2from divalent halide
brines, and if such an additive did exist, it would deplete over
time if the CO2influx was persistent. Also, commonly used
corrosion inhibitors are known to be ineffective in preventing
the onset of SCC.
The formate brine was tested under the most aggressive
conditions, i.e. the upper buffer level was overwhelmed
(depleted), representing the very worst case where CO2had
leaked into the brine over a very long period of time. The results
show that no additives or treatments other than buffering are
required in formate brines to prevent SCC from a CO2influx.
Table 8 Hydro Corporate Research Centre Long term SCC testing on a 1.7 s.g. / 14.2 ppg potassium/cesium formate brine and a
1.7 s.g. / 14.2 ppg calcium bromide brine, with CO2headspace. Temperature = 160C / 320F, and PCO2
= 1 MPa / 145 psi. The upper
buffer level in the formate brine was immediately overwhelmed and the pH was allowed to drop to the lower pH level. The tests were
run for three months with visual inspection of the specimens after each month.
Test specimenResults [SCC]
CaBr2+ 1% Cl- KCsFo+1% Cl-
1 month 1)
Modified 13Cr-1Mo LC80-130M 3/3 No
Duplex 22Cr EN 1.4462 3/3 No
Duplex 25Cr EN 1.4410 No No
2 months 1) 2)
Modified 13Cr-1Mo LC80-130M 3/3 No
Duplex 22Cr EN 1.4462 3/3 No
Duplex 25Cr EN 1.4410 No No
3 months 2)
Modified 13Cr-1Mo LC80-130M 3/3 No
Duplex 22Cr EN 1.4462 3/3 No
Duplex 25Cr EN 1.4410 2/3 No
crack cracks at the initiation stage no cracking
1) For the first and second month the cracking evaluation is only based on visual inspections and optical microscopy.2) These tests are not true 2 and 3 months tests as the cell has been opened for inspection. They do however provide a valuable comparison of the
cracking susceptibility of the two brines.
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7.2.2 Testing by Statoil at Centro Sviluppo Materiali
Centro Sviluppo Materiali used the four point bent beam
(fpbb) test to evaluate the SCC susceptibility of modified
13Cr-2Mo steel (5 different grades of 110 ksi) and alloy 718
in buffered cesium formate brine saturated with chloride at
165C / 329F [10]. The test was run for 1 month with a CO2
headspace pressure of 4 MPa. The amount of acid gas
added to the autoclaves was sufficient to drop the brine pH
to 8.38.5, but did not totally overwhelm the buffer. This
study concluded that the susceptibility to SCC and localized
corrosion was negligible in both metals (Table 9). There was
no evidence of embrittlement in any of the test metals.
Table 9 Centro Sviluppo Materiali fpbb testing in a 1.94 s.g. /
16.2 ppg cesium/potassium formate brine contaminated with
65 g/L Cl- at 165C / 329F. PCO2
= 4 MPa / 580 psi.
The results are taken from [10].
Test specimen
Results
Pitting SCC
Modified13Cr-2Mo
SubmergedLiquid/vapor interface
No No
No No
Alloy 718SubmergedLiquid/vapor interface
No No
No No
Statoil and Centro Sviluppo Materiali have also reported
some more extensive testing of a cesium/potassium formate
brine saturated with chloride and exposed to CO2[11]. The
CO2partial pressure was also 4 MPa / 580 psi. The final pH
of the brine was not reported, and it is therefore uncertain if
the buffer was overwhelmed or not. In addition to the four
point beam testing, this program also included slow strain
rate tensile (SSRT) testing performed in air at ambient
temperature to look for evidence of hydrogen embrittlement.
The testing gave the following results:
Modified 13Cr-2Mo
No SCC failures were observed with modified 13Cr-2Mo in
cesium formate and fresh water solutions. However, cracks
at the initiation stage were observed on modified 13Cr-2Mo
after 2 months at 140C / 284F. The results are shown in
Table 10.
The fact that Centro Sviluppo Materiali observed cracks at
the initiation stage on modified 13Cr-2Mo after 2 months at
140C / 284F, and Hydro Research did not on modified
13Cr-1Mo after 3 months at 160C / 320F could be related
to the difference in the chloride levels of the two brines (four
times higher in Statoils brine) or it could be related to the
difference in the test methods (Hydro Research opened the
test cell for visual inspection after each month).
Alloy 718
No failures were observed with alloy 718, but significant loss
of ductility was experienced. This phenomenon is discussed
in Section 11.
Table 10 Centro Sviluppo Materiali SSRT testing and fpbb testing of modified 13Cr-2Mo in 1.95 s.g. cesium/potassium formate brine
saturated with Cl-and exposed to CO2. PCO2= 4 MPa / 580 psi [11].
TemperatureTest duration (months) RA [%] EL [%] Cracks (fpbb) testing
C F
No exposure (reference) 52 21 --
100 212 1 74 20 No
140 284 1 nd nd No
140 284 2 nd nd Cracks at the initiation stage
165 329 1 nd nd No
170 338 1 nd nd No
crack cracks at the initiation stage no cracking
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8 Corrosion in Formate BrinesContaminated withH2S
Hydrogen sulfide, H2S, is highly aggressive towards metallic
materials. Depending upon the material, H2Scan cause
general corrosion, pitting corrosion, sulfide stress cracking
(SSC), stress corrosion cracking (SCC), hydrogen induced
cracking (HIC), stress oriented HIC (SOHIC), and hydrogen
embrittlement, and can promote corrosion fatigue. H2S
concentrations of only 50 ppmw dissolved in drilling and
completion fluids can cause highly stressed steel to fail in a
matter of minutes.
H2Scan enter the completion or packer fluid either with
reservoir gas influxes (along with CO2) or from decomposition
of sulfur-containing additives used as corrosion inhibitors in
halide brines (for example thiocyanates). A number of recent
failures of subsurface well equipment in halide brines have
been attributed to the H2Sformed from the thermal decom-
position of sulfur-based corrosion inhibitors [13][14].
H2Sis a very weak acid with pKa1of about 7, and when
introduced into an aqueous solution, the following equilibrium
will establish:
(15)
+
+
(16)
Therefore, in an alkaline aqueous solution, such as buffered
formate brines, the dissolved H2Sgas will largely exist as
bisulfide (HS-).
In non-oxygenated solutions, corrosivity is determined in part
by the pH. The lower the pH the greater the tendency for
corrosion. In addition, pH determines the stability/solubility of
corrosion scales.
Low general corrosion is expected in view of the high pH of
formate brines buffered with carbonate/bicarbonate, even in
the presence of high concentrations of hydrogen sulfide
(which will chiefly exist as HS-). At this pH, since little
corrosion that could lead to hydrogen uptake can occur,
SSC is unlikely.
By contrast, in high-density halide brines, the pH is low
(typically 26), and the H2Sgas will be solubilized directly as
H2S. Soluble H2Sin acidic brines can cause severe SSC.
As an additional benefit, the formate brines do not require
corrosion inhibitors of any kind, thus removing a potential
man-made source of hydrogen sulfide and atomic hydrogen.
There is a remote possibility that H2Scould flow into a formate
completion or packer fluid together with an influx of CO2large
enough to overwhelm the upper buffer level so that pH will drop
to 66.5. Hydro Corporate Research Centre, Porsgrunn and
Statoil (at Centro Sviluppo Materiali SpA) have investigated
the possible consequences of such a scenario (see 8.2.4).
8.1 Impact ofH2Son General and Pitting Corrosion
Both Statoil (Centro Sviluppo Materiali) [10][11] and Hydro
Research [15] have included H2Sin some of their corrosion
experiments with CO2in formate brines. Hydro Research
concluded that the presence of H2Shad very little impact on
the quality of the protective iron carbonate film that forms on
carbon and 13Cr steel surfaces in formate brines, even in the
case where pH is reduced to the lower buffer level by
exposure to a massive influx of CO2. Only when an extremely
high concentration of H2Swas applied or at very low CO2/
H2Sratios, was localized corrosion experienced. Testing with
PH2S= 2 kPa / 0.29 psi and PCO2/ PH2S= 500 on C-steel
(covering the acid gas content and composition of all
production wells in the Gulf of Mexico and the North Sea),
standard 13Cr, and modified 13Cr-1Mo showed no impact
from the presence of H2S. At PH2S= 100 kPa / 14.5 psi and
PCO2/ PH2S= 4, some localized corrosion was experienced.
Corrosion rate results with H2Sfrom both laboratories are
included in the plots in Figure 10 to Figure 14. The small
amount of pitting corrosion that was reported by Statoil [11]
in the presence of H2Scould be promoted by the rather highchloride contamination level in their test brine (saturated).
8.2 Impact ofH2Son SCC and SSC
The following provides an outline of the cracking of metallic
materials in contact with H2Sin the aqueous environments
found in oil and gas production systems. It is thought that the
behavior described also provides an indication of the likely
cracking behavior of such materials in completion brines
contaminated by H2Sinflux.
The service variables temperature, H2Spartial pressure,
chloride concentration, and pH, and the presence of sulfur in
the environment can, depending upon the material, affect its
cracking behavior. Produced sulfur is relatively rare in oil and
gas production environments. It can, however, also occur as
a result of the reaction of oxygen contamination, introduced
via surface facilities, with any H2Sthat is present.
The metallurgical state of an alloy and the total stress in a
material (the sum of both applied and residual stresses) are
also important variables in both these forms of cracking.
8.2.1 Sulfide Stress Cracking (SSC) of Carbon
and Low Alloy steels
SSC can affect susceptible carbon and low alloy steels at
very low H2Spartial pressures.
Figure 15 (taken from NACE MR1075/ISO 15156-2 [16])
defines the boundaries within which various strengths of
steels (often expressed in terms of hardness) remain crack
resistant when exposed to various H2Spartial pressures and
environmental pH values at room temperature. Materials
suitable for use in region 3 are also suitable for use in regions
0, 1 and 2 but not vice-versa.
As the temperature of the environment increases the
susceptibility of carbon and low alloy steels to SSC
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decreases and above about 100C / 212F cracking is not
normally observed.
The other environmental variables listed above are much less
important with respect to SSC.
As can be seen, pH is an important factor in cracking
behavior of these steels and hence the pH of buffered
formate brines (normally > 6.5 even after significant influx of
acid gases) is expected to make this form of attack much less
likely than in other completion brines (halide brines) whose
pH falls quickly when affected by the influx of CO2/ H2S.
8.2.2 Cracking of CRAs inH2SContaining Environments
More detail on the limits of applicability of CRAs in oil and
gas production environments containing H2Sis given in the
industry standard NACE MR0175/ISO 15156-3 [2]. The
information below refers to a primary mechanism of cracking
for the alloys discussed. More details on possible cracking
mechanisms are given in Reference [2], Annex B, Table B.1.
Sulfide Stress Cracking of Martensitic Stainless Steels
Martensitic stainless steels, such as the standard 13Cr andmodified 13Cr alloys are also subject to SSC as a mechanism
of cracking failure in H2Scontaining media. The H2Spartial
pressure limit set by the industry for the more widely used
alloys is 10 kPa (1.5 psi) at a pH no lower than 3.5.
It is believed, given the involvement of hydrogen uptake in
SSC, that at a higher pH, and/or a higher temperature, a
higher level of H2Swould be acceptable and that it may be
possible to construct a diagram similar to that in Figure 15 for
these alloys.
The other environmental variables listed above appear less
important with respect to the SSC of martensitic stainless
steels.
The likely importance of pH suggests that the cracking
behavior of these alloys in relation to brines of different types
will be similar to that of carbon and low allow steels.
Stress Corrosion Cracking of other CRAs
The stress corrosion cracking of austenitic and duplex
stainless steels is dependent in a complex way upon
temperature, H2S partial pressure, and chloride concentration.
For nickel based alloys the role of chloride concentration
appears less important than the other variables. The role of
pH in the cracking of all these alloys is less clear. Many alloys
are made more susceptible to cracking by the presence of sulfur.
The relatively low level of chloride in buffered formate brines
when compared to halide brines would be expected to make
some of these alloys less susceptible to SCC in the presence
of H2S.
In the laboratory data, reported in 8.2.3 to 8.2.5 below, little
or no evidence for SCC has been seen in formate brines.
8.2.3 High-Temperature Testing by CAPCIS
CAPCIS tested CRAs for SCC after exposure to buffered
1.7 s.g. / 14.2 ppg potassium/cesium formate brine at high
temperature (160C / 320F) [18]. U-bends and C-rings,
pre-stressed to yield method was used in accordance with
previous test programs performed by Hydro Research (Section
7.2.1 and 9.1.1). A 1.7 s.g. / 14.2 ppg calcium bromide brine
was included in the testing for comparison. No oxygen
scavengers or corrosion inhibitors were added to either brine.
The fluids were tested at 160C / 320F over a period of
Figure 15 Regions of environmental severity with respect to SSC of carbon and low alloy steels at room temperature. The limits are
taken from NACE MR0175 / ISO 15156-2 [16].
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1 month. Testing was done in Hastalloy vessels with
1 MPa / 145 psi CO2and 10kPa / 1.45 psi H2Sin the
headspace. The CRAs that were tested included triplicate
specimens of modified 13Cr-2Mo, Duplex 22Cr, Super
Duplex 25Cr, and alloy 718. The metal coupons were
galvanically coupled to the loading bolts (C-276) and
stressed beyond yield. In addition to the U-bend test pieces,
pre-machined, unloaded, tensile test pieces of each material
were added to assess the effect of any hydrogen uptake on
tensile properties. Coupons of each material were also
included for measurement of dissolved hydrogen. After the
specimens were added to the test vessel the vessel was
sealed and pressurized 5 times with 1 MPa CO2. The test
solutions were de-aerated by purging with nitrogen for at
least 12 hours prior to transfer to the test vessel. The test
solutions were purged with CO2in the test vessel for 30
minutes before introducing the test gas mixtures. At the end
of the exposure period the crack patterns in the specimens
that had failed were studied in cross-section under an optical
microscope.
During the test, the pH dropped from 11.9 to 7.60 (undiluted)
in the buffered formate brine, which indicated that the upper
buffer level of the carbonate/bicarbonate buffer was
overwhelmed. The pH in the bromide brine dropped slightly
from 3.41 to 3.30 (undiluted).
Table 11 shows the test results. At the end of the 4-week
test period only the modified 13Cr-2Mo test specimens
showed cracks at the initiation stage in the formate brine
(0.11 mm cracks on cross sections). In the bromide brine, all
modified 13Cr-2Mo samples and one of the alloy 718
samples were fractured. The tensile test pieces were tested
for changes in ductility within 6 hours after removal from the
test vessel to minimize loss of any absorbed hydrogen.
Samples were stored in liquid nitrogen after cleaning and
warmed up shortly before tensile testing. Coupons for
hydrogen measurement were brushed clean and analyzed
by vacuum hot extraction (VHE). Results of tensile tests and
hydrogen measurements are listed in Table 12. Some of the
samples that were exposed to the two brines, CO2and H2S,
contained probably slightly elevated levels of hydrogen. They
were not affected significantly by hydrogen embrittlement
apart from one anomalously high yield strength value fromAlloy 718 in CaBr2.
Table 12 CAPCIS room temperature tensile test data (EN10002-1) and hydrogen measurements after exposure to 1.7 s.g. / 14.2 ppg
calcium bromide and 1.7 s.g. / 14.2 ppg potassium/cesium formate brines at 160C / 320F for 30 days. PCO2
= 1 MPa / 145 psi and
PH2S=10 kPa / 1.45 psi. The tensile data are the average of measurements done on two test specimens. The hydrogen levels are based
on one single test.
Test specimen
Yield stress (Rp0.2)% of initial value
Tensile strength %of initial value
Elongation % ofinitial value
Hydrogen uptake[ppm]
CaBr2 KCsFo CaBr2 KCsFo CaBr2 KCsFo CaBr2 KCsFo
Modified 13Cr-2Mo 100 100 101 99 99 100 0.9 1.0
Duplex 22Cr 105 95 102 92 101 95 3.1 3.2
Duplex 25Cr 107 95 106 94 88 99 2.4 6.8
Alloy 718 112 1) 94 106 97 96 97 6.0 4.8
1) One sample showed 103% change; the other showed 121% change.
Table 11 CAPCIS testing of 1.7 s.g. / 14.2 ppg calcium bromide and 1.7 s.g. / 14.2 ppg potassium/cesium formate brines exposed to
CO2(1 MPa / 145 psi) and H2S(10 kPa / 1.45 psi) at 160C / 320F for 30 days.
Test specimenResults [SCC]
CommentCaBr2 CsKFo
1 month
Modified 13Cr-2MoSM13CRS-110ksi /UNS S41426
3/3 3/3 CsKFo: Cracks on cross-
sections 0.11 mm
Duplex 22CrEN 1.4462 /UNS S31803
No No
Duplex 25CrEN 1.4410 /UNS S32760
No No
Alloy 718 UNS N07718 1/3 No
crack cracks at the initiation stage no cracking
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8.2.4 High-Temperature Testing by Statoil at
Centro Sviluppo Materiali
Statoil completed some four point bent beam (fpbb) testing
at Centro Sviluppo Materiali, in 1.95 s.g. buffered cesium
formate brine exposed to CO2and H2S[10]. In this testing,
the acid gas exposure was sufficient to overwhelm the upper
buffer level (the carbonate part) and drop the pH to the lower
buffer level. Table 13 shows the results from these tests anda test with only CO2. The addition of H2Sdid not cause any
cracking of the modified 13Cr-2Mo over the 1 month
exposure period. There was some evidence of embrittlement
of the modified 13Cr-2Mo and alloy 718 used in the tests
with H2S.
Statoil and Centro Sviluppo Materiali also included the same
amount of H2S(PH2S= 3 kPa / 0.44 psi) in their four point bent
beam and SSRT testing [11] reported in Table 10 in the
previous chapter (modified 13Cr-2Mo, given 1 month of
exposure to cesium formate brine at 170C / 338F in the
presence of 4 MPa CO2). This showed cracks at the initiation
stage and some absorption of hydrogen into the steel. Under
the same test conditions, in the absence of H2S, there was
no cracking and no absorption of hydrogen into the steel
during the 1 month exposure. The paper does not state if the
cracks were caused by SCC or if it was SSC occurring during
cooling of the test sample. For alloy 718, there were no
failures but loss of ductility with and without H2S. This is
discussed further in Section 11.
There are no results listed for similar tests in halide brines
with H2S. The paper does, however, state that the presence
of CO2and H2Screated severe SCC in modified 13Cr-2Mo
metal samples immersed inZnBr2/CaBr2/CaCl2and CaBr2/
CaCl2brines, and that transgranular cracks were also found
in one of the tests.
H2Sformed by the thermal decomposition of sulfur-
containing corrosion inhibitors is another well-known cause
of SSC and SCC in completion/packer fluids. Corrosion
inhibitors are not required in formate brines, and so one
troublesome source of corrosion is eliminated.
8.2.5 Low-Temperature Testing by CAPCIS
CAPCIS tested CRAs for SSC after exposure to buffered
1.7 s.g. / 14.2 ppg potassium/cesium formate brine at low
temperature (40C / 104F) [18]. U-bends and C-rings, pre-
stressed to yield method, were used. A 1.7 s.g. / 14.2 ppg
calcium bromide brine was included in the testing for
comparison. No oxygen scavengers or corrosion inhibitors
were added to either brine. The fluids were tested at 40C /
104F over a period of 1 month. Testing was done in
Hastalloy vessels with 1 MPa / 145 psi CO2and 10kPa / 1.45
psi H2Sin the headspace. The CRAs that were tested
included triplicate specimens of modified 13Cr-2Mo, Duplex22Cr, Super Duplex 25Cr, and alloy 718. The metal coupons
were galvanically coupled to the loading bolts (C-276) and
stressed beyond yield. In addition to the U-bend test pieces,
pre-machined, unloaded, tensile test pieces of each material
were added to assess the effect of any hydrogen uptake on
tensile properties. Coupons of each material were also
included for measurement of dissolved hydrogen. After the
specimens were added to the test vessel the vessel was
sealed and pressurized 5 times with 1 MPa CO2. The test
solutions were de-aerated by purging with nitrogen for at
least 12 hours prior to transfer to the test vessel. The test
solutions were purged with CO2in the test vessel for 30
minutes before introducing the test gas mixtures. At the end
of the exposure period the crack patterns in the specimens
that had failed were studied in cross-section under an optical
microscope.
During the test, the pH dropped from 11.9 to 7.63 (undiluted)
in the buffered formate brine, which indicated that the upper
buffer level of the carbonate/bicarbonate buffer was
overwhelmed. The pH in the bromide brine increased slightly
from 3.41 to 3.65 (undiluted).
Table 14 shows the test results. At the end of the 4-week
test period no sign of cracking was seen on any of the test
specimens in the formate brine. In the bromide brine, all
modified 13Cr-2Mo samples showed signs of cracks at theinitiation stage. The tensile test pieces were tested for
changes in ductility within 6 hours after removal from the test
vessel to minimize loss of any absorbed hydrogen. Samples
were stored in liquid nitrogen after cleaning and warmed up
shortly before tensile testing. Coupons for hydrogen
measurement were brushed clean and analyzed by vacuum
hot extraction (VHE). Results of tensile tests and hydrogen
measurements are listed in Table 15. Some of the samples
that were exposed to the two brines, CO2, and H2Scontained
probably slightly elevated levels of hydrogen, but were not
affected significantly by hydrogen embrittlement.
Table 13 Centro Sviluppo Materiali fpbb testing of modified 13Cr-2Mo and alloy 718 in a 1.94 s.g. / 16.2 ppg CsKFobrine at 165C / 329F.
PCO2= 4 MPa / 580 psi. The results are taken from [10].
FluidH2S
Position in test cellModified 13Cr-2Mo Alloy 718
[kPa] [psi] Pitting SCC Pitting SCC
1 Month
CsKFo+ 20 g/L Cl- 3 0.44 SubmersedLiquid/vapor interface NoNo NoNo NoNo NoNo
CsKFo+ 65 g/L Cl-Submersed
Liquid/vapor interfaceNoNo
NoNo
NoNo
NoNo
CsKFo+ 75 g/L Cl- 3 0.44Submersed
Liquid/vapor interfaceNoNo
NoNo
NoNo
NoNo
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8.3 Use ofH2SScavengers in Formate Brines
The carbonate/bicarbonate buffer that is normally added to
formate brines when they are used as well construction fluids
provides useful protection against corrosion by H2S. The
alkaline pH helps to push the chemical equilibrium (Equation
16) towards the formation of bisulfide (HS-) from H2S(aq).
The capacity of the carbonate/bicarbonate buffer is enormous
(as demonstrated in Figure 3), and large amounts of acid gas
can be converted to HCO3-and HS-before the pH starts
dropping. The likelihood that a buffered formate brine would
ever receive a CO2gas influx large enough to overwhelm the
buffer during field use is low, but as can be seen from the
previous section (8.2.4), this could result in some loss of
ductility in CRAs and the addition of an H2Sscavenger could
be beneficial since the impact of H2Son lowering pH would
be reduced and less bisulfide ion, that might stimulate
hydrogen uptake, would be dissolved in the formate brine.
The addition of H2S scavengers has additional benefits over
the use of the buffer alone as the scavengers tie up the
sulfide rather than changing the equilibrium. Additionally, the
use of an additional H2Sscavenger will help to remove any
bisulfide from the formate brine.
A zinc-free, iron based H2Sscavenger, Ironite Sponge, has
been tested in formate brines, and is shown to have some
positive effect in scavenging the H2S. But Ironite Spongeis
a solid, which limits its application in clear completion fluids.
Another iron based scavenger, compatible with high
concentration formate brines, is iron gluconate [19], a Fe(II)
complex, which is water-soluble at high pH. In addition to
being solids free, this scavenger has the added benefit of
reacting very rapidly on a quantitative basis with sulfide.
8.5 kg/m3/ 3 lb/bbl of iron gluconate has been tested in a
buffered 2.2 s.g. / 18.3 ppg cesium formate brine (pH=11).
The added scavenger was shown to be compatible with the
brine; it dissolved completely within 5 minutes without any
change in pH.
A third iron based scavenger that may be compatible with
formate brines is iron oxalate. Compatibility testing still needs
to be carried out with this scavenger.
Another group of zinc-free H2Sscavengers that is expected
to be compatible with formates are the electrophilic organicinhibitors that bind up sulfur in an organic form. These have
the advantage that they do not form any solids when reacting
with H2S. These will also require compatibility testing.
Table 14 CAPCIS testing of 1.7 s.g. / 14.2 ppg calcium bromide and 1.7 s.g. / 14.2 ppg potassium/cesium formate brines exposed to
CO2(1 MPa / 145 psi) and H2S(10 kPa / 1.45 psi) at 40C / 104F for 30 days.
Test specimenResults [SCC] Comment
CaBr2 CsKFo
1 month
Modified 13Cr-2Mo SM 13CRS-110ksi /UNS S41426 3/3 No CaBr
2: cracks on cross sections 1.8 mmDuplex 22Cr EN 1.4462 / UNS S31803 No No
Duplex 25Cr EN 1.4410 / UNS S32760 No No
Alloy 718 UNS N07718 No No
crack cracks at the initiation stage no cracking
Table 15 Room temperature tensile test data (EN10002-1) and hydrogen measurements after exposure to 1.7 s.g. / 14.2 ppg calcium
bromide and 1.7 s.g. / 14.2 ppg potassium/cesium formate brines at 40C / 104F for 30 days. PCO2= 1 MPa / 145 psi and
PH2S=10 kPa / 1.45 psi. The tensile data are the average of measurements on two test specimens. The hydrogen levels are based
on one single test.
Test specimenYield stress (Rp0.2)% of initial value Tensile strength% of initial value Elongation% of initial value Hydrogen uptake[ppm]
CaBr2 KCsFo CaBr2 KCsFo CaBr2 KCsFo CaBr2 KCsFo
Modified 13Cr-2Mo 100 102 101 99 93 98 1.3 1.0
Duplex 22Cr 104 109 101 104 93 92 1.2 1.7
Duplex 25Cr 102 104 103 105 96 92 1.3 1.4
Alloy 718 104 107 106 108 96 103 3.0 2.7
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9 Corrosion in Formate BrinesContaminated with O2
Oxygen is generally accepted as a cause of general
corrosion, where the oxygen serves as an oxidant for
corrosion reactions. Concentrated formate brines have
beneficial properties that should help protect metals against
corrosion damage caused by oxygen:
1. Low solubility of oxygen in formate brines.
The solubility of oxygen in low-salinity aqueous solutions at
surface temperature and pressure is about 9 ppm. The
solubility decreases in high salinity formate brines, as shown
in Figure 16, and at elevated temperatures [20].
2. Formate brines are antioxidants.
Formate is a strong reductant, anti-oxidant, and free radical
scavenger. As this is a property of the formate ion itself,
which is present in massive quantities in high-density formate
brines, it will never be depleted.
Halide brines have no anti-oxidant properties. Therefore, if
oxygen is not removed from halide based drilling and
completion fluids, the soluble oxygen can cause severalforms of corrosion in sub-surface well equipment and
tubulars. For this reason, it is essential to add an oxygen
scavenger to halide brines. These scavengers are generally
quite effective until they become depleted (consumed) or
degraded, at which point further contamination with oxygen
could cause a problem. However, the standard bisulfite-
based oxygen scavengers are not particularly soluble in
calcium brines because they form solid calcium bisulfite. A
recent well tubular failure [21] was caused by oxygen (air)
ingress into a CaCl2packer fluid during an annular pressure
bleed-off operation. In this instance, the oxygen scavenger
present in the brine was apparently not able to cope with the
new influx of oxygen.
Concentrated formate brines contaminated with oxygen and
without added oxygen scavenger have never caused pitting
or SCC in the field. Laboratory testing with these brines
confirm their superior performance over halide brines.