Formate Brines Compatibility with Metals

Transcription

F O R M AT E
B R INE S
–
COMPATI B I L I TY
W I TH
ME TAL S
Formate Brines
Compatibility with Metals
Photo: Courtesy of Sandvik
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
F O R M AT E
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Contents
Purpose and Scope
Acknowledgements
Summary
1
Introduction to Formate Brines
2
Introduction to Oilfield Corrosion
2.1
Types of Corrosion
2.2
Types of CRAs and how they are chosen
3
HPHT Field Experience
4
What Makes Formates less Corrosive than Other Brines?
5
The Carbonate/Bicarbonate pH Buffer in Formate Brines
5.1
How the Carbonate/Bicarbonate Buffer Works
5.2
Buffer Protection against CO2 (H2S) influx
6
Corrosion in Formate Brines in the Absence of Corrosive Gases
7
Corrosion in Formate Brines Contaminated with CO2
7.1
CO2 Corrosion
7.1.1 CO2 Corrosion of C-Steel
7.1.2 CO2 Corrosion of 13Cr Steel
7.1.3 CO2 Corrosion of Higher Alloy Steels
7.1.4 CO2 Corrosion Rates
7.2
Impact of CO2 on SCC
7.2.1 Testing by Hydro Corporate Research Centre
7.2.2 Testing by Statoil at Centro Sviluppo Materiali
8
Corrosion in Formate Brines Contaminated with H2S
8.1
Impact of H2S on General and Pitting Corrosion
8.2
Impact of H2S on SCC and SSC
8.2.1 Sulfide Stress Cracking (SSC) of Carbon and Low Alloy steels
8.2.2 Cracking of CRAs in H2S Containing Environments
8.2.3 High-Temperature Testing by CAPCIS
8.2.4 High-Temperature Testing by Statoil at Centro Sviluppo Materiali
8.2.5 Low-Temperature Testing by CAPCIS
8.3
Use of H2S Scavengers in Formate Brines
9
Corrosion in Formate Brines Contaminated with O2
9.1
Impact of O2 on SCC
9.1.1 Testing by Hydro Research
9.1.2 Testing by CAPCIS
9.2
Use of O2 Scavengers in Formate Brines
10
Catalytic Decomposition of Formates – a Laboratory Phenomenon
11
Hydrogen Embrittlement of Metallic Materials in Formate Brines
11.1 Hydrogen Embrittlement
11.2 Sources of Hydrogen
11.2.1 Hydrogen Charging from Galvanic Coupling
11.2.2 Hydrogen Charging from Formate Decomposition
11.3 Field Evidence – Total’s Elgin Wells G1 and G3
12
Avoid Pitfalls in the Laboratory!
13
Avoid Pitfalls in the Field!
13.1 Four Simple Rules for Avoiding Corrosion in Formate Brines
13.2 Examples of Incorrect Use
References
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Purpose and Scope
Summary
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.
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 216°C /
420°F 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.
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.
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 6–6.5 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.
PA G E 3
F O R M AT E
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W I TH
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1 Introduction to
Formate Brines
2 Introduction to
Oilfield Corrosion
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.
2.1 Types of Corrosion
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 and
differential 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 216°C /
420°F, at pressures up to 117 MPa / 17,000 psi and in the
presence of corrosive gases such as CO2, 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 for
the oil companies who have chosen formate brines for use in
their HPHT well constructions.
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
anodic reaction 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 fastacting 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.
3USCEPTIBLE
MATERIAL
3##
4ENSILE
STRESS
%NVIRONMENT
Figure 1 Factors required for stress corrosion cracking (SCC).
PA G E 4
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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 oversaturation, or the hydrogen enters the steel directly at a low
temperature (less than about 100°C / 212°F) 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 100°C / 212°F
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
W I TH
ME TAL S
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 100°C / 212°F). 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 temperatures and the presence of H2S and 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 production
if 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 CO2 is
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 alloys that, 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 CO2 and are
further restricted by the level of CO2, H2S, and Cl- [1].
Group
Martensitic
Duplex
Name
13Cr
Modified 13Cr-1Mo (M13Cr)
Modified 13Cr-2Mo (S13Cr)
22Cr
25Cr
Cr %
Ni %
Mo %
13
13
12.5
22
25
-4
5
5
7
-1
2
3
4
PA G E 5
General application limit
[°C]
[°F]
<150
<300
<175
<350
<175
<350
<200
<400
<250
<480
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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 216°C / 420°F 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.
No. of wells
Hydrocarbon
Max. temp
Completion material
Liner material
Packer material
Brine density
Reservoir pressure
CO2
H2S
Exposure time
°C
°F
CRA
CRA
CRA
g/cm3
MPa
psi
%
ppm
days
Application
Total
Elgin/
Franklin
10
Gas
condensate
204
400
25Cr
P110
718
2.10 – 2.20
115.3
16,720
4
20 – 50
1.6 yrs
Workover
Completion
CT
Well kill
Perforation
BP Rhum
3/29a
Shell
Shearwater
Marathon
Braemar
BP
Devenick
Statoil
Huldra
3
Gas
condensate
149
300
S13Cr
S13Cr
718
2.00 – 2.20
84.8
12,300
5
5 – 10
250
6
Gas
condensate
182
360
25Cr
25Cr
718
2.05 – 2.20
105.6
15,320
3
20
65
1
Gas
condensate
135
275
13Cr
22Cr
718
1.80 – 1.85
74.4
10,800
6.5
2.5
7
1
Gas
condensate
146
295
13Cr
VM110
718
1.60 – 1.65
72.4
10,500
3.5
5
90
Perforation
Completion
Workover
Well kill
CT
Workover
Perforation
Workover
Perforation
Drill
Completion
Devon
West
Cameron
575 A-3
1
Walter O&G
Mobile Bay
862
Gas
Gas
135
275
13Cr
13Cr
718
6
Gas
condensate
149
300
S13Cr
S13Cr
718
1.85 – 1.95
67.5
9,790
4
10 – 14
45
Drilling
Completion
Screens
Statoil
Kvitebjørn
Statoil
Kristin
BP
High Island
A-5
Completion material
Liner material
Packer Material
7 to date
Gas
condensate
171
340
S13Cr
S13Cr
718
1
°C
°F
CRA
CRA
718
7 to date
Gas
condensate
155
311
S13Cr
13Cr
718
163
325
S13Cr
S13Cr
718
Devon
West
Cameron
165 A-7, A-8
1
Gas
condensate
149
300
13Cr
13Cr
718
Brine density
g/cm3
2.00 – 2.06
2.09 – 2.13
2.11
1.03
1.14
CO2
MPa
psi
%
81
11,700
2–3
90
13,000
3.5
99
14,359
5
80
11,650
3
74
10,731
3
216
420
G-3
G-3
G-3
2.11
1.49 packer
129
18,767
10
H2S
ppm
Max 10
12 – 17
12
5
5
100
57
57
4
3 yrs packer
2 and 1.3 yrs
1.4 yrs
20
1.5 yrs packer
Drilling
Completion
Screens
Liners
Drilling
Completion
Screens
Well kill
Completion
Packer
Packer
Packer
Well kill
Completion
Packer
No. of wells
Hydrocarbon
Max. temp
Reservoir pressure
Exposure time
Application
days
Gas
PA G E 6
1
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COMPATI B I L I TY
4 What Makes Formates less
Corrosive than Other Brines?
W I TH
ME TAL S
5 The Carbonate/Bicarbonate
pH Buffer in Formate Brines
There are several features of formate brines that make them
inherently less corrosive than other brines used by the oil
industry.
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.
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.
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 buffer’s ability to consume hydrogen ions (H+)
and/or hydroxide ions (OH-).
Antioxidant
Oxidants, such as O2 are known to cause corrosion
problems. The formate ion is a well-known antioxidant or free
radical scavenger, used in many industrial and medical
applications.
The carbonate/bicarbonate buffer system provides strong
buffering at two different pH levels:
Favorable alkaline pH
• Higher buffer level at pH = 10.2
Formate salts dissolved in water exhibit a naturally favorable
pH (8-10).

P+A
P+A (1)
#/ #/
( ←
PKT
⎯⎯
( →←(#/
⎯⎯
→
PKT
3 (#/3
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.

(#/
A
P+
P+
#/
(#/
P+
A
where
10.2
#/
#/
A =
⎯
→ (#/3
PKT
( ←⎯
P+A
P+A

P+
⎯⎯→(#/
PKT

(
←
⎯
→
(#/
PK
#/
A ( P+←
3⎯

A #/
3

( #/
(#/ 10.2
( (←
⎯→←(⎯
#/
PKT
⎯
(
→
PKT
⎯
solution
(#/
P+
At pH=(#/
buffered
contains
the
same
A ) the #/

(#/
P+
amount
of carbonate
(#/
( (#/ ).
P+A

)Aand bicarbonate
#/ A
P+
P+
A
←⎯
A #/
→(#/
P+A (P+
#/
((#/
⎯
(
PKT
P+
(#/
#/
(
3
(
#/
←
⎯
→
(#/
A (#/
PKT
⎯
←
⎯
⎯
→
(
#/
PKT
3
Traditional high-density halide brines typically have pH values
P+A
P+A

( =(#/
←
⎯⎯
→
PKT
(
(#/
←⎯⎯
→ (#/

PKT
(#/
level atpH
of between 2 and 6 (depending on the type of halide) and are
• Lower
buffer
6.35
(#/
P+A
PKT
#/
#/
#/
AQ
P+AG P+

#/
(#/
PKT
G
#/
AQ
P+
A
#/
( ←⎯⎯→
(#/
(
PKT
A (#/
#/3
therefore naturally more corrosive than formate brines.

P+A

(#/
((#/
#/
#/
⎯→

PKT
A A
P+P+
A( ←
⎯
(#/(
P+A P+
3 #/
#/
AQ #/
/AQ
←
(
(
P+
(2)
(#/
((
⎯

PKT
PKT
(
#/
((⎯
/ →
AQ
(
AQ
#/

PKT
A
#/
→
(#/
#/
P+
←
⎯
⎯
PKT
PKT
#/
AQ
(#/
#/
#/
AG
#/
(
←
⎯
⎯
→
(#/
PKT
3
Compatibility with Carbonate-based pH buffer

#/
AQ G
P+A#/
#/
#/ AQ (#/ PKT PKT
G
+ A #/
+ A
P+
(
⎯
⎯
(#/
AQ
((
AQ
AQ
P+

(#/
A
((#/
#/
→
A AQ
(←
#/
→
AQ
(#/
←
⎯
⎯
#/
P+
(
AQ(
PKT
The only truly reliable protection against corrosion from acid
where
6.35
(#/
PKT
#/
P+
#/
(

PKT
A =
AQ /
#/
AAQ
(
⎯
⎯
→
PKT
(
←
(#/
P+A
#/
#/
#/
( ←⎯⎯→ (#/
PKT
P+A 3
gas (CO2 and H2S) is to pre-treat the receiving brine with a
#/
AQ
(
/
(
#/
AQ
#/
AQ
(
/
(
#/
AQ
PKTPKT
(#/
←
⎯→ (
#/

PKT
⎯
(

OKT
#/
AQ
(
#/
AQ
→
(#/
AQ
OKT
PKT
+AAQ →
#/
#/
#/
AQ
P+A
AQ
#/
AQ
(
(#/
PKT

G #/
G
#/
AQ
←
⎯
⎯→ (#/
AQ(
#/
( AQ

carbonate/bicarbonate buffer. The buffer not only helps to(#/ ( ←At
pH
((P+
the
buffered
solution
contains
the
(#/
PKT
#/
⎯⎯
→=(6.35
A )AQ
PKT
#/
(#/
P+
+ A #/

A

+A
+ (of
#/bicarbonate
AQ P+
←⎯
⎯→
(#/
AQ
AQ(
#/
maintain the brine pH in the safe alkaline zone but also
same
amount
((#/
) (and
carbonic
( #/
AQ
←⎯
⎯
→ (#/
AQ PKT
( AQ
+
PKT
#/ AQ #/
((/
(#/
AQ
(AAQ

(#/
AQ
AQ
AQ
PKT
/
AQ
((#/
(AQ
#/ G OKT
G↔
(/
/↔
AQ
PKT
#/
(
#/
→
(#/
AQ PKT
#/
P+
AQ
P+A PKT

#/
G
AQ
#/
PKT
A
P+A
(#/acid
#/
promotes metal passivation.
( (#/
).
#/←
⎯
(→←
⎯→
(#/
(
⎯
(⎯
#/
P

(#/3 PKT

OKT
#/ AQ#/
(#/
#/
AQ
→((#/
AQ
(#/
#/ AQ
→
OK
PKT
#/
G
+A
AQ
AQ + A AQ (
+ AQ
( #/ AQ
#/
←⎯
⎯
→(#/
PKT

(
AQ
←
⎯
⎯
→
(#/
AQ
(
AQ
#/G
AQ
PKT
( #/ AQ
AQ

(#/
(
( AQ PKT
PKT
PKT
; ( =levels
⋅ ; (#/
#/ G #/ The
AQ exact
; ( #/
==⋅ ;P+
(#/
= (//↔
of
Traditional high density completion and packer fluids based
vary
somewhat
with
(#/
P+A will
#/
(
+ #/
+
A and+(#/
+
AQ
PKT
AQ
G
(/
(
#/0 G (#/
(#/
AQ
(
AQ PKT
PKT
0#/
#/

PKT
#/
(
/
↔
(#/
AQ
(
AQ
/↔
PKT
OKT

#/
#/
AQ
(
#/
AQ
→
(#/
AQ
on divalent halide brines (CaCl2, CaBr2, ZnBr2) cannot be
brine concentration,
and
pressure.
( P+
OKT
+A →
temperature,

#/ AQ
( #/
⎯
AQ
(#/
AQ
( #/
←
⎯→
AQA
#/ AQ (/ (#/ AQ PKT
AQPKT
AQ (#/
(#/
⎯
⎯
→
(
#/
PKT
PKT
#/
#/
AQ + A ( ←
; ( =G⋅ ; (#/
buffered because even small amounts of added carbonate/
=
+ + ( #/ AQ ←⎯
⎯→ (#/ AQ ( AQPKT
PKT
+ 0 = (#/
P(
(
;; (
= ⋅;#/
(#/
=#/
AQ

AQ
= ⋅ ; (#/
#/
GLOG
( ;/
↔
(
; (
PKT
=
=
P(
(
PKT
bicarbonate buffer are precipitated out. Carbonate/bicarbonate
+A
OKT
PKT
(
LOG
#/
G
(
/
↔
(#/
AQ
(
AQ
#/
AQ
AQ
→
(#/
AQ
PKT

( #/ AQ ←⎯
⎯→ (#/ AQ ( +
AQ
PKT
#/
PKT
(+P+
/
A (#/ (#/
AQ PKT
( #/
AQ
0#/

PKT
buffers are soluble in formate brines, and can be formulated
AQ → (#/ AQ
#/ AQ (0#/
#/
OKT

+
PKT
0#/
P( LOG
+
LOG
LOG
LOG0;#/
(#/
PKT

P(
LOG
+
LOG
=
= ; (#/

;
=
OKT
P(
LOG
(
to make fluids that remain pH stable in the face of quite large
PKT
#/ AQ ( #/ AQ
(#/
AQ (
+ A(#/ AQ
; ( →
= ⋅ ; (#/
( AQ
PKT
G =
/↔
; ( =#/
⋅=;(#/
+ #/
(
←#/
⎯
⎯→
(#/
( AQ
PKTPKT
AQ +
G
AQ
#/
AQ
+ 0
; ( GP(
= (

LOG influxes of CO2 .
; ( PKT
= AQ PKT
LOG(#/
#/
( AQPKT
PK
PKT
0
#/ P(
/↔
0
(#/
0
#/
#/
(#/

+
#/
PKT

0
P(

LOG
+

LOG
LOG
;
(#/
=

#/
#/ G ( / ↔ (#/ AQ ( AQ #/ AQ
OKT
AQ (
#/
(
AQ
→(#/
(#/
PKT
#/
/
AQ
AQ ; ( = ⋅PKT
; (#/
=
PKT
+
LOG + LOG
0
LOG
(#/
= LOG; (#/
P
P(
LOG
+;
LOG0#/
P(
PKT
In order to fully understand how the buffer in the formate
=
#/ AQ (#/
(#/
AQ
(#//
= AQ(#/
(#//(
AQ
AQ
;(LOG
= AQ
0
P(
LOG
(#/
((#//
AQ
(#//(
AQ
(#/
PKT
;(
= ⋅ ;
(#/
P(
PK
#/
= PKT
;
0
#/
PKT
+
+A
+

brine enhances the corrosion protection provided by the
(
#/
←
⎯
⎯
→
(#/
PKT
↔
PKT
(0
/
AQ
AQ AQ ( AQ
(
AQ
0(#/
PKT
0#/ #/ G(#/
; ( = ⋅ ; (#/ =
#/
(#/
#/
+

PKT
P+
(
#/

P+
(#//(
formate brine itself, one first needs to understand how this
PKT

0
P(

LOG
+

LOG
LOG
;
(#/
=
AQ
0
A
P+A (#/
P+
(#//(
A ; (#/
0#/
#/
PKT
LOG
P( LOG
+

LOG
=
A
(P(
#/
(#//
AQ
(#//(
AQ
(#/
AQ
;
=

LOG
(
#/
#/
AQ
( #/ AQ → PKT
(#/ AQ O

buffer works and how it reacts to influxes of common acid

(#//(
(#//
(
#/
AQ
AQ
AQ
(#/
AQ

(
#/
AQ
(#//
AQ
(#//(
AQ
(#/
;
(
=
⋅
;
(#/
=
;
=
P(
LOG
(
PKT
AQ

0#/ ( 0
(#/
(

+&E
→
&E
→
AQ&E
(
(#/
AQ
(#/
PKT
AQ
&E
AQ
(P+
#/
(
AQ
0AQ
LOG

(#/
gases such as CO2 and H2S.
PKT
#/ #/
G
PKT
LOG
#/
+ G (#//(
P+
PKT
0
A
P(

+

LOG
;
(#/
=
A
P( LOG ; ( =
#/ #/
PKT
#/ G ( / ↔ (#/
( AQ
PK
AQ
P+A (
#/ P+
P+
LOG
(#//(
A
+(#/
#/
A
PKT
(#//(
LOG
LOG0
P(
; (#/ =P+
A ( GAQ

(#//(

(
#/
AQ
(#//
AQ
(#/
AQ
PKT
&E
(#//(
AQ
→
&E
AQ

#//(
AQ
PKT
(
#//(
&E#/
(#//(
AQ
PKT
→

( AQ
G (
AQPKT
0#/
(
(#//
&E
AQ
AQ
(#//(
(#/
AQ
PKT
(#/
AQ
&E
#/
AQ
→
&E
AQ
G
(#/
AQ
P
P( LOG + LOG 0#/ LOG ; (#/ = P( LOG
PKT

; ( =

0#/ AQ

(#/
;
(
=
⋅
;
(#/
=
&E
(
#/
→
&E
AQ

(
G
(#/
AQ
P
&E
(
#/
AQ
→
&E
AQ

(
G
(#/
AQ
S
+A (#//(
#/

(#//(
P+ (P+
&E#/
PKT
PK
(#/
#/
(#//(
AQ
P+
P+
&E
↔
&E#/
S
A ↔
PKT
0#/
P
&E
(
#/
(#//
AQ
(#//(
AQ
(#/
AQ
AQ
→
&E
AQ

(
G
#//(
AQ
A
0
(#/ &E A #/

#/ PKT
P( LOG + LOG 0#/
LOG ; (#/
=

P
(#/
&E
(#//
AQ
G(#//(
AQ
G(#/
&E (#//(
&E
AQ AQ
→
AQ AQ

(&E
AQ
#//(
AQ
(#//(
→

(
#//(
AQ AQ

( G (#/
( 3
G&E
#/
((
3P+
AQ
&E
&E
(
→(
AQ
AQ
(#/
AQ
AQ
PKT
&E
(
AQ
3
&E#/
( PKT
G
PKT
AQ
→
AQ
GPKT
(
#/
AQ
PKT
#/
P+
&E0
#/
↔
PKT
(#/
7(#//
AQ
3
(#//(
AQ
A
(#/
A (#//(
(#/
S
P A AQ
GE
#/
P( LOG ; ( =
P

P+↔
(+#/
↔
&E#/ SP+
(#//(
#/
&E#/
PKT
A &E
S
#/
P+A &E PKT
A
−
+
P+
−(
A AQ
(
&E 3
(#//(
AQ
←
→
&E
AQ
3

G(
(
#//(
PKT
AQ PKT
(
AQ&E
(←
⎯
→
(3
(+&E
AQ
PKT
PKT
+
3P+
⎯
AQ
(#//(
⎯
⎯
→
(3
AQ
AQ
(#//(
AQ
→
AQ

G
#//(
AQ
(
3
G
AQ
&E
(
#/
AQ
→
&E
AQ

(
G
(#/
AQ
PKT
P+A (#/

( #/
AQ
(#// AQ (#//(
A
AQ (#/
P
P( LOG + LOG 0#/
LOG ;(#/
AQ
=

(
3
G
(
3
AQ
&E
(
#/
AQ
→
&E
AQ

(
G
(#/
AQ
PKT
(
3
G
(
3
AQ
PK

CAT

/
CAT AQ− (
G + PKT
PKT
←⎯→
(#//
AQ
(
(#/
P+
&E #/
↔
&E#/
S
PKT

A
(#//
AQ
AQ
&E#/
(
←
(#/
(
GG PKT
#/
AQ
S⎯→
→
PKT
/
AQ
( ←
⎯
AQ
+ (P+
AQ
(3
→
AQ

#//( AQ ⎯
0
&E ( #/ AQ → &E &E
AQ
(&E
(
↔
G(#//(
(#/
AQ
&E
3
(#//(
(#/
PKT
#/
P+
(
#/
A
P+ −
+ A
F O R M AT E
B R IN E S
–
COMPATI B I L I TY
W I TH
ME TAL S
P("EHAVIOROF#ARBONATE"ICARBONATE"UFFER7HEN!DDING3TRONG!CID
P+A
P(
P+A
&RACTIONOFBUFFERCONSUMED
!DDITIONOFSTRONGACID
Figure 2 The pH of water buffered with carbonate as a function of added strong acid (H+). The x-axis shows the fraction of the buffer
that 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 CO2 influx), the pH can never drop much below pKa1.
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” = 10.2±1. 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
P+A

P+
( A → (#/
#/
←⎯
⎯
⎯
PKT
converted
acid,
a CO
not
3 2 influx is therefore
#/
(to carbonic
←
⎯
→
(#/
PKT
3
capable of pulling the pH much below this second buffer

P+A
(#/

level.
P+
A ( #/
PKT
#/
←⎯⎯
→ (#/
The three different brine systems in Figure 3 will react in the
following way to a CO2 influx:
• Conventional divalent halide brines cannot 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 (2–6) and the influx of CO2 will, dependent
on the partial pressure of CO2, further lower the pH. The
CO2 will largely be converted to carbonic acid, which is
very corrosive.
P+A
#/

(#/
3

P+A
(#/
P+
A

P+A
#/ (#/
←⎯
⎯⎯
⎯→
→(
(#/
#/
PKT
( ←
(#/
(Protection
CO2 (H2S)PKT
5.2 Buffer
against
influx
P+A

(#/ ( ←⎯⎯→ (#/
PKT completion
The major cause of
acidification of conventional
P+
(#/
( #/
#/
A
P+
(#/
(
A

brines
gas (CO2) into the wellbore:
is influx of carbon dioxide
P+
(#/
( #/ A
#/GG
G #/
#/
#/
AQ
#/
#/
AQ AQ
PKT
(3)
#/
(/( /
( #/ AQ
#/ AQ
AQ
(#/ AQ
#/
AQ ( / (#/ AQ
+ A
PKT
(4)
PKT
PKT
PKT
PKT
( #/ AQ ←⎯
⎯→+(#/ AQ ( AQ
PKT
A

+⎯
A → (#/ AQ ( AQ
(5)
(#/
#/ AQ ←⎯
PKT
(
⎯→
(#/ AQ ( AQ
PKT
AQ ←⎯
#/ AQ ( #/ AQ → (#/ AQ OKT

OKT
Depending
on(the
pH inAQ
the
brine
system,
the dissolved
CO2
AQ +

#/
#/
→
(#/
OKT
AQ
AQ
#/
( #/
AQ

→ (#/ AQ
#/
( / ↔
AQ (
PKT
will Gremain
in(#/
thebrine
as AQ
either
carbonic
acid (H2CO3) or
+
to the equation 5. This is
bicarbonate (HCO
+

3) according
AQ ( AQ
#/;(G
G= ; (#/
( /
/ ↔
↔ (#/
(#/
PKT
AQ
#/
(
more
( AQCO
gas enters
⋅
=
PKT
in Figure
3.
demonstrated
As
into the
2
+
PKT
0#/
brine, the carbonic acid concentration builds up and the pH

drops
allows
brines to acidify.
=⋅;
;(
(and
(#/unbuffered
=
= ⋅ ;(#/
+
;LOG
=
P(
PKTPKT
; ( =
+
0#/
PKT
0
#/
PKT
P( LOG + LOG 0#/ LOG ; (#/ =

0#/ LOG
(#/
P(
;( =
P(
LOG
; ( =
PKTP A G E
PKT
( #/ AQ (#// AQ (#//( AQ (#/ AQ
0#/
P(

LOG
LOG+
+
LOG
LOG0
LOG ; (#/ =
P(
#/ LOG ; (#/ =
P+A (#/
• Buffered formate brines are 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 CO2 have confirmed that the pH
never drops below 6–6.5. This pH is still close to neutral,
meaning that this brine system cannot be “acidified” to
any great extent by exposure to CO2.
P+A (#//( PKT
PKT
PKT
• Unbuffered formate brines: The pH of these brine
systems behaves very much like halide brines when
exposed to CO2 gas. 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.
8
F O R M AT E
B R INE S
–
COMPATI B I L I TY
W I TH
ME TAL S
P(IN6ARIOUS"RINE3YSTEMSASA&UNCTIONOF#/)NFLUX6OLUME
"UFFEREDFORMATE
P(
#/MAINLYCONVERTEDTO
BICARBONATE(#/
WHICHDOESNOTPROMOTECORROSION
P( 5NBUFFEREDFORMATE
P(
#/MAINLYCONVERTEDTO
CARBONICACID(#/
WHICHPROMOTESCORROSION
#ALCIUMBROMIDE
"",'ASI NFLUX"",BUFFEREDFORMATEBRINE#/ ª#ª&ATM
)NCREASINGTIMEOF#/INFLUX
Figure 3 pH as function of CO2 influx in a typical halide brine, an unbuffered formate brine, and a buffered formate brine.
Influx of CO2 into a wellbore is often accompanied by
hydrogen sulfide (H2S). H2S is a very weak acid with a pKa1 at
around 7. H2S corrosion 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. Overtreatment with potassium carbonate is most often not a
problem.
PA G E 9
F O R M AT E
B R IN E S
–
COMPATI B I L I TY
W I TH
ME TAL S
6 Corrosion in Formate Brines in
the 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 218°C / 425°F, 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.
Table 3 General corrosion rates of C-steel in formate brines.
Density
Fluid
NaFo
CsFo
CsFo + 5% KCl
CsFo
CsFo
CsFo
CsFo
s.g.
ppg
1.26
10.5
2.18
18.2
1.94
16.2
pH
(diluted
1:10)
10.0
12.0
10.5
12.0
10.0
10.0
Temp.
days
°C
°F
163
163
177
177
191
204
218
325
325
350
350
375
400
425
P-110
7
7
40
7
?
17
30
C-110
mm/y
MPY
0.008
0.000
0.076
0.003
0.005
0.008
0.177
0.3
0.0
3.0
0.1
0.2
0.3
7.0
Q-125
mm/y
MPY
mm/y
MPY
0.065
1.0
0.051
2.0
Table 4 General corrosion rates of CRAs in formate brines.
Fluid
KFo
KFo
NaFo
CsKFo
+ 3 g/L ClKFo
KFo
CsFo
CsFo
CsFo
CsFo
Density
s.g.
1.26
1.57
1.26
ppg
10.5
13.1
10.5
1.95
pH
(diluted
1:10)
Temp.
days
9.8
9.8
10.0
°C
66
66
163
°F
150
150
325
30
30
7
16.2
10.4
165
329
30
1.26
1.57
10.5
13.1
9.8
9.8
10.0
10.0
1.94
16.2
185
185
191
204
204
218
365
365
375
400
400
425
30
30
?
17
7
30
13Cr
mm/y
0
0
0
MPY
0
0
0.0
Modified
13Cr
mm/y MPY
0
0.0
0.01
0.39
22Cr
25Cr
mm/y
0
0
MPY
0
0
0
0.043
0
0.003
0
1.7
0.0
0.1
0
0
0.03
0.03
0
0
1
1
9.25
364
0.41
16
• Shaded area = outside the operating envelope of the specific CRA
PA G E 1 0
mm/y
MPY
0.076
3
F O R M AT E
B R INE S
–
COMPATI B I L I TY
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 204°C / 400°F 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/ZnBr2 brine 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 bromide
was 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.
W I TH
ME TAL S
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 204°C / 400°F 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 5 General and localized corrosion on C-steel (P-110)
exposed to inhibited and uninhibited calcium/zinc bromide and
cesium formate brines at 204°C / 400°F.
Test Fluid
Uninhibited CaBr2/ZnBr2
Inhibited CaBr2/ZnBr2
Cs formate
PA G E 1 1
General
corrosion
rate
mm/y MPY
0.84
33
0.66
26
0.008
0.3
Rate of
maximum
penetration
mm/y MPY
7.72
304
13.1
517
(#/ ( ←⎯⎯→ (#/

P+A
F O R M AT E
B R IN E S
–
(#/
COMPATI B I L I TY
PKT
( #/
W I TH
ME TAL S
PKT
#/ G #/ AQP+A

#/ ( ←⎯
→ (#/3
PKT
P+⎯
A
#/ ( ←⎯
⎯
→ (#/3
PKT
A
#/ AQ (/ (P+
#/
AQ
PKT
#/ ( ←⎯
PKT

⎯→ (#/3
(#/ by the carbonate buffer
P+A acid
#/will
Carbonic
then be consumed
(#/
P+A
#/
+A

following
according
to⎯
the
(
⎯
→
(#/
AQ
reaction:
( AQ
PKT
#/ AQ ←
(#/
P+
P+A
A #/
(#/ ( ←P+
⎯⎯
→ (#/
PKT
A
(#/
(
←
⎯
⎯
→
(
#/
PKT

P+A AQ → (#/
OKT
#/
(6)
#/
AQ
(
AQ
(#/ ( ←⎯⎯→ (#/
PKT
P+

P+

P+A
(#/
(
#/
( ←
#/
(
←
⎯
⎯
→
(#/
PKT
#/
⎯
⎯
→
(#/
PKT
3
3
P+A case
( #/favorable
+ P+

(#/
⎯
In this
the
pH
will
remain
at PKT
about
the upper
(
⎯→
(#/
#/
A G ((#/
/
↔←
(#/
AQ
#/
(3 AQ
PKT
P+#/
(

P+

P+
(= P+
buffer
and
CO
corrosion
will
not
#/#/
(#/#/
P+
take
( ←⎯⎯→ (#/3
2(#/
A→
#/
level
←⎯
⎯
(#/
PKT
PKT
#/
(
#/
AQ
AQ
=A10.2)
G
3

PKT
#/
G
#/
(#/
P+until
#/
place
the
carbonate
component
of the pH buffer is
P+ P+
PKT

#/;(
GA = ⋅#/

⎯→

(#/
AQ
(3).
←
(→
#/( #/
PKT
; (#/
= Figure
(⎯
←⎯⎯
PKT
(#/
P+
#/
(#/
overwhelmed
(see
(#/
P+
#/
A
A AQ #/
(
/
(
#/
AQ
+
P+
( / ( #/
PKT
AQ
PKT
#/(#/
AQ 0
PKT
⎯
→ ( #/
( ←
⎯
PKT

#/
P+
( #/

P+
#/ AQ
(
AQ A#/ (#/
( / P+
PKT
P+
(#/
(
#/
←⎯⎯→ (#/
Aportion
(#/
(
←⎯
⎯
→
(
#/
PKT
(#/buffer
((the
Once the
carbonate
of
the
formate
brine’s
+A

+
A → (#/

(
#/
AQ
←
⎯
⎯
AQ
(
AQ
PKT
P+Abuffer
(#/
(
#/
AQ
(#/
AQ ←⎯
⎯
→ (#/
( AQ
G
been
upper
level)
has
orPKT
consumed,
the
PKT
#/
#/
AQ
overwhelmed
+
A =

;(
P(
LOG
PKT
( #/
←
⎯
⎯→
(#/
AQ
(AQ AQ
PKT
#/
#/
P+A
PKT
( #/
P+
AQ
(#/
(
#/
G
A
pH will
decrease according to the following
equations, (#/
which

AQ
OKT
G#/
#/
AQ
AQ
#/#/
(
#/
→
(#/
AQ
OKT
#/
AQ
(AQ
/ →
( #/
AQ AQ
#/
(
(#/
PKT
PKT
AQ
are
also
valid
for
unbuffered
brines:

#/
AQ
(; (#/
/ ( #/
PKT
OKT
0#/
P( LOG
(
LOG#/
LOG
= AQ
PKT
#/
AQ
+
AQ
PKT
#/
#/
G #/ AQ
#/
G AQ → (#/
AQ
#/ AQ ( (
/
(#/
AQ
++ #/
AQ←
⎯
⎯→ (#/
AQ
(
AQ
PKT
PKT
#/
G
(
/
↔
(#/
AQ
(
AQ

AQ +( AQ
PKT
PKT
/ ↔
AQ
+ (#/
0#/AQG (((#/
#/
( #/ AQ
( #/
←⎯
⎯→ (#/ AQ
((7)
AQ AQ ( /
#/
/
(
AQ
PKT

#/
PKT

#/ G ( / ↔
AQ
(AQ
AQ → (#/
+ (#/
PKT
(
AQ
OKT
(#/
AQ
( #/ AQ ←#/
⎯
⎯→
AQ#/
( AQ
PKT
7 Corrosion in Formate Brines
Contaminated with CO2
Carbon dioxide (CO2) influxes emanating from leakage of
reservoir gases into the well environment are common
sources of corrosion in carbon and low alloy steels. The
consequences of a CO2 leakage into a halide-based
completion fluid can be catastrophic for the integrity of
sub-surface equipment and tubulars.
A
A
A
A
A
A
Both pitting and stress corrosion cracking (SCC) can occur in
CRAs that have been exposed to CO2 and halide brines. For
some years it was thought that the incidence of localized
corrosion of CRAs would be restricted to wells where
chloride brines became contaminated with oxygen. More
recent research has revealed that bromide brines may cause
pitting and SCC in the presence of CO2 as well [5].
A
A
A
A
+ A

A
A

+A
#/
AQ
→ (#/

AQ
AQ
←⎯
⎯
→ (#/PKT
OKT
#/
AQ
((
AQAQ
(#/
+(
AQ
AQPKT
#/
AQ ( AQ
#/
;⎯
→(#//
((#//(
AQ
((#/
AQ
#/
; (

=←
(#/
== AQ
(
=⋅⋅;⎯
(#/

+ A

=
( AQ
#/
; ((#/
P(
#/
( /
↔
AQ#/
(9)
G ( / ↔ (#/ AQ ( AQ
PKT
PKT
P(
LOG
LOG
G
PKT

; ( = ; ( =⋅ ; (#/ =
&E
&E AQ ( G (#/
PKT
#/
AQ+→
AQ
P((
LOG
PKT

; ( =
PKT
0#/
; ( = ⋅ ; (#/ =
+
P( LOG ; ( =

PKT
PKT

PKT
LOG +0 LOG
0 LOG
P(
=
PKT
; ( = ⋅ ; (#/ =
; (#/
P(;
=LOG
+ #/
LOG
LOG
; (#/
(
⋅ ; (#/
=
#/&E
=( G #//(
+
&E
AQ
00#/
→
AQ

AQ PKT
+
(#//(
PKT
PKT
P(
LOG
+ LOG
(10)

#/ LOG ; (#/
=
0
0#/ P(
#/
PKT
LOG + LOG 0 LOG ; (#/ =
In the oilfield, aqueous fluids that have been acidified by an
influx of CO2 are known to cause high rates of general
corrosion and pitting corrosion.
There are two factors determining whether or not a completion
brine will inhibit CO2 corrosion. These are:
1.The ability of the brine to maintain an alkaline pH.
2.The ability of the brine to facilitate the quick formation of a
protective layer on exposed metal surfaces in the case the
CO2 influx is significant enough to lower the pH.
In field environments the likelihood that a buffered formate
brine would ever receive a CO2 gas influx large enough to
overwhelm the buffer is very low. Nevertheless, substantial
research has been concerned with looking at the consequences
of a CO2 influx sufficient to overwhelm the upper buffer level of
buffered formate brines [6][7]. Leth-Olsen, of Hydro Corporate
Research Centre, Porsgrunn, discovered in 2002 that a
protective layer of iron carbonate forms very quickly (within a
couple of days) on both C-steel and 13Cr steels in a buffered
formate brine exposed to a massive CO2 challenge. The
presence of the carbonate/bicarbonate buffer therefore not
only reduces the level of brine acidification in the presence of
CO2, but also plays a very important part in the formation of
the high quality protective carbonate film on the steel
surfaces as the acidification progresses and initial corrosion
occurs. When CO2 enters into the buffered formate brine,
carbonic acid will be formed according to Equations 3 and 4.
=
LOG ; (
P(
P+
#/

PKT
A → (#/
(#/
0
#/
(
←
⎯
⎯
#/
PKT
0#/
P(
3
; (=
(#/
LOG
PKT
P+
0
#/
A0 &E#/
P+A

#/
(#/
↔
Sbe
seen
PKT
⎯
#/
⎯
(#/
From
Equation
10
it(#/
can
that the
pHPKT
at
which the fluid
#/&E
(
←
→
PKT
#/
(
←
⎯
→
(#/
⎯
3 + 3LOG
PKT
P(

LOG
; (#/P(
0#/ LOG
;
=
P( LOG (
= LOG ; ( =
PKT

(#/
P+

eventually
stabilizes
doesn’t
only
depend
on
the
partial
#/
(
#/
AQ
(#//
AQ
(#//(
AQ
(#/
AQ
A

PKT
PKT
#/
0#/LOG
P( AQ
LOG
+

LOG
;
(#/
=

(
(#//
AQ
(#//(
AQ
(#/
AQ
PKT

AQ
(#//
(#/
AQ (#/
3 G
( (
#/
PKT
AQ (#//(
(
3
AQ
AQ
AQ
(
CO
(#//
(#//(
AQ PKT

PKT
pressure
of#/
), but
also
on
the concentration
ofAQ
#/
P+AP(
#/
(#/
P+
AQ
2 ( 0#/(#/
(#/
P( LOG
+ LOG 0#/ LOG ; (#/ =
P+A LOG ; (#/
PKT
A LOG
+ LOG
0#/
=

(#/
(
←
⎯
⎯
→
(
#/
0
PKT
bicarbonate
(
).
In
buffered
brines
the
effect
of
high
(#/
(#//( P+A #/
(#/P+
P+
A
P+
P+
(
#/
P+
(#//(
A
A − + (#//(
A
A P+
P+3Asubsequent
(
#/

P+

A→
⎯
Aoffset
(
⎯
AQ
+
(
AQ
(#/
(#/
←
→
(
P+
AQ
(
⎯
⎯
0
to(
a(3
large
a(#//(
very
high
(#/
←
(
←
→
(influx
#/
P+
PKT
0
#/
AQ
(#//
PKT
AQby
PKT
AQ(#/
(#/
#/
PK
A ⎯
#/
#/
⎯
AQ
(#/
is
A (#//(

P+

(#/
(
#/
pH
AQ
AQ
(
(#/
exposed
AQ AQ PKT
A(#/ AQ &E
AQ concentration.
measurements
on
formate
brines
(#//
(#//(
(
#/
→
&E
AQ

G
(#/

PKT
&E (#/ AQ → &ECAT AQ ( G (#/ PKT
PKT
AQ

AQ
#/
&E
Awide
(
AQ
/
→
&E
AQ
CO
(2G
(P+
(#/
#/
(
and

P+A(
(#/
(#//(
PKT
PKT
(
P+
(
#/
of
PKT
(#//
AQ (#//( AQ (
(#//
temperature
AQ
(P+
⎯→
(#/
AQ
G
(#/
G
(#/
#/
to
a
range
at
pressures
up
A←
AQ
(#//
AQ
(
(#//(
AQ
partial
#/
AQ
(
#/
&E
AQ
(#/
(
A AQ
#/ AQ → &E AQ
PKT
PKT
AQ →
&E
AQpH

( formate
G
#//(
AQ
#/
MPa
GA (
#/
(#//(
#/
psi
shown
P+
of
AQ
&E
to 4P+
/580
have
that
the
A (#//(
brines
&E (#//(
AQ → &E AQ ( G #//(
AQ PKT

P+
P+A (#//( PKT
&E
(
#/
AQ
&E
AQ
(
(G#/
AQ
(#/
PKT
AQ
#/P+
#/
GA
#/
←
AQ
CAT
PKT
AQ
G#/
drop
#/
below
#/
PKT
P+
G
A regardless
AAQ
&E
((#//(
(#//(
AQ
AQ
→6–6.5
&E

(
G
#//(
#//(
does
not
(diluted
and
PKT
⎯
(#//(
→
G (#//(
→
( &E
AQ
(
AQ
PKT
undiluted),
→ &E

&E
#/
↔
&E#/
S
PKT
#/ &E
AQ((#/
/ (AQ
( G PKT
→
&E
AQ
(#/
AQ
#/
AQ
PKT
of the
initiallevel of carbonate/bicarbonate
buffer [7].

&E#/
S

PKT
#/&E
&E
AQ
(
(#/
(
#/
AQ
(#//(
AQ
→ &E(#/
AQ
PKT
((G#/
PKT
#//(
AQ AQ
#/
AQ
(
/↔
(&E
#/
AQ
AQ → &E
( G (#
/
#/
AQ
&E
AQ
PKT

(→
3 &E
G AQ
(S3
( G PKT
&E #/
#/+A↔
↔
&E#/
PKT
AQ
PKT
&E#/
&E
S
PKT
&E AQ(#//(
AQ →AQ
&E
AQAQ
( G PKT
#//(
AQ PKT
( #/
←⎯
⎯→ (#/
(
Conventional
completion/packer
fluids
based
on
divalent
P+

+ A 3 AQ
&E#/
− G (
3(#//(
←
G AQ
+⎯A
&E
(#//(
AQ → &E AQ ( G #/
&E
S+#//(
PKT
PKT
&E
⎯
AQ
3
→
&E←
(
AQ
→
↔
AQ
( #/
#/
AQ
⎯
(#/
AQ
#/
AQ
(3
(
(
→
←(
⎯
→
AQ
A
(
(AQ
AQ
⎯
⎯
(+ PKT
AQPKT
like
(#/
AQ PKT
PKT
halide
brines
expected
to
behave
almost
pure
water

are
3
(
3
AQ
( &E
3 AQ
GG
AQ
OKT
PKT
PKT
#/
(
(
#/
AQ
→
(#/
AQ
#/
↔
&E#/
S
PKT
on contact
with
as they
be
buffered
with
2 gas,

CAT

P+A CO

AQ
+cannot

((3
3
G− (#/
3
PKT
OKT
(#//
←AQ
⎯→
AQ
(
G PKT
&E
↔ &E#/ S
#/&E
AQ
AQ
(
#/
AQ
(#/
+
#/
AQ
(
→((
(#/
AQ
OKT
↔
&E#/
→
SAQ
AQ
PKT
3
⎯
⎯
→
AQ
/
#/
(
#/
(
PKT
#/
AQ
←
+
carbonate/bicarbonate.
a typical
CO2PKT
influx
the rapid
P+
P+AA
−−Upon
++

(
3
G
(
3
AQ
(3
←
⎯
(
PKT
AQ
←
⎯
⎯
→(3
(3
AQ
+
AQ
→
PKT
#/
GAQ
(
/⎯
↔
(#/
AQ CAT
AQ
( +
AQ
( AQ
PKT
P+A
+
move to the
left
carbonate
bicarbonate
+
+ in the ←
(#//(
⎯
→⎯
#/
( −GAQ
(equilibrium
PKT
G
AQ
←
⎯→
(3
+(
AQ
(PKT
CAT
( 3

GG/↔
((#/
PKT
3
3 AQ
3
3
#/(
(#//
G
(
AQ
AQ
(
AQ
AQ
P+AQ
(
/←
⎯→
PKT
(PKT
#/
(AQ
↔
((#/
+ AQPKT
(#/
− drop
/
G
A
(Equation
5)
will
cause
a
in
pH,
sufficient
for
CO

CAT

2
(
3
⎯
→
(3
AQ
+
(
AQ ←⎯
CAT
AQ
PKT
PKT
PKT
(#//
AQ
(
/
←
⎯→
(#/
AQ
(
G
(#//
AQ
=( /
←⎯→ (#/
(
AQ
G P+A
CAT
P+Aensue.
( =←
⋅ ; (#/
corrosion
to
of⎯→
bicarbonate,
AQ
(+ (lack
(#/
AQ
the
←
(final
⎯
G→PKT
(#//
( 3
AQ
(3 − AQ + (+ AQ
(
3; AQ
⎯
⎯
→
(3 −Due
AQto
+ the
AQ
←
/
⎯
PKT
CAT
+
PKT
⎯→

PKT
#/ CAT
(#//(
(
G
0←
PKT
pH
of
brine
will
depend
(#/
AQ
(
/ ←⎯→
(#/
AQ ( Gmainly
; ( (#//
= ;⋅ (
;the
(#/
= #/
⋅acidified
;
=
halide
therefore
=
CAT
CAT
+ (#//(
+ ←
PKT
⎯
→
#/
GG CAT

CAT
PKT
PKT
(#//(
⎯
→
#/
(⎯
PKT
(
CAT
0#/
→
(#//(
←
#/and
PKT
(#//
AQlower
PKT
( / ←⎯→
(#/ AQ ( G
on
the
CO
pressure
(Equation
10),
significantly
0←
(#//
AQ
#/
( /
←⎯→
(#/
((be
GG
2
AQ CAT
PKT
(#//(
←
→ #/ brines.
( G
⎯formate
than
in buffered
P(
LOG
PKT
; ( =
CAT
CAT
→ #/ ( G
(#//(
←⎯
PKT
(#//(
←
⎯→
#/ ( G
; ( = ; ( =
P( P(
LOGLOG
PKT
PKT

A common
by new
usersPKT
of formate brines is
P(
LOG + concern
LOG 0#/voiced
LOG ; (#/
=

formic
acid
will
always
be
present
with the
PKT
PKT
P( that
LOG
+
LOG
LOG
;
(#/
=
0
P(
corrosive
LOG
+0
#/
LOG
LOG
;
(#/
=
#/ 0
formate
in(#/
solution
because of the following equilibrium:
#/

0#/ 0#/ (#/(#/
(#/ AQ (#// AQ (#//( AQ (#/ AQ
(11)
PKT

(#/
AQ (#//
AQ
(#//(
AQ (#/
PKT
(#/
AQ
(#//
AQ
(#//(
AQ
(#/
PKT
AQ AQ
Corrosion rates of carbon and low alloy steels in aqueous
environments containing CO2 can reach high levels (thousands
of mils per year), but the corrosion can be effectively reduced by
the formation of a protective layer of iron carbonate on the
metal surfaces, particularly at elevated temperatures.
7.1 CO2 Corrosion

G (AQ
/↔
(#/
AQ OKT
PKT
AQ (
+ #/ AQ #/
( #/
→
(8)(#/
PKT
AQ
PKT
;( =0
⋅0;#/
(#/ = +

#/

+
#/
( #/ AQ → (#/ AQ
#/ AQ ( #/#/
AQ
(#/
G →
(
↔ (#/
OKT
( PKT
AQ AQ PKT
/
AQ
AQ
0#/
+ P+A (#/
P+
;
A (#//( ( = ⋅ ; (#/
=
#/ G ( /
↔
(#/
AQ
(
AQ
PKT
+
+
PKT
+
0

Buffered formate brines are very different from halide brines
in the way their corrosivity is influenced by a CO2 influx. The
difference is mainly due to the influence of the carbonate/
bicarbonate pH buffer.
P+
is a weaker
P+A (#//(
formic
acid
Since
acid than
A (carbonic
#/ acid
P+A(P+
(A#/
P+
(#//(
<
),
formic acid
(
#/
P+
(#//(
A
A
&E
only
( #/
→
&Esmall
AQequilibrium
( G amounts
(#/ AQ
can
exist
very
even
when
PKT
AQin

&E the
( #/
AQbrine
&E
AQ (
G
(#/
AQ
formate
is
exposed
to
a
high
CO
concentration.
&E
(#/
→
AQ&E
→
AQ

(
G
(#/
AQ
PKT
PKT
2

&E
(#//(
AQ →
&E AQ
( G #//(
AQ toPKT
In order
to obtain
a substantial
conversion
of formate

&E &E
(#//(
AQ →
AQ AQ
(
G( #//(
AQ AQPKT
(#//(
AQ&E
→ &E
G #//(
PKT
PKT
PKT
PKT
( 3 G ( 3 AQ
PKT
( 3(G3 G( 3(AQ
PKT
PKT
3 AQ
P+A
( 3 AQ ←⎯
⎯→ (3 − AQ + (+ AQ
PKT
P+A P+A −
( 3(
AQ3 ←
⎯
(3
AQ− +AQ(++ AQ
AQ
⎯
←→
⎯⎯
→(3
(+ AQ PKT

&E #/ ↔ &E#/ S

PA G E
&E1 2&E
#/
↔ &E#/
↔ &E#/
S
#/
S
P+

A
#/ ( ←⎯⎯
→ (#/3
P+A
#/

F O R M A T PKT
E B R INE S
(#/
P+A
–
COMPATI B I L I TY
P+A⎯
(one with a lower
acid,
(#/
(a stronger
←
⎯→acid
( #/
formic
pKa) would
PKT
#/ ( ←
⎯⎯
→ (#/3 PKT
need to be introduced. An example of this would be
P+

A

←
⎯
#/
(
⎯→(#/
P+
PKT
(#/
((#/
hydrochloric
acid
The
presence
of a very
small amount
3
(HCl).
#/
P+AA #/
of formic acid has actually proven to be a benefit in promoting

P+A
PKT
#/
G #/
AQ
iron
P+
(#/
(
⎯→
((#/
#/ films that
#/
PKT
the
formation
of
carbonate
protect steel
A
←
⎯
surfaces against CO2 corrosion [7].

P+
#/
(
/ (
AAQ
( #/
P+AAQ (#/
(→
PKT
(
#/
(#/
←
⎯⎯
#/
PKT
W I TH
ME TAL S

• Amount of carbonate in the fluid. 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.
It is important
to keep in mind that the main purpose of the

PKT
#/
#/+⎯
AAQ

(
→in
(#/
( AQis
to maintain
G
PKT
#/
AQ ←⎯
AQ buffer
formate
a high pH so
P+
(#/
(brines
#/
A provided
that
CO
corrosion
is
prevented.
In
a
realistic
field situation the
2 ( / (#/ AQ

#/
AQ
PKT
OKT
#/ AQ ( #/ AQ → (#/ AQ likelihood
that aAQ
buffered
formate brine wouldPKT
ever receive a
Buffered formate brines that are exposed to a large amount
#/ G #/
+A
enough to overwhelm the buffer is low.
CO
influx
of CO2 form a higher quality protective layer than other
+ large
2 gas
( #/
AQ
←
⎯
⎯
→
(#/
AQ
(
AQ
PKT
#/ G ( / ↔ (#/ AQ ( AQ
PKT
(Figure
Traditional
high-density halide-based
brines do not
acidified completion brines because they provide both a
#/ AQ3).
(
PKT
/ (#/ AQ

OKT
#/ this
AQ advantage,
( #/ AQand
→ CO
(#/
have
commence after
higher amount of carbonate (see bullet point 2 above – effect
will
AQ
2 corrosion
+influx
A

even
a
minor
of
CO
.
of buffer) and a higher rate of initial corrosion (see bullet point
;
(
=
⋅
;
(#/
=
2
(#/ AQ ( AQ
(
#/ AQ ←⎯
+⎯→
PKT
+
PKT
#/ G (0 / ↔ (#/ AQ ( AQ
PKT
3 above – the additional small amounts of formic acid seem
#/
Even
a CO
influx
is sufficient enough
to overwhelm
the
not only to slightly increase the initial high corrosion rate but
#/if AQ
2 (
OKT
#/ AQ → (#/ AQ

carbonate
component
of the powerful pH buffer, a protective
also to significantly further promote the formation of the iron
=
; (LOG
= ⋅ ; (#/
;
=
P(
(
PKT
+
PKT
0#/ +layer will
iron carbonate
form much
faster
and much more
carbonate layer).
#/ G ( / ↔ (#/ AQ ( AQ
PKT
than in other high density
efficiently
in
a
buffered
formate
PKT
P( LOG + LOG 0#/ LOG ; (#/ =
7.1.1 CO2 Corrosion of C-Steel
completion
Here is why:
=
P( LOG ; (brines.
PKT

0#/ ; ( = ⋅(#/
; (#/
=
If the carbonate component of the buffer in a formate brine is
+

PKT
PKT
0#/
0
P( carbonic
LOG +
LOG
LOG
;
(#/
=
Both
acid
and
formic
acid
are
known
to
be
corrosive
overwhelmed by CO2 influx, the pH will start decreasing and
#/

to
lower
alloyed
steels
and
to
some
CRAs,
such
CO
(C-steel
#/ AQand
(#//
AQ
(#//(
AQ
(#/
AQ
PKT
2 corrosion will take place according to Equations 12 and 13.

0 (#/
as#/13Cr,
at elevated
temperatures. The corrosion takes place
An initial period of high general corrosion will be experienced
P( LOG ; ( =
PKT
P+A (#/
according
to
following mechanisms,
prior to the build-up of the protective iron carbonate layer.
P+A (#//(respectively:
the
(#/ AQ (#// AQ (#//(
AQ (#/ AQ
PKT
For C-steel this initial phase of high rates of general corrosion

PKT
P( LOG + LOG 0#/

LOG ; (#/ =
(12)
is readily measured by short-term weight loss tests. There are
&E
(
#/
AQ
→
&E
AQ

(
G
(#/
AQ
PKT
P+A (#/ P+A (#//( cases in the oilfield literature where exaggerated and

0#/
(#/

PKT misleading CO2 corrosion rates have been reported with

&E
(#//(
AQextent;
→ &E
AQ ( G #//(
AQPKT
and
lesser
&E to
(a#/
AQ → &E AQ ( G (#/ AQ
formates as a consequence of measuring the short-term

(#// AQ (#//( AQ (#/ AQ
( #/#/
AQ
&E ↔
PKT
(#//(
AQ&E#/
→ &E
AQ PKT
(13) PKT
weight loss and then extrapolating this rate linearly over time
S AQ ( G #//(
to create annual corrosion figures. It has therefore been

( #/
P+
3
AQ
P+A (#//(
up
in solution
(
iron
(
AG
liberated
&E
#/
↔
PKT
PKT
3
&E#/
Ferrous
builds
advised [6][7] not to use standard short-term weight loss
Sby these reactions
and eventually reaches a level at which the solubility of iron
methods to predict long-term CO2 corrosion rates for C-steel
P+3
− +
A AQ

(3
3 G
←(⎯
(
→
(3&E
AQ
+ (on
AQ
&E
(#/
exceeded
AQ
→
AQ

( corroding
GPKT
(#/
PKT
PKT
AQ
AQ
carbonate
is⎯
locally
the
surface.
in formate brines.
Furthercorrosion
will− then
cause
the build-up of an iron
P+A
+
CAT

( 3 AQ←
(3
⎯→
AQ+(#/
( AQ
PKT

(#//
AQ⎯
⎯
→
(AQ
/
←
AQ
PKT
&E
(#//(
→
&E
AQ

( (
G G#//(
AQ PKT
carbonate
layer
on
the
steel
surface:
Compared with halide brines, formate brines have been

CAT

PKT
shown to be much less aggressive to C-steel, even in tests
(#// AQ CAT
( / ←⎯→ (#/ AQ ( G
PKT
→ #/ ( G
⎯
(#//(
S
&E #/←
↔ &E#/
(14)
where high CO2 additions have decreased the pH to the
PKT
CAT
lower buffer level [8]. Figure 4 shows photos of 1.5 mm thick
PKT
(#//( ←⎯
→ #/ ( G
( 3 G (or 3additionally
AQ
Alternatively
to the formation of
this iron
C-steel coupons that have been exposed to 1.53 s.g. / 12.8
PKT
can be formed.
carbonate layer a magnetite (Fe3O4) layer
ppg calcium bromide and potassium formate brines acidified
P+A
( 3 AQ ←⎯
with CO2 at temperatures varying between 120°C / 248°F and
⎯→ (3 − AQ + (+ AQ
PKT
Both the iron carbonate and the magnetite films are known to
180°C / 356°F [7]. The coupon to the left shows severe

CAT
be
extremely
efficient
inhibiting
localized corrosion attacks on the coupon that was exposed
(#//
AQ ( / ←in⎯→
(#/further
AQ corrosion.
( G PKT
to the bromide brine, and the coupon to the right shows that
CAT
Factors
that
will→influence
quality
of the film
are [7]:
only general corrosion has taken place in the potassium
PKT
(#//(
←⎯
#/ (the
G
formate brine. A SEM photo of an iron carbonate layer
• Volume to surface ratio. The ratio between
formed on C-steel in a formate brine is shown in Figure 5.
the solution
volume and the area of steel exposed to the fluid. This is
The film is very dense, of thickness 5 to 20 µm. By comparison,
not a variable in an annular well environment, and it is
the surface layer that was formed in the calcium bromide
therefore important to accurately reproduce this in a
brine was found to be of a duplex structure with a thickness
laboratory test environment. 2–4 mL/cm2 is an acceptable
of 100 to 200 µm. Table 6 shows weight loss data and actual
range. Using higher ratios will generate misleading
local corrosion rates for the same coupons. Adding a
corrosion predictions. As an example, increasing this ratio
commonly used corrosion inhibitor to the bromide brine did
by a factor of 10 (typical ratio used for corrosion testing =
not improve the performance or stop the localized corrosion.
20 mL/cm2), has been shown to double the measured
No additional chloride was added to the brines used in these
corrosion rate of 13Cr steel at 120°C.
tests.
PA G E 1 3
F O R M AT E
B R IN E S
–
COMPATI B I L I TY
W I TH
ME TAL S
Corrosion
film
CaBr2
C-steel
K formate
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 CO2 influx at 120°C / 248°F, with an excursion
to and from 180°C / 356°F [7]. Severe localized corrosion
attacks are seen in the calcium bromide brine. The potassium
formate brine only caused general corrosion. (The CO2 influx
was 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 μm.
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 CO2 influx. The experiments were
commenced at 120°C / 248°F, with an excursion to and from
180°C / 356°F [7].
7.1.2 CO2 Corrosion 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 CO2 appear 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 120°C / 248°F to 180°C / 356°F.
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.
Corrosion rate
Fluid
Average rate
mm/y
Deepest attack
MPY
mm/y
1)
MPY
CaBr2
0.39
15.4
>8.7
>3421)
CaBr2 –
inhibited
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 CO2 are 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 was
formed on the metal surfaces exposed to the formate brines
within the first 20–30 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.
A SEM photo of the film formed in the formate brine is shown
in Figure 8. This film is thicker (100 μm) than the one seen on
C-steel, and the film quality and ability to inhibit corrosion are
not quite as good.
PA G E 1 4
F O R M AT E
B R INE S
–
COMPATI B I L I TY
W I TH
ME TAL S
)NITIAL#/#ORROSIONIN&ORMATESAND"ROMIDES
+&OSG ª#
+#S&OSG ª#
#A"RSG)NHIBITEDª#
#ORROSIONRATE;-09=
#ORROSIONRATE;MMY=
#A"R SG5NINHIBITED ª#
+#S&OSGª#
4IME;HOURS=
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 CO2 influx. 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 CO2 corrosion.
Corrosion
film
13Cr
CaBr2
K formate
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 CO2 where 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 was
The thickness is about 50–100 μm.
PA G E 1 5
F O R M AT E
B R IN E S
–
COMPATI B I L I TY
W I TH
ME TAL S
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
CaBr2
CaBr2-inhibited
KFo
KCsFo
KCsFo
Temp [°C]
days
120 – 1801)
120 – 1801)
120 – 1801)
150
175
62
62
50
34
34
Corrosion rate
Average rate
At deepest attack
mm/y
MPY
mm/y
MPY
0.061
2.4
2.1
83
0.055
2.2
2.6
103
0.72
28.3
----0.249
9.8
----0.119
4.7
-----
1) These tests were run at 120°C / 248°F, with a quick ramp-up to 180°C / 356°F and down again after 1,000 hours in the bromides and 700 hours in the
formates.
7.1.3 CO2 Corrosion of Higher Alloy Steels
7.1.4 CO2 Corrosion Rates
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 for
22Cr). The layers formed on these metals are of the thicker
variety (about 50–100μm). 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 CO2 influx.
General corrosion rates in formate brines as a function of
temperature and level of CO2 influx 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 H2S in the headspace
and with and without chloride contamination in the formate
brine. Neither H2S nor chloride contamination appear to have
any significant impact on the CO2 corrosion 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 influenced
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.
Corrosion
film
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.
22Cr
When using measured CO2 corrosion 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.
Figure 9 SEM photo of iron carbonate protective layer formed
on 22Cr in a potassium/cesium formate brine where pH was
The thickness of the layer is about 50–100 μm.
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 CO2 influx, 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 CO2 into 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.
PA G E 1 6
F O R M AT E
B R INE S
–
COMPATI B I L I TY
W I TH
ME TAL S
#/CORROSIONRATEOF#3TEELIN"UFFERED&ORMATE"RINES
4EMPERATUREª&
&ORMATEBRINESWITHINTACTBUFFER
!FTEREXTENDEDTIMEPERIODWITH#/(3INFLUX
#ORROSIONRATE-09
#ORROSIONRATEMMY
4EMPERATUREª#
Figure 10 Measured general corrosion rates for C-steel in buffered formate brines with various levels of CO2 influx 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.
#/CORROSIONRATESTANDARD#RIN"UFFERED&ORMATE"RINES
4EMPERATUREª&
4YPICAL/PERATING7INDOW
#ORROSIONRATEMMY
4EMPERATUREª#
#ORROSIONRATE-09
Figure 11 Measured general corrosion rates for 13Cr in buffered formate brines with various levels of CO2 influx 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.
PA G E 1 7
F O R M AT E
B R IN E S
–
COMPATI B I L I TY
W I TH
ME TAL S
#/CORROSIONRATEOFMODIFIED#RIN"UFFERED&ORMATE"RINES
4EMPERATUREª&
#ORROSIONRATEMMY
4EMPERATUREª#
#ORROSIONRATE-09
Figure 12 Measured general corrosion rates for modified 13Cr (1Mo and 2Mo) in buffered formate brines with various levels of CO2 influx 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.
#/CORROSIONRATEOF#RIN"UFFERED&ORMATE"RINES
4EMPERATUREª&
#ORROSIONRATE-09
#ORROSIONRATEMMY
4EMPERATUREª#
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.
#/CORROSIONRATEOF#RIN"UFFERED&ORMATE"RINES
4EMPERATUREª&
#ORROSIONRATE-09
#ORROSIONRATEMMY
4EMPERATUREª#
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.
PA G E 1 8
F O R M AT E
B R INE S
–
COMPATI B I L I TY
7.2 Impact of CO2 on 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 to
buffered 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 160°C / 320°F over a period of three months
with visual inspection after each month. Testing was done
with 1 MPa / 145 psi CO2 in 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.
W I TH
ME TAL S
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 CO2 is 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 CO2 from divalent halide
brines, and if such an additive did exist, it would deplete over
time if the CO2 influx 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 CO2 had
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 CO2 influx.
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 CO2 headspace. Temperature = 160°C / 320°F, 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.
Results [SCC]
KCsFo +1% ClCaBr2 + 1% Cl-
Test specimen
1 month 1)
Modified 13Cr-1Mo
Duplex 22Cr
Duplex 25Cr
2 months 1) 2)
Modified 13Cr-1Mo
Duplex 22Cr
Duplex 25Cr
3 months 2)
Modified 13Cr-1Mo
Duplex 22Cr
Duplex 25Cr
• crack • cracks at the initiation stage
LC80-130M
EN 1.4462
EN 1.4410
3/3
3/3
No
No
No
No
LC80-130M
EN 1.4462
EN 1.4410
3/3
3/3
No
No
No
No
LC80-130M
EN 1.4462
EN 1.4410
• no cracking
3/3
3/3
2/3
No
No
No
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.
PA G E 1 9
F O R M AT E
B R IN E S
–
COMPATI B I L I TY
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 165°C / 329°F. PCO2 = 4 MPa / 580 psi.
The results are taken from [10].
Results
Pitting
SCC
No
No
No
No
No
No
No
No
Modified Submerged
13Cr-2Mo Liquid/vapor interface
Alloy 718
Submerged
Liquid/vapor interface
ME TAL S
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 140°C / 284°F. The results are shown in
Table 10.
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
165°C / 329°F [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 8.3–8.5, 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.
Test specimen
W I TH
The fact that Centro Sviluppo Materiali observed cracks at
the initiation stage on modified 13Cr-2Mo after 2 months at
140°C / 284°F, and Hydro Research did not on modified
13Cr-1Mo after 3 months at 160°C / 320°F could be related
to the difference in the chloride levels of the two brines (four
times higher in Statoil’s 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.
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
CO2 partial 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:
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].
Temperature
Test duration (months)
RA [%]
EL [%]
No exposure (reference)
52
21
--
1
74
20
No
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
°C
°F
100
212
140
• crack
• cracks at the initiation stage
• no cracking
PA G E 2 0
Cracks (fpbb) testing
P+AA
(#/
#/

P+
P+AA (#/
⎯
(#/ (
( ←
←⎯
⎯
⎯→
→(
(#/
#/

P+
P+AA

(#/
(#/
(
(#/
#/
PKT
PKT
F O R M AT E
B R INE S
–
COMPATI B I L I TY
W I TH
ME TAL S
PKT
PKT
#/
G
#/
G #/
#/AQ
AQ
PKT
PKT
8 Corrosion in Formate
Brines
Contaminated
with
H
S
2
( #/ AQ ←⎯
⎯→ (#/ AQ ( AQ
PKT
8.1 Impact of H2S on General and Pitting Corrosion
#/
#/AQ
AQ ((/
/ ((#/
#/AQ
AQ
Both Statoil (Centro Sviluppo Materiali) [10][11] and Hydro
++A

A
( #/ AQ ←⎯
⎯→ (#/ AQ ( AQ
PKT
Research [15] have included H2S in some of their corrosion
Hydrogen
sulfide,
H
S,
is
highly
towards
metallic
experiments
with CO2 in formate brines. Hydro Research

aggressive
2

OKT
#/
#/ AQ
AQ (
(#/
#/AQ
AQ →
→ (#/
(#/ AQ
AQ OKT
materials.
Depending
upon the material,
H2S can cause
concluded that the presence of H2S had very little impact on
++
pitting corrosion,
general
corrosion,
sulfide
stress cracking
the quality of the protective iron carbonate film that forms on
#/
PKT
#/GG(
(/
/↔
↔(#/
(#/AQ
AQ (
( AQ
AQ
PKT
(SSC), stress corrosion cracking (SCC), hydrogen induced
carbon and 13Cr steel surfaces in formate brines, even in the
cracking
(HIC), stress oriented HIC (SOHIC), and hydrogen
case where pH is reduced to the lower buffer level by

;;(
( ==⋅⋅;;(#/
(#/ ==
+
embrittlement,
and can promote corrosion
fatigue. H2S
exposure to a massive influx of CO2. Only when an extremely
+ PKT
PKT
00#/
#/ concentrations
of only 50 ppmw dissolved in drilling and
high concentration of H2S was applied or at very low CO2 /
completion fluids
can
cause
highly
stressed
steel
to
fail
in
a
H
2S ratios, was localized corrosion experienced. Testing with
;;((==
P(
PKT
P( LOG
LOG
PKT
matter
ofminutes.
PH2S = 2 kPa / 0.29 psi and PCO2 / PH2S = 500 on C-steel
(covering the acid gas content and composition of all

PKT
P(
LOG ; (#/ =
PKT
P( LOG
LOG++ LOG
LOG00#/
#/ LOG ; (#/ =
H2S can enter the
completion or packer fluid either with
production wells in the Gulf of Mexico and the North Sea),

00#/
reservoir
gas
influxes
(along
with
CO
)
or
from
decomposition
standard 13Cr, and modified 13Cr-1Mo showed no impact
(#/
2
(#/
#/
of sulfur-containing additives used as corrosion inhibitors in
from the presence of H2S. At PH2S = 100 kPa / 14.5 psi and

(
AQ
AQ
PKT
halide
(for example
thiocyanates).
A number
AQ
(#/
#/brines
AQ
AQ (#//
(#//
AQ(#//(
(#//(
AQ (#/
(#/
AQ of recent
PKT PCO2 / PH2S = 4, some localized corrosion was experienced.
failures of subsurface well equipment in halide brines have
Corrosion rate results with H2S from both laboratories are
P+
the
#/
P+AA (
(
#/ P+
(#//(
AA(#//(
been
attributed
to the H2SP+
formed
from
thermal decomincluded in the plots in Figure 10 to Figure 14. The small
position of sulfur-based
corrosion
inhibitors
[13][14].
amount of pitting corrosion that was reported by Statoil [11]

&E
PKT
&E (
(#/
#/AQ
AQ →
→ &E
&EAQ
AQ
(
(GG (#/
(#/AQ
AQ
PKT
in the presence of H2S could be promoted by the rather high
H2S is a very weak acid
chloride contamination level in their test brine (saturated).
with pKa1 of about 7,and when
PKT
&E
(#//(
AQ
→
&E
AQ

(
G
#//(
AQ
&E (#//( AQ → &E AQ ( G #//( AQ PKT
introduced into an aqueous solution,
the following equilibrium

will
establish:
&E
PKT
&E #/
#/ ↔
↔&E#/
&E#/SS
PKT
8.2 Impact of H2S on SCC and SSC
(
(33GG (
(33AQ
AQ
(15)
P+
−
+
AA
P+
(
⎯
→
(33AQ
AQ←
←⎯
⎯
⎯
→(3
(3 −AQ
AQ ++ ((+AQ
AQ
The following provides an outline of the cracking of metallic
materials in contact with H2S in 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 H2S influx.
PKT
PKT
PKT
(16)
PKT
PKT
PKT
(#//
(
(#// AQ
AQin
an
(/
/←
←⎯→
⎯→(#/
(#/ AQ
AQsolution,
(
( GG such
Therefore,
alkaline
aqueous
as buffered

CAT
CAT

formate brines,
the dissolved H2S gas will largely exist as
CAT
CAT→ #/ ( G
PKT
(#//(
PKT
(#//(←
←⎯
⎯
-→ #/ ( G
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.
The service variables temperature, H2S partial 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 H2S that 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.
8.2.1Sulfide Stress Cracking (SSC) of Carbon
and Low Alloy steels
By contrast, in high-density halide brines, the pH is low
(typically 2–6), and the H2S gas will be solubilized directly as
H2S. Soluble H2S in acidic brines can cause severe SSC.
SSC can affect susceptible carbon and low alloy steels at
very low H2S partial pressures.
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 H2S could flow into a formate
completion or packer fluid together with an influx of CO2 large
enough to overwhelm the upper buffer level so that pH will drop
to 6–6.5. 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).
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 H2S partial 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
PA G E 2 1
F O R M AT E
P( K0A
PSI
B R IN E S
–
COMPATI B I L I TY
W I TH
ME TAL S
33#2EGIONSOF%NVIRONMENTAL3EVERITY
REGION
.ORMALLYNOSPECIALPRECAUTIONS
AREREQUIREDFORTHESELECTIONOF
STEELSFORUSEUNDERTHESE
CONDITIONS.EVERTHELESSHIGHLY
SUSCEPTIBLESTEELSCANCRACK
P(RANGEOFBUFFEREDFORMATES
WITHINTACTBUFFER
P(RANGEOFBUFFEREDFORMATES
WITHOVERWHELMEDBUFFER
33#REGIONSAND
3PECIFICGUIDELINESNEEDTOBE
FOLLOWEDFORSELECTIONOFMATERIAL
P(RANGEOFHALIDEBRINES
(3PARTIALPRESSURE;K0A=
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].
decreases and above about 100°C / 212°F cracking is not
normally observed.
important with respect to the SSC of martensitic stainless
steels.
The other environmental variables listed above are much less
important with respect to SSC.
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.
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 in H2S Containing Environments
More detail on the limits of applicability of CRAs in oil and
gas production environments containing H2S is 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 and
modified 13Cr alloys are also subject to SSC as a mechanism
of cracking failure in H2S containing media. The H2S partial
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 H2S would 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
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 (160°C / 320°F) [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 160°C / 320°F over a period of
PA G E 2 2
F O R M AT E
B R INE S
–
COMPATI B I L I TY
1 month. Testing was done in Hastalloy vessels with
1 MPa / 145 psi CO2 and 10kPa / 1.45 psi H2S in 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 CO2 in 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.
W I TH
ME TAL S
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, CO2 and H2S,
contained probably slightly elevated levels of hydrogen. They
were not affected significantly by hydrogen embrittlement
apart from one anomalously high yield strength value from
Alloy 718 in CaBr2.
During the test, the pH dropped from 11.9 to 7.60 (undiluted)
in the buffered formate brine, which indicated that the upper
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 160°C / 320°F for 30 days.
Results [SCC]
Test specimen
CaBr2
CsKFo
Comment
1 month
Modified 13Cr-2Mo
SM13CRS-110ksi /
UNS S41426
3/3
3/3
Duplex 22Cr
EN 1.4462 /
UNS S31803
No
No
Duplex 25Cr
EN 1.4410 /
UNS S32760
No
No
Alloy 718
UNS N07718
1/3
No
• crack
CsKFo: Cracks on crosssections 0.11 mm
• no cracking
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 160°C / 320°F 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
CaBr2
KCsFo
Modified 13Cr-2Mo
100
100
101
Duplex 22Cr
105
95
102
Duplex 25Cr
107
95
106
94
106
Alloy 718
112
1)
CaBr2
1) One sample showed 103% change; the other showed 121% change.
PA G E 2 3
KCsFo
Elongation % of
initial value
Hydrogen uptake
[ppm]
CaBr2
KCsFo
CaBr2
KCsFo
99
99
100
0.9
1.0
92
101
95
3.1
3.2
94
88
99
2.4
6.8
97
96
97
6.0
4.8
F O R M AT E
B R IN E S
–
COMPATI B I L I TY
W I TH
ME TAL S
Table 13 Centro Sviluppo Materiali – fpbb testing of modified 13Cr-2Mo and alloy 718 in a 1.94 s.g. / 16.2 ppg CsKFo brine at 165°C / 329°F.
PCO2 = 4 MPa / 580 psi. The results are taken from [10].
Fluid
H2S
[kPa] [psi]
Position in test cell
Modified 13Cr-2Mo
Pitting
SCC
Alloy 718
Pitting
SCC
1 Month
CsKFo + 20 g/L Cl-
3
0.44
3
0.44
CsKFo + 65 g/L ClCsKFo + 75 g/L Cl-
Submersed
Submersed
Submersed
8.2.4High-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 CO2 and 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 and
a test with only CO2. The addition of H2S did 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 170°C / 338°F 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 CO2 and H2S created severe SCC in modified 13Cr-2Mo
metal samples immersed in ZnBr2/CaBr2/CaCl2 and CaBr2/
CaCl2 brines, and that transgranular cracks were also found
in one of the tests.
H2S formed by the thermal decomposition of sulfurcontaining 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 (40°C / 104°F) [18]. “U-bends and C-rings, pre-
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
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 40°C /
104°F over a period of 1 month. Testing was done in
Hastalloy vessels with 1 MPa / 145 psi CO2 and 10kPa / 1.45
psi H2S in 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 CO2 in 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 the
initiation 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 H2S contained
probably slightly elevated levels of hydrogen, but were not
affected significantly by hydrogen embrittlement.
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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 40°C / 104°F for 30 days.
Results [SCC]
CsKFo
CaBr2
Test specimen
1 month
Modified 13Cr-2Mo
Duplex 22Cr
Duplex 25Cr
Alloy 718
• crack
SM 13CRS-110ksi /UNS S41426
EN 1.4462 / UNS S31803
EN 1.4410 / UNS S32760
UNS N07718
3/3
No
No
No
No
No
No
No
Comment
CaBr2: cracks on cross sections 1.8 mm
• 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 40°C / 104°F 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 specimen
Modified 13Cr-2Mo
Duplex 22Cr
Duplex 25Cr
Alloy 718
Yield stress (Rp0.2)
% of initial value
KCsFo
CaBr2
100
102
104
109
102
104
104
107
Tensile strength
% of initial value
CaBr2
KCsFo
101
99
101
104
103
105
106
108
Elongation
% of initial value
CaBr2
KCsFo
93
98
93
92
96
92
96
103
Hydrogen uptake
[ppm]
CaBr2
KCsFo
1.3
1.0
1.2
1.7
1.3
1.4
3.0
2.7
8.3 Use of H2S Scavengers 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 CO2 gas 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 H2S scavenger could
be beneficial since the impact of H2S on 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 H2S scavenger will help to remove any
bisulfide from the formate brine.
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 H2S scavengers that is expected
to be compatible with formates are the electrophilic organic
inhibitors 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.
A zinc-free, iron based H2S scavenger, Ironite Sponge®, has
been tested in formate brines, and is shown to have some
positive effect in scavenging the H2S. But Ironite Sponge® is
a solid, which limits its application in clear completion fluids.
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9 Corrosion in Formate Brines
Contaminated with O2
present in the brine was apparently not able to cope with the
new influx of oxygen.
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:
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.
1. Low solubility of oxygen in formate brines.
9.1 Impact of O2 on SCC
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].
Extensive testing has been carried out by Hydro Corporate
Research Centre, Porsgrunn, CAPCIS, and Statoil (at Centro
Sviluppo Materiali) to see if formate brines contaminated with
oxygen can cause stress corrosion cracking in alloy steels.
2. Formate brines are antioxidants.
9.1.1 Testing by Hydro Research
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.
Hydro Corporate Research Centre, Porsgrunn has tested
CRAs for SCC after exposure to buffered 1.7 s.g. / 14.2 ppg
potassium/cesium formate brine. They used the “U-bends and
C-rings, prestressed to yield” method [12]. A 1.7 s.g. / 14.2 ppg
3OLUBILITYOF/IN&ORMATE"RINES
3OLUBILITY;PPM=
3OLUBILITY;PPM=
&ORMATECONCENTRATION;WEIGHT=
Figure 16 Solubility of oxygen in potassium formate at 21°C / 70°F.
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 several
forms 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 bisulfitebased 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 CaCl2 packer fluid during an annular pressure
bleed-off operation. In this instance, the oxygen scavenger
calcium bromide brine was included in the testing for
comparison. Both brines were deliberately contaminated with
1% Cl-. In addition, the formate brine was tested with 0.3%
chloride contamination and the bromide brine was tested
without any added chloride. No oxygen scavengers or
corrosion inhibitors were added to either brine. The brines
were tested at 160°C / 320°F over a period of three months.
Testing was done with 1 MPa N2 and 20 kPa O2 in the
headspace. 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 of the
test metal samples were inspected with an optical microscope
after the first and second months. At the end of the exposure
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Table 16 Hydro Research / CAPCIS – Long term SCC testing over a 3-month period in 1.7 s.g. / 14.2 ppg formate and bromide brines
in the presence of oxygen. Temperature = 160°C / 320°F, PN2= 1 MPa, / 145 psi and PO2 = 20 kPa / 2.9 psi.
Results [SCC]
Test Specimen
1 Month 1)
Modified 13Cr-1Mo
22Cr
25Cr
2 Months 1)
Modified 13Cr-1Mo
22Cr
25Cr
3 Months
Modified 13Cr-1Mo
Modified 13Cr-2Mo
22Cr
25Cr
• crack
Calcium bromide
Formate
No added Cl - 1% added Cl - No added Cl - 0.3% added Cl - 1% added Cl -
LC80-130M
EN 1.4462
EN 1.4410
3/3
?
No
3/3
1/3
No
----
No
No
No
No
No
No
LC80-130M
EN 1.4462
EN 1.4410
3/3
3/3
1/3
3/3
3/3
1/3
----
?
No
No
2/3
No
No
LC80-130M
SM13CRS-110ksi
3/3
--
3/3
--
3/3
3/3
? 2/2
--
2/3
--
3/3
EN 1.4462
2/3
EN 1.4410
• cracks at the initiation stage • no cracking
3/3
2/3
No
No
No
No
No
No
1) For the first and second month the cracking evaluation is only based on visual inspections and optical microscopy.
Table 17 CAPCIS – Short term SCC in 1.7 s.g. formate and bromide brines contaminated with 1% Cl- in the presence of oxygen.
Temperature = 160°C / 320°F, PN2= 1 MPa / 145 psi, and PO2 = 20 kPa / 2.9 psi. The bromide brine was tested by CAPCIS and the
formate brine by Hydro Formates (Chapter 9.1.1).
Results [SCC]
Calcium bromide
Formate
1% added Cl 1% added Cl -
Test specimen
1 Week 1)
Modified 13Cr-1Mo
LC80-130M
1/3
No
22Cr
EN 1.4462
1/3
No
25Cr
EN 1.4410
No
No
Modified 13Cr-1Mo
LC80-130M
3/3
No
22Cr
EN 1.4462
3/3
No
25Cr
EN 1.4410
No
No
2 Weeks
• crack
• no cracking
1) For the first week the cracking evaluation is only based on visual inspections and optical microscopy.
period the crack patterns in the specimens that had failed were
studied in cross-section under an optical microscope. The
results of the testing are shown in Table 16. At the end of the
first month none of the metal samples exposed to the
chloride-contaminated formate brines showed any signs of
stress corrosion cracking. In the bromide brines with and
without chloride contamination, samples of both modified
13Cr-1Mo and Duplex 22Cr had cracked after only one
month. After three months of testing, none of the 22Cr and
25Cr metal samples had cracked in the chloride-contaminated
formate brines, but some cracks at the initiation stage were
evident in the modified 13Cr-specimens. In the bromide brines,
all of the metals had cracked after two months even in the
bromide brines that were not contaminated with added
chloride.
9.1.2 Testing by CAPCIS
CAPCIS carried out some additional short-duration tests at
160°C / 320°F with CRAs in chloride contaminated calcium
bromide brines to find out how quickly they cracked in the
presence of oxygen (1 MPa / 145 psi pressure; 20 kPa /
2.9 psi O2) [12]. The tests were carried out by exactly the same
method as the oxygen tests done by Hydro Research (9.1.1).
The results of this testing are shown in Table 17. It is clear
that the modified 13Cr-1Mo and Duplex 22Cr metal samples
exposed to chloride- and oxygen-contaminated bromide
brines were beginning to crack within 7 days. The 25Cr was
more resistant to cracking in the contaminated bromide
brine, but Hydro Research had previously shown that
cracking would eventually take place after 2 months.
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CAPCIS also repeated the long term (3-month test) in
formate with oxygen, but without chloride contamination [not
yet published]. The results from this test are shown in Table
16 together with the long term testing done by Hydro
Corporate Research Centre, Porsgrunn (9.1.1). The results of
this showed that the cracking seen by Hydro Research (9.1.1)
is unlikely to be related to the chloride contamination. As
similar crack initiation was not observed in the same
experiments carried out in a CO2 contaminated formate brine
(7.2.1), the oxygen contamination seems likely to be the
cause of the cracking.
Centro Sviluppo Materiali used four point bent beam (fpbb)
tests to evaluate the SCC susceptibility of modified
13Cr-2Mo steel and Alloy 718 in a buffered 1.95 s.g. cesium/
potassium formate brine with some oxygen present in the
headspace of the reaction vessel [10][11]. Their test
temperature was 165°C / 329°F, and the pressure in the
headspace was 0.7 MPa. The partial pressure of oxygen was
low (about 100 ppb). The tests were run for 1 month. One
brine sample was contaminated with 3g/L of Cl- and the
other was saturated with NaCl (85 g/L Cl-). Testing was
conducted on alloy 718 and 4 different grades of modified
13Cr-2Mo. None of the metal samples showed any signs of
pitting or stress corrosion cracking.
Table 18 Centro Sviluppo Materiali – 1 month fpbb testing at
165°C / 329°F on modified 13Cr-2Mo and Alloy 718 in a
cesium/potassium formate brine contaminated with chloride.
PN2 = 0.7 Pa + 100 ppb O2.
Pitting
SCC
CsFo + 3 g/L Cl
No
No
CsFo + 87 g/L Cl-
No
No
-
ME TAL S
9.2 Use of O2 Scavengers in Formate Brines
The corrosive properties of oxygen are related to its strong
oxidizing properties.
Due to the strong antioxidant properties of concentrated
formate brine, it has never been thought necessary to
scavenge soluble oxygen from high density formate brines. It
has not been normal practice to add an oxygen scavenger to
formate brines prior to field use.” The big difference that has
been seen when cracking takes place in the formate brine
and the bromide brine (9.1), supports the fact that formate
brines do have antioxidant properties. Whether the slight
cracks at the initiation stage that were seen in modified 13Cr
after three months of exposure at high temperature could be
avoided by pre-treating the brine with an oxygen scavenger
is still unknown. Until experimental evidence is available it
would be advisable to pre-treat the brine with an oxygen
scavenger in case of long exposure of modified 13Cr to
formate brines at high temperature.
Low-density formate brines, containing more water than
formate, may not offer the same corrosion protection as their
higher density cousins. A 1.06 s.g. / 8.84 ppg potassium
formate brine was recently shown to cause severe under
deposit corrosion damage initiated from pits of 1%Cr and
3%Cr C-steel [22]. Such a diluted brine would probably have
benefited from the addition of an oxygen scavenger.
Sodium ascorbate has been proposed as an effective oxygen
scavenger in formate brines.
Modified 13Cr-2Mo + Alloy 718
Fluid
W I TH
PA G E 2 8
P( LOG + LOG 0#/ LOG ; (#/
0#/
PKT
=

(#/
F O R M AT E B R INE S
(#/ AQ (#// AQ (#//( AQ (#/ AQ
P+A (#/ COMPATI B I L I TY
PKT
W I TH
ME TAL S
P+A (#//( 10Catalytic Decomposition
&E ( #/ AQ → &E AQ ( G (#/ AQ
of Formates – a Laboratory
Phenomenon
&E (#//(
AQ → &E AQ ( G #//( AQ
–
bore, after modest formate decomposition, the hydrogen

PKTpartial pressure may rise to a level where the equilibrium for
the formate decomposition reaction shifted towards the
PKT reactants, opposing further formate decomposition. By
The technical
literature contains extensive experimental

&E #/(e.g.
↔[23])
&E#/
S
evidence
for
the decompositionPKT
of formate and
formic acid at high temperatures to molecular hydrogen and
( 3 G ( 3 AQ
PKT
other
products. The two decomposition mechanisms most
commonly cited
are:
P+A
−
+
( 3 AQ ←⎯⎯→ (3 AQ + ( AQ
PKT
CAT
(#// AQ ( / ←⎯→
(#/ AQ ( G
CAT
(#//( ←⎯
→ #/ ( G
PKT
(17)
(18) PKT
Note that both these reactions produce molecular hydrogen.
Equation 17, leading to the formation of bicarbonate and
hydrogen gas, is the one cited most frequently in alkaline
solutions of formates heated to high temperatures [23].
Equation 18 requires the presence of formic acid and might
be more likely to occur in acidic formate solutions. As a
buffered formate brine is almost always alkaline, and can only
assume a slightly acidic state of pH = 6–6.5 after a massive
acid gas influx, this reaction is unlikely to ever be dominating.
Both of these decomposition reactions can be catalyzed by
metal surfaces. Nickel, an alloying component in commonly
used Cr-steel oilfield tubulars, is known to be a good catalyst
for formate decomposition.
Against this background of laboratory data showing
hydrogen evolution from formate decomposition, new users
sometimes express reservations about the suitability of
formate brines for HPHT application despite the fact that
formates have been in daily use in HPHT wells since 1996.
Cabot Specialty Fluids have provided formate brines to more
than 130 high pressure high temperature (HPHT) well
operations, and they are in routine use in HPHT wells every
day of the year. Cesium formate brines have a long history of
being exposed to high well temperatures for long periods.
During a well suspension job in Total’s Elgin Franklin field in
the North Sea a buffered cesium formate brine was left
downhole for 450 days at temperatures close to 200°C /
405°F. Despite close monitoring with specialist equipment, no
gaseous or soluble formate decomposition products were
detected either during or after the operation. Similarly, no
formate decomposition products were detected in a Mobile
Bay well in which a buffered cesium formate brine was
exposed to 216°C / 420°F for 20 days during a completion
operation. As a matter of fact, there are no reports of formate
decomposition from any of the approximately 130 HPHT
wells drilled and/or completed with buffered formate brines
since 1996 (Table 2). If formates substantially decomposed
on metal surfaces in wells at temperatures as low as 100°C /
212°F then reports of hydrogen evolution from HPHT wells
should be commonplace.
contrast, most laboratory experiments have been carried out
at low pressure using autoclaves containing a gas-filled
headspace (the gases are typically nitrogen, air, or CO2).
Under these artificial conditions more substantial formate
decomposition will occur before a sufficient hydrogen partial
pressure can exist. One way to create a high partial pressure
of hydrogen in a laboratory reactor is to make a highly
pressurized gas cap of pure hydrogen.
Such an experiment was carried out by Hydro Corporate
Research Centre, Porsgrunn, Norway. They used a
35 MPa / 5,076 psi gas cap of hydrogen to simulate a
realistic partial pressure of hydrogen that would immediately
exist if decomposition took place at the bottom of a well at a
moderate depth [24]. The experiments were run with buffered
formate brines with a high pH level, and buffered formate
brines in which the buffer had been overwhelmed with CO2
and thereby dropped the pH to the lowest level possible
(6–6.5). In both cases, the presence of the high partial
pressure of hydrogen in the reactor significantly increased the
temperature threshold at which decomposition of formate
brine was initiated. In fact, the temperature threshold for
initiation of catalytic decomposition of formate was reported
to be raised to the sort of level normally required to initiate
bulk decomposition of the brine.
Another factor that has to be considered when going from a
laboratory environment to a field environment is the possible
formation of thin layers of corrosion products on service
steels or the presence of chemicals that poison the catalytic
sites on metal surfaces that might drive formate decomposition
reactions.
We conclude that whilst surface-catalyzed decomposition of
buffered formate brines is well described in laboratory
experiments, it is not likely to occur substantially in the field,
and has certainly not been detected in the field. At the
moment the highest temperature to which a formate brine
has been exposed in the field is 216°C / 420°F (at 10,000 psi)
during the completion of a Mobile Bay well. Again, there was
no evolution of hydrogen gas from the brine over the 16 days
the brine was in the well.
A possible explanation for why decomposition of formate
brines is not detected in field applications is that in the well
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11Hydrogen Embrittlement
of Metallic Materials in
Formate Brines
In summary: a specific material’s susceptibility to hydrogen
embrittlement depends on hydrogen solubility, diffusivity, and
the concentration threshold at which the material might be
damaged. All these factors are temperature dependent.
11.1Hydrogen Embrittlement
In practice, hydrogen embrittlement failures are seldom
observed in the field, for one or more of the following
reasons:
Hydrogen embrittlement of metallic materials is the result of
hydrogen uptake into the metal. Hydrogen solubility
increases with temperature, so that far more hydrogen
uptake is needed at high temperature to achieve the same
level of hydrogen embrittlement as may be caused at a lower
temperature with less hydrogen uptake.
Metallic materials exposed to brines at wellbore temperatures
will, under some conditions, absorb hydrogen. Typically for
some materials, e.g. carbon and low alloy steels, the level of
hydrogen uptake will be greater than that necessary to cause
embrittlement at low temperatures and the consequences of
the (rapid) cooling of the material, when it is recovered from a
well, or when temperature variations occur because of
production shut-in, must be considered.
Little evidence has been found that relates hydrogen uptake
at the in-service temperature to the degree of embrittlement
caused by this hydrogen at the same temperature.
For carbon and low alloy steels embrittlement may result
from intense hydrogen entry due to corrosion at low
temperatures in the presence of a ‘hydrogen promoter’. At
temperatures above about 150°C / 300°F it is known that
hydrogen embrittlement of carbon and low alloy steels does
not occur because the hydrogen mobility in the steel
becomes very high, allowing hydrogen to escape from the
material.
• the hydrogen activity at the surface of the metallic material
is insufficiently high to exceed the threshold of hydrogen
uptake for significant embrittlement to occur at the service
temperature
• the equipment is not exposed for a long enough time
• corrosion-resistant alloys are passive, such that the
corrosion rate is very low. This results in low levels of
hydrogen (NB. galvanic couples are a special case, see
below).
11.2Sources of Hydrogen
Corrosion processes generating atomic hydrogen provide the
most common source of hydrogen that can diffuse into
metallic alloys. Sulfide ions poison the recombination of
atomic hydrogen to molecular hydrogen reaction. This further
increases the atomic hydrogen available for diffusion (see
Section 8). Another common source of hydrogen charging of
corrosion-resistant alloys (CRA) is the cathodic reaction that
occurs on the CRA surface as a result of galvanic coupling to
a less noble material. The catalytic decomposition of organic
acid has been suggested as another source of hydrogen in
organic brines.
11.2.1 Hydrogen Charging from Galvanic Coupling
For martensitic stainless steels, such as 13Cr alloys, the
situation seems likely to be similar to that for carbon and low
alloy steels.
For other CRAs the situation is less clear. As an example, for
nickel alloys some hydrogen uptake can take place over the
whole temperature range with, for a given set of environmental
conditions, the level of uptake increasing with temperature.
The higher the hydrogen concentration in the alloy the higher
is the potential degree of loss of ductility and embrittlement.
The ability of nickel alloys to retain the hydrogen once
absorbed (lower hydrogen diffusivity) can make these effects
particularly marked when these alloys are cooled from
elevated temperatures. Some recent cases exist where well
components made of alloy 718 (a nickel-based alloy) have
been found to be embrittled after retrieval from the well.
Alloy 718 is frequently used in packers and tubing/liner
hangers in HPHT wells, and the susceptibility of this material
to hydrogen embrittlement has raised a concern in the
industry [26], though no fresh evidence of in-service failures
in brines was found during this review.
Hydrogen charging of alloy 718 has been observed both in
the field and in the laboratory for several brine systems
including formates. As alloy 718 is mainly used for packers
and liner/tubing hangers, this material is normally coupled
galvanically to other metals, often C-steel. In any given
solution, galvanic coupling will tend to contribute to an
enhanced propensity for hydrogen embrittlement.
11.2.2 Hydrogen Charging from Formate Decomposition
Catalytic decomposition of formate and formic acid has been
found to be a source of hydrogen charging of metallic alloys
(e.g. alloy 718) in the laboratory environment [11].
There is some evidence, however, that this might not occur in
the field. In Total’s Elgin well G3, the 25Cr tubing was
exposed to a formate brine at about 200°C / 392°F for 16
months. Laboratory testing [25] has shown that 25Cr will
serve as a catalyst for decomposition of formate at this
temperature, and the 25Cr tubing should, according to this
theory, be charged with hydrogen. When the tubing was
retrieved, no increased hydrogen levels were measured (see
Section 11.3 below). The measured hydrogen levels were
indeed lower than those measured in the section of the same
tubing that had been exposed to SBM (Synthetic Based Mud).
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11.3Field Evidence – Total’s Elgin Wells G1 and G3
Total’s Elgin and Franklin fields in the central part of the UK
North Sea comprise the largest HPHT development ever
undertaken anywhere in the world. The reservoir gas from
these fields contains 4% CO2 and 20-50 ppm H2S. The
bottom hole static temperature in the development wells was
initially about 204°C / 400°F, and the pressure 110 MPa /
16,000 psi.
In 1999, TotalFinaElf drilled the first two production wells in
the Elgin field, G1 and G3, which were completed with 25Cr
tubing in inhibited seawater. The wells were drilled with
SBM (Synthetic Based Mud). Both wells were produced for
about a day before they were suspended:
Well G1: The well was initially shut in with hydrocarbons
below the SCSSV. Due to a leak in the production packer, the
well was killed with cesium formate brine. After 21 days
exposure to cesium formate the tubing was cut and retrieved,
the packer was milled out, and the well cemented.
Well G3: This well was initially shut in with hydrocarbons
below the SCSSV. The well was later killed and suspended
with SBM from bottom hole to 3,900 meters and cesium
formate from 3,900 meters to surface. After 15 months of
exposure to these fluids, the well was worked over and the
tubing retrieved.
Total had previously carried out laboratory testing at low
pressures with buffered cesium formate brine where the
buffer had been overwhelmed by exposure to high levels of
acid gas. Total found that at temperatures above 170°C / 338°F,
this brine could suffer significant catalytic decomposition and
release hydrogen gas. As both of the Elgin wells would be
exposed to cesium formate brine at temperatures up to
W I TH
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204°C / 400°F, there was some concern that formate
decomposition might occur and possibly cause hydrogen
charging and embrittlement of the 25Cr tubing. Hydrogen
detectors were therefore installed on both wells during the
entire exposure period, but no hydrogen was ever detected.
After their retrieval from the G1 and G3 wells, both sets of
25Cr tubulars were analyzed for hydrogen content at several
points along their length. The measured hydrogen levels in
both tubulars that had been exposed to cesium formate brine
were found to be in the range 2.15–3.92 ppmw, which is only
slightly higher than the levels that are normally found in a
typical manufactured 25Cr tubing (1.5–3.5 ppmw). For
comparison, the hydrogen levels found in the lengths of
tubing that had been exposed to the SBM were much higher,
at up to 7.23 ppmw.
Independent mechanical testing by Bodycote on both sets of
tubulars concluded that the properties of the steel that had
been exposed to cesium formate were still within specification,
and suitable for further use in HPHT wells [27].
Cesium formate brines have since been used very successfully in another 8 wells over a period of 7 years in the Elgin/
Franklin fields as workover, completion, coil tubing, well kill,
and perforation fluid. In a later well, G5, a full analysis was
made on the cesium formate brine that was recovered after
being left below the packer for 9 months at 204°C / 400°F.
The analysis showed no signs of decomposition products in
the brine, and the low levels of soluble chromium and iron
found in the brine indicated that corrosion had been minimal.
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12Avoid Pitfalls in the Laboratory!
Correctly formulated formate brines do not cause corrosion
problems in the field, and when tested under realistic
downhole conditions, they also don’t cause corrosion
problems in the laboratory. Formate brines are, however,
much more sensitive to the laboratory test environment than
other oilfield brines. Some standard corrosion test procedures
provide such unrealistic conditions and their use creates
artifacts that for many years have lead researchers to draw
misleading conclusions about the corrosivity of formate
brines.
These are the major pitfalls that should be avoided when
carrying out laboratory corrosion experiments with formates:
• Always include an appropriate dose of carbonate/
bicarbonate buffer in the formulation. Even though
corrosion tests may sometimes be carried out under
conditions in which the upper buffer level is completely
overwhelmed (i.e. large amounts of CO2 in the head
space), the buffer should never be left out. This is because
the buffer not only serves as a pH stabilizer, but also
contributes to the quality of the iron carbonate protective
film that is formed under these conditions.
• Use a realistic fluid volume-to-metal surface area ratio.
Using a realistic ratio of around 2–4 mL/cm2, as typically
found in a cased hole, has shown to be critical when
testing C-steel and standard 13Cr steel with formate
brines exposed to acid gas in the laboratory. If the ratio is
made unrealistically large, a lot of corrosion will take place
before the protective iron carbonate film can be formed. If
the corrosion rates are then measured by weight loss of
metal test coupons over a short time period the results will
be unrealistic and misleading. Testing with higher fluid
volume-to-surface metal area should not be necessary
unless the material tested is destined for use in wirelines.
• Avoid short term weight loss measurements. Even
when realistic fluid volume-to-metal surface ratios are used
in the laboratory, there will usually be an initial peak in
corrosion rate in formate brines exposed to large amounts
of acid gases while a protective film is formed. Short
duration weight loss measurements with C-steel and
standard 13Cr test coupons under these conditions yield
misleadingly high apparent corrosion rates if extrapolated
linearly over time. Continuous LPR (Linear Polarization
Resistance) measurements calibrated against weight loss
are recommended instead. The LPR measurements should
continue until the protective film has formed and the
corrosion rates have stabilized to a steady state value.
The required time for the film to form depends on
temperature and metal type. If weight loss measurements
are to be used, a minimum of at least 30 days of testing is
recommended. If unrealistically high rates are measured by
this method, one should re-measure over a longer time
period or by use of the LPR method (calibrated against
weight loss).
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• Never use borosilicate (e.g. Pyrex) glass containers for
corrosion experiments with formate brines. Corrosive
chemicals are released from borosilicate glass by formate
brines. These corrosive substances will cause unrealistically
high corrosion rates that do not simulate what will happen
in field environments.
• Never use corrosion inhibitors in concentrated formate
brines. Corrosion inhibitors interfere with the formation of
natural protective films on metals in formate brines and
may cause localized pitting corrosion.
• Be aware that the use of laboratory reactors with gasfilled headspace volumes does not simulate downhole
well conditions. Due to the powerful pH buffering action
of formate brines, a very large amount of CO2 must be
introduced into a laboratory reactor in order to overwhelm
the upper buffer level and initiate CO2 corrosion. Most of
the corrosion rates reported here have been measured
after exposing metals to a very high partial pressure of CO2
(e.g. 1 MPa) in the headspace above the formate brine,
which is large enough to decrease pH to the lower buffer
level. It is important to keep in mind that this laboratory
environment represents absolutely the worst case
scenario, simulating a massive and prolonged influx of CO2
into a wellbore. More often than not in real life, the upper
buffer level will not be overwhelmed and actual corrosion
rates in the well will be more realistically projected from
corrosion experiments with formate brines that are not
exposed to CO2. This is not true for halide brines where
even a minor CO2 influx will be enough to cause carbonic
acid to form and CO2 corrosion to commence. The
presence of an unrealistic gas cap might also be the
cause of catalytic decomposition of formate brines,
which is frequently experienced in the laboratory, but not
in the field.
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13 Avoid Pitfalls in the Field!
The correct use of buffered formate brines will avoid corrosion
problems in HPHT wells. Here are four simple rules that must
be followed to ensure success:
13.1Four Simple Rules for Avoiding Corrosion
in Formate Brines
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temperatures. The corrosion is a result of interactions
between formate and zinc, which is present in the coating of
galvanized steels. It cannot be mitigated through the use of
carbonate/bicarbonate buffer. Fortunately, galvanized steel is
normally not used in any critical sub-surface equipment
required for well construction operations.
13.2Examples of Incorrect Use
Never use Corrosion Inhibitors in Formate Brines!
Buffered formate brines are naturally protective towards
C-steel and CRAs. Adding a corrosion inhibitor to a formate
brine is not only unnecessary and costly, but can actually
cause localized corrosion:
• In the event that the upper buffer level in a buffered
formate brine is overwhelmed by a massive CO2 influx,
no corrosion inhibitors can give better protection against
CO2 corrosion than the protective iron carbonate layer that
is formed by the buffered formate brine itself. If the upper
buffer level is not overwhelmed, the corrosion rates will
remain low, and no further protection is needed anyway.
• Sulfur-containing corrosion inhibitors are known to cause
cracking of susceptible metals at high temperatures in a
zinc-free environment [28]. In formates, the use of any form
of corrosion inhibitor is unnecessary and should be
avoided. The use of thiocyanate-based inhibitors was once
recommended to suppress the catalytic decomposition of
formates. It is now believed that catalytic decomposition
does not occur in formate brines under realistic wellbore
conditions (Section 10) and the addition of thiocyanate is
not recommended.
There are a couple of examples of corrosion incidents
reported from field operations as a result of using formate
brines incorrectly. These are:
Be Cautious with C-steel or standard 13Cr Wireline!
In the event that a very large CO2 influx (large enough to
overwhelm the upper buffer level and pull the pH down to the
lower buffer level) should occur during use of wireline,
significant CO2 corrosion can be expected. This is because
the metal surface area-to-fluid volume presented by the
wireline is very low, and a significant amount of corrosion can
take place before the fluid becomes saturated with iron
carbonate and allows a protective film to be formed on the
wireline surface. Use of C-steel and standard 13Cr wireline
material is therefore not recommended in formates if there is
any chance of receiving a very large CO2 influx into the
wellbore. Be also aware that a positive laboratory test result
might be misleading if the metal surface-to-fluid volume ratio
used in the test is unrealistic.
Wireline Failure II
Corrosion damage occurred in a C-steel wireline during the
recompletion of a Hydro operated gas-condensate well in the
North Sea. The C-steel wireline was immersed in unbuffered
potassium formate brine inside a modified13Cr-2Mo
production tubing at about 131°C / 268°F. The fluid was
exposed to an acid gas influx, and was acidified due to the
lack of a buffer. Failure analyses concluded that a significant
amount of corrosion had taken place, and that the color of
the cable had changed to black. The black color is likely to
have been a protective iron carbonate layer. A large amount
of corrosion must have occurred before the iron carbonate
layer was formed. The absence of bicarbonate (no buffer)
and the very high fluid volume-to-metal surface ratio are
factors that are known to slow down the formation of the
protective layer.
Never leave out the Buffer!
Unbuffered formate brines have been used in a few special
applications [29]. If formate brine is being used without a
buffer, one should be aware of the consequences this could
have in the event of a CO2 influx. In this case, the formate
brine will behave in a similar fashion to a halide brine:
corrosion will commence after just a small influx of CO2, and
the protective layer will form more slowly and be of poorer
quality.
Keep Formate Brines away from Galvanized Steel!
Formate brines are corrosive to galvanized steel at high
Wireline Failure I
The failure of a galvanized wireline has been reported
following use in a formate brine. Failure analysis concluded
that the galvanized coating around the wire body had been
removed by mechanical abrasion and the underlying C-steel
was subsequently exposed to hydrogen sulfide and attacked
by localized pitting corrosion.
In this case, the galvanized coating was removed mechanically.
However, galvanized coating is not compatible with formates
and would probably have been breached by the formate
brine without the assistance of mechanical removal.
In contrast to halide brines, buffered formates are compatible
with C-steel exposed to large influxes of sweet and sour gas.
However, this only applies to cases with a relatively low fluid
volume-to-metal surface ratio, and does therefore not apply
to wireline applications.
Two lessons were learnt from this incident:
1.Formate brines should always be buffered. In this case,
if this brine would have been buffered, the amount of acid
gas influx that was experienced would most likely not have
been high enough to lower the pH and the wireline would
not have corroded. In the situation that the acid gas influx
would have been large enough to overwhelm the upper
buffer level, the huge amount of bicarbonate would
contribute to limiting he corrosion by preventing further
acidification and also assisting in the faster formation of
the iron carbonate protective layer.
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2.Be cautious with C-Steel and standard 13Cr wirelines
in formates. Due to the high fluid volume-to-metal surface
ratio normally seen in wireline operations, extreme care
should be taken if a large acid gas influx is expected. Even
buffered formate brines might, in the case of a high
volume-to-surface ratio, allow excessive corrosion to take
place before the protective layer forms.
Thiocyanate
Thiocyanate was added to a formate-based packer fluid in a
well in Brazil, causing failure in the Duplex 22Cr tubing [30].
Thermal degradation of this sulfur-containing corrosion
inhibitor in a sodium formate packer fluid caused pitting
corrosion of the string, which was charged with hydrogen as
a result of galvanic contact with the steel casing. The pits
provided a sufficient stress intensity factor to cause brittle
fracture of the couplings. Just as in halide brines, the thermal
decomposition of thiocyanate at high temperature causes
environmental cracking of CRAs. Thiocyanates or other
corrosion inhibitors are not required in formate brines and
should never be used.
Use of Unbuffered Formate Brine
It is reported [31] that during the period 1996-2000, Mobil
Germany drilled a series of 15 wells in the HPHT gas fields of
North Germany with unbuffered sodium/potassium formate
based drill-in fluids. The BHST of these wells was around
150°C / 300°F. For three years Mobil had no problems while
drilling these HPHT gas wells with formate brines but in 1999,
while tackling a gas kick in their Soehlingen Z 13 well, a
routine gas analysis showed the presence of measurable
levels of molecular hydrogen in the unbuffered formate brine
[31]. It was suggested at the time that the hydrogen gas
could have originated from the decomposition of formic acid
in equilibrium with formate ions at the low fluid pH temporarily
created by the influx of a gas kick containing CO2. After the
addition of potassium carbonate, to raise the pH and create
some pH buffering in the fluid, no further dissolved hydrogen
gas was detected.
With the benefit of new understanding created by Hydro
Research’s decomposition testing on formate brines under
realistic hydrogen pressures (Section 10), we can now be
fairly sure that the cause of hydrogen evolution in the
Soehlingen well (maximum temperature of 150°C / 300°F)
was not the decomposition of formic acid. At the low pH
levels that can be temporarily created downhole in an
unbuffered formate brine under static conditions during a
CO2 influx, it is more likely that other reactions (e.g. corrosion,
or polymer degradation) could have generated the hydrogen
gas seen in the Soehlingen well. Without the protection
against CO2 corrosion provided by a carbonate/bicarbonate
buffer, corrosion rates in the formate brine following an acid
gas influx could have been significant.
Regardless of the actual cause of the hydrogen evolution in
this well; it was shown to disappear with proper buffering.
Had the formate brine been properly buffered from the start,
it is unlikely that the pH would have dropped during the acid
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gas influx. In any event, the buffer would have prevented the
brine pH from dropping any lower than 6–6.5. With proper pH
buffering the degradation of biopolymers by acid hydrolysis
is minimized and the amount of formic acid formed following
an acid gas influx would be significantly lower than in an
unbuffered formate brine.
No Packer Failure
Back in 2000 it was reported that a SAB3 packer with a
manufacturing fault that had been pulled from Total’s Elgin
G1 well in the North Sea showed signs of cracking in the
Alloy 718 component when examined at the surface.
The SAB3 packer failed to seal shortly thereafter and a
workover operation was initiated within a few weeks.
The manufacturer of the packer incorrectly blamed the
cracking on the cesium formate brine that had been used to
complete the well.
An investigation carried out by Total into the sequence of
events concluded that the cracking incident had not been
caused by cesium formate:
1.The FB3 packer was successfully set and pressure tested
in a clear cesium formate brine.
2.During circulating bottoms up, a hydrogen detector
showed only trace levels of hydrogen (0.012–0.030%).
Based on this, it was concluded that there was no
evidence of any formate decomposition and that corrosion
was either nonexistent or minimal. pH was also monitored
throughout and was within the range of 9.5 to 10.0 at all
times.
3.The completion was then run in cesium formate with an
integral SAB3 packer. Once this had tagged the FB3
packer the string was spaced out for the hanger and the
well was displaced firstly to potassium formate, and then
to water inhibited with sodium thiocyanate. (Prior to this,
tests were successfully run in a flow loop using cesium
formate brine to check a) the feasibility of circulating the
brine under HPHT conditions without causing damage to
the SAB3 packer and b) the ability of the packer to seal
afterwards.)
4.The SAB3 packer failed to seal shortly thereafter and a
workover operation was initiated within a few weeks.
During the kill operation the well was again displaced to
cesium formate. In all, the SAB3 packer was exposed to
cesium formate for no more than a couple of days.
The operator believes that the cracking of the faulty packer
was caused by the presence of thiocyanate in the inhibited
water. Thiocyanates are known to decompose to H2S at high
temperatures and cause cracking of CRAs in HPHT wells
[28]. Over the past 6 years similar packers constructed of
alloy 718 have successfully been exposed to cesium formate
brines in a further 8 Elgin wells, under essentially the same
downhole conditions, but without sodium thiocyanate added
to the packer fluid.
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References
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[2] NACE MR0175/ISO 15156-3: “Petroleum and natural gas industries – Materials for use in H2S containing environments in oil
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[3] Mahmoud, S.: “Report # MTL 03-115-Corrosion of Steels and CRAs in Formate Based Fluids. Part I. Review and Interpretation
of Available Corrosion/Cracking Data.”
[4] Unpublished data from Cabot Specialty Fluids.
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[6] Leth-Olsen, H.: “CO2 Corrosion of Steel in Formate Brines for well Applications”, NACE 04357, 2004.
[7] Leth-Olsen, H.: “CO2 Corrosion in Bromide and Formate Well Completion Brines”, SPE 95072, May 2005.
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[14] Mack, R. et al.: “Stress Corrosion Cracking of a Cold Worked 22Cr Duplex Stainless Steel Production Tubing in a High
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[15] Leth-Olsen, H.: “Corrosion Testing of Well Materials in Formate Brines with Influx of CO2 and H2S”, Report # D4S_B03,
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Statfjord Field”, NACE 06134, March 2006.
[23] McCullom, T.M. and Seawald, J.: Testal Constraints on the Hydrothermal Reactivity of Organic Acids anions: I: Formic Acid
and Formate”, Geochemica et Cosmochimica Acta, Vol. 67, No. 19, pp. 3625-3644, 2003.
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[26] Glass, A.W.: “High pressure, high temperature developments in the United Kingdom Continental Shelf”, Research Report 409,
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[27] TotalFinaElf Exploration UK PLC: “G1, G3 Tubing Investigation Final Report”, October 2002.
[28] Ke, M. and Qu, Q.: “Thermal Decomposition of Thiocyanate Corrosion Inhibitors: A Potential Problem for Successful Well
Completions”, SPE 98302.
[29] Messler D., et al: A Potassium Formate Milling Fluid Breaks the 400° Fahrenheit barrier in Deep Tuscaloosa Coiled Tubing
Clean-out”, SPE86503, February 2004.
[30] Harris, D. et al.: “Completion Optimization: Equipment & Material Qualification”, SPE, 97598, May 2005.
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