Document Text Contents
Page 1
Casing Materials
Selection &
Corrosion
Guidelines
BP Amoco report no. BPA-D-003
dated September 1999
Main CD
Contents
J W Martin
Page 2
September 1999 Issue 2
Section C15 Material Selection and Corrosion Guidelines 15-17
BP Amoco
Casing Design Manual BPA-D-003
Page
15.1 Scope 15-1
15.2 Material Selection Process 15-2
15.2.1 Casing Exposed to Muds and Brines 15-2
15.2.2 Sour-service Exposed to Produced Fluids 15-3
15.3 Corrosion Control 15-9
15.3.1 Exploration/Appraisal Wellls 15-10
15.3.2 Development Wells 15-11
15.4 External Corrosion 15-14
15.5 Flowchart for Corrosion Control Measures 15-14
Figure
15.1 Material Selection for Casing 15-3
15.2 Sour Gas Systems 15-4
15.3 Sour Multiphase Systems 15-4
15.4 Sulphide Stress Cracking Performance Domain
of Grade P110 Carbon Steel 15-9
15.5 Sulphide Stress Cracking Performance Domain
of Grade N80 Carbon Steel 15-9
15.6 Major Corrosion Control Measures for Casing 15-15
Page 12
September 1999 Issue 2
15-10 Material Selection and Corrosion Guidelines Section C15
BP Amoco
BPA-D-003 Casing Design Manual
In the case of oil-based muds, there is little danger of corrosion problems
under normal operating conditions, as oil is the continuous phase in the
mud and the metal surface will be ‘oil-wet’. The major exception to this is
the contamination of the mud with water and acid gases (ie CO2 and/or
H2S) due to formation fluid in-flow. Therefore, it is important to ensure that
the drilling fluid hydrostatic head and fluid density are maintained to
minimise this inflow. In addition, it may be necessary to make chemical
additions to oil-based muds, eg sulphide scavengers.
The dissolved gas that most commonly determines the general corrosivity
of water-based drilling muds is oxygen, although the insurgence of acid
gases due to formation fluid in-flow may also be important. In casing
design, general corrosion of the type associated with oxygen or acid gases
is not normally an issue as the periods of exposure are relatively short. In
addition, the pH of the mud is controlled to minimise the likely corrosion
rate.
An important corrosion problem that can occur during drilling is sulphide
stress cracking (SSC). This occurs as a result of hydrogen sulphide in the
mud. This hydrogen sulphide can have a number of sources, the more
important being:
• Inflow of formation fluids containing hydrogen sulphide
• Bacterial activity
• Degradation of the mud
The second and third of these sources can be adequately controlled by the
addition of biocides to the mud and correct mud selection. Although the
likelihood of the first source can be reduced by maintenance of the drilling
fluid hydrostatic head and fluid density to minimise formation fluid inflow,
the possibility of such inflow must still be considered; even a short
exposure time to a ‘sour’ environment can lead to a potentially catastrophic
failure. Therefore, if the presence of hydrogen sulphide is expected,
additional preventative measures need to be taken to ensure that SSC will
not occur, for example:
• Maintain the pH at a value of 10 or higher to neutralise the
hydrogen sulphide
• Use chemical sulphide scavengers
In addition, consideration can be given to the use of sour resistant casing
materials (refer to Section 15.1.2). For wells which are expected to be
‘sour,’ it is normal practice within BPA to use sour-resistant casing grades
for the casing strings likely to be exposed to the sour fluids.
15.3.1
Exploration/
Appraisal Wells
Page 22
September 1999 Issue 2
Section C15 Material Selection and Corrosion Guidelines 15A-5
BP Amoco
Casing Design Manual BPA-D-003
Halide ions, eg chloride and bromide ions, are present in many of the
fluids likely to be encountered downhole, ie formation waters,
injection waters, completion brines, workover fluids, etc.
Halide ions can cause localised corrosion damage to materials used for
downhole equipment in the form of corrosion pitting and/or crevice
corrosion. In addition, they can increase the corrosion damage resulting
from the effect of other corrodants.
Halide ions can also give rise to stress corrosion cracking (SCC) of
susceptible materials, principally austenitic stainless steels. This type of
cracking will normally only occur at elevated temperatures, typically above
50°C (120°F) for austenitic stainless steels, and under the action of
tensile stresses. This can also include residual stresses from mechanical
working.
Stress corrosion cracking can be defined as crack initiation and growth
in an alloy caused by the conjoint action of corrosion and tensile stress.
This cracking can occur at stresses well below the yield strength.
The mechanism by which this occurs is not fully understood, but it
requires the presence of certain specific alloy/environment combinations,
eg austenitic stainless steel in chloride-containing solutions. The result of
SCC is that normally ductile materials can suffer from catastrophic,
apparently brittle, failures.
This is the preferential corrosion that can occur to one of the metals, when
two different metals are electrically coupled in a corrosive environment.
In such a couple, one of the metals will act as an anode (ie it will corrode
at an enhanced rate) and the other will act as a cathode (ie there will be
a certain degree of protection). The susceptibility of a material couple
towards galvanic corrosion of the ‘anodic’ metal (ie the metal with the
lower equilibrium potential) is influenced by a number of factors, such as
the conductivity of the corrosive medium, the relative surface area of the
two metal components and the difference in the equilibrium potentials of
the two metals in the corrosive environment.
15A.2.5
Galvanic Corrosion
15A.2.4
Halide Ions
Page 23
September 1999 Issue 2
15A-6 Material Selection and Corrosion Guidelines Section C15
BP Amoco
BPA-D-003 Casing Design Manual
There are two types of localised corrosion that are likely to be encountered
downhole, ie corrosion pitting and crevice corrosion. As has already
been indicated, corrosion pitting occurs when certain regions in the
metal act as strong anodes. An example of this is the corrosion pitting of
certain stainless steels in chloride-containing environments. In this case,
pitting is enhanced by the presence of dissolved oxygen. The pitting
process is strongly affected by temperature. There are often temperatures
below which corrosion pitting will not occur in a particular environment,
this is known as the ‘critical pitting temperature’. Pitting is more damaging
than general corrosion as it can result in penetration in much shorter
times and is more difficult to detect. This is an aspect that should be
borne in mind when selecting materials for downhole service, particularly
corrosion-resistant alloys.
Crevice corrosion is the localised damage that can result at a narrow gap
or ‘crevice’ between two adjacent components. The crevice may be
between two similar materials, two different materials (in which galvanic
corrosion may also play a role), or even between a metal and a non-metal
(eg elastomers). An important factor in determining whether crevice
corrosion will occur is the size of the gap. Crevice corrosion is often
exacerbated at higher temperatures. The local environment produced
within a crevice can be quite different to the bulk fluid environment,
leading to corrosion damage which could not be predicted from the
general fluid composition.
15A.2.6
Localised Corrosion
Casing Materials
Selection &
Corrosion
Guidelines
BP Amoco report no. BPA-D-003
dated September 1999
Main CD
Contents
J W Martin
Page 2
September 1999 Issue 2
Section C15 Material Selection and Corrosion Guidelines 15-17
BP Amoco
Casing Design Manual BPA-D-003
Page
15.1 Scope 15-1
15.2 Material Selection Process 15-2
15.2.1 Casing Exposed to Muds and Brines 15-2
15.2.2 Sour-service Exposed to Produced Fluids 15-3
15.3 Corrosion Control 15-9
15.3.1 Exploration/Appraisal Wellls 15-10
15.3.2 Development Wells 15-11
15.4 External Corrosion 15-14
15.5 Flowchart for Corrosion Control Measures 15-14
Figure
15.1 Material Selection for Casing 15-3
15.2 Sour Gas Systems 15-4
15.3 Sour Multiphase Systems 15-4
15.4 Sulphide Stress Cracking Performance Domain
of Grade P110 Carbon Steel 15-9
15.5 Sulphide Stress Cracking Performance Domain
of Grade N80 Carbon Steel 15-9
15.6 Major Corrosion Control Measures for Casing 15-15
Page 12
September 1999 Issue 2
15-10 Material Selection and Corrosion Guidelines Section C15
BP Amoco
BPA-D-003 Casing Design Manual
In the case of oil-based muds, there is little danger of corrosion problems
under normal operating conditions, as oil is the continuous phase in the
mud and the metal surface will be ‘oil-wet’. The major exception to this is
the contamination of the mud with water and acid gases (ie CO2 and/or
H2S) due to formation fluid in-flow. Therefore, it is important to ensure that
the drilling fluid hydrostatic head and fluid density are maintained to
minimise this inflow. In addition, it may be necessary to make chemical
additions to oil-based muds, eg sulphide scavengers.
The dissolved gas that most commonly determines the general corrosivity
of water-based drilling muds is oxygen, although the insurgence of acid
gases due to formation fluid in-flow may also be important. In casing
design, general corrosion of the type associated with oxygen or acid gases
is not normally an issue as the periods of exposure are relatively short. In
addition, the pH of the mud is controlled to minimise the likely corrosion
rate.
An important corrosion problem that can occur during drilling is sulphide
stress cracking (SSC). This occurs as a result of hydrogen sulphide in the
mud. This hydrogen sulphide can have a number of sources, the more
important being:
• Inflow of formation fluids containing hydrogen sulphide
• Bacterial activity
• Degradation of the mud
The second and third of these sources can be adequately controlled by the
addition of biocides to the mud and correct mud selection. Although the
likelihood of the first source can be reduced by maintenance of the drilling
fluid hydrostatic head and fluid density to minimise formation fluid inflow,
the possibility of such inflow must still be considered; even a short
exposure time to a ‘sour’ environment can lead to a potentially catastrophic
failure. Therefore, if the presence of hydrogen sulphide is expected,
additional preventative measures need to be taken to ensure that SSC will
not occur, for example:
• Maintain the pH at a value of 10 or higher to neutralise the
hydrogen sulphide
• Use chemical sulphide scavengers
In addition, consideration can be given to the use of sour resistant casing
materials (refer to Section 15.1.2). For wells which are expected to be
‘sour,’ it is normal practice within BPA to use sour-resistant casing grades
for the casing strings likely to be exposed to the sour fluids.
15.3.1
Exploration/
Appraisal Wells
Page 22
September 1999 Issue 2
Section C15 Material Selection and Corrosion Guidelines 15A-5
BP Amoco
Casing Design Manual BPA-D-003
Halide ions, eg chloride and bromide ions, are present in many of the
fluids likely to be encountered downhole, ie formation waters,
injection waters, completion brines, workover fluids, etc.
Halide ions can cause localised corrosion damage to materials used for
downhole equipment in the form of corrosion pitting and/or crevice
corrosion. In addition, they can increase the corrosion damage resulting
from the effect of other corrodants.
Halide ions can also give rise to stress corrosion cracking (SCC) of
susceptible materials, principally austenitic stainless steels. This type of
cracking will normally only occur at elevated temperatures, typically above
50°C (120°F) for austenitic stainless steels, and under the action of
tensile stresses. This can also include residual stresses from mechanical
working.
Stress corrosion cracking can be defined as crack initiation and growth
in an alloy caused by the conjoint action of corrosion and tensile stress.
This cracking can occur at stresses well below the yield strength.
The mechanism by which this occurs is not fully understood, but it
requires the presence of certain specific alloy/environment combinations,
eg austenitic stainless steel in chloride-containing solutions. The result of
SCC is that normally ductile materials can suffer from catastrophic,
apparently brittle, failures.
This is the preferential corrosion that can occur to one of the metals, when
two different metals are electrically coupled in a corrosive environment.
In such a couple, one of the metals will act as an anode (ie it will corrode
at an enhanced rate) and the other will act as a cathode (ie there will be
a certain degree of protection). The susceptibility of a material couple
towards galvanic corrosion of the ‘anodic’ metal (ie the metal with the
lower equilibrium potential) is influenced by a number of factors, such as
the conductivity of the corrosive medium, the relative surface area of the
two metal components and the difference in the equilibrium potentials of
the two metals in the corrosive environment.
15A.2.5
Galvanic Corrosion
15A.2.4
Halide Ions
Page 23
September 1999 Issue 2
15A-6 Material Selection and Corrosion Guidelines Section C15
BP Amoco
BPA-D-003 Casing Design Manual
There are two types of localised corrosion that are likely to be encountered
downhole, ie corrosion pitting and crevice corrosion. As has already
been indicated, corrosion pitting occurs when certain regions in the
metal act as strong anodes. An example of this is the corrosion pitting of
certain stainless steels in chloride-containing environments. In this case,
pitting is enhanced by the presence of dissolved oxygen. The pitting
process is strongly affected by temperature. There are often temperatures
below which corrosion pitting will not occur in a particular environment,
this is known as the ‘critical pitting temperature’. Pitting is more damaging
than general corrosion as it can result in penetration in much shorter
times and is more difficult to detect. This is an aspect that should be
borne in mind when selecting materials for downhole service, particularly
corrosion-resistant alloys.
Crevice corrosion is the localised damage that can result at a narrow gap
or ‘crevice’ between two adjacent components. The crevice may be
between two similar materials, two different materials (in which galvanic
corrosion may also play a role), or even between a metal and a non-metal
(eg elastomers). An important factor in determining whether crevice
corrosion will occur is the size of the gap. Crevice corrosion is often
exacerbated at higher temperatures. The local environment produced
within a crevice can be quite different to the bulk fluid environment,
leading to corrosion damage which could not be predicted from the
general fluid composition.
15A.2.6
Localised Corrosion
