CORROSION GUIDE

Casing Materials Selection & Corrosion Guidelines J W Martin BP Amoco report no. BPA-D-003 dated September 1999

Main CD Contents

BP Amoco Casing Design Manual

BPA-D-003

Page 15.1 Scope

15-1

15.2 Material Selection Process 15.2.1 Casing Exposed to Muds and Brines 15.2.2 Sour-service Exposed to Produced Fluids

15-2 15-2 15-3

15.3 Corrosion Control 15.3.1 Exploration/Appraisal Wellls 15.3.2 Development Wells

15-9 15-10 15-11

15.4 External Corrosion

15-14

15.5 Flowchart for Corrosion Control Measures

15-14

Figure 15.1 15.2 15.3 15.4

Material Selection for Casing Sour Gas Systems Sour Multiphase Systems Sulphide Stress Cracking Performance Domain of Grade P110 Carbon Steel 15.5 Sulphide Stress Cracking Performance Domain of Grade N80 Carbon Steel 15.6 Major Corrosion Control Measures for Casing

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15-3 15-4 15-4 15-9 15-9 15-15

Material Selection and Corrosion Guidelines 15-17

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15.1 Scope

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Two types of service need to be considered when selecting materials for casing strings: • Casing strings that will normally only be exposed to completion brines/ drilling muds Materials selection for such strings is covered in Sections 15.1.1 and 15.1.2. • Casing strings that will/may be exposed to production/injection fluids for a significant part of their life (eg liners, some dual completion wells) Materials selection for such items is a complex issue, with many parameters that need to be taken into account. In addition, materials for such components change frequently as new corrosion-resistant options come onto the market. For these reasons the selection of materials for such casing strings and for tubular strings are covered in a stand-alone document entitled ‘Guidelines for Selecting Downhole Tubular Materials for Oil and Gas Wells’. This section contains two flow diagrams designed to assist the user in the selection of casing materials and corrosion control requirements respectively. These flow diagrams are not intended as exhaustive ‘stand-alone’ documents. Rather, the intention is to ‘flag’ the major considerations that need to be taken into account when selecting materials and/or corrosion control methods. With the very complex issues that are involved, it is not possible to be certain that nothing has been omitted from these flow diagrams. Therefore it is incumbent upon the users of the flow diagrams to ensure that all necessary aspects have been addressed before making the final selection. In the flow diagrams, decision points at which it will be necessary to consult the relevant specialist(s) have been highlighted. If you are unsure who the relevant specialist is, advice on contacts should be available from one of the Materials/Corrosion Engineers within UTG, BP Amoco.

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Material Selection and Corrosion Guidelines 15-1

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15.2 Materials Selection Process 15.2.1 For such duties, casing materials are normally carbon or low-alloy steels. Casing Exposed to There is a wide range of strength grades available for these steels, as Muds and Brines indicated in API 5CT/ISO11960. In addition, there are a number of proprietary grades not contained within the API/ISO Standards, eg 110ksi ‘sour-resistant’ grades. Usually, final selection of the strength required will be based upon the mechanical requirements of the casing design. Corrosion resistance is not usually a critical issue in the selection of materials for casing strings which are normally only exposed to completion brines or drilling muds. However, there is one significant exception to this rule and that is the temporary exposure of the casing string to hydrogen sulphide, ie sour conditions. The reason for this is that sulphide stress corrosion (SSC) cracking, which can result from exposure to sour conditions, can occur very rapidly. In addition, SSC can result in a catastrophic failure, with the material acting in an apparently brittle manner. If sour conditions are anticipated, the use of an SSC-resistant casing is often required. Guidelines for materials selection in the case of sour conditions are discussed in Section 15.1.2. It is becoming more common within BP Amoco to specify L80 in preference to N80 when available. The L80 grade meets the requirements of NACE MR-0175 and is normally no more expensive nor more difficult to source than N80. The use of API controlled hardness grades for sour-service can lead to extremely thick wall designs for high-pressure wells which require sour-service casing. As an alternative, the proprietary high strength (eg 110ksi) grades of sour-service casing can be considered. Testing within BP Amoco has indicated that these proprietary high-strength sour-service steel grades cannot be considered fully sour-resistant. However, they are acceptable for slightly sour conditions (refer to Section 15.1.2 for further details). A BP Amoco specification for the supply of 110ksi grade sour-resistant casing is also available. The flowchart in Figure 15.1 can be used when selecting casing materials that will be exposed to drilling muds and/or completion brines.

15-2 Material Selection and Corrosion Guidelines

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FIGURE 15.1 MATERIAL SELECTION FOR CASING Known data: • Pipe size • Material strength required • Connection type

As defined by NACE MR-0175-91 (See Section 15.1.2) YS - Specified Minimum Yield Strength

Completion Brines/ Drilling Muds ONLY

Service Environment

Produced Fluids

Refer to Guidelines for Selecting Downhole Tubular Materials for Oil and Gas Wells

Use carbon or lowalloy steel casing

Has corrosion resistant alloy production tbg been specified

Refer to the appropriate specialists and Guidelines for Selecting Downhole Tubular Materials for Oil and Gas Wells

Is exposure to sour conditions likely

Consideration can be given to using N80 (Q+T) or C95 in addition to the standard sour-resistant casing materials in API 5CT and NACE MR-0175-91

(150°F) 65°C

What is the minimum service temperature

Specify materials according to API 5CT and/or BP Engineering Standard (BP ES) 145

(175°F) 80°C

Consideration can be given to using H40, N80, or P110 grades in addition to the standard sour-resistant casing materials in API 5CT and NACE MR-0175-91

(150°F) 400°F, 200°C). Therefore, care needs to be exercised when using these types of fluid.

15.4 External Corrosion

External corrosion of casing can be a problem, especially where the casing passes through aquifers. If such problems are expected or encountered, consideration may need to be given to external cathodic protection or cementing across the zone of concern. The design of such systems is outside the scope of this manual and reference should be made to the appropriate specialists.

15.5 Flowchart for Corrosion Control Measures

The purpose of the flow diagram in Figure 15.6 is to assist in deciding the corrosion control measures required for the fluids normally in contact with the casing, ie completion brines or drilling muds. When selecting the chemical treatment package for completion brine, it is important to contact the relevant specialist(s), to ensure the suitability/compatibility of the various additives.

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FIGURE 15.6 MAJOR CORROSION CONTROL MEASURES FOR CASING What type of well is it?

Is the casing exposed to produced fluids

Have carbon/low alloy steel tubulars been selected throughout?

Refer to Guidelines for Selecting Downhole Tubular Materials for Oil and Gas Wells

Have carbon/low alloy steel tubulars been selected for casing or tubing

What fluids are in contact with the casing?

Where corrosion-resistant alloys are being specified, contact the specialists

Select completion brine Are the fluids going to be sour at any stage?

Use normal corrosion control measures for drilling

Select the required brine based on the specific gravity

Is the brine salinity >12% wt/wt

Is superficial initial corrosion apt to cause problems

Maintain a pH of 10 or greater in the drilling mud

Add biocide

Add a sulphide scavenger to the drilling mud prior to drilling sour interval

l

Add oxygen scavanger l

s

Is the specific gravity >1.2

Has a CaCi2/CaBR brine been selected

Check fluid is non-damaging to the formation. Consult the Completion Design Manual

Add corrosion inhibitor l

Add scale inhibitor l

l

Consult the specialists and ensure compatibility

s

Consult the specialists on superficial corrosion plugging valves

Draw up the specification for the completion brine

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Material Selection and Corrosion Guidelines 15-15

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Appendix 15A CORROSION BACKGROUND 15A.1 General

One of the prerequisites for corrosion to occur is the presence of an aqueous phase, although even a trace of water can lead to corrosion. Corrosion is an electrochemical process, so that an electrical current flows during corrosion. For an electrical current to flow, there must be a driving force, ie a voltage source, and a complete electrical circuit. The voltage source is the metal itself. All metals contain stored energy, eg as a result of refining, mechanical working. This means that metal will adopt an electrical potential when it is put into an aqueous solution, known as the ‘equilibrium potential’.

FIGURE 15A.1 DIAGRAMMATICAL REPRESENTATION OF THE CORROSION PROCESS FOR IRON

Anode

Fe -> Fe++ + 2 Electrons

Current Flow

Cathode

Electrolyte

2H+ + 2 Electrons -> H2 (Gas) Metal

The electrical circuit consists of three parts. These are shown diagrammatically in Figure 15A.1 and consist of: The Anode which is the portion of the metal surface which is dissolving or ‘corroding’. For iron this can be represented by the chemical reaction: Fe ⇒ Fe2+ + 2 electrons The Cathode which is the portion of the metal surface at which the electrons formed by the anodic reaction are ‘consumed’. There are many cathodic reactions that can occur, depending on the composition of the solution. For an acid the cathodic reaction would typically be: 2H+ + 2 electrons ⇒ H2 (gas) September 1999 Issue 2 Section C15

Material Selection and Corrosion Guidelines 15A-1

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The Electrolyte which is the electrically conductive solution on the metal surface through which the electrical current (or electrons) necessary to support the corrosion process flows. In the case where there is no externally applied electrical current, the anodic and cathodic reactions are balanced, ie there will be no ‘total’ current flow measured. The reasons why some areas of the metal surface act as anodes, whereas others act as cathodes, are complex. A major factor is inhomogeneity in the metal surface and/or electrolyte. In general corrosion, the anodes and cathodes will be randomly distributed over the surface and will ‘move’ during the corrosion process. In localised corrosion, eg pitting, the anodes will be restricted to certain, small areas. Many different types of corrosion damage can occur. The more likely to be experienced by downhole casing can be classified as follows: (1)

General Corrosion This results in a fairly uniform loss of material across the surface of a component, leading to a loss in load carrying capacity, eg the ability to contain a pressure, tension, collapse.

(2)

Localised Corrosion This results in uneven wastage of the component eg pitting corrosion. Pitting corrosion is a particularly damaging form of corrosion in which components can fail by perforation with only a small percentage weight-loss. In addition, pits will act as stressconcentrators, reducing the load-carrying capacity of the component. Alternatively, localised corrosion may occur at particular locations, eg crevices, mixed metal sites (galvanic attack), areas of high turbulence (erosion-corrosion).

(3)

Environment-sensitive Cracking (ESC) These mechanisms can lead to catastrophic, brittle failures. Cracking can occur rapidly and without the accompaniment of significant material wastage. In addition, the cracks can be very fine, making them difficult to detect using conventional inspection techniques. Examples of ESC are sulphide stress cracking (SSC), chloride stress corrosion cracking (CSC) and corrosion-fatigue.

15A-2 Material Selection and Corrosion Guidelines

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15A.2 Corrosion Mechanisms

As has already been indicated, there are many mechanisms by which corrosion damage can occur. This section covers the corrosion damage that can be accrued as a result of chemical contaminants and some of the other corrosion mechanisms that must be considered in casing design.

15A.2.1 Carbon Dioxide

Carbon dioxide is commonly found associated with well fluids. Carbon dioxide dissolved in water forms a weak acid, known as carbonic acid, which can cause corrosion. This is of particular importance for carbon steel, in which case an iron carbonate film is sometimes formed on the metal surface. CO2 corrosion of carbon steels often occurs at locations where the iron carbonate film is deficient, resulting in a particular form of localised pitting corrosion, known as ‘mesa’ attack. In circumstances where there is no iron carbonate film, the corrosion will be general. The rate of CO2 corrosion will be dependent on a number of factors, including CO2 partial pressure, pH, temperature, flow velocity, and the presence and nature of other chemical species (eg oxygen, chlorides, H2S). There are numerous guidelines that can be used to predict the severity of CO2 corrosion. Contact relevant specialist.

15A.2.2 Hydrogen Sulphide

There are a number of possible sources of hydrogen sulphide in downhole fluids. These include: • Associated with the well fluids • Generated as a result of bacterial activity. In this case sulphate-reducing bacteria (SRBs) can reduce sulphates in the fluids to hydrogen sulphide • Breakdown products of chemical species in the fluids. One such source could be bisulphites added to remove oxygen from injection water Hydrogen sulphide dissolved in water can react with a steel surface, producing an iron sulphide scale. H2S corrosion often results in deep pits in regions where the iron sulphide scale is not present. In practice, this type of H 2S corrosion has little practical significance unless the H2S content is high, ie several mole %.

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Material Selection and Corrosion Guidelines 15A-3

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Of greater importance, at the relatively low H2S levels often found in downhole fluids, is the mechanism known as ‘sulph ide stress cracking’ (SSC). Sulphide stress cracking occurs as a result of the entry of atomic hydrogen into the metal. Aqueous corrosion will produce atomic hydrogen which would normally tend to recombine via the reaction: 2H+ 2 electrons ⇒ H + H ⇒ H2 (gas) These hydrogen gas molecules are too large to enter the metal and are thus not harmful to it. However, hydrogen sulphide is thought to discourage the recombination of hydrogen atoms to form H2 gas and hence encourages the entry of atomic hydrogen into the metal. Once in the metal the atomic hydrogen will diffuse to ‘trap’ sites, where it will lead to a local increase in the stress and/or a reduction in the strength of the metal lattice. For a material under load, there is evidence to suggest that the atomic hydrogen will concentrate near stress concentrators and may give rise to crack initiation at such points, hence leading to a brittle-like fracture. This type of cracking can occur quite rapidly. Thus, even if materials are only to be exposed to sour conditions for short periods of time, they must be resistant to SSC. This aspect is covered in some detail in Paragraph 15.1 (Materials Selection) of this manual.

15A.2.3 Oxygen

The presence of dissolved oxygen can have a marked influence on the corrosion of oil-field goods. High corrosion rates can result even at relatively low concentrations of dissolved oxygen (much less than 1ppm). In this process iron is converted by a corrosion reaction to oxides and/or hydroxides. The cathodic reaction in this case is: O2 + 2H2O + 4 electrons ⇒ 4OHThe corrosion rate in oxygenated near-neutral solutions is often controlled by the rate at which oxygen can diffuse to the cathodic areas to support the corrosion reaction. As such, the corrosion rate will be increased by flow etc. Oxygen corrosion is not normally a problem with produced fluids, as they contain no dissolved oxygen. However, it can be a significant issue in water-based drilling muds, in which case it may be necessary to control the dissolved oxygen content using oxygen scavengers. Another area where oxygen corrosion can be a significant issue is in injection water systems, in which case care must be taken to reduce the dissolved oxygen to acceptable levels, eg using gas stripping or vacuum degassing.

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BP Amoco Casing Design Manual 15A.2.4 Halide Ions

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.

15A.2.5 Galvanic Corrosion

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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.

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BPA-D-003 15A.2.6 Localised Corrosion

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.

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