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

September 1999 Issue 2 Section C15

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

Material Selection and Corrosion Guidelines 15-17


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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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) <65°C Use only the standard sour-resistant casing materials in API 5CT and NACE MR-0175-91 (Refer to Table 3 of NACE MR-0175-91 "For all Temperatures" Column)

<95 ksi

What is the required strength grade

>95 ksi

Consideration can be given to using proprietary sourresistant casing grades with up to 110 ksi YS - consult with a relevant specialist

Has a suitable Specify materials according to (API 5CT and/or combination of strength ISO 11960) together with (NACE MR-0175 and SSC resistance and/or BP ES 153) been achieved If in doubt, ask the u appropriate specialists

Refer to Section 15.1.2 and/or consult the relevant specialists

15.2.2 Sour-service

NACE Standard MR0175 (Standard Material Requirements – Sulphide Stress Cracking Resistant Metallic Materials for Oilfield Equipment) is recommended as the document to be used to define a sour environment for BP Amoco worldwide. A ‘sour environment’ is defined in NACE Standard MR0175 as a fluid containing water as a liquid, together with hydrogen sulphide at a level exceeding certain criteria, as detailed in Figures 15.2 and 15.3.




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FIGURE 15.2 SOUR GAS SYSTEMS

Grains H2S Per 100 SCF 1

10000

10

100

1000

A

1000

B

Sulfide Stress Cracking Region

100 65 PSIA Total Pressure

10 .0001

.001

.01

.1

1

10

1000

10000

100000

MOL % H2 S in Gas PPM H2S in Gas 1

10

100

FIGURE 15.3 SOUR MULTIPHASE SYSTEMS

Grains H2S Per 100 SCF 1

10000

10

100

A

1000

1000

Sulfide Stress Cracking Region

265 PSIA Total Pressure

B 100

10 .0001

.001

.01

.1

1

10

1000

10000

100000

MOL % H 2S in Gas PPM H2S in Gas 1

10

100




BPA-D-003 From Figures 15.2 and 15.3 it is clear that the definition of sour conditions is different for gas and oil wells. For the purposes of this definition, any well with a gas/oil ratio of greater than 5000 standard cubic feet per barrel of oil is taken as a gas well. It is also apparent from these figures that the definition of sour conditions is normally based upon the partial pressure of hydrogen sulphide in the gas phase. To determine the partial pressure of hydrogen sulphide in the gas phase, certain field information is required. Considering a gas well, the information required is the bottomhole pressure and the mole (or volume) fraction of hydrogen sulphide in the gas. The partial pressure is then calculated simply by multiplying the mole fraction of hydrogen sulphide in the gas by the bottomhole pressure. For example, for a 5500m deep gas well with a bottom hole pressure of 14,000psi and a hydrogen sulphide content of 5ppm mole, the partial pressure of hydrogen sulphide would be 0.07psia (5/1,000,000*14,000), ie the well would be classified as sour. For oil wells under circumstances where there is gas present (multiphase wells), the partial pressure of hydrogen sulphide can be estimated by multiplying the total pressure by the mole fraction of hydrogen sulphide. The situation for oil wells in which there is no gas phase present under downhole conditions is somewhat different. The partial pressure of hydrogen sulphide that needs to be calculated is that in a gas phase in equilibrium with that dissolved in the well liquids (oil/water). An alternative description of this is the partial pressure of hydrogen sulphide in the gas phase formed at its bubble point. Therefore, a ‘convenient’ method often used to calculate the partial pressure is to multiply the bubble point pressure by the mole fraction of hydrogen sulphide in the gas phase. For example, for a 2000m deep oil well with a bottom hole pressure of 2500psi, a bubble point pressure of 1000psia and a hydrogen sulphide content of 40ppm mole, the pressure of hydrogen sulphide would be 0.04psia, ie the well would be classified as ‘sweet’. The major concern with sour conditions for casing string is the possibility of SSC. The mechanism of SSC is described in Appendix 15A. Two approaches have been developed to account for SSC in the materials selection process. These two approaches are described below. It should be noted that these approaches are only concerned with the resistance of materials to SSC in sour conditions. However, there are other failure mechanisms that may occur in the presence of hydrogen sulphide. These need to be borne in mind when selecting materials for sour-service. For example, some steels used in pipelines and vessels may suffer from blistering or step-wise cracking as a result of hydrogen damage in sour environments. This aspect is covered for such materials in BP Guidance for Specification (GS) 136-1. Also, some austenitic stainless steels and highly alloyed materials may suffer from chloride stress corrosion cracking at elevated temperatures (above about 50°C, 120°F), this can be aggravated in some circumstances by the presence of hydrogen sulphide. Again, this aspect is covered to some extent in BP GS 136-1.




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NACE Standard MR0175 (Standard Material Requirements – Sulphide Stress Cracking Resistant Metallic Materials for Oilfield Equipment) The NACE Standard MR0175 is concerned with the resistance of materials to SSC in sour conditions. In some countries, such as the United States, the Standard is a legislative requirement, ie it must be applied there. This document should be referred to for initial information on materials with adequate resistance to SSC for sour conditions. Having defined the field conditions to be ‘sour’, the latest version of NACE MR0175 should be consulted for materials requirements. In general, the NACE MR0175 Standard classifies the acceptability of various materials grades for sour-service in terms of their hardness (which is related to tensile strength). Section 10.2 of NACE Standard MR0175 deals specifically with materials for well casing and tubing. When applying Section 10.2 of the NACE MR0175 Standard, it should be noted that increasing the temperature reduces the likelihood of SSC, particularly for low-alloy steels. Hence, NACE MR0175 allows the use of materials with a specified minimum yield strength above that of the fully sour-resistant grades under circumstances where the minimum operating temperature is above certain limits. The information in Table 15.1, based upon Table 5 from NACE MR0175-98, details the acceptable tubular material grades for different temperature ranges (refer to NACE MR0175 for the full table). For all Temperatures (1,2)

For Operating Temperatures 65°C or Greater (3)



API Spec 5CT grades H40 (Note 4); J55; K55; L80 (Type 1); C90 (Type1); T95 (Type1)

API Spec 5CT grades N80 (Q + T); C95

API Spec 5CT grades H40; N80; P110

API Spec 5CT grade Q125. See Note 5

TABLE 15.1 ACCEPTABLE API SPECIFICATIONS FOR TUBULAR GOODS

Proprietary grades Proprietary Q + T Proprietary Q + T Per NACE MR-0175 grades with grades with Section 10.2 110ksi or less 140ksi or less maximum yield maximum yield strength strength

Notes to Table 15.1: (1)

Impact resistance may be required by other standards and codes for low operating temperatures.

(2)

Grade 155 casing is not covered in this table and is unsuitable for sour-service conditions at any of the temperature ranges specified.




BPA-D-003 (3)

Continuous minimum temperature; for lower temperatures, select from Column 1.

(4)

For H40 material the maximum permissible yield strength is 80ksi.

(5)

Regardless of the requirements for the current edition of API Spec 5CT, the Q125 grade shall always (1) have a maximum yield strength of 150ksi; (2) be quenched and tempered; (3) be an alloy based on Cr-Mo chemistry. The C-Mn alloy chemistry is not acceptable.

When using these criteria, it is important to bear in mind that SSC can occur within a relatively short timespan, so that periods of exposure to sour conditions at temperatures below those stated in the table could potentially lead to SSC problems. For this reason it is important to note that the temperature levels quoted in Table 15.1 are the minimum operating temperature the casing will experience. If temperatures below this minimum are expected even for short periods of time then the non-sour higher strength materials should not be used. BP Amoco Methodology for Selecting Materials with Adequate SSC Resistance It was recognised some time ago that the use of the NACE Standard MR0175 alone is not sufficient to allow the selection of the optimum material with adequate SSC resistance. For example, the NACE Standard makes no reference to the ‘in-situ’ pH, which is known to affect the likelihood of SSC of materials. In addition, the testing solution used in assessing the acceptability of materials for sour-service in NACE is very severe (1 bar H2S, pH 2.8), meaning that the standard is very conservative regarding which materials are acceptable for hydrogen sulphide service. Finally, there is insufficient information in the NACE Standard regarding the operating limits of many alloys. Therefore, BPA have developed a methodology based upon laboratory test results and field experience, to allow the user to select the correct material for the intended service. The decision was made to carry out all testing for the ‘BPA methodology’ under ambient (24°C +/- 3°C) temperature conditions, ie the ‘worst case’ scenario. Therefore, the methodology described here is applicable to all likely operating temperatures Note:


This methodology need not be applied to the traditional ‘sour-resistant grades’ in API 5CT (ie L80, C90, T95) which it is assumed are suitable for all sour conditions on the basis of past experience and test data.



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To apply the BPA methodology, it is necessary to know certain information about the proposed well, ie the partial pressure of hydrogen sulphide in the gas phase and the ‘in-situ’ pH of the water associated with the produced fluids. Note:

If no in-situ pH is available then one of the methodologies outlined in Appendix A of the ‘Guidelines for Selecting Downhole Tubular Materials for Oil and Gas Wells’ can be used to assess the in-situ pH on the basis of certain well information.

Once the necessary information has been collected, the conditions can be plotted onto the appropriate ‘sulphide stress cracking performance domain’ charts for individual alloys at the end of these guidelines. There are two domains identified on the individual alloy ‘go/no go’ charts. (1)

If the operating conditions fall within the ‘acceptable’ domain then the material is likely to have an acceptable resistance to SSC under the prevailing conditions. However, it is important to note that the go/no go charts were developed on limited information, ie it was only possible to tests a selection of the wide range of materials available on the market and only at one time (manufacturing techniques can change with time which may also affect their SSC resistance). Therefore, it is important to check the resistance of the material to the anticipated conditions before finalising the selection of a non-sour material grade for potentially sour-service. The suitability can be confirmed in two ways: • From prior satisfactory testing or service experience with material from the same supplier and made by the same manufacturing route under conditions equivalent to or worse than the intended service • From the successful outcome of small scale SSC laboratory tests under test conditions representative of the intended service on material from the same supplier and made by the same manufacturing route. Note that material testing lead times of perhaps 8 weeks need to be considered in planning For further information contact the relevant specialist.

(2)

If the operating conditions fall within the ‘unacceptable’ domain then it will be necessary to consider a material with greater SSC resistance.

It should be noted that the domain charts are not ‘all encompassing’, but only deal with resistance to SSC.



BP Amoco Casing Design Manual FIGURE 15.4 SULPHIDE STRESS CRACKING PERFORMANCE DOMAIN OF GRADE P110 CARBON STEEL

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6.5 Suitable 5.5 4.5 Unsuitable 3.5

0.001 0.015

0.01 0.15

0.1 1.5

1.0 15

10 (Bar) 150 (Psi)

Hydrogen Sulphide Partial Pressure

FIGURE 15.5 SULPHIDE STRESS CRACKING PERFORMANCE DOMAIN OF GRADE N80 CARBON STEEL

6.5 Suitable 5.5 4.5 Unsuitable 3.5

0.001 0.015

0.01 0.15

0.1 1.5

1.0 15

10 (Bar) 150 (Psi)

Hydrogen Sulphide Partial Pressure

15.3 Corrosion Control

It is necessary to consider the two different types of wells separately: • Exploration/Appraisal Wells • Development Wells The design of downhole completion equipment against corrosion is beyond the scope of this manual, for further information on this area reference should be made to the ‘Downhole Equipment Materials Guidelines’. In these types of wells, the major corrosive agent is the drilling mud. Two types of mud are in common use, ie oil-based or water-based.




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15.3.1 In the case of oil-based muds, there is little danger of corrosion problems Exploration/ under normal operating conditions, as oil is the continuous phase in the Appraisal Wells 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.




BPA-D-003 In the case of high-temperature/high-pressure wells, the situation was somewhat more complex for UK sector North Sea applications in the past. Document CSON 59, produced by the Department of Environment, required the operator to provide supporting data that non-sour casings can be relied upon not to fail catastrophically during: • A temporary period of exposure to sour reservoir fluid (eg whilst circulating out a kick or if there is a leak in the test string during production testing) and not subsequently thereafter in the remainder of its service life, or • The time between first exposure to sour reservoir fluids and completion of evacuation of the drilling installation in the event of total displacement of the well bore contents to such fluids These requirements have led operators to consider thick-wall sour-resistant casing or proprietary high-strength sour-resistant grades (normally up to 110ksi minimum specified yield strength). These are discussed in the section on materials selection (Section 15.1) and reference should be made to that section before specifying these types of material. Note:

15.3.2 Development Wells

CSON 59 has now been superseded by PON13 which imposes no requirement other than notification of expected H2S and incident reporting to PON 11.

Well design should endeavour to contain the corrosive produced fluids within the production tubing, eg by the correct selection of tubing material and the use of tubing strings with premium connections, where necessary. Therefore, the prime consideration in accounting for corrosion in well casing design is to ensure the correct selection of the annulus fluid. However, it is recognised that tubing leaks and subsequent pressurised annuli are possibilities. Therefore, measures need to be taken to ensure the adequate protection of the casing under such circumstances. These aspects are discussed in this section. Any part of the casing that is likely to be exposed to the produced fluids for a significant length of time should be designed to withstand such an environment. This means that when designing such casing, considerations very similar to those given for production tubing need to be addressed when selecting materials. This area is addressed in the ‘Guidelines for Selecting Downhole Tubular Materials for Oil and Gas Wells’.




BPA-D-003 Corrosion Control in Completion Fluids

Completion fluids can be defined as any borehole fluid placed across the producing zone prior to bringing on a well. These fluids are field/well specific and fulfil many roles. Brine completion fluids are used in well testing operations, workovers, completions and as packer fluids. The function in a completion is to fill the annulus space between the production tubing and casing. Completion fluids are commonly brines and are selected based upon the required specific gravity. Examples of some of the brines used and the specific gravity ranges they cover are given in Table 15.2. TABLE 15.2 TYPICAL BRINES USED AS COMPLETION FLUIDS

Brine

Specific Gravity Range

PPG

Sea Water KCl NaCl NaBr CaCl2 CaBr2 ZnBr2/CaBr2/CaCl2

1.02 1.16 1.19 1.50 1.39 1.39 to 1.71 1.82 to 2.31

8.5 9.7 10.0 12.5 11.6 11.6 to 14.3 15.2 to 19.3

A number of chemical additives can be made to these muds to assist in corrosion control, ie: Biocide Biocide is added to prevent the growth of aerobic and/or anaerobic bacteria. Such bacteria can lead to corrosion problems, eg by the production of hydrogen sulphide. Therefore, it is necessary to prevent their activity. There are a number of biocides commercially available. Final selection will be based upon many factors. However, one of the most important factors is the salinity of the completion brine. Where the brine salinity is very high (greater than 12% wt/wt), the addition of a biocide is unnecessary, as the high salinity is sufficient within itself to prevent bacterial activity. Another factor that will affect the selection of a suitable biocide is the presence of an oxygen scavenger (compatibility). Therefore, it is important to get the input of a suitable specialist when selecting biocides for completion brines. Oxygen Scavenger Oxygen scavenger is required to remove dissolved oxygen from the completion brine to reduce its corrosivity. The chemicals most commonly used for this function are ammonium or sodium bisulphite. The dosage rate will depend on the oxygen content of the brine. It is important to avoid overdosing of the oxygen scavengers as these can be corrosive in their own right and/or can lead to the deposition of iron sulphide scales. It is recommended that the oxygen level of the treated fluid is monitored to ensure effective treatment. 15-12 Material Selection and Corrosion Guidelines



BPA-D-003 If the completion brines are not deaerated, the available oxygen may in any case be quickly consumed by the superficial corrosion of the carbon/ low alloy casing where the two are in contact. Therefore, a decision must be made on whether or not an oxygen scavenger is required. This decision needs to be based upon a number of factors. For example, even the short period of enhanced corrosion in non-deaerated solutions may produce significant quantities of corrosion product. There may be concerns that this corrosion product dropping to the bottom of the annulus will block injection valves. Therefore, future use of the annulus needs to be considered. Additionally, if corrosion-resistant alloy (CRA) tubulars are specified then the presence of oxygen may initiate corrosion, eg pitting corrosion, crevice corrosion, galvanic corrosion, or even SSC, especially if the oxygen is not rapidly consumed by superficial corrosion of carbon/ low alloy steel (eg if the fluids are inside the tubing for any reason, areas where carbon steel is not present in the region of CRA tubulars). If in any doubt, the relevant specialists should be consulted. Corrosion Inhibitor Some of the high-density brines can be corrosive in their own right (eg zinc bromide). In such circumstances it will often be necessary to use a film-forming corrosion inhibitor to reduce the corrosion rates to permissible levels. There are many corrosion inhibitors available on the market therefore selection should be made with care. It is recommended that due reference is made to the relevant specialists. One corrosion inhibitor commonly used is a quarternary amine, which is dosed at a rate of 5% v/v (50,000ppm). As a rule of thumb, the cut-off point when deciding whether to consider a corrosion inhibitor or not is a specific gravity of 1.2 (10ppg), with a corrosion inhibitor being given consideration above this specific gravity. Compatibility with the formation itself should also be considered to avoid formation swelling or blocking. Scale Inhibitor This is the final chemical additive in completion brines. It is not added to control the corrosivity, but rather to prevent scales forming when the completion brine comes into contact with the formation brine. If a compatible completion brine has been selected, or where the completion brine will not come into contact with the formation fluids, a scale inhibitor is unnecessary. For example, where a sodium or potassium based brine is used, the high solubility of the products formed by mixing with formation water means that the addition of a scale inhibitor is unnecessary. Under normal conditions, scale inhibitors are only necessary in calcium chloride/ bromide completion brines. Under such circumstances, it is recommended that the relevant specialist be contacted.




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To avoid corrosion problems resulting from completion fluids, the use of alternative ‘non-aqueous’ fluids is sometimes considered, eg diesel oil. It has been found that one alternative fluid (bromoil/densoil) can be corrosive at elevated temperatures (>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

01112174




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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 %.




BPA-D-003

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.



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


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.



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.



CORROSION GUIDE

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