Materials Selection in Oil and Gas

In the oil and gas industry, corrosion-related failures have been reported to constitute over 25% of total safety incidents. The problem of corrosion in oilﬁeld environments is predominantly associated with the presence of corrosive species such as CO2 (causing sweet corrosion) and H2S (causing sour corrosion), and other associated reservoir constituents. Oxygen-related corrosion is mostly encountered in water injection systems. Some of the corrosion is found associated with as-manufactured defects on metallic components. This corrosion leads to material degradation causing costly failures with severe consequences for human life and the environment [1]–[3].

According to NACE IMPACT, in 2013, the global cost of corrosion-related economic losses for all industries is estimated to be USD 2.5 trillion, which is equivalent to 3.4% of the global Gross Domestic Product (GDP) including corrosion in the oil and gas production industry where the total annual cost of corrosion is estimated to be USD 1372 billion [1], [4].

Commonly, corrosion control focuses on materials and environments. Active corrosion control is by taking effective control of the process of corrosion, which includes the modeling of the system, material selection, and general design. The material selection process is one of the key stages in the integration assurance of the system, which plays an important role in the overall corrosion control process [1], [5].

Materials Selection Consideration

Choosing among materials to manage the corrosion needs a very careful understanding of the working and environmental conditions including design pressure and temperature, weldability, compatibility, and corrosion concerns especially the severity of the service fluid, such as pH, H2O, H2S, CO2, O2, salt, and other fluid content of the crude oil or gas. The materials selection process shall consider all statutory and regulatory requirements. The project design criteria, such as design lifetime, cost profile (CAPEX/OPEX), inspection and maintenance philosophy, safety and environmental profiles, operational reliability, failure risk evaluations, and other specific project requirements should be considered [5]–[7].

In addition, other criteria such as the safety and easy-to-repair level should be considered in the material selection process. As a rule of thumb, it should be taken extra attentions to products that are used in hard-to-repair locations. For offshore installations and particularly subsea, access for the purposes of maintenance and repair can be limited and costly and should be carefully considered in the design [5]–[7].

Material Selection Methods

The selection of materials can be a complex procedure, if improperly carried out can lead to mistakes in application and misunderstanding about the performance of a materials in a specific service environment. There are a variety of ways individuals and companies select materials [8]:

Companies with large research facilities typically initiate a test program that involves simulating the particular part of the field environment under study (i.e. flowlines versus downhole). Based on the available information, a group of alloys is selected that represents a possible range of alternatives. It is more cost-effective and less time-consuming to test only a few materials that are likely candidates, rather than test all alloys all the time [8].
Review the literature for corrosion data that generally applies to the anticipated field conditions. This can narrow the number of candidate alloys for testing. The selected materials are then tested under very specific conditions to fill gaps in literature data and/or field experience. Care must be taken when using this approach, for example, the corrosion resistance of many materials is specific to a particular temperature range. Likewise, changes in critical environmental components such as elemental sulfur can have a profound impact on the resistance to stress corrosion cracking (SCC), and another important factor in alloy selection [8].
The quickest and least expensive alloy selection method is simply to review the codes, standards, and literature including but not limited to ISO 21457 [6], NORSOK M-001 [7], and ISO 15156/NACE MR0175 (all parts) [9], [10], and existing or similar field data, and make the selection. These standard covers different alloy types with separate tables for different applications. It is important to obtain the latest version and corrigenda. This method can be quite unsatisfactory since certain critical factors or conditions will not be known and must be assumed. A greater chance for error exists in this approach is the introduction of a potential for failure of the materials or the use of a more expensive alloy than is required. It is advisable if this method is used, to consult with someone who has a working knowledge of materials and their applications [8].

Materials Selection Framework

This article provides an overview of material selection and corrosion protection for the oil and gas industry based on well-established and robust material selection guidelines standards including ISO 21457 [6], NORSOK M-001 [7], and ISO 15156/NACE MR0175 (all parts) [9], [10]. Figure 1 shows the material selection framework. This article gives an overview of guidance and requirements for:

Corrosion evaluation.
Design and limitations in mechanical properties
Material selection based on codes, standards, and literature.
Compatibility of dissimilar materials.
Corrosion protection and control.
Cost-effective selection.
Corrosion monitoring.

Figure 1. Materials selection framework

Corrosion Evaluation

Corrosion evaluation is an inevitable part of the material selection process. It is necessary to know the environment of oil and gas in the system. Commonly, sweet service or sour service. ISO 15156/NACE MR0175 defines ‘sweet service’ as service in any gas free of hydrogen sulfide. While ‘sour service’ is used to identify environments containing measurable amounts of H2S [10]. Production of sand and other solids are also common in most oil and gas wells. Therefore, materials selection in oil and gas is normally based on an evaluation of corrosion and erosion. The corrosion mechanisms and the specified process design parameters are included in ISO 21457, for offshore installations, NORSOK M-001 should be considered, see Table 1 and Table 2 [5]–[7].

All internal and external media should be considered for the entire design life. This should also include the stages of transportation, storage, installation, testing, and preservation. The aim of corrosion evaluation is to find how corrosive and aggressive the service fluid is to the materials. Corrosion evaluations and calculations should be based on well-known corrosion models (such as the Sell model, NORSOK M-506, etc.), laboratory tests, or field experiences [5]–[7].

Calculated corrosion rates based on models should be verified by the end user in order to incorporate field experience. If corrosion evaluation using the field experiences method, requires a well-documented successful experience of the material usage at the specific service fluid condition for at least two years and should preferably involve a full examination of the equipment following field use. In this case, according to ISO 15156/NACE MR0175, the usage of the same material at a similar service condition is acceptable. The severity of intended service conditions shall not exceed that of the field experiences [5]–[7], [10].

Design and Limitations in Mechanical Properties

Mechanical properties such as yield strength, tensile strength, hardness, and impact toughness should be considered in the selection of materials. In addition, for parts of the production system that operate at low temperatures or experience low temperatures, can suffer thermal cooling stresses and thus require material toughness to be sufficient to prevent brittle fracture under these conditions [6], [7], [9], [10].

Exposure temperatures during intermediate stages, such as manufacturing, storage, testing, commissioning, transport, and installation, should be considered when specifying the design temperature. Material properties based upon the minimum and maximum design metal temperatures and wall thicknesses shall be in compliance with specified design codes. The material weldability should also be considered to ensure an effective fabrication [6], [7], [9], [10].

The following guidelines for design and limitations in mechanical properties should apply for materials selection [6], [7], [9], [10]:

The specified minimum yield strength (SMYS) of carbon and low alloy steels intended for welding should not exceed 560 MPa. A higher SMYS may be specified, provided that documentation showing acceptable properties with respect to weldability and the properties of the base material, heat-affected zone, and weld metal is presented.
Usage limitations for materials in H2S-containing environments shall be in accordance with ISO 15156-2 and ISO 15156-3.
Free-machining steel grades should not be used.
Austenitic SS castings with PREN ≥ 40 should not be used for butt weld components due to risk of micro cracking in the heat-affected zone (HAZ) in weldments.
For martensitic carbon, low-alloy and CRA, the hardness of any components shall not exceed 328 HB or 35 HRC (submerged parts that exposed to CP).
Ferritic-austenitic (duplex) stainless steel shall be regarded as potentially susceptible to HISC, independent of SMYS or specified maximum hardness. Compliance with DNV-RP-F112 shall be specified (submerged parts that exposed to CP).
The hardness of weld and HAZ of any steel grade should not exceed 350 HV10 for non-H2S-containing service.
Titanium should not be used for hydrofluoric acid or anhydrous methanol with water content less than 5 %.
Certain titanium alloys in submerged parts may not be compatible with cathodic protection.

Materials Selection Based on Standards

Nowadays, codes like ISO 21457 [6], NORSOK M-001 [7], and ISO 15156/NACE MR0175 (all parts) [9], [10] provide materials selection guidelines for specific systems and areas in the oil and gas industry. Based on these codes [6], [7], [9], [10], for wet hydrocarbon systems, the internal and external corrosion mechanisms indicated in Table 1 and Table 2 should be evaluated. Materials carbon steel or corrosion-resistant alloy (CRA) listed in Table 1 and Table 2 are the recommended options for material selection in this systems. CRA should be evaluated against carbon steel when this is considered appropriate in the materials selection process [6], [7].

However, these standards do not exclude the use of other materials. Use of materials with equal or better performance shall be agreed with end-user [6], [7]. Furthermore, materials selection for other systems and areas such as oil and gas production and processing systems, flare systems, produced water systems, injection systems, utility systems, pipelines, and flowlines are provided in ISO 21457 [6] and NORSOK M-001 [7].

In addition, the possibility for "sour" service conditions during the lifetime shall be evaluated. Sour service definition, metallic materials' requirements, and qualification shall be according to ISO 15156/NACE MR0175 (all parts) [6], [7], [9], [10]. The evaluation and use of materials in conditions containing H2S, where cracking including hydrogen-induced cracking (HIC) shall follow the requirements. This evaluation should include the potential for future changes in reservoir H2S content. Dehydration of gas or use of corrosion inhibitors should not relax the requirement to use H2S-resistant materials [6], [7], [9], [10].

Material selection shall be optimized and provide acceptable safety and reliability for the entire design life. As a minimum based on code and standard [6], [7], [9], [10], the following shall be considered:

Corrosivity, taking into account specified operating conditions including start up and shut-down conditions.
Design life and system availability requirements.
Failure probabilities, failure modes and failure consequences for human health, environment, safety, and material assets.
Resistance to brittle fracture.
Inspection and corrosion monitoring.
Access and philosophy for maintenance and repair.
Minimum and maximum operating temperature.
Minimum and maximum design temperature.
Weldability (girth welds and overlay welds).
Hardenability (carbon and low alloy steels).

For the final material selection, the following additional factors shall be included in the evaluation:

Priority shall be given to materials with good market availability and documented fabrication and service performance.
Number of different materials shall be minimized considering stock, costs, interchangeability and availability of relevant spare parts.
Environmental impact and authority permissions, e.g., on discharge of chemicals like corrosion inhibitors shall be considered.

Table 1. Materials prone to internal corrosion mechanisms in hydrocarbon systems [6], [7], [11].

Corrosion mechanism	Description	Parameters	Materials prone
Corrosion mechanism	Description	Parameters	CS & LAS¹	CRA²
CO₂ and H₂S corrosion	CO₂ corrosion is one of the most common corrosion mechanisms oil and gas production and processing systems. The presence of H₂S in combination with CO₂ influences the corrosion. The type of corrosion is dependent on the proportions of these constituents in the production fluids.	Temperature, partial pressure and fugacity of CO₂and H₂S, pH, content of organic acids and flow conditions.	Yes	Yes³
MIC	Microbiologically induced corrosion (MIC) caused by living organisms such as bacteria, algae, or fungi. It is often associated with the presence of tubercles or slimy organic substances. Often, the bacteria produce localized corrosion in the form of pitting or crevice corrosion.	Water intermittent, stagnant, or low-flow conditions allow and/or promote the growth of microorganisms. pH range of 0 to 12, and temperatures from 0 °F to 235 °F.	Yes	Yes
SSC/SCC caused by H₂S⁴	Sulfide Stress Cracking (SSC) is the cracking of a susceptible metal under the combined action of tensile stress and corrosion in the presence of water and H₂S. SSC occurs in high-strength (high-hardness) steels, in highly localized zones of high hardness in weld metal and HAZs. PWHT is beneficial in reducing the high hardness and residual stresses.	H₂S level, pH, contaminants, temperature, microstructure, hardness (correlates to strength), and tensile stress level (applied or residual).	Yes	Yes
HIC/SWC⁴	Hydrogen-Induced Cracking (HIC) results from hydrogen atoms diffusing into the steel as a result of corrosion, resulting in internal separations parallel to the surface of the steel. The separations grow then eventually forming a thru-wall leak path. Interconnecting cracks between HIC separations on different planes have a stair-step appearance, so HIC is sometimes referred to as “Stepwise Cracking (SWC)”.	See SSC/SCC caused by H₂S, with consideration that blistering and HIC damage develop without applied or residual stress. PWHT will not prevent them from occurring.	Yes	No
ASCC⁵	Alkaline environments containing compounds such as amines, caustic or carbonates can cause alkaline stress corrosion cracking (ASCC) of carbon steels, especially where there is the potential to concentrate these compounds, e.g. in the presence of crevices or evaporation. Typical mitigation measures may include heat treatment after welding or forming, use of protective coatings, and CRA.	Level of tensile stress and/or residual stress, the type and concentration of amines, NH₃ and H₂S, caustic or carbonates, temperature, pressure, fluid velocity, localized turbulence, pH, and alloy composition.	Yes	No
SCC without H₂S	Internal Stress Corrosion Cracking (SCC) can occur in SS in the absence of H₂S and dissolved oxygen. This is due to water evaporation and deposition/concentration of chlorides in high salinity waters and at high temperatures. Systems where this can occur should be designed with fresh wash water injection facilities or resistant materials should be used.	Chloride content, temperature, pH, tensile stress, presence of oxygen, and alloy composition.	No	Yes
Erosion/Erosion-Corrosion	The material loss due to flowing solid particles (sand) or in a liquid or vapor stream physically abrading the material to material loss accelerated by the flow of corrosive liquid or vapor possibly combined with the velocity-assisted removal of a protective film or scale.	The velocity and number of impacting particles (sand), size, shape, hardness, and density of particles, the hardness of the material, and the angle of impact.	Yes	Yes
¹⁾CS = Carbon Steel; LAS = Low Alloy Steel ²⁾CRA = Corrosion-Resistant Alloy ³⁾ The presence of H₂S in combination with CO₂ can also lead to localized attacks of CRAs. There are no generally accepted limits and the limits vary with type of CRA. ⁴⁾The evaluation and use of materials in conditions containing H₂S, where cracking including hydrogen-induced cracking is possible, shall follow the requirements given in ISO 15156/NACE MR0175 (all parts) [9], [10] ⁵⁾Reference can be made to NACE RP0403 for guidance on caustic cracking or to API RP 945 for guidance on amine cracking.

Table 2. Materials prone to external corrosion mechanisms in hydrocarbon systems [6], [7], [11].

Corrosion mechanism

Description

Parameters

Materials prone

CS & LAS¹

CRA²

External marine atmospheric environments

The external marine atmospheric environment contains water and chloride salts. Carbon steel will be corroded. CRAs can suffer from corrosion, including pitting, crevice corrosion and SCC. Welds are particularly vulnerable to SCC.

A coating may be applied to prevent such corrosion and SCC. Operate material below Maximum Operating temperature (MOT) limits to avoid chloride-induced SCC.

Nickel-, titanium- and copper-based alloys are in general considered to be immune to SCC in marine environments.

MOT limits to avoid chloride-induced SCC:

Material Grade	MOT (°C)
Type 316 ASS	60
Type 6Mo ASS	120
Type 22Cr DSS	100
Type 25Cr DSS	110
ASS = Austenitic SS DSS = Duplex SS

Yes

Buried and submerged installations

The corrosion of metals from exposure to soils and submerged environment. The external protection of buried or submerged structures is usually achieved by a combination of external coatings and cathodic protection.

Depending on metallurgical condition, some CRAs, such as UNS S17400, UNS N05500 and duplex stainless steel, can be susceptible to HSC while catholically protected.

Temperature, moisture and oxygen availability, soil/water resistivity, soil/water type, cathodic protection, stray current drainage, and coating type, age, and condition.

Yes

Corrosion Under Insulation (CUI) and fireproofing

Corrosion of piping, pressure vessels, and structural components resulting from water trapped under insulation or fireproofing.

Temperature, presence of chlorides, local condensation on the metal surface, duration of wetting, coating system, insulation and sealing system, and environment.

Yes

¹⁾CS = Carbon Steel; LAS = Low Alloy Steel

²⁾CRA = Corrosion-Resistant Alloy

Corrosion-Resistant Alloy (CRA) Selection Literature

Corrosion-resistant alloys (CRAs) are employed in severe oil and gas production environments that operate at high pressures and temperatures and contain chlorides, CO2, and H2S. They exhibit high resistance to uniform corrosion in these environments due to their passivity. CRA generally includes a wide range of Fe–Ni–Cr–Mo–W and Ti alloys that tend to form a passive film [12].

However, CRA can suffer from different forms of environmentally assisted cracking (EAC), depending on the environmental and metallurgical conditions. The localized corrosion resistance of the CRAs is often ranked by the pitting resistance equivalent number (PREN). The limits of SCC resistance are given in terms of chloride concentration, temperature, pH, and H2S partial pressure. ISO 15156/NACE MR0175 provides a number of guidelines for the selection of CRAs for sour service. The ISO15156-3/NACE MR0175-3 standard lists a number of environments where different CRAs could be used in service without further testing [9], [10], [12], [13].

Today, the qualification of materials for oil and gas production is based on a research and development, combination of standard tests, fitness for purpose evaluations, and, perhaps more importantly, experience [13]. Several research has been conducted for the development of selection corrosion-resistance alloys for the oil and gas industry. A selection scheme for CRAs was identified by Ueda and Sumitomo Metals and reproduced in Figure 2 [12], [14].

Figure 2. CRA selection scheme, adapted from Ueda and Sumitomo Metals [12], [14].

Compatibility of Dissimilar Materials

Galvanic corrosion can occur when dissimilar metallic materials are connected together in a conductive corrosive fluid. The extent of the galvanic corrosion risk is influenced strongly by such factors as the area ratio of the two metals, the cathode efficiency of the more noble metal, the conductivity of the electrolyte, oxygen content, and temperature. It is necessary to evaluate all these parameters in the design of the facilities [6], [7].

Wherever dissimilar metals are coupled together, a corrosivity evaluation shall be made. If galvanic corrosion is likely to occur, there are the following methods to mitigate it [6], [7]:

Flange connection is the preferred method of connecting dissimilar materials when there is a significant risk for internal galvanic corrosion.
Install a distance spool between the dissimilar metals so that they will be separated by at least 10 pipe diameters from each other. The distance spool may be either of a solid electrically non-conducting material (e.g. GRP) or of a metal that is coated internally with an electrically non-conducting material, e.g. vulcanized rubber. The metal in the distance spool should be the most noble of the dissimilar metals unless vulcanized rubber lining is selected.
Apply a corrosion allowance on the less noble metal or a sacrificial thick-walled carbon steel spool, which is designed for replacement at scheduled intervals.
Install internal sacrificial anodes through access fittings near the interface, e.g. resistor-controlled cathodic protection for seawater systems.
Apply electrical isolation of dissimilar metals; however, the risk of electrical continuity via pipe supports, decks and earthing cables should be evaluated.
At critical interfaces between dissimilar metals in hydrocarbon production and processing systems, weld overlay of the flange face of the less noble material with a corrosion-resistant material may be considered.
Apply a non-conducting coating on the most noble of the dissimilar metals to reduce the cathode area. The coating shall extend at least 10 pipe diameters into the most noble pipe material.
For connections between copper alloys and stainless steel/nickel alloys/titanium, the use of easily replaceable spools with added wall thickness should be evaluated.
Direct contact between aluminum and carbon steel or copper alloys shall be prevented.
If the use of dissimilar metals is unavoidable and necessary, an attempt to select metals which form “compatible couples or groups” should be made. The “Galvanic Corrosion Indicator” published by the International Nickel Company Ltd. can be useful [15].

Corrosion Protection and Control

For dry gas/oil/condensate systems, carbon steel can be selected with no requirements for internal corrosion control. However, a corrosion allowance may be required if periods of wetness are envisaged during the construction/commissioning phases or during the operational phase [6].

For wet gas/oil/condensate processing, the corrosivity of the wet gas/oil to carbon steel can be very high due to the low pH of the condensed-water phase. Therefore, the appropriate material choice combined with appropriate corrosion control shall be considered [6], [7].

1. Chemical Treatment

Common methods of chemical treatment for carbon steel in production and processing facilities are the use of film-forming inhibitors, oxygen scavengers, biocides, anodic inhibitors, and pH stabilizers. Environmental requirements for the use of corrosion inhibitors should be agreed with the end user [6], [7].

Parameters that can strongly influence the feasibility of chemical inhibition are temperature, flow conditions, H2S content, compatibility with other chemicals, and effects of erosion in solids-containing systems. For produced water systems, contaminants such as oxygen and MIC should also be considered. These parameters should be defined in the design basis. The performance of inhibitors should be confirmed via laboratory testing. Actual field trials should be performed to test and optimize the dosing [6], [7].

2. Corrosion Allowance (CA)

An internal corrosion allowance is commonly used for carbon steel. The corrosion allowance should be added in response to expected internal corrosion. Each system should be evaluated and the selected corrosion allowance supported by corrosion evaluations. Possible corrosion during the construction, installation, preservation, start-up period and production upsets should be included, in addition to the expected corrosion during normal operation. The corrosion allowance formula was provided in NORSOK M-001 [6], [7].

Commonly used corrosion allowances in piping systems are listed below [6], [7]:

1.0 mm to 1.5 mm for non-corrosive service.
3.0 mm for mildly corrosive service.
6.0 mm for severely corrosive service.

For pipeline systems, a maximum internal corrosion allowance of 8 mm to 10 mm should be used as a general upper limit for use with carbon steel [6], [7].

3. Internal and External Coating

Selection of internal coating for equipment should be performed on an individual basis due to the very wide range of possible service conditions. Additionally, some internal coating systems are specified in conjunction with cathodic protection [6].

External coating system selection for carbon steel should consider the design life, operating conditions and conditions during construction, transport, storage, commissioning and installation of the facilities. Carbon steel shall always have external surface protection when exposed to external atmospheric environment. Guidance on selection of coating system selection for different environments is given in ISO 12944-5 and surface preparation grades are defined in ISO 12944-4. Performance of the external coating system for carbon steel for offshore atmospheric and immersed conditions should generally conform to the requirements of ISO 20340, or NORSOK M-001 and NORSOK M-501 [6], [7], [16].

For equipment with SS material in the marine atmosphere, special consideration should be given to coating selection, surface preparation, and quality control during the application of the selected coating system. It should be recognized that external coatings can have service lives that are shorter than the anticipated operational life cycle and can require maintenance in order to minimize the threat of SCC of SS equipment or external corrosion of carbon steel. The coating systems selection and requirements for application shall be as specified in ISO 12944-5, ISO 12944-4, and ISO 20340, or NORSOK M-001, and NORSOK M-501 [6], [7], [16].

4. Cathodic Protection (CP)

A. Offshore

The cathodic protection design shall be in accordance with NORSOK M-503 [17] for submerged installations and seawater-containing compartments or NACE SP0176 [18] or DNV-RP-B401 [19] for subsea structures and components, and ISO 15589-2 [20] for offshore pipelines. Subsea installations should be protected against corrosion using paint or other coating systems combined with cathodic protection. Cathodic protection systems, or coating systems, or both, should be used for all metallic materials that are susceptible to seawater corrosion. An exception is made for components where it is impractical to obtain reliable electrical contact with the anode system. Such components shall be made either of seawater-resistant materials or of carbon steel with a sufficient corrosion allowance for the required lifetime [6], [7].

B. Onshore

The cathodic protection design for onshore buried pipelines should be as described in ISO 15589-1 [21]. Cathodic protection should be considered for all other underground steel equipment, e.g. buried fire-water ring mains, but this should depend on the external corrosivity evaluation [6].

5. Splash Zone Protection

For structures and risers in splash zones, the corrosion protection for permanently installed equipment shall consist of coating and corrosion allowance. The selected coating should be designed to perform for the entire design life. Damage to the coating system should be expected. The corrosion allowance for risers should take into account exposure of bare steel to the environment for a realistic period for repair of coating damage. The corrosion allowance for carbon steel should be based on the predicted corrosion rate and design life but should be a minimum of 6 mm unless otherwise specified. NORSOK M-001 provides guidelines for splash zone protection [6], [7].

6. Corrosion Protection of Closed Compartments

For completely closed and sealed dry atmospheric compartments in carbon steel structures, internal corrosion protection is not necessary. Dehumidification equipment can be applied in a closed or semi-closed atmospheric compartment to prevent humidity and corrosion [6], [7].

For completely closed seawater filled compartments in carbon steel (e.g. in jacket legs, J-tubes and caissons) no internal corrosion protection is needed. For compartments with volume to area ratios exceeding 1 m3/m2 and a possible, but restricted sea water exchange (e.g. subsea installations), treatment with oxygen scavenger can be used as an alternative to cathodic protection. In structural compartments with low water circulation where H2S can be formed, zinc anodes should be used [6], [7].

7. Corrosion Under Insulation Control

Insulation for structures, vessels, equipment, piping systems etc. shall be according to NORSOK R-004 and ensure drainage at low points and access in areas where maintenance and inspection are required. Heat tracing shall be avoided in conjunction with stainless steel materials [7].

Passive fireproofing materials for protection of structural steel or for area segregation should be of spray applied types. A corrosion protection coating system shall be applied to the steel. The use of cement type fire protection of aluminum structures should be avoided [7].

8. Other Corrosion Controls

Other corrosion controls are provided in ISO 21457, in additional for offshore installations, NORSOK M-001 should be considered [6], [7].

Cost-Effective Selection

Before extensive efforts are made to make a final CRA selection for a specific application, it is often desirable to make preliminary selections of candidate CRAs to test in a simulated field environment or to perform an economic analysis to judge the cost-effectiveness of several corrosion control alternatives (i.e. carbon steel plus inhibitors, CRAs, etc.). In most instances, there will be different alternative materials that may be considered for a specific application [8], [15]. Calculation of true long-term costs requires estimation of the following:

Total installation cost.
Service life.
Maintenance cost.
Time and cost requirement to replace or repair at the end of service life.
Cost of downtime to replace or repair.
Cost of inhibitors, extra facilities, or training required to assure achievement of predicted service life.
Time value of money.
Factors which impact taxation, such as depreciation and tax rates.
Inflation rate.

For example, in the offshore atmospheric environment, material selection and surface protection shall be such that general corrosion is cost-effectively prevented and chloride stress corrosion cracking, pitting, and crevice corrosion are prevented. It should be realized that every process and treatment will give added value and increase the final material cost. Also, the costs of alloys will be higher than those of unalloyed metals [7], [15].

Corrosion Management

A corrosion management program shall be prepared and implemented before start-up of production. Carbon steel in combination with suitable measures to control corrosion is the base case material selection for most production facilities. Selection of CRAs will limit the need for inspection and monitoring. A corrosion management program for carbon steels used in corrosive service should as a minimum consist of the following parts [6], [7]:

Definitions of roles, responsibilities and reporting routines within the organization.
Corrosion risk evaluation.
Planning and execution (methods, location and frequency) for corrosion monitoring, process parameter monitoring and water analyses.
Planning and execution of addition of corrosion control chemicals.
Develop procedures for evaluation of corrosion monitoring data and for verification that the corrosion rates and conditions are within acceptable levels (pre-defined targets).
Definition of consequences and actions if targets are not met.

1. Corrosion Monitoring

Requirements for corrosion monitoring including locations for monitoring devices and sample points should be included as a part of detailed engineering. The design of corrosion monitoring systems shall take into account the probability and consequences of failure. Typical monitoring methods and their application are given in Table 3 [6], [7].

Permanent corrosion monitoring shall always be used when the corrosion control is based on chemical treatment. For cathodically protected components should be considered when the components are not accessible for potential measurements. Monitoring can include both reference electrode(s) for potential measurement and monitored anodes for current determination. Other methods that can be used to assess the corrosivity are fluid analyses and wall thickness measurements and various inspection methods. It is recommended to use at least two methods. One method should always be weight loss coupon(s) [6], [7].

Table 3. Internal corrosion monitoring [7].

Method	Applicable systems	Comments	Notes
Weight loss coupon	All systems	Coupon should be of the same/similar material as the wall. May include weld	1
Linear polarization resistance	Systems with an aqueous/electrically conducting phase	Requires normally approx. 30% aqueous phase with min. 0.1% salinity
Galvanic probes	Aqueous	Water injection systems
Electrical resistance	All systems	Downstream inhibitor injection points when monitoring pipelines
Erosion/sand monitoring probes	Process flowline systems Subsea production systems
Hydrogen probes	Hydrocarbon systems	For sour service conditions
Notes 1. Recommended maximum time between inspection/replacement: 3 months.

References

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[11] ANSI/API, “ANSI/API RP 571: Damage Mechanisms Affecting Fixed Equipment in the Refining Industry,” 2020.

[12] N. Sridhar, R. Thodla, F. Gui, L. Cao, and A. Anderko, “Corrosion-resistant alloy testing and selection for oil and gas production,” Corrosion Engineering Science and Technology, vol. 53, pp. 75–89, Mar. 2018, doi: 10.1080/1478422X.2017.1384609.

[13] M. Iannuzzi, “Environmentally assisted cracking (EAC) in oil and gas production,” 2011.

[14] Sumitomo Metals, “Material Selection Guidelines: SUMITOMO PRODUCTS FOR THE OIL AND GAS INDUSTRIES.”

[15] Alireza. Bahadori, Corrosion and materials selection : a guide for chemical and petroleum industries. 2014.

[16] NORSOK, “M-501: Surface Preparation and Protective Coating,” 2012.

[17] NORSOK STANDARD, “M-503: Cathodic Protection,” 2007.

[18] T. National Association of Corrosion Engineers (Houston, NACE Standard RP0176-2003 Corrosion control of steel fixed offshore structures associated with petroleum production. NACE, 2003.

[19] D. Norske Veritas, “DNV-RP-B401: RECOMMENDED PRACTICE CATHODIC PROTECTION DESIGN,” 2010. [Online]. Available: http://www.dnv.com

[20] International Organization for Standardization, “ISO 15589-2: Petroleum, petrochemical and natural gas industries - Cathodic protection of pipeline transportation systems - Part 2: Offshore pipelines,” 2012.

[21] International Organization for Standardization, “ISO 15589-1: Petroleum, petrochemical and natural gas industries - Cathodic protection of pipeline systems - Part 1: On-land pipelines,” 2015.

Materials Selection in Oil and Gas - An Overview