Pipeline Piping Material Selection Basis

1 Overview of the Article

The article presents material selection for pipeline and piping systems. The general focus of the article is material selection for systems transporting oil and gas products.

The material selection described in this article covers mainly metallic pipe, including carbon steel, stainless steel, duplex steel etc. The selection criteria described here are mostly based on fluid and environmental corrosion on the selected materials.

Piping materials recommended in this article are based on a general rule of thumb, author experience and codes recommendations. A detailed analysis is required for final decision making on the selection of materials.

2 Introduction

Material selection is a key component of the design process of any facility. Material selection covers piping, static and rotating equipment, valves, fitting, inline components etc. Generally, some materials are commonly used for certain applications, i.e., non-metallic piping materials such as PVC pipes for building plumbing works, HDPE and GRP Piping for general water services and corrosive water application, carbon steel pipes for sweet services etc. The selection of the material type is a critical activity that commences during the project conceptualisation. Material selection has a huge impact on the project cost; therefore, material selection should be based on technical evaluation and commercial evaluation.

Experienced material engineers perform material selection; they may utilise software such as Hydrocor for various simulations that aid the selection of appropriate material. The key analysis performed is determining the material corrosion rate based on the type and condition of fluid flowing through the pipe and the environment where the pipe will be installed. The analysis performed predict the service life corrosion (SLC) of the pipeline or piping.  Also, materials usually have maximum and minimum service ranges (Pressure and Temperature); these are considered during the material selection phase.

Material selection is documented in a report with the selection criteria’s properly spelt out, the governing codes and standards defined etc.

Note the key variable in material selection is corrosion; other variables are evaluated after the suitability of the material to transport the fluid and withstand the environmental conditions has been determined.

Some organisations, e.g. SHELL, ExxonMobil have developed guidelines and procedures that aid material selection; this is achieved by the selection process and the development of corrosion management process for the selected materials. NACE MR-01-75 has a list of materials that exhibit resistance to sulfide stress cracking (SSC); Norsok M-001 also provide guidance and requirements for material selection and corrosion protection for materials used on fixed offshore installation, including subsea production systems. The Norsok standard also applies to onshore terminals except for structural and civil works.

Selecting materials involves short-listing all technically acceptable materials for the transportation of the fluid, followed by selecting the most cost-effective option for the required operational life, satisfying all relevant Health, Safety and Environmental regulations. Material selection requires several iterations before an optimal choice is made.

Material Selection Process shall take into consideration the following:

2.1 HAZARD and Effects Management

The material selection process shall be in accordance with HSE Hazards and Effect Management Process (HEMP). All the identifiable risks associated with the material are documented, and applicable mitigations and barriers are implemented.

2.2 Corrosion Management

A corrosion management procedure shall be clearly defined for the materials selected. This include:

• Identifying threats that result in degradation of materials
• Specifying and implementing barriers to mitigate corrosion
• Designing the barriers for the entire lifetime of the system
• Defining corrosion management elements including developing corrosion management manuals, defining corrosion control method, defining chemical injection requirements, inspection and corrosion monitoring etc.

3 Material selection basis

Material selection is based on several factors; however, the key factor described in this article is corrosion.

Section 4.2 of the Norsok M-001 standard itemised some of the selection criteria. Materials selected shall provide acceptable safety and reliability. As a minimum, the following shall be considered

• Corrosivity, considering the system specified operating conditions, including start-up and shut-down conditions. To be considered is the possibility of a new corrosion mechanism occurring in the future.
• The design life and system availability requirements.
• Failure probabilities, failure modes and failure consequences for human health, environment, safety and material assets;
• Material resistance to brittle fracture
• Inspection and corrosion monitoring
• Access and philosophy for maintenance and repair;
• Minimum and maximum operating temperature of the system, considering future operating conditions.
• Minimum and maximum design temperature taking into consideration future changes in operating conditions.
• Weldability (girth welds and overlay welds).
• Hardenability (carbon and low alloy steels).

Final material selection shall also consider

• Market availability of the selected materials with priority given to materials with good market availability and documented fabrication and service performance.
• Number of different materials shall be minimised considering cost, stock, interchangeability and availability of relevant spare parts.
• Environmental impact and authority permissions (Local and international authorities).

As previously stated, corrosion is one of the key material selection criteria; below subsections explain some types of corrosion-related to material selection.

3.1 Corrosion

Corrosion is the degradation of the internal or external of a metal due to its reaction to its environment. The internal environment is the fluid transported, including any contaminants or impurities. The external environment includes ambient conditions such as rainwater, air, sunlight, contact with other elements etc.

Concerns about corrosion dominate materials selection. Understanding corrosion and the common strategies used to deal with it are key to selecting appropriate materials for oil and gas applications.

Should evaluate all possible forms of corrosion during material selection. Below is a summary of some of the major forms of corrosion and possible materials that could withstand the corrosion.

3.1.1 Internal Corrosion

This form of corrosion results from the interaction between the fluid and the internal surface of the pipe. They are categorised into:

3.1.1.1 Wet carbon dioxide (CO₂) corrosion

Carbon dioxide (CO₂) is one of the most predominant causes of wall thickness loss in carbon steel and low alloy piping and pipelines. The presence of CO₂ can result in severe pitting if not properly mitigated.

At the temperature usually encountered within oil and gas production systems, dry CO₂ gas is not corrosive to C-Mn steel. However, CO₂ is extremely soluble in water and brine. It dissolves to form an aqueous carbonic acid (H₂CO₃). It is the acid that attacks the walls of Carbon Steel pipes resulting in corrosion. CO₂ corrosion is affected by several factors, including those listed below:

• The presence of water aids corrosion caused by Wet CO₂, i.e. there must be water wetting for this corrosion to occur.
• pH affects the corrosion rate. Corrosion tends to decrease as the pH value increases above 5.5. This implies that low-value pH increases the rate of corrosion
• Increase in temperature usually increases the corrosion rate
• Higher partial pressure of wet CO₂ also speed up the corrosion process. A rule of thumb is to use carbon steel material when the partial pressure is lesser than 4Psi.

CO₂ corrosion can be mitigated primarily by:

• The external of the pipes can be protected using a coating such as 3LPE (3 – Layer Polyethylene, 3LPP (3 layer Polypropylene), appropriate painting etc.
• Consider the use of alloy such as stainless steel because they are resistant to CO₂ attack
• Use of internal lining or coating to prevent the acid from coming in contact with the pipe walls
• Use of corrosion inhibitors.
• Altering the environment to render it less corrosive.

Of all the proposed, most companies tend to use alloys such as stainless steel (316, 316L etc.) for piping. Internally lined carbon steel pipes are considered for pipelines. When there is no possible evidence of CO₂ and other forms of corrosion, the two most commonly used pipes are the ASTM A 106, Grade B and API 5L Grade B for onshore facilities. For low-temperature applications, consideration is given to ASTM A333, A334, while for high-temperature A 335 materials are considered. Higher grades should be used when there is an excessive increase in wall thickness due to increasing pressure.

The wall thickness loss due to CO₂ corrosion can be estimated. Formulas and guidelines described in Norsok Standard M-506 can be used to predict the corrosion resulting from CO₂. The standard does not cover additional effects of other constituents which may influence the corrosivity, such as O₂, H₂S etc. The effect of these additional constituents should be evaluated separately.

3.1.1.2 H₂S corrosion

This type of corrosion is predominant in onshore production facilities such as crude oil and gas production systems. This type of corrosion is termed sour corrosion. Sour corrosion occurs in pressure vessels, storage tanks, piping and pipelines, mostly during periodic stagnation that produces a buildup of hydrogen sulfide on the metal surface.

Corrosion caused by H₂S can take the form of pitting, cracking or blistering, mostly occurring in the internal of the piping system.

Sour corrosion can result in material failure at stress levels less than their normal yield strength; this is termed Sulfide Stress Cracking (SSC).

Sulfide Stress Cracking (SSC) results from the absorption of atomic hydrogen produced by the corrosion process on the metal surface. Some of the hydrogens diffuse into the steel and cause cracking. The hydrogen diffusion depends on the fluid pressure, the material thickness and the metal surface combination.

Selection of the material to mitigate SSC is a function of the Service life corrosion (SLC), Partial pressure of H₂S (pH2S), the temperature of the system, and chloride concentration.

NACE MR 0175 has specified general principles for the selection of cracking-resistant materials. See various tables for the selection of appropriate materials. Also, Norsok M-001 has recommended typical materials that may be applicable for these services.

3.1.1.3 Erosion Corrosion

Pipe internal erosion-corrosion is brought about by the impingement of high moving fluids on the piping walls or by abrasion of the solid suspensions in the fluids on the piping walls.

With the presence of corrodents such as CO₂, H₂S, etc., the metal is degraded faster than expected from erosion or corrosion alone.

All materials suffer erosion-corrosion if flow rates are too high; this is usually more significant at piping locations where there are changes in configurations such as tees, reducers, elbows, valves etc. Therefore to tackle this risk, it is better to keep the flow velocity within acceptable limit.

Installation of filters, sieves, gravel packs within production wells and piping is recommended to reduce the effect of solid suspensions.

In API 14E, it is recognised that a critical velocity exists above which erosion-corrosion can become a significant problem in two-phase flow. API 14E equation 2.14 is used to establish the critical velocity (V_e) above which erosion will occur.

Where:

V_e = fluid erosional velocity, feet/second

c = empirical constant

p_m = gas/liquid mixture density at flowing pressure and temperature, lbs/fts

Extract from API 14E (Industry experience to date indicates that for solids-free fluids, values of c = 100 for continuous service and c = 125 for intermittent service are conservative. For solids-free fluids where corrosion is not anticipated or when corrosion is controlled by inhibition or employing corrosion-resistant alloys, values of c = 150 to 200 may be used for continuous service; values up to 250 have been used successfully for intermittent service. If solids production is anticipated, fluid velocities should be significantly reduced. Different values of “c” may be used where specific application studies have shown them to be appropriate.

Where solids and corrosive contaminants are present or where “c” values higher than 100 for continuous service are used, periodic surveys to assess pipe wall thickness should be considered. The design of any piping system where solids are anticipated should consider the installation of sand probes, cushion flow tees, and a minimum of three feet of straight piping downstream of choke outlets.

3.1.1.4 Under Deposit Corrosion

Under deposit corrosion may occur between the debris deposits in piping, especially in slow-flowing horizontal piping and pipeline. These forms of deposit could be organic or inorganic, with the most prevalent inorganic deposit been sand. This type of corrosion can induce pitting.

The solid deposit also prevents the removal of the corrosive products by the flow action and limits the contact of corrosion inhibitors on the internal pipe wall.

This type of corrosion occurs around lap joints, gasket surfaces or crevices that are under bolts. This type of corrosion is very aggressive, and in some cases, pitting can be seen throughout the entire metal surface.

Under deposit, corrosion can be minimised by regular maintenance at suspected locations and using an appropriate internal coating. Possible materials resistant to this type of corrosion are stainless steel such as AISI 316, 316L, duplex stainless steel, etc.

3.1.2 External Corrosion

These are the type of corrosion resulting from the interaction of the external environment and the pipe surface. These are categorised into:

3.1.2.1 Chloride Stress Corrosion Cracking (CSCC)

External chloride stress cracking can be a threat in swamp and coastal areas if alloy and stainless steel are selected to prevent hydrogen sulfide and carbon dioxide corrosion. Chloride stress cracking can also happen when the process stream contains water with chloride.

Piping attacked by CSCC will fail at a stress level lower than the allowable stress limits.

Chloride settlement on the piping surface can be significant if chloride carry over from saltwater settles on the piping, especially if oxygen is present and the temperature is over 140^oF (60^oC). This type of corrosion may still occur at a lower temperature. When it is established that there is a tendency of CSCC, the use of alloy such as  AISI 300 series austenitic stainless steels, precipitation hardening stainless steels, and “A-286’’ (ASTM A453, Grade. 660) should not be used unless it has been reasonably established that they are suitable for the proposed environment.

Duplex stainless steel tends to be more resistant to CSCC. Kindly note that if the threat of CSCC is on the external, properly coating the pipes external and proper maintenance can mitigate against CSCC. CSCC threat on the internal should be mitigated by selecting appropriate materials.

3.1.2.2 Galvanic Corrosion

Galvanic corrosion occurs when two different metals are in electrical contact in an electrolyte.

This type of corrosion occurs around the contact interface between noble metal and active metal. The more noble metal is protected, the more active metal tends to corrode faster. Galvanic corrosion only occurs if the following conditions are satisfied.

• The metals involved must be electrochemically dissimilar.
• The metals must be exposed to an electrolyte
• The metals must be in electrical contact.

This type of corrosion can be mitigated by installing isolation flange kits or isolation joints.

3.1.2.3 Atmospheric Corrosion

This is the gradual degradation of a metal or alloy by contact with substances present in the atmosphere, such as carbon dioxide, oxygen, water vapour, sulphur dioxide. This type of degradation can occur on piping surfaces and crevices. Any material can be selected provided that appropriate surface coating is applied and appropriate maintenance implemented

3.1.2.4 Crevice Corrosion

This type of corrosion is initiated by stagnant solution in crevices such as edges of nuts and rivets head, under gaskets etc.

Crevice corrosion is initiated by differences in concentration in the local solution within the crevices. The most common form is oxygen differential cell corrosion. The moisture in the crevices has low oxygen concentration, thus forms the anode, while the metal in contact with the moisture exposed to air forms the cathode. This type of corrosion can be controlled by regular inspection, maintenance painting/coating; therefore, any appropriate material can be selected.

3.2 Brittle fracture

This happens in process operation when the metal temperature suddenly drops below the minimum design metal temperature. This phenomenon can trigger fracture and can propagate rapidly. This happens on blowdown lines; therefore, simulation should be performed to determine the minimum temperature during exceptional cool down events caused by high rate depressurisation across ESD system, relieve valves, and blowdown lines. One of the most selected carbon steel pipes used for this type of operation is ASTM A333.

3.3 Operation Data

All material has an applicable limit of operation. All material has maximum and minimum service temperature and pressure; therefore, materials selection shall consider the design minimum/maximum temperature and pressure.

3.4 Weldability or Ease of Joining the Material

Ease of joining the metals should be considered during material selection. Low carbon steel pipes are usually more weldable. Also, carbon steel pipes are more weldable than stainless steel pipes

3.5 Cost

Cost is one of the major considerations during material selection. Selecting high-grade stainless steel such as duplex stainless steel and super duplex stainless steel must be carefully evaluated. Usually, carbon steel pipes are the primary choice when they are not suitable for the application other materials should be selected

4 References

API 14E: Recommended Practice for Design and Installation of Offshore Production Platform Piping Systems

NACE MR0175: Petroleum and natural gas industries — Materials for use in H₂S-containing environments in oil and gas production. Part 1: General Principles for Selection of Cracking-Resistant Materials

Norsok M-001:  Materials Selection

Norsok Standard M-506: CO₂ Corrosion Rate Calculation Model

DEP 39.01.10.12-Gen: Selection of Materials for Upstream Equipment (Amendments/Supplements to ISO 15156:2015)

DEP 39.01.10.11-Gen.: Selection of Materials for Life Cycle Performance (Upstream Equipment) – Materials Selection and Corrosion Management