Specifying non-standard technical requirements or non-commercially available materials can impact the economics and timeframe of any project. When specifying a material for a specific oil and gas application, there are many different factors to consider. This blog discusses some practical examples illustrating how simple material parameters can add or reduce value and complexity.
Simplifying and designing for cost-effectiveness
Standardized procurement specifications make a step-change improvement in the specification, procurement and delivery of equipment for the global oil and gas industry. In the past, oil and gas operators would ask their suppliers to deliver against a different set of specifications for each order, and, in some cases, these requirements were different even for projects by the same operator.
Recognizing this incredibly inefficient process, which often resulted in industry-wide overruns on cost and schedule, prompted the International Association of Oil and Gas Producers (IOGP) to introduce the Joint Industry Programme 33 (JIP33). Initiatives such as this have already made a positive impact on harmonizing requirements and reducing supply chain complexity. However, there is still significant complexity around end-users and project specifications that almost head in the opposite direction to what seems logical or sensible.
When selecting materials for instrumentation, engineers need to consider the harsher environments and extreme operating conditions, tighter regulations, and the fear of catastrophic equipment failure. Other considerations may not be so apparent, such as the economic consequences of choosing a non-standard material. All these factors add to the complexity of the material selection process.
Material selection versus corrosion control
Material selection and corrosion control are always a balancing act. The primary aim of material selection is to always look for the most cost-effective alternative with the right set of technical criteria that deliver trouble-free systems. There are technical requirements, but other aspects, such as safety regulations and availability, must also be considered. As this is a time-bound exercise, the expected useful life must be factored into the equation. To make the material best choice, there are also the commercial aspects to consider; see Figure 1.
There is a wide choice of materials specifications; some are commercially available, others are not. Some critical applications have complex technical requirements in the oil and gas industry, such as temperature range, pressure rating, component type and purpose.
Depending on these application criteria, a particular alloy may be selected. However, there may be up to a hundred different combinations for that alloy once the whole specification is taken into account. In some applications, these many different combinations are necessary. In most situations, the reason for these combinations is the lack of not unifying on common grounds.
To quantify all this complexity - the different material prices, the different lead times and the management input required for selecting a single material - an expensive corrosion-resistant alloy (CRA) might have been a more cost-effective and better alternative right from the beginning. As far as practical, the idea is to simplify everything, thereby reducing the chances of intermixing materials and its associated risk that will, ultimately, impact cost and lead time.
Understanding how commercially available materials are produced and how special chemistries can greatly impact time and cost without adding a lot of technical advantage can sometimes be an oversight if considered in isolation and in a very simplistic manner.
The global steel and CRAs supply is estimated on anticipated demand, with most mills planning a year in advance and producing material on this basis. In most cases, CRAs are produced according to harmonized industry standards that specify a chemical range for a particular material grade. To illustrate this, a prime example is stainless steel (316L).
Figure 1: Factors to consider when starting your material selection journey.
Table 1: The Chemical Composition of Non-Standard 316L Steel Alloys Can Deviate Considerably from Commercially Available Materials.
Table 1 details the allowable chemistry as per the industry codes and the typical concentrations of commercially available 316L steel. As soon as the chemistry deviates from commercially available material, for example, by enhancing the nickel content from 10 to 12%, we have two challenges ahead.
In lead time terms, non-commercially available chemistries require a whole mill run, equating to several tonnes of steel. The lead time on raw material can be 22 weeks or more, depending on the alloy. In economic terms, any special chemistry has a cost impact, which can be very elevated if the raw element is expensive, as is usually the case. Other examples of this are 316 with high molybdenum, 316 with high chromium, or Alloy 825 with a high nickel content.
Focusing on the volatility and high cost of nickel, which is one of the main alloying elements in the 316 family, it can leap up by 10% per tonne overnight. It forms the austenitic structure, which gives the alloy its strength, toughness, and resistance to oxidation and corrosion. The obvious question is: What difference does a 2% nickel increase make if harmonized standards suggest that anything with 10 to 14% nickel content is still the same alloy?
Stress corrosion cracking
One of the most common failure modes in the oil and gas industry is stress corrosion cracking (SCC). For SCC to happen, the material must be susceptible, be in a corrosive environment, and be under a tensile load. Material susceptibility is not only determined by its chemistry or composition but also by many other factors such as material processing, specific microstructure or surface condition, see Figure 2. This analysis is an excellent way to evaluate the difference nickel makes in service.
Those parameters make a difference under real-life service conditions when controlled and optimized. However, just modifying the content of an element in a given alloy in isolation marginally usually brings very little value but makes supply very complicated. Figure 3 shows the Copson Curve that plots the effect of nickel content and the time to failure due to SCC on boiling magnesium chloride. Standard 316 steel, which has a nickel range of 10% to 14%, is highlighted in red. It behaves very similarly to the non-standard 316 and is only beyond 14%, which is out of the 316 family scope.
To summarise, 316 steel with higher nickel or chromium content is still a 316 grade steel, with its strengths and limitations, but never a replacement for higher CRAs. As a good practice, always question whether those special chemistries will bring value to assets.
Figure 2: Stress Corrosion Cracking (SCC) is a Common Failure Mode in the Oil and Gas Industry.
Figure 3: Copson Curves Shows the Effect of Nickel Content on Time to Failure of Fe-Ni-Cr Alloy Wires Under Stress in Boiling Magnesium Chloride
Pitting corrosion
The pitting resistance equivalent number (PREN) is a theoretical value derived from the chemistry of a particular alloy. It serves as a corrosion indicator when pitting corrosion is a concern. In steels, PREN is a function of chromium, molybdenum and nitrogen content. The higher the PREN indicates higher resistance to pitting corrosion. Standard alloys have a fixed chemical range; for example, 316 steels can have a nickel content of 10 to 14%. A typical commercially available grade has a PREN value of around 22 to 26.
In the case of the 316 family of steels, altering the chromium or molybdenum content has a limited impact on the PREN value, see Table 2. However, the compositional limits allow more flexibility with a standard super duplex alloy, and PREN can significantly vary from cast to cast. According to the Association for Materials Protection and Performance (AMPP) NACE MR0175 standard entitled: ‘Petroleum and Natural Gas Industries — Materials for use in H₂S-containing environments in oil and gas production”, super duplex steels are sub-divided into types with PREN below 40 or over 40, each with a different service allowance. In the case of super duplex steels, end-users tend to customize their chemistry to have a PREN on the high end, but this can have a commercial impact when deviating from standard material.
Table 2: PREN Comparison Between Standard 316 and Alloys with More Chromium or Molybdenum Content: Note the High PREN with Standard Super Duplex Steel.
The piping legacy
For many decades, piping standards have dominated a good part of the control lines in the oil and gas industry, and its legacy remains. Small-bore tubing (SBT) systems are as critical as main process systems as they carry the same fluid types at similar pressures. As they are control lines too, they should not be treated simply as bits of plumbing. For example, when there is air loss to an emergency shut down valve (ESDV), the valve fails to close, and the process stops, resulting in an expensive shutdown time.
The obvious main differentiator between a pipe and a tube is its size, where piping is typically larger. Considering that more than 95% of SBT installations are ½” (12mm) or less, the metallurgical requirements for piping and tubing should be different somehow. The Joint Industry Programme 33 (JIP33) and similar initiatives are certainly heading in the right direction. However, many oil and gas end-users have also created different internal specifications to address tubing and instrumentation equipment separately.
Piping typically covers large items in comparison to SBT systems. Therefore, the processes used in production, such as forging and casting, come to the fore. In very generic terms, from a metallurgical perspective, large items can present a higher risk of defects as processing and heat treatment can be more complex when compared to small diameters. For this reason, in piping, the destructive and non-destructive testing requirements are very stringent.
A prime example is carbon steel; taking a straight instrumentation needle valve as an example, its body is made from steel bar as it offers better mechanical performance than forged or cast steel, see Figure 4. The thickness of the body is typically below 30mm and, according to industry codes, must undertake tensile testing and impact testing in one direction, typically the rolling or longitudinal direction. Given the valve’s small thickness and high reliability and repeatability of this manufacturing process, there is very little need to test in more critical directions or add complexity with high-frequency non-destructive evaluation (NDE) to ensure quality. In summary, this is a commercially available material that meets all design and high safety standards and delivers the best cost and lead times possible.
Figure 4: A Straight SBT Instrumentation Needle Valve Made from Bar Carbon Steel.
Figure 5: A Carbon Steel Process Valve Requires Stringent Testing. Source: shutterstock
On the other hand, with a piping process valve, the typical testing schedule is much more stringent, see Figure 5. The critical transverse and tangential directions need tensile strength and impact resistance testing. There are also the risks of defects during manufacture and high impacts during service. Most engineers also ask for a high-frequency NDE of the ball valve to ensure trouble-free operation before any assembly work. Typically, all this extra testing is not found on commercially available materials, even from the best mills. Although it can be performed, it is at the expense of extra cost and lead time. If destructive testing is required, there is also the expense of sacrificial parts to consider.
To summarize, non-standard testing impacts cost and lead time - sometimes several weeks. Depending on the product family and dimensions, they can add very little value to assets. Keeping complexity to a minimum and questioning the suitability and value of non-standard requirements, especially when it relates to SBT systems, ensure cost-effectiveness.
Looks can be deceiving
It may be tempting to opt for an identical product that is available for a fraction of the price, but looks can be deceiving. Take a twin ferrule fitting, for example. Approximately 80% of the cost of any fitting comes from raw material prior to any machining operations. Therefore, manufacturing in low-cost countries has little impact on the final cost. For a fitting that looks the same but is at half the price, it is not inconceivable that this saving is at the expense of quality.
For more information about how Parker is supporting material selection decisions, please visit www.parker.com/ipd.
Article contributed to by Clara Moyano, material scientist, Parker’s Instrumentation Products Division Europe.
This article was first published by Fluid Handling International Magazine - fluidhandlingmag.com in February 2023.
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