Addressing the sour gas challenge
Recent developments in corrosion resistant alloys help operators to overcome the challenges of hydrogen sulphide induced cracking in pipelines and key components.
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Natural gas is experiencing a major upturn. As a fossil fuel, it offers control and resilience to the energy mix, but when burned it produces a lot less carbon dioxide (CO2) than oil or coal. As a result, gas has become an important part of the energy mix, and demand is set to continue to grow by 2% annually until 2030.
However, according to the International Energy Agency (IEA), more than 40% of the world’s gas reserves are sour, containing significant levels of acidic compounds such as CO2 and hydrogen sulphide (H2S). This presents a major challenge to the lifetime and integrity of drilling equipment, pipeline components, and equipment, especially as temperatures and pressures in production environments can reach as high as 260˚C and 1700 bar.
Sour gas is a particular issue for operators in the Middle East, where 60% of gas reserves are sour, and also in Russia, which is the world’s largest producer of natural gas and where sour gas accounts for more than a third of reserves.
Sweet and sour
All production fluids and gases in the oil and gas industry can be classified as being either ‘sweet’ or ‘sour’, depending on the content of acidic compounds such as H2S and CO2.
While sweet environments contain little or no H2S, they may contain high levels of O2, which can accelerate the corrosion of carbon steels. It is also undesirable as it decreases the amount of energy yielded from gas. Another concern is that CO2 freezes at low temperatures, which creates problems for flow lines carrying LNG, which can operate at -160˚C.
Sour environments are a bigger challenge as they contain significant amounts of H2S and sometimes also CO2. The main concern is that, under certain conditions, H2S can embrittle metals and thereby cause sulphide stress cracking (SSC), especially in pipelines. However, a further issue is that H2S is also flammable and toxic, which creates a challenge during processing.
To avoid embrittlement of pipelines and process equipment, engineers have turned to materials that provide the combination of high strength and high corrosion resistance, especially resistance to the corrosion mechanism of SSC. In turn, they can expect reliable service over a 30-year service life, and can optimise the total cost of ownership and reduce maintenance and replacement costs.
Over the years, engineers have specified carbon steel and duplex (austenitic-ferritic) stainless steel grades. However, nickel alloys such as Outokumpu’s Ultra Alloy 825 also offer high performance when managing production from sour gas reserves.
Sulphide stress cracking
Corrosion is a complex topic and the form of corrosion depends on many variables, such as the presence of chemical agents or microbiological content. However, when working with sour gas in the oil and gas industry, the presence of H2S means that SSC is the most likely type of corrosion.
Although its mechanism is not fully understood, SSC takes place at a metal’s surface when sulphides act as a catalyst for a metal to absorb hydrogen atoms. As a result, the metal becomes brittle and vulnerable to hydrogen-induced cracking (HIC), especially at low temperatures.
A further challenge is that hydrogen absorption can happen at the same time as chloride stress corrosion cracking (SCC), which is another corrosion mechanism that is common at elevated temperatures. This increases the overall risk of environmentally induced cracking.
That said, when H2S is present at low levels, the system will have a low redox potential (a measure of the ease with which a molecule will accept electrons), which in fact reduces the risk of chloride- induced corrosion such as SCC and crevice corrosion.
In practice, operators experience most risk of environmentally induced cracking of austenitic and duplex stainless steels due to H2S and chlorides at intermediate temperatures, approximately in the range 80-100°C.
Indirect effects of CO2
As the other main acidic compound in sour gas, it is also worth considering the impact of CO2. Carbon steels are susceptible to uniform CO2 corrosion in sweet and sour environments, but stainless steel grades are not and can therefore ensure longer service life.
However, as a side effect of high CO2 levels, carbonic acid may form. This reduces pH and increases the risk of hydrogen being absorbed into the metal. As a result, SSC may become more likely, especially when H2S is present at high concentrations in sour gas environments.
Using stainless steel in oil and gas
The oil and gas industry has many different applications for different types and grades of stainless steel. Stainless steels are characterised by their microstructure: ferritic, martensitic, austenitic, and duplex, which is a combination of ferritic and austenitic.
Ferritic stainless steels provide high resistance to corrosion and chloride-induced SCC. However, they can be sensitive to SSC, especially when components have been hardened by cold working. A further point to consider is that some ferritic grades offer only limited resistance to chloride-induced pitting and crevice corrosion. As a result, ferritic stainless steels are rarely used for sour production environments.
Martensitic stainless steels are often adopted in sweet environments when high strength is needed. These provide a cost-effective way to resist uniform CO2 corrosion as an alternative to carbon steel. However, martensitic stainless steels are susceptible to chloride- induced localised corrosion as well as SSC.
Classic austenitic stainless steels are also sometimes used in oil and gas. They are less prone to SSC than ferritic and martensitic alloys as long as they are in the annealed condition. However, they are not suited to sour gas conditions if components have been heavily cold worked as austenitic grades are susceptibility to SSC even at ambient temperatures.
‘Super austenitic’ grades have higher levels of chromium and nickel, and offer high resistance to pitting and crevice corrosion. As a result, they are often used for seawater piping applications and in heat exchanger systems where seawater is used as a coolant.
As an alternative, duplex stainless steels combine the properties of austenitic and ferritic grades. They have high resistance to chloride-induced SCC, and as a result many operators have adopted them in production applications, where their high strength allows for weight savings. For example, duplex stainless steel alloys are regularly used in process piping, umbilicals, separators, and solid or flexible flow-lines, as well as in structural components such as blast walls on offshore installations.
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