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Oil and Gas

0.05 psi

H2S partial pressure that triggers sour-service rules (ISO 15156)

22 HRC

Max hardness for carbon/low-alloy steel in sour service

>40

PREN required for reliable seawater / subsea service

3 parts

ISO 15156 structure: principles, carbon steel, CRAs

In the oil and gas industry, materials operate under high temperature, high pressure, and highly corrosive conditions. Stainless steels and nickel alloys earn their place because of corrosion resistance, high strength, high-temperature stability, and dependable mechanical properties. They are used across reactors, heat exchangers, piping systems, storage tanks, pipelines, wellhead equipment, and processing facilities.

JINIE insists on supplying stainless steel materials for the oil and gas industry. We produce a variety of corrosion-resistant and high-temperature resistant stainless steel, duplex steel, super duplex steel and nickel alloys. These alloys are mainly designed for high temperature, high pressure and highly corrosive environments, and can operate stably and for a long time in oil and gas environments.

Application Scenarios

Oil and Gas Pipelines

Valves

Other Equipment

Why stainless steel and nickel alloys matter in oil & gas?

Oil and gas assets fail in ways: corrosion, cracking, and creep. The operating envelope keeps widening — reservoirs now sit in deeper water, at higher pressure, and with more sour (H2S-rich) contents than a decade ago. A misstep in alloy specification is rarely a line item; it can mean a containment loss, a multi-million-dollar workover, or a safety incident.

Carbon steel remains the low-cost default, but it is vulnerable to CO2 and H2S corrosion and to chloride cracking. Corrosion-resistant alloys (CRAs) — austenitic stainless, duplex and super duplex stainless, and nickel alloys — close those gaps. JN Alloy supplies corrosion-resistant and high-temperature 304, 316, 310S, 600, and a broad range of duplex, super duplex, and nickel grades engineered for stable long-term service in aggressive oil and gas environments.

Oil and Gas key corrosion mechanisms

Mechanism	Driver	Typical outcome	Alloy defense
Sweet (CO2) corrosion	CO2 + water → carbonic acid; worsens with pCO2 and temperature	Uniform thinning, pitting	Cr/Mo content; 316L, duplex, CRAs
Sour (H2S) / SSC	H2S + water + tensile stress	Sulfide stress cracking (brittle, sudden)	Hardness control, low S/P, nickel alloys, ISO 15156
Hydrogen-induced cracking (HIC)	Atomic H from H2S absorbed into steel	Internal stepwise cracks, blisters	Clean steels, HIC-tested plates
Chloride pitting & crevice	Seawater, brine, deposits	Localized holes, crevice attack	High PREN: 2507, 254SMO, 625
Chloride stress corrosion cracking (Cl-SCC)	Cl− + tensile stress + temp	Catastrophic cracking	Duplex > austenitic; nickel alloys best
High-temp hydrogen attack (HTHA)	H at high T reacts with carbon	Methane voids, embrittlement	Low-C, 1.25Cr-0.5Mo + V, CRA cladding
Erosion-corrosion	Sand, flow, particulates	Wall loss at bends, downstream of orifices	High-strength duplex, hardfacings

Deepwater, Onshore, Refinery Application

Deepwater / subsea

Subsea combines high chloride, cathodic protection, dynamic fatigue, and often HPHT sour reservoirs. The dominant criterion is crevice corrosion temperature in seawater.

Flowlines & risers: super duplex 2507 is the workhorse — FPREN ~42–43, CCT ~35–45°C, yield ~550 MPa, compatible with sacrificial-anode CP. S32760 adds tungsten for even better pitting/crevice resistance.
Umbilicals & control lines: seamless 2507 tube; 316L fails above ~10°C, 2205 only to ~15–20°C. 2507 hits the sweet spot of cost vs. performance for long lengths.
Hot, sour HPHT wells / trees / hangers: Alloy 625 or precipitation-hardened 718/725 where H2S, sulfur, or extreme stress demand it. Isolate high-strength bolting from CP over-protection to avoid hydrogen embrittlement.
Seawater lift & firewater: 2507 or 90-10 Cu-Ni; Monel 400 where erosion-corrosion dominates.

Onshore / gas plants / gathering

Onshore duty is diverse: sweet gas, sour gas, amine treating, produced water, and sulfur recovery. Weight lifecycle cost heavily because access is easier than subsea but downtime is still expensive.
Sweet gas processing: carbon steel with corrosion inhibitor; 316L for heat exchangers and coastal/cooling duty.
Sour gas / separators: duplex 2205 for vessels and piping; Incoloy 825 for higher H2S/acid streams and amine-contact parts.
Amine & sour-water strippers: 825 or 625 cladding/liners; carbon steel underneath with CRA weld overlay is common to control cost.
Piping & skids: 2205/2507 for strength-to-weight and chloride resistance; 904L or 254SMO where sulfuric/phosphoric acid is present.

Refinery / downstream

Refineries run hot and chemically aggressive; the governing cracking standard shifts to NACE MR0103. Threats include sulfidation, naphthenic acid, polythionic acid SCC, and high-temperature hydrogen.

Furnace & pyrolysis tubes: 800H/800HT, 600/601 for creep strength and oxidation/carburization resistance.
Hydrotreaters / hydrocrackers: 825 and 625 per MR0103; watch for polythionic acid SCC on sensitized stainless after shutdowns — use low-carbon "L" grades and proper passivation.
Sulfidation & naphthenic acid: 316L/317L, Incoloy 825; higher-alloy CRAs where acid concentration is severe.
Severe acid / high chloride: Hastelloy C276 for mixed acid and reducing environments; 625 for broad sour/acid tolerance.

JN Alloy Products for Oil & Gas

JN Alloy stocks and produces a full range of corrosion- and high-temperature-resistant materials for the sector. Common starting points:

Alloy 304

Alloy 316

Alloy 310S

Alloy 600

Alloy 625

Alloy 718

Alloy 825

Alloy C276

Alloy 400

Alloy K-500

Beyond these, JN Alloy supplies duplex 2205, super duplex 2507, 904L, 254SMO, Incoloy 800H/800, Inconel 600/718, and Hastelloy C-22 in plate, bar, pipe, tube, and forgings — with NACE MR0175/ISO 15156 and MR0103 documentation on request.

H2S/CO2 corrosion environment material selection

Follow these steps:

Define the worst-case envelope. Capture H2S partial pressure, CO2 partial pressure, chloride concentration, in-situ pH (including organic acids), temperature, and presence of elemental sulfur. Model the most aggressive credible condition, not the annual average.
Screen steel material. If H2S ≥ 0.05 psi and free water exists, apply ISO 15156-2: hardness ≤ 22 HRC, HIC (TM0284) and SSC (TM0177) testing, low S/P chemistry. Many sweet, low-chloride, onshore lines stay here with inhibitors.
Step up to duplex / super duplex for chlorides. When chloride pitting or Cl-SCC dominates, move to 2205 (FPREN ~35) or 2507 (FPREN ~42–43). Use PREN = %Cr + 3.3×%Mo + 16×%N as the screening metric; seawater service needs PREN > 40.
Step to nickel alloys for aggressive sour/acid. When H2S > ~1 bar, elemental sulfur is present, temperatures are elevated, or the component is inaccessible (subsea tree, downhole hanger), specify Alloy 825, 625, 725, or C276.
Confirm welding & fabrication. Verify qualified WPS, interpass temperature, and post-weld heat treatment. Duplex is especially sensitive to heat input; nickel alloys need controlled procedures to preserve corrosion resistance in the HAZ.

If your environment is…	Recommended grade	Why
Sweet (CO2 only), low Cl−, onshore	Carbon steel + inhibitor; 316L for exchangers	Lowest cost, adequate with chemical management
Moderate H2S + moderate Cl−	Duplex 2205	Balanced strength + SSC/pitting resistance
High Cl− + moderate H2S, high strength needed	Super duplex 2507	FPREN >40, ~2× yield of 316L
High H2S + acid + moderate Cl−	Incoloy 825	Ni-Cr-Mo; tolerant of acid and sour
Very high H2S, sulfur, HPHT, inaccessible	Inconel 625 / 725 / C-276	Highest SSC/SCC margins, no practical limit
High temperature (>500°C) process	800H/800HT, 600/601	Creep strength, oxidation resistance

Alloy data

Use this quick comparison to pre-screen candidates against your envelope. Values are typical minima and vary by product form and specification; always confirm against the governing ASTM/ASME grade and the ISO 15156 environmental table.

Grade (UNS)	Family	PREN	Min yield (MPa)	Best-fit
316L (S31603)	Austenitic	~24–26	170	Exchangers, mild chloride, sweet service
2205 (S32205)	Duplex	~34–36	450	Sour/Cl− piping, separators, topside
2507 (S32750)	Super duplex	~42–43	550	Subsea, seawater, risers, HPHT flowlines
904L (N08904)	Austenitic (high Ni/Mo)	~35–38	220	Sulfuric / phosphoric acid service
254SMO (S31254)	Super-austenitic	~43	300	High chloride + acid, scrubbers
825 (N08825)	Ni-Fe-Cr-Mo	~30–35	241	Sour gas, amine units, acid gas
625 (N06625)	Ni-Cr-Mo	~45+	414	HPHT sour, elemental sulfur, downhole
800H/HT (N08810)	Ni-Fe-Cr (high-T)	n/a (high-T focus)	~170	Furnace / pyrolysis tubes > 500°C
C276 (N10276)	Ni-Mo-Cr	~50+	283	Severe mixed acid / high chloride

Frequently asked questions

What is sour service and when does NACE MR0175/ISO 15156 apply?

Sour service is any oil or gas stream containing hydrogen sulfide (H2S) with free water. Under ISO 15156-2 the system is classified as sour when the H2S partial pressure reaches 0.05 psi (0.3 kPa, about 0.0003 MPa). At that point materials must comply with NACE MR0175/ISO 15156. Dry H2S without liquid water cannot cause sulfide stress cracking.
What hardness limit applies to carbon and low-alloy steels in sour service?

The general maximum is 22 HRC (about 235 HBW / 250 HV) for the base metal, heat-affected zone, and weld overlay. Harder microstructures are far more susceptible to sulfide stress cracking. Austenitic stainless, duplex, super duplex, and nickel alloys have their own higher, grade-specific limits defined in ISO 15156-3.
When should I choose super duplex 2507 instead of Alloy 625?

Choose super duplex 2507 (UNS S32750) for moderate-to-high chloride with moderate H2S (typically up to about 20 kPa H2S partial pressure at temperatures up to 232°C) where its high strength lets you use thinner walls at lower cost. Move to nickel Alloy 625 (UNS N06625) when H2S is very high, elemental sulfur is present, temperatures are elevated, or the component is mission-critical and inaccessible, such as a subsea tree or downhole tubing hanger.
Can 316L stainless steel be used in H2S service?

Only in limited, well-defined envelopes. ISO 15156-3 qualifies solution-annealed austenitic stainless such as 316L for H2S partial pressure up to about 0.1 MPa, chloride up to about 100,000 mg/L, pH above 3.0, and temperatures up to about 100°C. Above those limits, or where chloride stress corrosion cracking is a risk, duplex, super duplex, or nickel alloys are required.
Which alloys suit refinery high-temperature service?

Refineries run hot, so nickel alloys dominate high-temperature duty: Alloy 800H/800HT and 600/601 for furnace tubes, pyrolysis coils, and radiant sections; Alloy 825 and 625 for sour hydrotreaters, amine units, and reactor effluent; and C-276 for severely acidic, high-chloride services. Downstream pressure vessels are governed by NACE MR0103 rather than MR0175.
How do I prove a material meets NACE MR0175/ISO 15156?

The Mill Test Certificate (MTC) should explicitly state conformance to NACE MR0175 / ISO 15156 and include the UNS designation, heat-treatment condition, hardness test results, and HIC (NACE TM0284) and SSC (NACE TM0177) results where applicable. Always pair the certificate with a documented environmental severity assessment.
Is duplex 2205 acceptable for subsea use?

Duplex 2205 works in colder waters, but its critical crevice corrosion temperature in seawater is only about 15–20°C. In warm, deepwater fields (for example the Arabian Gulf or tropical subsea), super duplex 2507 with a crevice temperature of roughly 35–45°C is the safer choice for umbilicals, risers, and manifolds.
What does PREN mean and why does it matter?

PREN (Pitting Resistance Equivalent Number) estimates resistance to chloride pitting: PREN = %Cr + 3.3 × %Mo + 16 × %N. A value above 40 is the usual threshold for seawater service and distinguishes super duplex from standard duplex. 2507 reaches about 42–43, 2205 about 34–36, and 316L about 24–26.