When drilling in sour service environments, the choice between N80 and L80 casing can mean the difference between safe operations and costly failures. This comprehensive guide compares N80 and L80 API 5CT casing grades to help you select the right specification for your well conditions.
N80 is the industry-standard intermediate-strength grade for sweet service applications, while L80 is specifically designed for wells containing hydrogen sulfide (H2S). Understanding the technical differences, cost implications, and proper applications of each grade is critical for well integrity and regulatory compliance.
Quick Comparison: N80 vs L80 at a Glance
| Property | N80-1 / N80Q | L80-1 | L80-9Cr / L80-13Cr |
| Yield Strength | 80,000 - 110,000 psi | 80,000 - 95,000 psi | 80,000 - 95,000 psi |
| H2S Resistance | ✗ No (N80Q limited) | ✓ Yes (standard sour) | ✓ Yes (enhanced) |
| NACE Compliant | ✗ No | ✓ Yes | ✓ Yes |
| Cost Premium | Baseline | +15-25% | +60-150% |
| Typical Application | Sweet service wells | Sour service wells | Extreme corrosion |
Technical Specifications Comparison
API 5CT Grade Definitions
N80 Family
N80-1 (Type 1): The most common general-purpose intermediate-strength casing grade. N80-1 can be manufactured through either quenching and tempering OR normalizing and tempering, providing mills with flexibility but potentially introducing property variations. With a yield strength range of 80,000 to 110,000 psi and tensile strength minimum of 100,000 psi, N80-1 serves the majority of sweet service applications from intermediate casing to production strings in non-sour environments.
N80Q (Quenched + Tempered): A premium variant that mandates quench and temper heat treatment exclusively, eliminating the normalize and temper option. This restriction produces more consistent mechanical properties and improved toughness compared to N80-1. The tighter chemistry control includes reduced sulfur (0.010% maximum vs 0.030%) and phosphorus (0.020% vs 0.030%), resulting in better impact resistance and potentially limited sour service qualification on a case-by-case basis. N80Q typically costs 5-10% more than N80-1.
L80 Family
L80-1 (Type 1): The standard NACE MR0175-compliant sour service grade. L80-1 contains controlled chromium additions (0.15-0.25%) and strict limits on sulfur and phosphorus to resist sulfide stress cracking (SSC). Note the intentionally lower maximum yield strength of 95,000 psi compared to N80's 110,000 psi – this prevents overstressing in H2S environments. L80-1 requires mandatory quench and temper heat treatment with controlled cooling rates. It serves as the workhorse sour service grade for moderate H2S partial pressures.
L80-9Cr (9% Chromium): An enhanced corrosion-resistant variant containing 8.0-10.0% chromium. The higher chromium content provides superior resistance to both H2S and CO2 corrosion, making L80-9Cr the preferred choice for wells with combined sour gas and high carbon dioxide content. The chromium also improves resistance to chloride stress cracking in high-salinity formations. Applications include geothermal wells, CO2 injection wells, and ultra-deep sour wells with aggressive chemistry.
L80-13Cr (13% Chromium): A martensitic stainless steel grade with 12.0-14.0% chromium, providing maximum corrosion protection. L80-13Cr excels in extremely corrosive environments combining high H2S, high CO2, elevated temperatures, and high chloride concentrations. While maintaining the same 80,000 psi minimum yield strength, the cost premium reaches 100-150% above N80-1, limiting use to critical high-value wells where failure consequences justify the expense.
Chemical Composition Comparison
| Element | N80-1 | N80Q | L80-1 | L80-9Cr | L80-13Cr |
| Carbon (C) max | 0.45% | 0.45% | 0.43% | 0.15% | 0.15-0.22% |
| Chromium (Cr) | - | - | 0.15-0.25% | 8.0-10.0% | 12.0-14.0% |
| Sulfur (S) max | 0.030% | 0.010% | 0.010% | 0.010% | 0.010% |
| Phosphorus (P) max | 0.030% | 0.020% | 0.020% | 0.020% | 0.020% |
| Manganese (Mn) | Per mill | Per mill | Controlled | Controlled | Controlled |
Key Insight: L80 grades have significantly tighter sulfur and phosphorus limits compared to N80-1. These elements increase susceptibility to sulfide stress cracking, so their reduction is critical for H2S resistance. The chromium additions in L80-9Cr and L80-13Cr create a protective oxide layer that resists corrosion.
Mechanical Properties
| Property | N80-1 / N80Q | L80-1 | L80-9Cr / L80-13Cr |
| Yield Strength (min) | 80,000 psi (552 MPa) | 80,000 psi (552 MPa) | 80,000 psi (552 MPa) |
| Yield Strength (max) | 110,000 psi (758 MPa) | 95,000 psi (655 MPa) | 95,000 psi (655 MPa) |
| Tensile Strength (min) | 100,000 psi (689 MPa) | 95,000 psi (655 MPa) | 95,000 psi (655 MPa) |
| Elongation (min) | 18% (varies by size) | 18% (varies by size) | 18% (varies by size) |
| Hardness (max) | 25.4 HRC | 23 HRC | 25.4 HRC |
Critical Design Note: L80 has a LOWER maximum yield strength than N80 (95,000 psi vs 110,000 psi). This is intentional, not a deficiency. Higher strength steels become more susceptible to sulfide stress cracking in H2S environments. The reduced maximum yield strength prevents overstressing and improves SSC resistance in sour service conditions.
H2S Resistance & Sour Service Requirements
NACE MR0175/ISO 15156 Compliance
The selection between N80 and L80 fundamentally hinges on the presence of hydrogen sulfide. NACE MR0175 (now ISO 15156) defines sour service as any environment where H2S partial pressure exceeds 0.0003 MPa (0.05 psia) in the aqueous phase. Even trace amounts of H2S trigger mandatory use of sour service-qualified materials.
N80 Sour Service Capability
N80-1: NOT qualified for sour service under standard API 5CT. Use in H2S environments violates NACE standards and most operator policies.
N80Q: May be used in limited sour service ONLY with engineering approval and documented compliance with NACE MR0175 requirements. Maximum hardness 23 HRC (stricter than standard), specific H2S partial pressure limits apply, and case-by-case evaluation required. Many operators prohibit N80Q in sour service due to liability concerns despite theoretical qualification.
L80 Sour Service Capability
L80-1: Fully qualified for sour service per NACE MR0175/ISO 15156 Region 2. Standard choice for moderate sour service conditions.
L80-9Cr: Qualified for enhanced sour service including Region 2 and Region 3 applications with higher H2S partial pressures and temperatures.
L80-13Cr: Maximum sour service resistance for the most aggressive H2S environments combined with CO2 and chlorides.
H2S Partial Pressure Limits
| Grade | Max H2S Partial Pressure | NACE Region | Notes |
| N80-1 | Not qualified | N/A | Sweet service only |
| N80Q | Limited (case specific) | Per evaluation | Requires approval |
| L80-1 | Per NACE Region 2 | Region 2 | Standard sour service |
| L80-9Cr | Per NACE Region 2/3 | Regions 2 & 3 | Enhanced resistance |
| L80-13Cr | Per NACE Region 2/3 | Regions 2 & 3 | Maximum protection |
Sulfide Stress Cracking (SSC) Mechanisms
Sulfide stress cracking is a form of hydrogen embrittlement that occurs when susceptible steels are exposed to H2S-containing environments under tensile stress. H2S molecules dissociate at the steel surface, releasing atomic hydrogen that diffuses into the material. This hydrogen accumulates at microstructural discontinuities, reducing ductility and causing brittle fracture at stresses well below the material's normal yield strength.
Key factors affecting SSC susceptibility:
Material Hardness: Higher hardness correlates directly with increased SSC risk. NACE limits hardness to 22-23 HRC maximum for sour service materials.
Yield Strength: Higher strength steels are more prone to SSC, explaining L80's reduced maximum yield compared to N80.
Chemistry: Sulfur and phosphorus segregate to grain boundaries, creating preferential hydrogen trapping sites. L80's strict S/P limits mitigate this.
Heat Treatment: Proper quench and temper cycles with controlled cooling rates minimize susceptible microstructures.
Applied Stress: Even residual stresses from manufacturing or makeup can initiate SSC in susceptible materials.
Safety Warning: Never substitute N80 for L80 in documented sour service environments. The cost savings are negligible compared to the catastrophic consequences of casing failure due to SSC, including well abandonment, environmental releases, and potential fatalities. Regulatory compliance and operator policies mandate L80 or equivalent for H2S service.
When to Use N80 vs L80
Use N80-1 When:
✓ Sweet service confirmed: No H2S present in reservoir fluids or produced gases
✓ Dry gas wells: Non-associated gas with no liquid hydrocarbons or water production
✓ Budget constraints: Cost-sensitive projects where L80 premium not justified
✓ Non-critical strings: Surface or shallow intermediate casing isolated from production zones
✓ Moderate depths: Typically wells less than 10,000 ft in sweet formations
Typical N80-1 Applications:
Surface casing in fields with confirmed sweet reservoir characterization
Intermediate casing strings above production zones in stratified sweet/sour fields
Production casing in sweet oil and gas wells (coalbed methane, tight gas, sweet conventional)
Injection wells for waterflooding or enhanced recovery in sweet formations
Use N80Q When:
✓ Enhanced toughness required: Cold climate wells, thermal cycling applications
✓ Better impact resistance: Areas prone to seismic activity or dynamic loading
✓ Improved consistency: Projects requiring tighter property tolerances than N80-1
✓ Marginal sour service: Very low H2S concentrations with engineering approval (rare)
Typical N80Q Applications:
Arctic and sub-arctic drilling operations requiring low-temperature toughness
Wells in seismically active regions (California, Alaska, international tectonically active basins)
High-value wells where property consistency justifies 5-10% premium
Occasionally approved for very mild sour service (operator/regulator dependent)
Use L80-1 When:
✓ H2S confirmed or suspected: Any formation with sour gas history
✓ NACE compliance mandated: Regulatory or operator policy requirement
✓ Production casing in sour wells: Direct exposure to H2S-bearing fluids
✓ Long-term sour exposure: Wells with decades-long production life
✓ Safety-critical applications: Populated areas, environmentally sensitive locations
Typical L80-1 Applications:
Production casing in sour oil fields (Middle East, Western Canada, Permian Basin sour zones)
Any string exposed to H2S during drilling, completion, or production
Deep sour gas wells with moderate H2S concentrations (typically <15% H2S)
Offshore platforms in sour service fields (North Sea, Gulf of Mexico sour trends)
Intermediate casing strings that may see sour fluids during well control events
Use L80-9Cr When:
✓ High CO2 + H2S: Combined sweet and sour corrosion mechanisms
✓ High chloride content: High-salinity formation waters (>100,000 ppm TDS)
✓ Geothermal applications: High temperature plus corrosive fluids
✓ CO2 injection wells: Enhanced oil recovery or carbon sequestration
✓ Ultra-deep sour wells: HPHT conditions with aggressive chemistry
Typical L80-9Cr Applications:
CO2 injection wells for EOR (Permian Basin, Wyoming, international)
High CO2 gas fields (>10% CO2) with H2S co-production
Geothermal production and injection wells (>150°C, corrosive brines)
Deep offshore wells combining high pressure, temperature, and aggressive fluids
Carbon capture and storage (CCS) injection wells
Use L80-13Cr When:
✓ Maximum corrosion resistance required: Extreme environmental conditions
✓ Very high CO2 environments: Near-pure CO2 streams or >30% CO2
✓ High temperature + high H2S + high chloride: Triple-threat corrosion
✓ Premium wells with intolerance for failure: Subsea, deepwater, remote locations
✓ Extended well life requirements: 30+ year production horizons
Typical L80-13Cr Applications:
Ultra-HPHT wells with severe corrosion potential (>175°C, >15,000 psi)
Deepwater subsea completions in aggressive sour environments
High-rate gas wells with extreme erosion-corrosion conditions
Wells where workovers or casing replacements are prohibitively expensive
Critical infrastructure wells in sensitive environmental or populated areas
Cost Comparison & Economic Analysis
Relative Pricing
| Grade | Price Index
(N80-1 = 1.0) | Typical Premium | 7" 29 lb/ft Example Cost* |
| N80-1 | 1.00 | Baseline | $35/ft |
| N80Q | 1.05-1.10 | +5-10% | $37-$39/ft |
| L80-1 | 1.15-1.25 | +15-25% | $40-$44/ft |
| L80-9Cr | 1.60-1.80 | +60-80% | $56-$63/ft |
| L80-13Cr | 2.00-2.50 | +100-150% | $70-$88/ft |
* Example costs for illustration only; actual prices vary significantly by market conditions, quantity, delivery location, and connection type. Premium connections add 30-50% to base pipe cost.
Price Drivers: The premium for L80 over N80 reflects stricter chemistry control, mandatory quench-temper processing, additional SSC testing (HIC, SSC qualification tests), longer heat treatment cycles, higher rejection rates during manufacturing, and premium positioning based on critical application value.
Total Cost of Ownership Analysis
Material cost represents only a small fraction of total well cost. The economic analysis must consider failure consequences:
Cost-Benefit Example: 10,000 ft Production Casing String
| Scenario | Material Cost | Failure Risk | Failure Cost | Risk-Adjusted Total |
| N80-1 in Sweet Service | $500,000 | 0.5% | $8M (workover) | $540,000 |
| L80-1 in Sour Service | $600,000 | 0.5% | $8M (workover) | $640,000 |
| N80-1 in Sour Service | $500,000 | 15-50% | $5-50M (abandonment) | $1.25M - $25.5M |
Economic Reality: Using N80 in sour service to save $100,000 on material cost exposes the operator to $5-50 million in potential losses from SSC failure. The 20% L80 premium becomes trivial compared to failure consequences: well abandonment, environmental remediation, regulatory fines, legal liability, and reputational damage. For sour service wells, L80 is not an "upgrade" but the minimum acceptable standard.
ROI Calculation Framework
Decision Formula:
L80 Premium Cost = (L80 Price - N80 Price) × String Length
If (Failure Probability × Failure Cost) > L80 Premium Cost → Use L80
In sour service: Failure Probability >> 0%, therefore L80 mandatory
Example Calculation (8,000 ft production string):
N80-1 cost: $40/ft × 8,000 ft = $320,000
L80-1 cost: $48/ft × 8,000 ft = $384,000
L80 premium: $64,000
SSC failure cost: $5-20 million (well abandonment, cleanup)
Even 1% failure risk = $50,000-200,000 expected loss
Conclusion: L80 premium ($64k) justified by risk mitigation
Manufacturing & Quality Control
Heat Treatment Differences
N80 Heat Treatment Options
N80-1: Mills may choose between two heat treatment routes:
Quench + Temper (Q+T): Heat to austenitizing temperature, rapid quench in oil or water, followed by tempering. Produces fine-grained martensitic/bainitic structure with high strength.
Normalize + Temper (N+T): Heat to austenitizing temperature, air cool (slower than quench), followed by tempering. Produces slightly coarser grain structure, potentially lower toughness.
The dual-route option means N80-1 properties can vary more than single-route grades, though both must meet API 5CT minimum requirements.
N80Q: Quench + temper mandatory, no alternative. This restriction ensures consistent fine-grained microstructure, predictable toughness, and superior impact properties. The "Q" designation explicitly mandates the quench process.
L80 Heat Treatment Requirements
All L80 grades require quench and temper with strict process controls:
Precise austenitizing temperature control (typically 900-950°C)
Controlled quench rate (oil or polymer quench to achieve target structure)
Tempering temperature optimization (typically 550-650°C) to achieve hardness below 23 HRC
Controlled cooling after temper to prevent untempered martensite formation
Multiple tempering cycles may be required for tight hardness control
The tighter heat treatment window for L80 results in higher energy costs, longer processing time, and increased rejection rates compared to N80-1.
Testing & Qualification Requirements
Standard Testing (Both N80 and L80)
Tensile testing per API 5CT (yield, tensile, elongation)
Hardness testing (Rockwell C scale)
Hydrostatic pressure testing (pipe body integrity)
Dimensional inspection (OD, wall thickness, ovality)
Drift testing (internal diameter verification)
Visual inspection for surface defects
Ultrasonic testing (UT) for internal/external defects
Additional L80 Sour Service Testing
HIC Testing (Hydrogen Induced Cracking): NACE TM0284 qualification on heat-treated samples exposed to H2S-saturated solutions. Measures CLR (crack length ratio), CSR (crack sensitivity ratio), CTR (crack thickness ratio). Acceptance: CLR ≤ 15%, CSR ≤ 2%, CTR ≤ 5%.
SSC Testing (Sulfide Stress Cracking): NACE TM0177 Method A (tensile), Method B (bent beam), or Method D (DCB). Samples stressed in H2S environment for 720 hours minimum. No cracking permitted.
Hardness Survey: More extensive than standard testing, often every joint or multiple locations per joint to ensure no hard spots exceed 23 HRC.
Impact Testing: Charpy V-notch testing may be specified for critical applications, especially for L80-9Cr and L80-13Cr.
Testing Impact on Lead Time: HIC and SSC testing require 30+ days for test completion. Combined with heat treatment complexity, L80 lead times typically exceed N80 by 2-4 weeks. Plan accordingly for critical path scheduling.
Quality Assurance & Traceability
L80 grades require enhanced documentation:
Material Test Reports (MTR): Must include chemistry, mechanical properties, heat treatment records, and sour service test results
Heat Traceability: Full traceability from heat number through pipe joints to well application
Third-Party Inspection: Often required by operators for L80 (Bureau Veritas, SGS, Intertek)
NACE Compliance Certification: Documentation that material meets MR0175/ISO 15156 requirements
API Monogram: Mills must maintain API 5CT licensing for Grade L80 (stricter than N80)
Field Handling & Storage
Handling Precautions
N80 Handling (Standard Practices)
Use proper thread protectors (API certified or mill-supplied)
Avoid dropping or impact damage to threads
Store on level racks with adequate support
Protect from moisture to prevent corrosion
Standard thread compound suitable (API-modified or equivalent)
L80 Handling (Enhanced Requirements)
Thread Compounds: Must be H2S-compatible (zinc-free for sour service). Verify compound approval for NACE service.
Contamination Prevention: Avoid contact with sulfur-bearing materials (elemental sulfur, high-sulfur crude, sulfur-based thread compounds) which can initiate SSC.
Moisture Control: More critical for L80 to prevent hydrogen charging from corrosion. Use desiccants in enclosed storage.
Thread Inspection: More rigorous inspection before makeup. Any damage may compromise seal and SSC resistance.
Separate Storage: Store L80 separately from lower grades to prevent mix-ups and contamination.
Thread Compound Selection
| Compound Type | N80 Sweet Service | L80 Sour Service |
| API Modified | ✓ Acceptable | ✗ Not acceptable |
| Heavy Metal (Zinc, Lead) | ✓ Acceptable | ✗ Not acceptable (galvanic issues) |
| NACE-Approved Metal-Free | ✓ Acceptable | ✓ Required |
Thread Compound Warning: Using zinc-based thread compounds on L80 in sour service can create galvanic cells that accelerate corrosion and hydrogen charging, defeating the SSC resistance. Always verify compound NACE compliance before application.
Running Procedures
Both N80 and L80 follow standard API RP 5C1 running procedures, but L80 requires additional attention:
Makeup Torque: Follow API torque tables or mill recommendations precisely. Over-torque creates residual stresses that increase SSC risk.
Crossover Joints: When transitioning between grades (e.g., N80 intermediate to L80 production), use appropriate crossover with compatible connections.
Fill-Up Frequency: Maintain proper fill to prevent collapse, especially critical for L80 which has lower max yield.
Running Speed: Control speed to prevent shock loading on connections.
Elevators & Slips: Ensure proper sizing to avoid damage to L80 pipe body or connections.
Connection Compatibility
Both N80 and L80 are available with all standard API and premium connections:
API Connections
STC (Short Thread & Coupling): Lowest cost, adequate for moderate service
LTC (Long Thread & Coupling): Improved sealing over STC
BTC (Buttress Thread Coupling): Higher torque capacity, better for higher pressures
For detailed BTC specifications, see our Understanding Buttress Thread Casing (BTC) Guide.
Premium Connections
VAM TOP, New VAM, VAM 21
Hydril 521, 563
Tenaris Dopeless, Blue, Wedge
Other proprietary designs
Premium connections are often specified for L80 in critical sour service to ensure gas-tight performance and enhanced structural integrity.
Frequently Asked Questions
Q: Can I substitute N80 for L80 to save cost?
A: Absolutely not in sour service. Using N80 instead of L80 in H2S environments violates NACE MR0175 standards, regulatory requirements, and prudent engineering practice. The material cost savings of 15-25% are insignificant compared to the catastrophic failure risk and potential losses of $5-50 million from SSC-induced casing failure. In sweet service, N80 is the appropriate specification.
Q: Is N80Q acceptable for mild sour service?
A: Potentially, but with extreme caution. N80Q may be qualified for very limited sour service applications per NACE MR0175 if hardness is controlled to 23 HRC maximum and H2S partial pressures are low. However, many operators and regulators prohibit N80Q in any sour service due to liability concerns and lack of field history. Engineering approval and regulatory acceptance are required. L80-1 is the safer, standard choice for any H2S exposure.
Q: Why does L80 have lower maximum yield strength than N80?
A: This is intentional design, not a limitation. Higher strength steels become increasingly susceptible to sulfide stress cracking in H2S environments. By capping L80's maximum yield at 95,000 psi versus N80's 110,000 psi, the specification prevents overstressing and reduces SSC risk. The lower maximum yield improves sour service reliability while maintaining adequate strength for most applications.
Q: How do I know if my well is sour service?
A: Per NACE MR0175/ISO 15156, sour service is defined as any aqueous environment where H2S partial pressure exceeds 0.0003 MPa (0.05 psia). This is a very low threshold – even trace H2S triggers sour service requirements. Check reservoir fluid analysis, offset well production data, and regional geological knowledge. If any uncertainty exists, treat as sour service. The cost of L80 is far less than the cost of guessing wrong.
Q: Can L80 be used in sweet service?
A: Yes, L80 performs excellently in sweet service, but it's usually not cost-effective. The 15-25% premium is wasted if no H2S is present. However, L80 may be justified in sweet service if: (1) future H2S breakthrough is possible, (2) well will be deepened into sour zones later, (3) operator has standardized on L80 to simplify inventory, or (4) improved corrosion resistance needed for other reasons (CO2, chlorides).
Q: What's the difference between L80-1 and L80 Type 1?
A: They are the same. "L80-1" is common shorthand for "L80 Type 1" per API Spec 5CT nomenclature. The full designation is "Grade L80 Type 1" but industry practice abbreviates to "L80-1" on purchase orders, MTRs, and technical documents.
Q: Do I need L80-9Cr or is L80-1 enough?
A: L80-1 handles moderate sour service effectively (the majority of applications). Upgrade to L80-9Cr when you have: (1) high CO2 content (>10%) combined with H2S, (2) high chloride concentrations (>100,000 ppm TDS), (3) high temperature (>150°C), (4) geothermal conditions, or (5) CO2 injection service. The 60-80% cost premium for L80-9Cr is only justified when standard L80-1 corrosion resistance is inadequate.
Q: Can I mix N80 and L80 in the same well?
A: Yes, this is common practice. Use L80 for any string exposed to H2S (typically production casing and potentially intermediate casing if sour zones are present). Use N80 for strings isolated from sour exposure (surface casing, intermediate casing above production zones in stratified sweet/sour fields). Example: 13-3/8" surface casing in N80-1, 9-5/8" intermediate in N80-1 or L80-1 depending on zone, 7" production in L80-1. This optimizes cost while maintaining safety.
Q: What thread compound should I use for L80?
A: For L80 in sour service, use only NACE MR0175-approved, metal-free thread compounds. Avoid zinc-based or lead-based compounds which can create galvanic corrosion and hydrogen charging. Popular NACE-approved compounds include: API-modified alternatives, specialty sour service compounds from Bestolife, Jet-Lube, or equivalent. Verify NACE compliance documentation before application. The thread compound selection is critical – incorrect compound can negate L80's SSC resistance.
Q: How much more does L80 cost than N80?
A: L80-1 typically costs 15-25% more than N80-1 (price index 1.15-1.25 vs 1.00). For a 10,000 ft production string, this translates to roughly $100,000-150,000 additional cost. L80-9Cr costs 60-80% more (index 1.60-1.80), and L80-13Cr costs 100-150% more (index 2.00-2.50). Actual premiums vary with market conditions, order quantity, and connection type. Premium connections add another 30-50% regardless of grade.
Conclusion
The choice between N80 and L80 casing grades is straightforward: the presence or absence of hydrogen sulfide dictates the decision. N80 serves as the cost-effective workhorse for sweet service applications, offering excellent performance in non-sour environments with universal availability and proven field history. L80 provides essential sulfide stress cracking resistance for H2S environments, with chemistry and heat treatment specifically optimized for sour service safety.
Selection Summary
| Well Condition | Recommended Grade | Rationale |
| Sweet service, moderate depth | N80-1 | Cost-effective, adequate strength, proven performance |
| Sweet service, cold climate | N80Q | Enhanced toughness and impact resistance |
| Sour service, standard conditions | L80-1 | NACE compliant, industry standard for H2S |
| Sour + high CO2 | L80-9Cr | Enhanced corrosion resistance for combined threats |
| Sour + extreme corrosion | L80-13Cr | Maximum protection for severe environments |
The 15-25% cost premium for L80 in sour service is not an "upgrade option" but rather mandatory insurance against catastrophic failure. Never compromise on material selection in H2S environments – the consequences of sulfide stress cracking far exceed any material cost savings. When in doubt, consult with materials engineers, review NACE MR0175 requirements, and err on the side of safety.
