Pipeline Design

Pipeline Material Selection

Select appropriate carbon steel grades per API 5L, evaluate sour service requirements per ISO 15156 (NACE MR0175), determine temperature limits and impact testing needs per ASME B31.8, and specify corrosion allowance and coating systems.

Launch Calculator Carbon Steel Grades

API 5L Grades

X42 to X80

X42 (42 ksi SMYS), X52, X60, X65, X70, X80. PSL2 for sour service.

Sour Service Limit

HRC ≤ 22

ISO 15156: Maximum hardness 22 HRC (248 HV) in weld, HAZ, and base metal.

Impact Testing

T < 32°F

CVN testing required below 32°F per ASME B31.8. Min 15 ft·lb average.

Contents

Use this guide when you need to:

  • Select carbon steel grade for pipeline or piping.
  • Evaluate sour service (H2S) requirements.
  • Determine if impact testing is required.
  • Specify corrosion allowance and coating system.

1. Overview & Applications

Material selection for pipelines and piping systems must account for mechanical strength, corrosion resistance, operating temperature, fluid composition (especially H2S and CO2), and fabrication requirements.

Mechanical strength

SMYS and toughness

Select grade based on required wall thickness (SMYS) and fracture toughness.

Corrosion resistance

H2S, CO2, chlorides

Sour service (H2S) and sweet service (CO2) require specific material limits.

Temperature limits

-50°F to 250°F typical

Carbon steel service temperature range; impact testing below 32°F.

Fabrication

Weldability, forming

Higher strength grades require controlled welding procedures (PWHT, preheat).

Key Concepts

  • SMYS (Specified Minimum Yield Strength): Minimum yield strength in psi or MPa (e.g., X52 = 52,000 psi SMYS)
  • Sour service: Service containing H2S; requires materials resistant to sulfide stress cracking (SSC) and hydrogen-induced cracking (HIC)
  • Sweet service: Service containing CO2 but no H2S; CO2 corrosion managed by inhibitors, coatings, or corrosion allowance
  • Impact testing: Charpy V-notch (CVN) testing to verify toughness at minimum design temperature
  • Corrosion allowance (CA): Extra wall thickness beyond pressure design to accommodate metal loss over service life
Why material selection matters: Incorrect material selection can lead to catastrophic failures. Using non-sour-rated material in H2S service causes sulfide stress cracking. Inadequate toughness at low temperature leads to brittle fracture. Insufficient corrosion allowance results in leaks and failures before design life.

2. Carbon Steel Grades

Carbon steel is the most common material for oil and gas pipelines and piping due to low cost, availability, and adequate strength. API 5L and ASTM standards specify composition, mechanical properties, and testing requirements.

API 5L Pipeline Grades

Grade SMYS (psi) SMYS (MPa) Tensile (psi) Typical Application
API 5L Grade B 35,000 241 60,000 Low pressure gathering, older pipelines
API 5L X42 42,000 290 60,000 Gathering systems, distribution
API 5L X52 52,000 359 66,000 Transmission, most common grade
API 5L X60 60,000 414 75,000 High-pressure transmission
API 5L X65 65,000 448 77,000 High-pressure transmission, offshore
API 5L X70 70,000 483 82,000 High-pressure transmission, Arctic
API 5L X80 80,000 552 90,000 Ultra-high pressure, specialized applications

API 5L PSL 1 vs. PSL 2

Product Specification Levels: PSL 1 (Product Specification Level 1): - Standard quality - Limited chemical composition requirements - No mandatory impact testing - Lower cost - Suitable for non-critical applications PSL 2 (Product Specification Level 2): - Higher quality and tighter tolerances - Stricter chemical composition (C, Mn, P, S, Cu, Ni, Cr, Mo, V limits) - Mandatory Charpy V-notch testing at specified temperature - Non-destructive examination (NDE) requirements - Supplementary requirements available (sour service SR15, HIC SR17) - Required for sour service, offshore, Arctic, high-consequence areas Chemical Composition Limits (PSL 2, X52 example): C: ≤ 0.26% Mn: ≤ 1.40% P: ≤ 0.025% S: ≤ 0.015% C_eq: ≤ 0.43% (weldability limit) Where: C_eq = C + Mn/6 + (Cr+Mo+V)/5 + (Ni+Cu)/15

ASTM Pipe and Tube Grades

Specification Type/Grade SMYS (psi) Application
ASTM A106 Grade B 35,000 Seamless pipe for high-temp service (to 750°F)
ASTM A53 Grade B 35,000 Welded or seamless pipe, general purpose
ASTM A333 Grade 6 35,000 Low-temp service (to -50°F), impact tested
ASTM A694 F52, F60, F65 52,000-65,000 Forgings for flanges, fittings (high strength)
ASTM A105 — 36,000 Carbon steel forgings for flanges, valves (ambient to 650°F)

Grade Selection Based on Design Pressure

Barlow's Formula (ASME B31.8): t = (P × D) / (2 × S × E × F × T) Where: t = Minimum wall thickness (in) P = Design pressure (psig) D = Outside diameter (in) S = SMYS (psi) E = Longitudinal joint factor (1.0 seamless, 1.0 ERW, 0.80 furnace butt weld) F = Design factor (0.72 typical Class 1, 0.60 Class 2, 0.50 Class 3) T = Temperature derating factor (1.0 for T ≤ 250°F) Example: Design 24" OD pipeline for 1440 psig, Class 1 location (F=0.72). Using X52 (SMYS = 52,000 psi): t = (1440 × 24) / (2 × 52,000 × 1.0 × 0.72 × 1.0) t = 34,560 / 74,880 = 0.461 in Select: 0.500 in wall (standard size) Using X65 (SMYS = 65,000 psi): t = (1440 × 24) / (2 × 65,000 × 0.72) t = 34,560 / 93,600 = 0.369 in Select: 0.375 in wall (thinner, lighter, less expensive) Higher grade → thinner wall for same pressure Trade-off: Material cost vs. weight/installation cost

Weldability and Heat Treatment

Grade C_eq Typical Preheat Required PWHT Required Weldability
X42-X52 0.38-0.43 Not usually (if T > 32°F) No (unless t > 1.25 in) Excellent
X60-X65 0.43-0.47 Yes, 200-300°F Optional (sour service: yes) Good
X70-X80 0.45-0.50 Yes, 250-400°F Yes (especially sour service) Fair (requires controlled procedures)
Grade selection trade-offs: Higher strength grades (X70, X80) reduce wall thickness and weight, lowering installation costs for large-diameter pipelines. However, they require stricter welding procedures, higher material cost, and may have reduced toughness at low temperature. For most applications, X52 or X60 provides best balance of cost, weldability, and performance.

3. Sour Service Requirements

Sour service (presence of H2S) requires materials resistant to sulfide stress cracking (SSC), hydrogen-induced cracking (HIC), and stress-oriented hydrogen-induced cracking (SOHIC). NACE MR0175 / ISO 15156 defines material limits.

Sour Service Definition

ISO 15156 / NACE MR0175 Sour Service Criteria: Sour service exists when BOTH conditions are met: 1. H₂S partial pressure > 0.05 psia (0.3 kPa) P_H2S = P_total × y_H2S Where: P_total = Total pressure (psia) y_H2S = Mole fraction of H₂S in gas phase 2. Water (aqueous phase) is present If no water → not sour service (dry H₂S is not corrosive) Example: Gas at 1000 psia contains 100 ppm H₂S (0.0001 mole fraction). P_H2S = 1000 × 0.0001 = 0.1 psia 0.1 > 0.05 → SOUR SERVICE if water is present ✓ Even 50 ppm H₂S at 1000 psia (pH₂S = 0.05 psia) triggers sour service.
ISO 15156-2 NACE MR0175 SSC severity regions diagram showing H2S partial pressure (0.1-1000 kPa log scale) versus in-situ pH (2.5-7.0) with color-coded regions: Region 0 non-sour below 0.3 kPa sour service threshold (white), Region 1 low severity 0.3-1 kPa at pH≥4.5 requiring HRC≤22 and PWHT (light yellow), Region 2 moderate severity 1-10 kPa requiring HIC-resistant steel or CRA (light orange), Region 3 severe above 10 kPa or low pH requiring CRA (light red), typical sour gas well marked, increasing SSC severity arrow
ISO 15156-2 SSC severity regions for sour service material selection.

ISO 15156-2 SSC Regions

Region Severity pH₂S Range Material Requirements
Region 0 Non-sour < 0.3 kPa (0.05 psia) No SSC requirements; standard materials acceptable
Region 1 Low 0.3-1 kPa at pH ≥ 4.5 Carbon steel with HRC ≤ 22, PWHT required
Region 2 Moderate 1-10 kPa at pH ≥ 4.5 HIC-resistant steel (SR17) or CRA required
Region 3 Severe > 10 kPa or low pH CRA required; full ISO 15156 qualification

SSC Resistance Requirements

Hardness Limits (NACE MR0175-3): Carbon steel (weld metal, HAZ, base metal): - Maximum hardness: 22 HRC (248 HV, 237 HB) - Applies to ALL regions: base metal, weld, HAZ If hardness > 22 HRC → susceptible to SSC → NOT ACCEPTABLE Hardness Testing: Method: Rockwell C (HRC), Vickers (HV), or Brinell (HB) Spacing: Every 2 in along weld and HAZ Acceptance: 100% of readings ≤ 22 HRC Conversion (approximate): 22 HRC = 248 HV = 237 HB Achieving HRC ≤ 22: - Limit carbon equivalent: C_eq ≤ 0.43% - Post-weld heat treatment (PWHT): 1100-1200°F for 1 hr/in thickness - Controlled cooling rate after welding - Low-hydrogen welding electrodes (E7018, E8018)

HIC and SOHIC Resistance

Two-panel diagram showing HIC and SOHIC cracking mechanisms in steel: Left panel HIC mechanism with H2S at surface producing atomic hydrogen, H atoms diffusing into steel, H2 gas accumulating at high pressure at MnS inclusions from rolling, stepwise internal cracks connecting inclusions parallel to rolling direction; Right panel SOHIC mechanism near weld showing weld metal, HAZ, base metal zones, residual tensile stress arrows perpendicular to weld, cracks aligned perpendicular to stress starting from HIC laminations propagating toward weld toe; comparison table showing location, orientation, and prevention methods
HIC and SOHIC cracking mechanisms in carbon steel exposed to H₂S service.
Hydrogen-Induced Cracking (HIC): Occurs in base metal due to atomic hydrogen from H₂S corrosion. Hydrogen accumulates at inclusions/laminations → internal cracks. Prevention: - Use HIC-resistant steel (low sulfur ≤0.002%, Ca-treated, controlled rolling) - API 5L PSL 2 Supplementary Requirement SR17 (HIC testing) HIC testing per NACE TM0284: - 96-hour immersion in synthetic sour brine (H₂S saturated, pH 2.7) - Ultrasonic inspection for cracks - Acceptance: CLR < 15%, CTR < 5%, CSR < 2% Where: CLR = Crack Length Ratio (Σcrack lengths / specimen width) CTR = Crack Thickness Ratio (Σcrack heights / specimen thickness) CSR = Crack Sensitivity Ratio (Σcrack areas / specimen cross-section) Stress-Oriented HIC (SOHIC): HIC + tensile stress (especially in heat-affected zone). Occurs near welds in high-stress regions. Prevention: - Same as HIC prevention - PWHT to reduce residual stress (1100-1200°F for 1 hr/in) - Avoid stress concentrations (smooth transitions, generous radii)

Sour Service Material Selection

Material Specification SSC Resistant? HIC Resistant? Comments
API 5L PSL 2 X42-X65 With SR15 (SSC) Yes (if HRC ≤ 22) No (unless SR17) PWHT required to meet hardness; verify by testing
API 5L PSL 2 + SR17 HIC tested Yes Yes Preferred for sour service; higher cost
ASTM A106 Grade B PWHT required Yes (with PWHT) No Piping; PWHT to reduce hardness
13Cr stainless Modified (≤ 0.01% C) Yes Yes Used for severe sour + CO2; expensive
Duplex stainless (22Cr) UNS S31803 Yes Yes Excellent sour + chloride resistance; very expensive
Inconel 625, 825 Nickel alloys Yes Yes Extreme sour service; highest cost

PWHT Requirements for Sour Service

Post-Weld Heat Treatment (PWHT): Purpose: - Reduce hardness in HAZ and weld metal - Relieve residual stresses - Improve toughness Temperature: 1100-1250°F (593-677°C) Holding time: 1 hour per inch of thickness (minimum 30 min) Heating/cooling rate: < 400°F/hr (< 220°C/hr) When PWHT is Required: ALWAYS for sour service if: - Wall thickness > 0.75 in (19 mm) - Grade X60 or higher - P_H2S > 3 psia - Design temperature < 32°F OPTIONAL for sour service if: - Wall thickness < 0.75 in - Grade X52 or lower - Hardness testing confirms HRC ≤ 22 without PWHT Exemptions: - Small-bore piping (≤ 2 in NPS, ≤ 0.5 in thick) - Stub-in connections with fillet welds - If hardness survey proves HRC ≤ 22 without PWHT

Sweet Service (CO₂ Only)

CO2 corrosion mechanism diagram showing cross-section of steel surface with water layer and gas phase, numbered reaction steps: 1 CO2 dissolving into aqueous phase, 2 carbonic acid formation CO2+H2O→H2CO3, 3 acid dissociation H2CO3→H++HCO3-, 4 cathodic reaction 2H++2e-→H2 with bubble, 5 anodic reaction Fe→Fe2++2e- iron dissolution, 6 FeCO3 scale formation Fe2++CO32-→FeCO3 crystals on surface, temperature effect box showing T<60°C non-protective scale high corrosion vs T>70°C protective FeCO3 scale forms, overall reaction equation at bottom
CO₂ corrosion mechanism showing electrochemical reactions and protective scale formation.
CO₂ Corrosion (No H₂S): CO₂ + H₂O → H₂CO₃ (carbonic acid) → general/localized corrosion Corrosion rate depends on: - CO₂ partial pressure (P_CO2) - Temperature (max rate ~70-80°C) - Flow velocity (wall shear stress) - In-situ pH, water chemistry de Waard-Milliams Correlation (screening): log(CR) = 5.8 - 1710/T + 0.67×log(pCO₂) Where: CR = mm/yr, T = Kelvin, pCO₂ = bar pCO₂ < 0.5 bar (7 psia): Low risk (<5 mpy) 0.5 < pCO₂ < 2 bar (7-30 psia): Moderate risk (5-20 mpy) pCO₂ > 2 bar (30 psia): High risk (>20 mpy) Mitigation Options: - Corrosion inhibitor injection (85-95% efficiency) - Internal coating (epoxy, FBE, phenolic) - Corrosion allowance (3-6 mm typical) - pH stabilization (raise pH to form protective FeCO₃ scale) - CRA upgrade (13Cr, Duplex for severe cases) Sweet service does NOT require HRC ≤ 22 or PWHT (unless other factors). Standard carbon steel (API 5L PSL 1 or PSL 2) is acceptable.
Sour service cost impact: Sour service materials (PSL 2 with SR15/SR17) cost 15-30% more than standard pipe. PWHT adds $5-20 per inch-diameter-foot for field welds. Hardness testing adds inspection time and cost. For marginal sour service (P_H2S near 0.05 psia), consider operating changes (dehydration, H2S scavenging) to eliminate sour service requirements and reduce costs.

4. Temperature Limits & Impact Testing

Carbon steel service temperature is limited by creep (high temperature) and brittle fracture (low temperature). Impact testing verifies adequate toughness at minimum design temperature.

Carbon Steel Temperature Limits

Temperature Range Material Behavior Requirements
-50°F to -20°F Potential brittle fracture Impact testing mandatory; ASTM A333 or normalized steel
-20°F to 32°F Ductile-to-brittle transition Impact testing required per ASME B31.8 Table 841.1.8-1
32°F to 250°F Normal ductile behavior No special requirements; standard carbon steel
250°F to 650°F Strength reduction, no creep Temperature derating factor (T < 1.0); use ASTM A106
> 650°F Creep, oxidation Alloy steel (Cr-Mo); carbon steel not recommended

Impact Testing Requirements (ASME B31.8)

When Impact Testing is Required: Per ASME B31.8 Table 841.1.8-1: Impact testing is REQUIRED if: 1. Design temperature < 32°F (0°C), OR 2. Design temperature < 50°F (10°C) AND wall thickness > 0.75 in, OR 3. Specified by pipeline specifications (e.g., Arctic, offshore) Impact testing is EXEMPT if: - Temperature ≥ 50°F and t ≤ 0.75 in - Material is normalized (heat treated for improved toughness) - Material specification includes mandatory impact testing (API 5L PSL 2) Charpy V-Notch (CVN) Requirements: Test temperature: Minimum design temperature or -20°F, whichever is LOWER Acceptance criteria (ASME B31.8): - Average of 3 specimens: ≥ 15 ft·lb (20 J) - Minimum single specimen: ≥ 12 ft·lb (16 J) Higher toughness preferred: - Onshore transmission: 20-30 ft·lb average - Offshore, Arctic: 40-60 ft·lb average - HCA (High Consequence Area): 30+ ft·lb average

Brittle Fracture Mechanism

CVN impact energy versus temperature chart for typical X52 steel showing S-shaped transition curve from 5 ft-lb at -100°F to 95 ft-lb at +100°F, three labeled regions: lower shelf brittle behavior (light red) with cleavage fracture below 15 ft-lb, transition zone (light yellow) with mixed ductile-brittle behavior, upper shelf ductile behavior (light green) above 80 ft-lb with plastic deformation, horizontal dashed line at ASME B31.8 minimum 15 ft-lb average, vertical dashed line at DBTT ductile-to-brittle transition temperature around -10°F, impact test threshold at 32°F
Ductile-to-brittle transition curve showing CVN impact energy vs. temperature for carbon steel.
Ductile-to-Brittle Transition: At low temperature, carbon steel transitions from ductile (plastic deformation) to brittle (cleavage fracture) behavior. Transition temperature depends on: - Carbon content (higher C → higher DBTT) - Grain size (finer grain → lower DBTT) - Alloy content (Ni lowers DBTT; P, S raise it) - Strain rate (faster loading → higher effective DBTT) Fracture Toughness (K_Ic): Linear elastic fracture mechanics: K_Ic = Y × σ × √(π × a) Where: K_Ic = Fracture toughness (ksi·√in) Y = Geometry factor (~1.12 for edge crack) σ = Applied stress (ksi) a = Crack depth (in) CVN energy correlates to K_Ic (Barsom-Rolfe): K_Ic (ksi·√in) ≈ 15 × √(CVN ft·lb) For CVN = 20 ft·lb: K_Ic ≈ 15 × √20 = 67 ksi·√in (typical for carbon steel at 32°F) For CVN = 60 ft·lb: K_Ic ≈ 15 × √60 = 116 ksi·√in (high toughness)

Low-Temperature Material Options

Specification Grade Minimum Temp CVN Requirement Application
API 5L PSL 2 X42-X70 -20°F 15 ft·lb @ test temp Standard pipeline with impact testing
ASTM A333 Grade 6 -50°F 13 ft·lb @ -50°F Low-temp piping (e.g., propane, refrigeration)
API 5L PSL 2 X65 (normalized) -40°F 40-60 ft·lb @ -40°F Arctic pipelines (normalized for toughness)
ASTM A350 LF2 -50°F 15 ft·lb @ -50°F Forged flanges, fittings for low temp
304/316 Stainless — -425°F (cryogenic) Not required (austenitic, no DBT) LNG, cryogenic service (very expensive)

High-Temperature Considerations

Temperature Derating (ASME B31.8): For service temperature > 250°F, reduce allowable stress: T_factor per ASME B31.8 Table 841.1.7-1: Temperature (°F) T Factor 250 1.000 300 0.967 350 0.933 400 0.900 450 0.867 Updated Barlow's formula: t = (P × D) / (2 × S × E × F × T) For 350°F service, T = 0.933: Required wall thickness increases by 7% compared to ambient design. Creep Limit: Carbon steel experiences time-dependent deformation (creep) at T > 650°F. For T > 650°F, use Cr-Mo alloy steels: - 1.25Cr-0.5Mo (P11): to 1000°F - 2.25Cr-1Mo (P22): to 1100°F - 5Cr-0.5Mo (P5): to 1200°F
Impact testing is cheap insurance: CVN testing costs $100-300 per heat of pipe, a negligible fraction of project cost. Failure to impact test low-temperature service has caused catastrophic brittle fractures (e.g., Liberty ships in WWII, natural gas pipelines in cold climates). Always specify impact testing for T < 32°F.

5. Corrosion Allowance & Coatings

Corrosion allowance (CA) is extra wall thickness to accommodate metal loss over service life. Internal and external coatings prevent or reduce corrosion, potentially eliminating need for CA.

Corrosion Allowance Calculation

Required Corrosion Allowance: CA = Corrosion_rate × Design_life Where: Corrosion_rate = Uniform metal loss (mils/year or mm/year) Design_life = Service life (years, typically 20-30) Example: Sweet CO2 service with corrosion rate = 10 mpy (mils per year) Design life = 25 years CA = 10 mpy × 25 yr = 250 mils = 0.250 in Add to pressure design wall thickness: t_total = t_pressure + CA If t_pressure = 0.375 in: t_total = 0.375 + 0.250 = 0.625 in Order 0.625 in or next larger standard wall. Typical Corrosion Rates (Uncoated Carbon Steel): Dry natural gas: < 1 mpy → CA = 0.000" (no allowance needed) Sweet gas (CO2, inhibited): 5-10 mpy → CA = 0.125-0.250" Sweet gas (CO2, uninhibited): 10-30 mpy → CA = 0.250-0.625" Sour gas (H2S, inhibited): 5-15 mpy → CA = 0.125-0.375" Saltwater (uninhibited): 20-50 mpy → CA = 0.500-1.250"

Internal Coatings

Coating Type Typical Thickness Temperature Limit Application Cost ($/ft² typical)
Liquid epoxy 10-16 mils 180°F Gas pipelines, multiphase lines; excellent CO2 resistance $3-6
Fusion bonded epoxy (FBE) 12-20 mils 250°F Dry gas, oil lines; powder applied and cured $4-8
Phenolic 10-15 mils 200°F Sour gas service; H2S permeation barrier $5-10
Polyurethane 15-25 mils 180°F Abrasive service (sand production) $6-12
Cement mortar 0.25-0.50 in 150°F Water lines (potable, firewater); corrosion + scale prevention $2-4

External Coatings (Pipeline)

Cross-section diagram of 3-layer polyethylene 3LPE pipeline coating system showing curved pipe wall section with four distinct layers from inside to outside: steel pipe API 5L X52 blast cleaned to Sa 2.5, Layer 1 FBE primer 0.2-0.5mm dark green providing corrosion barrier and adhesion to steel, Layer 2 copolymer adhesive 0.2-0.3mm light orange bonding FBE to PE topcoat, Layer 3 PE topcoat 1.8-3.0mm black providing mechanical protection and moisture barrier, total coating thickness 2.2-3.8mm (85-150 mils), callout box showing temperature limit 80°C and application steps, note for T>80°C use 3LPP polypropylene
3-Layer polyethylene (3LPE) coating system cross-section for buried pipeline protection.
Coating Type Typical Thickness Temperature Limit Application Cost ($/ft² typical)
3-Layer polyethylene (3LPE) 80-120 mils 140°F Standard for buried pipelines; FBE + adhesive + PE $5-8
3-Layer polypropylene (3LPP) 100-150 mils 250°F High-temp pipelines, offshore; better than 3LPE for T > 140°F $8-12
Fusion bonded epoxy (FBE) 12-20 mils (single), 24-40 mils (dual) 250°F Moderate soil conditions; lower impact resistance than 3LPE $3-5
Coal tar enamel 100-200 mils 140°F Legacy coating; good performance but carcinogenic (avoid) $4-6
Tape wrap (polyethylene) 40-80 mils 120°F Field joints, repairs; lower quality than plant-applied $2-4

Cathodic Protection

Cathodic Protection (CP) for External Corrosion: External coating + CP = industry standard for buried pipelines. Coating provides primary barrier; CP protects coating holidays (defects). Impressed Current CP: Rectifier supplies DC current to pipeline (cathode). Anodes (graphite, MMO) buried near pipeline. Current requirement: I = (Coating_area × current_density) / coating_efficiency Typical current density: 0.5-2 mA/ft² (bare pipe) Coating efficiency: 95-99.5% (well-coated pipe) For 10 miles of 24" pipe with 99% coating efficiency: Coating area = π × 2 ft × 52,800 ft = 331,000 ft² Bare area = 331,000 × 0.01 = 3,310 ft² I = 3,310 ft² × 1 mA/ft² = 3.3 A Rectifier size: 5-10 A capacity (with margin) Sacrificial Anode CP: Magnesium or zinc anodes buried along pipeline. Galvanic current flows from anode to pipe (no external power). Anode consumption: Life (years) = (Anode_weight × Utilization% × Capacity) / (Current × 8760) Where: Capacity = 1300 A·hr/lb (magnesium), 780 A·hr/lb (zinc) Utilization = 85% (typical)

Coating vs. Corrosion Allowance Economics

Economic Comparison: Option 1: Corrosion allowance (no internal coating) Extra wall thickness: 0.250 in Pipe cost increase: ~$5-10 per ft (24" pipe) 10 miles: ~$250,000-500,000 Option 2: Internal epoxy coating Coating cost: $5 per ft² × 6.3 ft² per ft = $31.50 per ft 10 miles: $1,660,000 Corrosion allowance is MUCH cheaper for pipelines. However, internal coating may be required if: - Corrosion rate > 30 mpy (CA would be excessive) - Flow assurance (reduce friction, prevent wax/hydrate deposition) - Product purity (prevent iron contamination) - Existing pipeline (can't add wall thickness) For piping and vessels (small diameter, high surface area per volume): Internal coating is often more economical than CA. For gas gathering/transmission (dry gas, low corrosion): Neither CA nor coating may be required (bare carbon steel).

Material Testing and Certification

  • Mill Test Report (MTR): Certifies chemical composition, mechanical properties, heat treatment, and test results for each heat/lot. Required for all pressure-containing materials.
  • Positive Material Identification (PMI): Field verification of alloy content using XRF analyzer. Ensures correct material installed (prevents mixing carbon steel with stainless).
  • Hardness testing: For sour service, verify HRC ≤ 22 in weld, HAZ, and base metal. Rockwell or Vickers tester; non-destructive.
  • Impact testing (CVN): Charpy V-notch specimens machined from pipe, tested at specified temperature. Required for low-temp service or per specification.
  • Hydrostatic testing: Proof test at 1.5 × MAOP for pipelines, 1.3 × design pressure for piping. Verifies no leaks and material adequacy.
  • Non-destructive examination (NDE): Radiography (RT), ultrasonic testing (UT), or phased-array UT (PAUT) for weld quality. Required percentage depends on class location and specification.
Documentation is critical: For regulatory compliance (DOT 49 CFR 192, API 5L), maintain MTRs, PMI reports, hardness test results, CVN data, and hydrostatic test records for the life of the pipeline. Inability to prove material compliance can result in regulatory violations, required hydrotesting, or even replacement.

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