Pipeline Design

Sand & Erosional Velocity

Calculate erosional velocity limits and predict sand erosion rates using API RP 14E and DNV RP O501 methodologies for gas, liquid, and multiphase pipeline systems.

Launch Calculator API RP 14E Method

API RP 14E

Ve = C / √ρ

Erosional velocity formula

Clean Service

C = 100-150

No sand, inhibited service

Sandy Service

C = 50-100

Sand-producing wells, uninhibited

Contents

Use this guide when:

  • Setting velocity limits for production piping
  • Evaluating erosion risk in sand-producing wells
  • Selecting C-factor for API RP 14E calculations
  • Designing sand management systems

1. Overview

Erosion is one of the primary failure mechanisms in production piping and pipeline systems. When fluid velocities exceed critical limits or when solid particles (sand) are entrained in the flow stream, material is removed from pipe walls, fittings, and equipment at rates that can lead to wall thinning, leaks, and catastrophic failure.

Production Piping

Wellhead to Separator

Highest erosion risk zone due to sand production, high velocity, and flow direction changes.

Gathering Systems

Multiphase Flow

Slug flow and annular flow patterns create localized high-velocity impacts on pipe walls.

Process Piping

Choke & Control Valves

Pressure letdown creates high velocities and turbulence at trim, seats, and downstream piping.

Compressor Stations

Discharge Piping

High gas velocity at compressor discharge can cause erosion at elbows and tees.

Critical distinction: Erosional velocity (API RP 14E) addresses velocity-induced erosion in clean service, while sand erosion (DNV RP O501) addresses particle-impact erosion. Both mechanisms can act simultaneously, and sand erosion rates increase dramatically with velocity.

2. Erosion Mechanisms

Pipeline erosion occurs through several distinct mechanisms depending on the fluid phase, particle loading, and flow geometry.

Particle Impact Erosion

The dominant erosion mechanism in sand-producing systems. Solid particles entrained in the flow stream impact pipe walls at elbows, tees, and other direction changes. The erosion rate depends on particle velocity, impact angle, particle size, and target material hardness.

Erosion Rate Dependence: E ∝ Vn × m_p × f(α) Where: E = Erosion rate (mass loss per unit time) V = Particle impact velocity n = Velocity exponent (typically 2.0-2.6) m_p = Particle mass flow rate f(α) = Impact angle function The velocity exponent n means: Doubling velocity increases erosion ~4-6x This is why velocity limits are critical in sand-producing systems.

Liquid Droplet Erosion

In high-velocity gas systems, entrained liquid droplets can cause erosion when they impact pipe walls. This mechanism is significant in wet gas systems, downstream of separators with carryover, and in compressor discharge piping.

Cavitation Erosion

Occurs in liquid systems when local pressure drops below the fluid vapor pressure, forming vapor bubbles that collapse violently against pipe walls. Common at control valves, pump suctions, and flow restrictions.

Flow-Accelerated Corrosion (FAC)

The synergy between erosion and corrosion where high fluid velocity removes protective oxide layers, exposing fresh metal to corrosive attack. This combined mechanism produces metal loss rates greater than either erosion or corrosion acting independently.

Mechanism Dominant Phase Critical Factor Most Vulnerable Location
Particle impact Gas or multiphase Sand rate, velocity Elbows, tees (outer wall)
Droplet erosion Wet gas Gas velocity, liquid loading Elbows, reducers
Cavitation Liquid Pressure drop, vapor pressure Valves, orifices, pump suction
FAC Liquid or wet gas Velocity + CO2/H2S Downstream of disturbances

3. API RP 14E Method

API Recommended Practice 14E provides the most widely used method for establishing maximum allowable velocity in production piping. The erosional velocity formula sets an upper bound on fluid velocity to prevent erosion damage.

API RP 14E Erosional Velocity: V_e = C / √ρ_m Where: V_e = Erosional velocity (ft/s) C = Empirical constant (dimensionless) ρ_m = Fluid mixture density (lb/ft³) For gas-only flow: ρ_m = ρ_gas = (P × M) / (z × R × T) For multiphase flow: ρ_m = ρ_l × λ + ρ_g × (1 - λ) Where: λ = Liquid volume fraction (no-slip) ρ_l = Liquid density at conditions ρ_g = Gas density at conditions

Mixture Density Calculation

Two-Phase Mixture Density: ρ_m = (12,409 × S_l × Q_l + 2.7 × S_g × R × P) / (198.7 × Q_l + R × T × z) Where: S_l = Liquid specific gravity (water = 1.0) Q_l = Liquid flow rate (bbl/day) S_g = Gas specific gravity (air = 1.0) R = Gas-liquid ratio (scf/bbl) P = Operating pressure (psia) T = Operating temperature (°R = °F + 460) z = Gas compressibility factor

Example: Gas Pipeline

Given: Natural gas, S_g = 0.65 Pressure = 800 psia Temperature = 100°F (560°R) z = 0.88 C = 100 (continuous service, no sand) Gas density: ρ_g = (800 × 0.65 × 28.97) / (0.88 × 10.73 × 560) ρ_g = 15,064 / 5,284 ρ_g = 2.85 lb/ft³ Erosional velocity: V_e = 100 / √2.85 V_e = 100 / 1.689 V_e = 59.2 ft/s This is the MAXIMUM velocity. Design velocity should be well below this limit (typically 50-80% of V_e).
Important limitation: API RP 14E was developed empirically in the 1980s and does not explicitly account for sand loading, pipe material, or geometry. For sand-producing wells, the C-factor must be reduced or a more rigorous method such as DNV RP O501 should be used.

4. DNV RP O501 Method

DNV Recommended Practice O501 provides a mechanistic erosion prediction model that accounts for particle size, particle rate, fluid properties, pipe geometry, and material properties. It is more rigorous than API RP 14E and is widely used in offshore and subsea applications.

Erosion Rate Model

DNV RP O501 Erosion Rate (Simplified): E = K × m_p × V_pn × F(α) × G × (1/ρ_t) Where: E = Erosion rate (mm/year or kg/m²/s) K = Material erosion constant m_p = Sand mass rate (kg/s) V_p = Particle impact velocity (m/s) n = Velocity exponent (~2.6 for steel) F(α) = Impact angle function G = Geometry factor (elbow, tee, etc.) ρ_t = Target material density (kg/m³) Material constants for carbon steel: K = 2.0 × 10²&sup9; n = 2.6

Geometry Factors

Component Relative Erosion Rate Most Eroded Location
Straight pipe 1.0 (baseline) Bottom of pipe (settled sand)
Standard elbow (R/D = 1.5) 3-10 Outer wall at 30-45° from exit
Long-radius elbow (R/D = 3) 2-5 Outer wall, distributed
Tee (flow through branch) 5-15 Opposite branch opening
Reducer 2-4 Converging section wall
Choke valve 10-50+ Trim, cage, seat

Impact Angle Function

Ductile Material Impact Angle Function (Steel): For ductile materials (carbon steel, stainless steel): Maximum erosion occurs at α = 20-30° Near-zero erosion at α = 0° (glancing impact) Reduced erosion at α = 90° (normal impact) For brittle materials (ceramics, tungsten carbide): Maximum erosion occurs at α = 90° (normal impact) Erosion increases monotonically with angle This distinction is critical for material selection: Standard elbows create 15-45° impact angles, which is near the peak erosion angle for steel.

5. C-Factor Selection

The empirical constant C in the API RP 14E formula is the most critical parameter and the most debated. Its selection depends on the service conditions, corrosivity, sand loading, and pipe material.

C-Factor Guidelines

C Value Service Condition Application
250-300 Clean, non-corrosive, CRA pipe Stainless/duplex, no sand, no CO2/H2S
150-200 Clean, inhibited carbon steel Gas pipelines, no sand, corrosion inhibited
100-150 Continuous service, carbon steel API RP 14E default range, mild conditions
75-100 Intermittent service, some solids Wells with occasional sand, uninhibited
50-75 Sandy service, corrosive Sand-producing wells with CO2 or H2S
< 50 Severe erosion-corrosion High sand rate + corrosive + high temperature

Factors Affecting C-Factor Selection

Increase C (higher velocity allowed) when: - Corrosion-resistant alloy (CRA) pipe material - Effective corrosion inhibition program - No sand or solids production - Thick-walled pipe (large corrosion allowance) - Short service life or acceptable replacement Decrease C (lower velocity limit) when: - Carbon steel in CO2/H2S service - Sand-producing wells - No corrosion inhibition - Thin-walled pipe or minimal corrosion allowance - Elbows and fittings (concentrators) - Long design life required (20+ years) - Multiphase slug flow (intermittent high velocity)
Industry practice: Many operators use C = 100 as a default for carbon steel in continuous gas service with no sand. For sand-producing wells, C should be reduced to 50-75, or preferably, a mechanistic model such as DNV RP O501 should be used to establish allowable sand rates at the operating velocity.

6. Multiphase Considerations

Multiphase flow significantly complicates erosion prediction because the flow pattern determines the local velocity distribution, liquid film thickness, and particle impact behavior.

Flow Pattern Effects

Flow Pattern Erosion Risk Mechanism
Stratified Low to moderate Sand settles in liquid phase, low gas velocity at pipe bottom
Slug flow High Slug front creates high-velocity liquid impact; intermittent high velocity
Annular flow Moderate to high High gas core velocity carries particles; thin liquid film offers little cushioning
Mist flow Very high High-velocity gas carries both droplets and particles directly to pipe wall

Liquid Cushioning Effect

Effect of Liquid Film on Particle Erosion: A liquid film on the pipe wall absorbs particle kinetic energy before impact, reducing erosion rate. Thin film (< 1-2 mm): Minimal cushioning, particles penetrate to wall Erosion rate ~ same as dry gas Moderate film (2-5 mm): Significant cushioning for small particles (< 100 μm) Large particles still penetrate Thick film (> 5 mm): Effective cushioning for most particle sizes Erosion rate reduced 50-90% The liquid cushioning effect is one reason why wet gas systems sometimes experience less erosion than expected.

Sand Transport in Multiphase Flow

Sand particles can be transported in suspension, as a sliding bed, or as settled deposits depending on the flow velocity, fluid properties, and particle size. Minimum transport velocity must be maintained to prevent sand accumulation in low points.

Minimum Sand Transport Velocity (Horizontal Pipe): For gas-dominated flow: V_min ≈ 10-15 ft/s (30-50 μm sand) V_min ≈ 20-30 ft/s (100-250 μm sand) For liquid-dominated flow: V_min ≈ 3-5 ft/s (typical production sand) Below minimum transport velocity, sand settles and accumulates at pipe low points, reducing flow area and potentially causing under-deposit corrosion.

7. Sand Management

Sand Detection and Monitoring

Method Measurement Application
Acoustic sand detector Sand particle impacts on pipe wall Real-time monitoring, non-intrusive
Erosion probes Weight loss of sacrificial element Cumulative erosion rate measurement
UT thickness monitoring Pipe wall thickness change Periodic inspection at critical locations
Separator desanding Volume of sand collected Batch measurement of total production

Sand Exclusion and Removal

Downhole Sand Control: - Gravel packing (most reliable, highest cost) - Screens (standalone or with gravel) - Frac-pack (combines fracturing with gravel pack) - Chemical consolidation (resin injection) Surface Sand Removal: - Desanders (hydrocyclone-based) - Sand jetting systems (in separators) - Sand traps and settling tanks - Inline strainers and filters

Design Strategies for Erosion Mitigation

  • Use long-radius elbows (R/D = 3 or greater) instead of standard elbows (R/D = 1.5)
  • Replace tees with laterals or weld-o-lets to reduce impact angle
  • Increase pipe size to reduce velocity (velocity decreases with D²)
  • Install erosion-resistant trim in control valves (tungsten carbide, ceramic)
  • Use CRA cladding or overlay at critical locations
  • Install sacrificial pipe spools at high-erosion locations for easy replacement
  • Implement real-time sand monitoring with automatic choke-back on high sand events

Allowable Sand Rates

Typical Allowable Sand Production Rates: Continuous production: Conservative: < 1 lb/day per well Moderate: 1-10 lb/day per well Aggressive: 10-50 lb/day per well High-rate sand management: With desanding: 50-500 lb/day With dedicated sand handling: 500-5,000+ lb/day The allowable rate depends on: - Pipe material and wall thickness - Flow velocity (erosion rate ∝ V^2.6) - Inspection frequency and accessibility - Consequence of failure (environmental, safety) - Economics of sand exclusion vs pipe replacement
Best practice: Establish a sand management philosophy early in field development. The cost of downhole sand exclusion (gravel packing) is high but may be justified if it eliminates surface erosion problems, reduces processing complexity, and extends the life of surface facilities.

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