Line Sizing
Engineering fundamentals for pipe diameter selection
1. Sizing Principles
Line sizing balances capital cost (larger pipe = more expensive) against operating cost (smaller pipe = higher pressure drop = more compression/pumping energy). Key constraints include velocity limits, pressure drop, and erosion.
Sizing Criteria
| Criterion |
Concern |
Limit |
| Maximum velocity |
Erosion, noise, vibration |
Service-dependent (see tables) |
| Minimum velocity |
Liquid holdup, solids deposition |
3–5 ft/s liquids; varies for gas |
| Pressure drop |
Available pressure, compression cost |
0.5–2 psi/100 ft typical |
| Noise |
Personnel safety, equipment damage |
<85 dBA at 1m |
Basic Velocity Equation
Gas:
V = 0.4087 × (Q × Z × T) / (P × D²)
Where:
V = Velocity (ft/s)
Q = Flow rate (MMSCFD)
Z = Compressibility factor
T = Temperature (°R)
P = Pressure (psia)
D = Inside diameter (inches)
Liquid:
V = 0.4085 × Q / D²
Where:
V = Velocity (ft/s)
Q = Flow rate (GPM)
D = Inside diameter (inches)
2. Gas Line Sizing
Erosional Velocity
The maximum velocity to prevent pipe wall erosion, especially with entrained liquids or solids:
API RP 14E Erosional Velocity:
V_e = C / √ρ
Where:
V_e = Erosional velocity (ft/s)
C = Empirical constant (100–150 typical)
ρ = Gas density at flowing conditions (lb/ft³)
C-factor guidelines:
C = 100: Continuous service, solids present
C = 125: Intermittent service, clean gas
C = 150: Clean, dry gas, non-corrosive
C = 200: Very clean service (sometimes used)
Recommended Gas Velocities
| Service |
Velocity (ft/s) |
Notes |
| Compressor suction |
30–50 |
Low ΔP critical |
| Compressor discharge |
50–80 |
Higher density |
| Process headers |
60–100 |
General rule |
| Transmission pipelines |
20–50 |
Long distance, optimize ΔP |
| Flare headers |
0.3–0.5 Mach |
Noise, backpressure limits |
| Relief valve inlet |
<3% ΔP |
Per API 520 |
Pressure Drop Approach
For long pipelines, size based on allowable pressure drop:
Target pressure drop:
Gathering lines: 5–20 psi/mile
Transmission: 1–5 psi/mile
Plant piping: 0.5–2 psi/100 ft
Solve for D using flow equations (Panhandle, Weymouth, etc.)
📊 Gas Line Sizing Chart
Nomograph or chart with: X-axis: Flow rate (MMSCFD, log scale 0.1 to 100). Y-axis: Pipe ID (inches, 2" to 24"). Family of curves for different velocities (30, 60, 100 ft/s) at reference pressure (say 500 psia). Overlay erosional velocity limit (red dashed line). User can read pipe size for given flow and velocity constraint.
3. Liquid Line Sizing
Recommended Liquid Velocities
| Service |
Velocity (ft/s) |
Notes |
| Pump suction |
3–5 |
NPSH critical; minimize friction |
| Pump discharge |
6–10 |
Higher velocity acceptable |
| Gravity flow |
1–3 |
Depends on available head |
| Process lines (general) |
5–8 |
Balance cost vs. ΔP |
| Crude oil pipelines |
3–7 |
Optimize for energy cost |
| Water service |
5–10 |
Cooling water, utility |
| Slurries |
>5 |
Keep solids suspended |
Minimum Velocity
Prevent settling of solids or accumulation of gas pockets:
- Liquids with solids: V_min = 3–5 ft/s to keep particles suspended
- Gas-cut liquids: V_min = 3 ft/s to sweep gas through
- Clean liquids: No strict minimum, but avoid dead legs
Quick Sizing Formula
Approximate pipe diameter:
D = √(0.4085 × Q / V)
Example: Q = 500 GPM, V = 6 ft/s
D = √(0.4085 × 500 / 6) = √34.0 = 5.8"
→ Use 6" Schedule 40 (ID = 6.065")
4. Two-Phase Considerations
Two-phase (gas-liquid) lines require special attention for flow regime, liquid holdup, and slug formation.
API RP 14E for Two-Phase
Mixture velocity:
V_m = V_sg + V_sl
Erosional velocity (two-phase):
V_e = C / √ρ_m
ρ_m = (W_L + W_G) / (W_L/ρ_L + W_G/ρ_G)
Where:
V_sg, V_sl = Superficial gas, liquid velocities
W_L, W_G = Mass flow rates (lb/hr)
ρ_L, ρ_G = Densities (lb/ft³)
Slug Flow Considerations
- Terrain slugging: Hilly pipelines can form severe slugs at low points
- Riser slugging: Vertical sections at pipe end collect liquid
- Mitigation: Size slug catchers, use flow conditioners, increase velocity
⚠ Slug catcher sizing: Two-phase gathering lines can produce slugs of 100–1000+ barrels. Size inlet separators and slug catchers for worst-case liquid volume using dynamic simulation.
Flow Regime Guidance
| Regime |
Characteristics |
Design Impact |
| Stratified |
Gas on top, liquid on bottom |
Corrosion at bottom; pigging needed |
| Slug |
Alternating liquid plugs and gas |
Slug catcher required; vibration |
| Annular |
Gas core, liquid film on wall |
Generally acceptable; high velocity |
| Mist |
Liquid droplets in gas |
Erosion concern; entrainment |
5. Economic Optimization
Optimal pipe size minimizes total cost = capital cost + operating cost (NPV basis).
Cost Components
| Component |
Effect of Larger Pipe |
| Pipe material |
Increases (more steel) |
| Installation (trenching, welding) |
Increases |
| Valves, fittings |
Increases |
| Compression/pumping energy |
Decreases (lower ΔP) |
| Compressor/pump size |
Decreases |
📈 Economic Pipe Diameter
Graph showing: X-axis: Pipe diameter (inches). Y-axis: Annualized cost ($/year). Three curves: (1) Capital cost (increasing with diameter), (2) Operating cost/energy (decreasing with diameter), (3) Total cost (U-shaped). Mark optimum diameter at minimum of total cost curve. Annotate that larger pipe saves energy but costs more upfront.
Rules of Thumb
- Short lines (<1 mile): Size on velocity; energy cost is minor
- Long pipelines (>10 miles): Detailed economic analysis; energy cost dominates
- High utilization: Larger pipe justified (more operating hours)
- Expansion potential: Consider future flow increases
Quick Economic Velocity
Peters & Timmerhaus correlation:
V_opt = K × ρ^(-0.37) × D^0.13
Typical result for hydrocarbons:
Gas: V_opt ≈ 60–100 ft/s
Liquid: V_opt ≈ 5–8 ft/s
These coincide with typical velocity limits—
velocity criteria usually give near-economic sizing.
References
- API RP 14E – Recommended Practice for Design and Installation of Offshore Production Platform Piping Systems
- GPSA Engineering Data Book, Section 17
- Process Piping (ASME B31.3)
- Ludwig's Applied Process Design, Vol. 1