1. Overview & Applications
Pipeline pigs are devices inserted into pipelines to perform maintenance, cleaning, inspection, or product separation. Pig speed control is critical for safe operations and effective pig performance.
Image: Common Pipeline Pig Types
Technical illustration showing foam pig, solid cast pig, steel mandrel pig, MFL tool, and gauge pig with labeled components.
Cleaning operations
Debris removal
Scraper pigs remove wax, scale, liquids, and debris at 3-5 ft/s optimal speed.
Inline inspection
ILI tool speed
MFL and UT tools require 2-6 ft/s for data quality and sensor response time.
Batch separation
Product interface
Batch pigs separate products in multi-product pipelines at flow velocity.
Hydrotesting
Dewatering pigs
Foam pigs push water out after hydrostatic testing at low speeds (1-3 ft/s).
Key Concepts
- Pig velocity: Speed of pig relative to pipeline (ft/s or m/s)
- Slip velocity: Difference between fluid velocity and pig velocity due to bypass
- Differential pressure (ΔP): Pressure drop across pig providing driving force
- Surge pressure: Transient pressure spike from rapid pig deceleration/acceleration
- Bypass ratio: Fraction of flow passing around pig sealing elements
Why pig speed matters: Too slow and pig may stall or allow product mixing. Too fast and pig can damage, create dangerous surges, or miss defects. Optimal speed ensures safe, effective pigging operations.
Pig Types and Speed Requirements
| Pig Type | Typical Speed | Speed-Critical Factor |
|---|---|---|
| Foam cleaning pig | 3-8 ft/s | Mechanical cleaning action requires momentum |
| Scraper/brush pig | 3-7 ft/s | Balance between cleaning effectiveness and wear |
| MFL inspection tool | 2-5 ft/s | Sensor sampling rate and data resolution |
| UT inspection tool | 2-6 ft/s | Ultrasonic coupling and signal processing time |
| Gauge/caliper pig | 3-8 ft/s | Mechanical finger response time to deformations |
| Batch/sphere | Flow velocity | Maintains seal to prevent product mixing |
| Dewatering pig | 1-3 ft/s | Low speed prevents water carry-over and surge |
API RP 1171 Speed Recommendations
API Recommended Practice 1171 and ILI vendor guidelines provide speed guidance:
- Minimum speed: 2 ft/s to prevent stalling in uphill sections
- Maximum speed: 15 ft/s to prevent pig damage and excessive wear
- Preferred range: 3-10 ft/s for most operations
- ILI tools: 2-6 ft/s optimal for magnetic flux leakage (MFL) and ultrasonic testing (UT)
- Speed control: ±20% target speed tolerance recommended
2. Pig Velocity Calculations
Pig velocity depends on fluid flow rate, differential pressure across pig, bypass flow, and pipeline geometry. Accurate velocity prediction is essential for operation planning.
Fundamental Velocity Equation
Pig Velocity (Gas Pipelines):
V_pig = (Q / A) × (1 - β)
Where:
V_pig = Pig velocity (ft/s)
Q = Gas volumetric flow rate at line conditions (ft³/s)
A = Pipe cross-sectional area (ft²)
β = Bypass ratio (fraction of flow bypassing pig, typically 0.02-0.10)
Cross-sectional area:
A = π D² / 4
Where D = internal pipe diameter (ft)
For liquid pipelines:
V_pig ≈ V_fluid (pigs travel at approximately fluid velocity in liquids)
Bypass Ratio Effects
Bypass flow past pig sealing elements reduces pig velocity below fluid velocity:
Bypass Ratio Definition:
β = Q_bypass / Q_total
Typical bypass ratios:
- New pigs, tight fit: β = 0.05 (5% bypass)
- Worn pigs: β = 0.10-0.15 (10-15% bypass)
- Undersized pigs: β > 0.20 (excessive, may stall)
Effective pig velocity:
V_pig = V_fluid × (1 - β)
Example:
Gas velocity: 20 ft/s
Bypass ratio: 0.10 (10%)
V_pig = 20 × (1 - 0.10) = 18 ft/s
Practical Velocity Estimation
For gas pipelines, pig velocity is primarily determined by gas flow rate and pipe area, not differential pressure. The practical approach:
Gas Pipeline Pig Velocity:
V_pig = (Q_actual / A) × f_pig × (1 - β)
Where:
Q_actual = Volumetric flow at line conditions (ft³/s)
A = Pipe cross-sectional area (ft²)
f_pig = Pig efficiency factor (0.85-0.95)
β = Bypass fraction (0.02-0.10)
Converting Standard to Actual Flow:
Q_actual = Q_std × (P_std / P_line) × (T_line / T_std) × Z
Where:
Q_std = Standard flow (scf/s) = MMSCFD × 10⁶ / 86,400
P_std = 14.73 psia
T_std = 519.67°R (60°F)
Z = Compressibility factor
Example - 12" Gas Pipeline (Solid Cast Pig, f_pig = 0.92):
Flow: 50 MMSCFD
Pressure: 800 psig (814.7 psia)
Temperature: 60°F (519.67°R)
Z = 0.9
Bypass: 5%
Q_std = 50 × 10⁶ / 86,400 = 578.7 scf/s
Q_actual = 578.7 × (14.73/814.7) × (519.67/519.67) × 0.9
Q_actual = 578.7 × 0.0181 × 0.9 = 9.42 ft³/s
A = π × (12/24)² = 0.785 ft²
V_gas = 9.42 / 0.785 = 12.0 ft/s
V_pig = 12.0 × 0.92 × 0.95 = 10.5 ft/s
Image: Pig Velocity vs Gas Velocity Relationship
Cross-sectional diagram showing pig in pipeline with gas flow arrows, bypass flow around seals, and velocity vectors (V_gas, V_pig, V_bypass).
Force Balance Method
Pig Motion Force Balance:
Driving force = Resistance forces
F_pressure = F_friction + F_gravity + F_inertia
ΔP × A_pig = f × W_pig + W_pig × sin(θ) + (W_pig/g) × a
For steady-state (a = 0) on level ground (θ = 0):
ΔP = (f × W_pig) / A_pig
Where:
ΔP = Differential pressure (psi)
A_pig = Pig cross-sectional area (in²)
f = Friction coefficient (0.1-0.3)
W_pig = Pig weight (lb)
θ = Pipeline angle (degrees, + for uphill)
a = Acceleration (ft/s²)
g = Gravitational constant (32.2 ft/s²)
Required ΔP for uphill section:
ΔP_required = [(f × W_pig) / A_pig] + ρ × g × Δh / 144
Where Δh = elevation change (ft)
Travel Time Calculation
Calculate pig transit time for operational planning:
Travel Time:
t = L / V_pig
Where:
t = Travel time (hours)
L = Pipeline length (miles)
V_pig = Pig velocity (ft/s)
Convert to hours:
t (hours) = [L (miles) × 5,280 ft/mile] / [V_pig (ft/s) × 3,600 s/hr]
t = L × 1.467 / V_pig
Example:
Pipeline length: 50 miles
Pig velocity: 5 ft/s
t = 50 × 1.467 / 5 = 14.67 hours
Add safety margin:
Expected arrival window: 14.7 hrs ± 2 hrs = 12.7 to 16.7 hrs
Variable Speed Along Pipeline
Pig speed varies with elevation changes, pipe diameter changes, and flow rate variations:
| Pipeline Section | Length (mi) | Diameter (in) | Elevation Δ (ft) | Est. Velocity (ft/s) | Travel Time (hr) |
|---|---|---|---|---|---|
| Section 1 (level) | 15 | 20 | 0 | 6.0 | 3.67 |
| Section 2 (uphill) | 8 | 20 | +300 | 3.5 | 3.35 |
| Section 3 (downhill) | 12 | 20 | -200 | 9.0 | 1.96 |
| Section 4 (reduced dia) | 5 | 16 | 0 | 9.4 | 0.78 |
| Total | 40 | — | — | — | 9.76 |
Note: Uphill sections slow the pig, while downhill sections accelerate it. Speed also increases in reduced diameter sections due to conservation of mass (continuity).
Speed control challenges: Pig velocity can vary 2-5× along a pipeline with significant elevation changes. Flow rate adjustment, pressure differential control, and pig selection must account for worst-case sections.
Liquid vs. Gas Pipeline Pig Speed
- Liquid lines: Pig velocity approximately equals fluid velocity due to incompressibility. Flow rate directly determines speed.
- Gas lines: Gas compressibility allows differential pressure to build. Pig velocity less dependent on flow rate, more sensitive to ΔP and bypass.
- Two-phase flow: Liquid holdup ahead of pig can dramatically slow or stall pig. Requires higher ΔP to move accumulated liquid slug.
3. Surge Pressure Analysis
Rapid pig acceleration or deceleration creates pressure surges that can exceed pipe design pressure. Surge analysis is critical for safe pigging operations, especially in liquid pipelines.
Image: Pressure Surge During Pig Arrival
Pressure vs time graph showing surge spike at pig arrival, with annotations for baseline pressure, peak surge, and attenuation curve.
Water Hammer Equation
Joukowsky Equation (Instantaneous Valve Closure):
ΔP_surge = ρ × c × ΔV / 144
Where:
ΔP_surge = Surge pressure (psi)
ρ = Liquid density (lb/ft³)
c = Wave speed (ft/s)
ΔV = Velocity change (ft/s)
144 = conversion factor (in²/ft²)
Wave speed in liquid pipelines:
c = √[(K/ρ) / (1 + (K/E) × (D/t))]
Where:
K = Bulk modulus of liquid (psi) - 300,000 psi for water
E = Pipe elastic modulus (psi) - 30×10⁶ psi for steel
D = Pipe OD (in)
t = Wall thickness (in)
Typical wave speeds:
- Rigid pipe (thick wall): c ≈ 4,800 ft/s
- Flexible pipe (thin wall): c ≈ 3,500 ft/s
- Gas pipelines: c ≈ 1,000-1,500 ft/s (sonic velocity)
Pig Surge Pressure Calculation
Surge from Pig Stoppage:
ΔP = (ρ × c × V_pig) / 144
Example - Liquid Pipeline:
Crude oil density: 55 lb/ft³ (API 35°)
Wave speed: 4,000 ft/s
Pig velocity: 8 ft/s (suddenly stopped at receiver)
ΔP = (55 × 4,000 × 8) / 144
ΔP = 1,760,000 / 144 = 12,222 psi surge!
With pipe operating at 800 psi:
Peak pressure = 800 + 12,222 = 13,022 psi (exceeds MAOP!)
Reality: Attenuation factors reduce actual surge
- Pig deceleration not instantaneous (0.5-2 seconds typical)
- Pipe elasticity absorbs energy
- Friction dampens wave
- Actual surge typically 10-30% of Joukowsky value
Realistic surge: 12,222 × 0.20 = 2,444 psi
Peak pressure: 800 + 2,444 = 3,244 psi (still excessive!)
Deceleration Time Factor
Gradual deceleration reduces surge pressure:
Modified Surge with Deceleration Time:
ΔP_surge = (ρ × L × ΔV) / (144 × g × t_d)
Where:
L = Length of liquid column ahead of pig (ft)
ΔV = Velocity change (ft/s)
t_d = Deceleration time (seconds)
g = 32.2 ft/s²
Example:
Liquid column: 10,000 ft (2 miles ahead of pig)
ρ = 55 lb/ft³
ΔV = 8 ft/s (pig stops)
t_d = 2 seconds (receiver closure time)
ΔP = (55 × 10,000 × 8) / (144 × 32.2 × 2)
ΔP = 4,400,000 / 9,273.6 = 474 psi
If operating pressure is 800 psi:
Peak = 800 + 474 = 1,274 psi (more manageable)
Surge Mitigation Strategies
| Strategy | Method | Surge Reduction | Cost/Complexity |
|---|---|---|---|
| Slow pig speed | Reduce line flow rate during pigging | High (surge ∝ velocity) | Low (operational change) |
| Bypass valve at receiver | Open bypass before pig arrival to gradually slow pig | Very high (50-80% reduction) | Medium (valve + controls) |
| Surge tank | Accumulator absorbs pressure spike | High (30-60% reduction) | High (tank + controls) |
| Gradual receiver closure | Slow closure valve (2-5 seconds) | Medium (increases t_d) | Low (valve sizing) |
| Pig with bypass | Use pig design allowing controlled bypass | Low-medium (softens impact) | Low (pig selection) |
| Reduced pipeline pressure | Lower operating pressure during pig run | None (but increases margin) | Low (operational) |
Gas Pipeline Surge Considerations
Gas compressibility reduces surge severity compared to liquids:
- Lower wave speed: Gas sonic velocity ~1,200 ft/s vs. ~4,000 ft/s in liquids → 3× lower surge
- Compression absorption: Gas compression ahead of pig cushions deceleration
- Pack formation: Main risk is liquid accumulation ("pack") ahead of pig creating liquid-like surge
- Typical gas surge: 50-200 psi manageable with proper procedures
Surge pressure rule: Liquid line surges can reach 5-20× operating pressure if pig suddenly stops at full speed. Gas line surges typically 10-30% of operating pressure. ALWAYS plan for surge mitigation in high-speed liquid pig runs.
Maximum Safe Pig Velocity
Calculate maximum pig speed to limit surge below pressure rating:
Max Velocity Based on Surge Limit:
V_max = (ΔP_allowable × 144 × g × t_d) / (ρ × L)
Example:
Allowable surge: 300 psi (pipe rated 1,500 psi, operating 800 psi, margin 400 psi, allow 300 psi surge)
ρ = 55 lb/ft³
L = 10,000 ft liquid column
t_d = 2 seconds deceleration
V_max = (300 × 144 × 32.2 × 2) / (55 × 10,000)
V_max = 2,782,080 / 550,000
V_max = 5.06 ft/s
Recommendation: Limit pig to 5 ft/s or less for this scenario.
4. Launcher/Receiver Design
Pig launchers and receivers must be sized to accommodate the pig, provide adequate pressure differential for launching, and safely receive pigs with surge control.
Image: Pig Launcher Assembly Schematic
Side-view technical drawing of pig launcher showing barrel, closure door, kicker line, mainline valve, bypass valve, and pressure indicators with dimensions labeled.
Launcher Sizing Requirements
Launcher Barrel Length:
L_barrel = L_pig + L_margin
Where:
L_pig = Pig length (typically 1.5-3.0 × pipe diameter for cleaning pigs, up to 10+ ft for ILI tools)
L_margin = Safety margin (minimum 2-3 ft)
Typical launcher barrel lengths:
- Cleaning pigs (20" line): 8-10 ft barrel
- ILI tools (20" line): 15-20 ft barrel
- Smart pigs with electronics: Match tool length + 3 ft
Launcher barrel diameter:
D_barrel = Pipe OD + 2 inches (minimum)
Common practice: Use next pipe size up (e.g., 20" line → 24" barrel)
Launcher Pressure Differential
Sufficient pressure differential required to overcome pig static friction and accelerate pig into flow:
Minimum Launch Pressure:
ΔP_launch = ΔP_seal + ΔP_weight + ΔP_acceleration + ΔP_margin
Seal friction component (dominant term):
ΔP_seal = Empirical; typically 15-50 psi depending on seal type and condition
Pig weight friction component:
ΔP_weight = (μ_s × W_pig) / A_pig
Where:
μ_s = Static friction coefficient (0.2-0.4 for pig-on-steel)
W_pig = Pig weight (lbf)
A_pig = Pig cross-sectional area (in²)
Note: Pig weight friction is typically small (<1 psi) relative to seal friction.
Typical launch requirements:
- Gas pipelines: 50-150 psi differential
- Liquid pipelines: 30-100 psi differential
- Heavy ILI tools: 150-300 psi differential
Example - 20" Gas Line:
Pig weight: 500 lb
μ_s = 0.3
A_pig = π × (20)² / 4 = 314 in²
ΔP_weight = (0.3 × 500) / 314 = 0.5 psi
ΔP_seal ≈ 25 psi (cup/disc seal friction, empirical)
ΔP_accel ≈ 30 psi (acceleration to line velocity)
ΔP_margin = 50 psi (safety margin)
Total: 0.5 + 25 + 30 + 50 ≈ 105 psi required for launch
Launcher Pressure Rating
Launchers must be rated for pipeline MAOP plus margin:
| Pipeline MAOP | Launcher Rating (ASME B31.8) | Typical Construction |
|---|---|---|
| < 500 psi | MAOP × 1.5 or Class 300 minimum | Seamless pipe, Class 300 flanges |
| 500-1,000 psi | MAOP × 1.25 or Class 600 | Seamless pipe, Class 600 flanges |
| 1,000-1,440 psi | Class 900 | Heavy wall seamless, Class 900 flanges |
| > 1,440 psi | Class 1500 | Forged construction, Class 1500 flanges |
Receiver Design Considerations
Receivers must safely stop pig and handle surge pressures:
Receiver Barrel Length:
L_receiver = L_pig + L_decel + L_margin
Where:
L_decel = Deceleration distance (typically 3-5 ft)
L_margin = Safety margin (3-5 ft)
Typical receiver lengths:
- Standard cleaning pig: 12-15 ft
- ILI tool: 20-25 ft
- Gas line with high-speed pigs: Add 5 ft for deceleration
Receiver barrel diameter:
Same as launcher: Pipe OD + 2" or next pipe size up
Receiver Closure Mechanisms
| Closure Type | Pressure Range | Closure Time | Surge Control |
|---|---|---|---|
| Quick-opening closure | < 600 psi | Instant | Poor (hard stop) |
| Ball valve | Up to 1,500 psi | 1-3 seconds | Fair (some cushioning) |
| Gate valve | Up to 2,000+ psi | 3-10 seconds | Good (gradual closure) |
| Actuated valve with ramp | Any | Programmable 5-20 sec | Excellent (controlled decel) |
| Bypass valve system | Any | Bypass opens, main closes slowly | Excellent (minimal surge) |
Bypass Valve Surge Control
Recommended for high-speed or liquid pipelines:
Bypass Valve Operation:
1. Pig approaches receiver (detected by pig detector)
2. Bypass valve opens, allowing flow around receiver
3. Main receiver closure valve begins closing (2-5 seconds)
4. Pig enters receiver at reduced velocity
5. Main valve fully closed, bypass valve closes
6. Depressurize receiver, open closure, extract pig
Bypass valve sizing:
Size for 30-50% of line flow rate at 50 psi pressure drop
For 100 MMscf/d gas line:
Bypass flow: 40 MMscf/d = 463 ft³/s at line conditions
ΔP: 50 psi
Use 8-10" bypass valve with automated control
Pig Trap Instrumentation
Safety and operational instrumentation for launchers/receivers:
- Pressure transmitters: Monitor barrel and pipeline pressure, calculate ΔP for launch
- Pig detectors (upstream): Magnetic or acoustic detector 100-500 ft before receiver warns of pig arrival
- Closure position switches: Confirm closure door/valve fully closed before pressurizing
- Vent/drain valves: Depressurize barrel safely before opening closure
- Interlocks: Prevent closure opening under pressure, prevent pressurizing with open closure
- Flow meters: Confirm flow through launcher/receiver for pig movement verification
Safety critical: Launcher/receiver closures MUST have mechanical interlocks preventing opening under pressure. Opening a pressurized closure has caused fatalities. Never defeat interlocks.
5. Operational Considerations
Pre-Pigging Checklist
| Item | Verification | Consequence if Missed |
|---|---|---|
| Pig size correct for pipe ID | Measure pig OD, verify against pipe ID + tolerance | Stuck pig, bypass, ineffective cleaning |
| Pipeline configuration known | Review as-builts: bends, tees, reducers, valves | Pig lodged at fitting, damage, stuck |
| Receiver ready to accept pig | Confirm receiver empty, closure opens/closes | Pig damage, pressure surge, safety hazard |
| Flow rate stable | Verify steady flow, no transients expected | Pig stalls or races, uncontrolled speed |
| Pressure adequate for launch | ΔP launcher-to-receiver ≥ minimum (100+ psi typical) | Pig won't launch, stuck in launcher |
| All valves in correct position | Line valves open, bypasses closed, vents closed | Pig can't enter line, pressure loss, stuck |
| Pig detectors operational | Test magnetic/acoustic detectors | Unknown pig location, missed receiver prep |
| Communication plan | Radio/phone contact launcher ↔ receiver | Coordination failure, safety issues |
Pig Tracking Methods
- Pig passage indicators: Acoustic or magnetic detectors at key locations report pig passage time
- Calculated arrival: Use launch time + estimated travel time ± margin for receiver prep
- Pressure monitoring: Pressure rise at receiver indicates pig approaching
- Flow changes: Flow rate drop at receiver when pig arrives and blocks flow
- Smart pig telemetry: GPS-enabled pigs transmit real-time position (rare, expensive)
Common Pigging Problems
| Problem | Symptoms | Likely Causes | Solution |
|---|---|---|---|
| Pig stuck/stalled | Pig doesn't arrive, pressure rises | Insufficient ΔP, pipeline obstruction, undersized pig | Increase pressure, reverse flow, mechanical removal |
| Excessive speed | Early arrival, loud impact, surge | Too much ΔP, downhill run, oversized pig | Reduce flow, use pig with bypass, check for damage |
| Pig bypass | Slow arrival, low ΔP, incomplete cleaning | Worn pig seals, undersized pig | Replace pig, verify sizing |
| Pig lodged at tee | Stops at branch connection | Flow into branch diverts pig | Close branch valve before pigging |
| Pig damaged in run | Pig arrives damaged/deformed | Excessive speed, sharp edges, debris | Slow speed, inspect/clean line first |
| Large pressure surge | Pressure spike at receiver arrival | High speed + sudden stop, liquid line | Install bypass valve, reduce pig speed |
Pigging Frequency Guidelines
Recommended pigging intervals by application:
| Pipeline Type | Purpose | Typical Frequency |
|---|---|---|
| Dry gas transmission | Cleaning/inspection | Every 1-3 years (or per integrity plan) |
| Wet gas gathering | Liquid removal | Weekly to monthly |
| Crude oil | Wax/paraffin removal | Monthly to quarterly |
| Refined products (multi-product) | Batch separation | Every batch (daily to weekly) |
| NGL pipelines | Cleaning | Annually |
| Integrity management (ILI) | Corrosion/defect inspection | Every 5-7 years (or per regulation) |
Speed Control Techniques
Methods to maintain pig within target velocity range:
1. Flow Rate Adjustment:
Reduce line flow during pigging to slow pig velocity
V_pig ∝ Q_line
2. Differential Pressure Control:
Use pressure control valves to limit ΔP across line
Target 100-150 psi ΔP for controlled 3-5 ft/s speed
3. Pig Selection:
- High bypass pig for speed reduction (brush/fin design)
- Tight-sealing pig for maximum speed (molded urethane)
- Speed control pig with calibrated bypass orifices
4. Elevation Profile Management:
Launch pig at high point if possible
Avoid long downhill sections where pig accelerates
5. Batch/Slug Ahead of Pig:
In gas lines, inject liquid slug ahead of pig
Liquid weight slows pig, provides cushion at receiver
6. Bypass Valve at Receiver:
Open bypass before arrival to reduce ΔP and slow pig
Gradual closure allows controlled deceleration
Best practice: Monitor first pig run in new pipeline carefully. Use pig detectors to measure actual travel time and calculate velocity. Adjust flow rate or pressure differential for subsequent runs to achieve target speed.
Regulatory Requirements
Key standards and regulations for pigging operations:
- API RP 1171: Functional Integrity of Natural Gas Pipelines
- API Spec 5L: Line Pipe (pig-compatible pipeline specifications)
- ASME B31.4: Liquid Pipeline Systems (launcher/receiver design for liquids)
- ASME B31.8: Gas Transmission Pipelines (launcher/receiver design for gas)
- 49 CFR 192: Gas Pipeline Safety (ILI frequency and integrity management)
- 49 CFR 195: Liquid Pipeline Safety (ILI frequency and integrity management)
- NACE SP0102: Inline Inspection of Pipelines (inspection practices)
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