production · multiphase flow
Pipeline Pressure Drop (Multiphase)
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Inputs
STB/d
Mscf/d
ft³/scf
in
in
lb/ft³
lb/ft³
cp
cp
ft
Description
Computes the total multiphase (gas-liquid) pressure drop along a horizontal or near-horizontal pipeline segment, using the Beggs and Brill (1973) correlation at θ=0° — the same correlation Multiphase Gradient (Beggs-Brill) implements for vertical wells, simplified for horizontal flow: the elevation term vanishes entirely and the inclination correction is unconditionally 1 for every flow regime, not just distributed. Notably has one fewer input than the vertical calculator: gas-liquid surface tension only ever feeds the inclination-correction path (via the liquid velocity number NLV), which is never invoked at θ=0° — asking for a value with zero effect on the result would be misleading, so it's simply not an input here. Evaluates the gradient at one representative point and multiplies by pipe length for a total pressure drop — the same single-point-times-length approach Flowing Bottomhole Pressure (Tubing Traverse) already uses for single-phase flow.
Variables
| Symbol | Unit | Description |
|---|---|---|
| dP/dz | psi/ft | Pressure Gradient |
| ΔP | psi | Total Pressure Drop |
| qL | STB/d | Liquid (oil, water, or total liquid) production rate at surface (stock-tank) conditions. |
| qG | Mscf/d | Gas production rate measured at standard surface conditions. |
| Bg | ft³/scf | Gas formation volume factor at the local flowing pressure/temperature — converts the standard-condition gas rate to its actual (in-situ) volume, the same correction Gas Velocity requires. Run the Gas FVF (Bg) calculator first and carry its result in here (see relatedCalcs). |
| d | in | Pipeline internal diameter at the representative flowing conditions being evaluated. |
| ε | in | Absolute roughness of the pipe's internal surface. 0.0018 in (0.0457 mm) is the standard commercial steel value, matching Multiphase Gradient (Beggs-Brill)'s own default. |
| ρL | lb/ft³ | Density of the liquid phase at local flowing conditions. |
| ρG | lb/ft³ | Density of the gas phase at local flowing conditions. No dedicated gas-density calculator exists yet on this platform (same gap as Multiphase Gradient (Beggs-Brill)'s own limitations); estimate from the real gas law using a gas gravity/molecular weight and a Z-factor from the Gas Z-Factor calculator. |
| μL | cp | Viscosity of the liquid phase at local flowing conditions — run the Oil Viscosity calculator first and carry its result in here (see relatedCalcs). |
| μG | cp | Viscosity of the gas phase at local flowing conditions. No dedicated gas-viscosity calculator exists yet on this platform. |
| L | ft | Length of pipeline over which the total pressure drop is evaluated, using the gradient computed at the representative flowing conditions entered above — the same single-point-times-length approach Flowing Bottomhole Pressure (Tubing Traverse) already uses. |
Assumptions
- Horizontal or near-horizontal pipe (θ≈0°) — a meaningfully inclined pipeline needs Multiphase Gradient (Beggs-Brill)'s own vertical treatment, or the correlation's general inclined-pipe form, which this platform does not provide
- Flowing conditions (rates, densities, viscosities, surface tension) are representative of the full pipeline length — steady-state, one set of local conditions
- The fluid system is genuinely two-phase (gas + liquid) only, same as Multiphase Gradient (Beggs-Brill)'s own assumption
Limitations
- Evaluated at one representative point along the pipeline and multiplied by length — does not account for gas expansion or other property changes as pressure drops along a long line; for a line with pressure drop that's large relative to absolute pressure, break it into shorter segments and re-evaluate representative properties at each
- Restricted to horizontal (θ=0°) flow only — a meaningfully inclined gathering line needs the general inclined-pipe form of the correlation, which this platform does not implement (same restriction Multiphase Gradient (Beggs-Brill) discloses for its own vertical-only scope, mirrored here for the opposite angle)
- The flow-regime classification is known to be sensitive near the L1-L4 boundary curves — the same documented characteristic already disclosed by Multiphase Gradient (Beggs-Brill)
- No dedicated gas-density or gas-viscosity calculator exists yet on this platform — both are direct numeric entries here with representative-range guidance, the same gap Multiphase Gradient (Beggs-Brill) already flags
- An empirical correlation fit to laboratory air-water/air-kerosene data in 1-1.5 in. pipe, same as Multiphase Gradient (Beggs-Brill) — accuracy degrades outside the conditions it was originally fit to (very large pipe, very high-viscosity liquid, etc.)
Use Cases
- → Surface gathering line sizing: Estimate the total pressure drop across a horizontal or near-horizontal multiphase gathering line from a wellsite to a central facility.
- → Flow-regime diagnosis for a pipeline: Determine which flow regime a pipeline's actual rates and diameter fall into, and how close the operating point sits to a regime boundary — the same diagnostic Multiphase Gradient (Beggs-Brill) offers for a vertical well.
Related Calculations
Region Notes
Global
For a gathering system with a meaningful elevation change (not truly flat terrain), Multiphase Gradient (Beggs-Brill)'s own vertical treatment — or a segment-by-segment combination of both calculators — better represents the actual pressure behavior than treating the whole line as purely horizontal.
References
Primary source
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