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Natural Gas Pipeline Throughput AGA 10 / Weymouth Simulator

Estimate the capacity of high-pressure long-distance natural-gas trunk lines. As you adjust inside diameter, length, inlet/outlet pressures, gas gravity, temperature and roughness, the flow rate (Weymouth / Panhandle A / Panhandle B / AGA 10), in-pipe velocity, pressure gradient, erosional limit and Reynolds number update in real time.

Parameters
Inside diameter D
inch
DN500 ≈ 20", DN1000 ≈ 40"
Pipe length L
km
Spacing between compressor stations
Inlet pressure P₁
MPa
Outlet pressure P₂
MPa
Gas specific gravity G
air = 1.0, pure methane ≈ 0.554
Gas temperature T
K
Flow equation
Pick by distance, diameter and roughness
Pipe roughness k
mm
New steel 0.04-0.07, internally coated 0.005-0.01
Results
—
Flow (MMSCFD)
—
Flow (m³/h, std)
—
Pipe velocity (m/s)
—
Pressure gradient (kPa/km)
—
Erosional limit (m/s)
—
Reynolds number
—
Pipeline cross-section & gas flow animation

Particles inside the blue pipe represent gas molecules flowing from high pressure (left, red) to low pressure (right, blue). End boxes are compressor stations; arrow length scales with in-pipe velocity.

Flow vs inlet pressure P₁
Equation comparison (same conditions, MMSCFD)
Theory & Key Formulas

$$Q = 3.23 \cdot \frac{T_b}{P_b}\sqrt{\frac{P_1^{2} - P_2^{2}}{G \cdot T \cdot L}} \cdot D^{8/3}$$

Weymouth equation (English units, MMSCFD). P₁/P₂ are pressures in psi, L in mi, D in inch, G is gas gravity, T in °R; base conditions T_b = 519.67 °R, P_b = 14.73 psia.

$$F_{t} = 4\,\log_{10}\!\left(\frac{3.7\,D}{k}\right), \qquad Q \propto F_{t}\cdot D^{2.5}\sqrt{\Delta(P^2)/G\,T\,L}$$

AGA 10 fully turbulent — Nikuradse's transmission factor F_t derived from roughness k. Smoother pipe gives a larger F_t and therefore higher throughput.

$$v_e = \frac{C}{\sqrt{\rho_g}}, \qquad Re = \frac{\rho_g\,v\,D}{\mu_g}$$

API RP 14E erosional velocity v_e (C = 100 in SI, ρ_g = actual gas density in kg/m³) and Reynolds number Re. Dry gas mains are usually in the Re = 10⁶-10⁷ range.

Natural Gas Pipeline Throughput — AGA 10, Weymouth, Panhandle

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Aren't gas pipelines just "thick steel pipes"? Why do we need so many different flow equations for them?
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They look like steel pipes, but inside it's more complicated. Gas is a compressible fluid, so when pressure drops from, say, 7 MPa to 6 MPa, the volume expands and the in-pipe velocity changes along the line even at constant mass flow. That's why we don't use plain Darcy-Weisbach. Instead we use a family of special equations — Weymouth (1912), Panhandle A (1956), Panhandle B (1962) and AGA 10 — that work in terms of P₁²-P₂².
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Got it. So when do I pick which one? The "Flow equation" selector on the left changes the number quite a lot.
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Good question. Weymouth pins the friction factor to f ∝ 1/D^(1/3) and works for short-to-medium trunks up to about 200 mi and 20-inch diameters. Panhandle A fits long, large-diameter lines at moderate Reynolds (Re ≤ ~5×10⁶), and Panhandle B handles high-Re mains (Re ≥ ~10⁷, 24-inch and bigger). AGA 10 computes the transmission factor F_t from pipe roughness k, which is great for operational tuning where you want to match measured header pressures. Look at the bar chart below to see all four side by side for the same conditions.
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You also have an "erosional velocity" output. What goes wrong if the flow is too fast?
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Gas always carries some liquid droplets (condensed heavy ends, water) and sometimes sand. At high velocity those particles hammer the inside of elbows and tees and locally thin the wall — that's erosion-corrosion. API RP 14E gives v_e = 100/√ρ in SI: roughly 18-25 m/s for dry clean gas and 10-15 m/s for wet or sandy gas. This tool computes v_e from the actual in-pipe density and compares to the real velocity. Exceeding it is a top failure mode for leaks, which matters more than ever now that methane emissions are heavily regulated.
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You also mention "compressor stations every 100-150 km". If I push L to 2000 km the flow collapses. How is this handled in practice?
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Exactly — at constant P₁²-P₂² the flow roughly scales as L^(-0.5), so doubling the length cuts throughput by a factor of √2. Real long-haul mains are therefore broken into segments of 100-150 km, with a compressor station between each segment to restore P₁. China's West-East Pipeline runs 18,000 km in 4 parallel lines with dozens of stations; Power of Siberia (3,000 km) and Nord Stream (1,224 km, twin subsea) follow the same idea. Try L = 100-150 km, P₁ = 10 MPa, P₂ = 7 MPa in this tool to feel the per-segment capacity.
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Last one: does designing gas pipelines still make sense in a decarbonising world?
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Natural gas is still a transition fuel through the 2050s, and there is a huge push to repurpose existing lines for hydrogen and ammonia. Hydrogen is much lighter (G ≈ 0.07), so the small molecules raise leakage and embrittlement risks, and on a mass basis you only get about a third of the energy throughput of natural gas in the same pipe. Plug G = 0.07 into this tool to feel that the volumetric MMSCFD goes up, but mass-based energy capacity drops sharply. Flow modelling is essential not just for new build but for retrofit feasibility too.

Frequently Asked Questions

Weymouth (1912) assumes a friction factor of the form f ∝ 1/D^(1/3) and is the classical choice for short-to-medium pipelines (up to about 200 mi) with small-to-medium diameters. Panhandle A (1956) fits long-distance large-diameter lines at moderate Reynolds numbers (Re ≤ ~5×10⁶), while Panhandle B (1962) is for very high Reynolds (Re ≥ ~10⁷) and 24-inch-plus mains. AGA 10 builds the transmission factor F_t from Nikuradse's fully-turbulent law and therefore reflects pipe roughness directly — it gives the best precision for operational studies and system simulation.
API RP 14E gives a screening limit v_e = C/√ρ (SI: C=100, ρ in kg/m³) to prevent erosion-corrosion in pipes carrying liquid droplets or sand. Dry clean gas typically allows 18-25 m/s while wet or sandy gas is limited to 10-15 m/s. This tool uses the actual in-pipe gas density to compute v_e and flags an NG verdict when the real velocity exceeds it. Going above v_e accelerates wall thinning at elbows and fittings, which in turn drives coating breakdown and methane leakage.
With inlet 7.5 MPa, outlet 6.0 MPa, gas gravity 0.6 and 20°C, the Weymouth equation returns about 330 MMSCFD (~9.35 million m³/d, ~390,000 m³/h). In-pipe velocity is around 5-6 m/s, Reynolds number is on the order of 10⁷ and the pressure gradient is 7.5 kPa/km. These are typical numbers for a medium-sized natural-gas trunk line; compressor stations are normally placed every 100-150 km to restore inlet pressure.
Methane (CH₄), the main component of natural gas, has a 100-year global-warming potential about 28-34 times that of CO₂ and over 80 times on a 20-year horizon. Long pipelines leak continuously through valve seals, compressor vents, connectors and pig launchers, contributing a large share of anthropogenic methane. After events such as the 2015 Aliso Canyon storage release (~100,000 t CH₄), regulators have tightened LDAR (leak detection and repair) rules and quantification with OGI cameras and satellites such as GHGSat or MethaneSAT. Design-side levers include optimal compressor spacing, recovery compressors and vent-gas capture.

Real-world applications

Continental trunk lines: The world's natural-gas pipeline network totals roughly 2 million km. Iconic examples include Trans Alaska (1,287 km), Nord Stream (1,224 km Baltic twin subsea), Power of Siberia (3,000 km), TurkStream (930 km Black Sea), Yamal-Europe (4,107 km) and China's West-East Pipeline (4 parallel lines, 18,000 km combined). These run 20-56 inch at 5-10 MPa with compressor stations every 100-150 km, sized with exactly the equations used in this tool.

Compressor-station spacing optimisation: Compressor brake power scales with the pressure ratio P₁/P₂ and mass flow. Stretching the spacing from 100 to 150 km reduces the number of stations but pushes the per-segment inlet pressure up, which feeds back into MAOP (maximum allowable operating pressure) and wall thickness (API 5L X70 etc.). Practitioners combine Weymouth/AGA hand calculations with full-system simulators such as AspenTech HYSYS, Pipephase or Synergi to find the optimum capex/opex trade-off.

Hydrogen / ammonia blending feasibility: European and US operators are running trials to blend 5-20% H₂ into existing methane pipelines — UK HyDeploy and Germany's GET H2 are well-known examples. Because H₂ has G ≈ 0.07, plugging that into the tool roughly doubles MMSCFD for the same pipe and pressure, but the mass-based energy throughput drops to about a third. Material embrittlement and leak risk further constrain operating pressure, so retrofit feasibility must look at flow and metallurgy together.

Operational simulation and LDAR compliance: Coupling OpenFOAM or AspenTech HYSYS with NIST REFPROP property data lets engineers solve transients (line-pack swings on compressor trip, blowdown wave propagation). For leak quantification, OGI cameras, satellite observations (GHGSat, MethaneSAT) and airborne LDAR identify methane hotspots; comparing measured emissions to the theoretical throughput from a tool like this is a growing research approach to estimate fugitive rates.

Common misconceptions & gotchas

The biggest pitfall is mixing Weymouth and Panhandle coefficients from different textbooks. Different references use different units (SCFD / MMSCFD / m³/h, psi / kPa / bar, °R / K, mi / km), so the leading coefficients (871, 433.5, 3.23, 38.774, etc.) change with them. This tool internally fixes everything to "P: psi, L: mi, T: °R, D: inch, Q: SCFD" and converts SI outputs (m³/h, m/s) afterwards. If you cross-check by hand, pin one unit system and verify the coefficient before comparing.

Second, do not trust a Z = 1 (or Z = 0.9 fixed) shortcut for real operations. This tool uses an approximate Z for teaching purposes, but in field conditions Z ≈ 0.85-0.90 at 7 MPa / 20°C and varies further at low temperatures (winter desert or Arctic service), shifting flow by 5-10%. Production designs use BWRS or GERG-2008 EOS with REFPROP/HYSYS property packages and iterate Z(P,T). Treat this calculator as a first-pass sizing aid, not a procurement basis.

Third, "velocity is below v_e, so we are safe" is overstated. The API RP 14E limit v_e = 100/√ρ is conservative for continuous dry gas with a small droplet fraction. In wet-gas slugging or sandy gas from un-desanded wells, the local velocity at elbow insides can be 2-3× the bulk value and erosion-corrosion accelerates by orders of magnitude. Keep R/D ≥ 3 at elbows, install sand filters and slug catchers where appropriate, and combine the v_e check with continuous methane-leak monitoring to build defence in depth.

How to Use

  1. Enter pipe diameter (dNum) in inches; typical trunk lines range 16–42 inches (dRange)
  2. Specify pipe length (lNum) in miles; long-distance lines typically 50–500 miles (lRange)
  3. Input upstream pressure (p1Num) and downstream pressure (p2Num) in psig; common operating range 400–1200 psig (p1Range, p2Range)
  4. The simulator calculates flow rate using the AGA 10 Weymouth equation, accounting for gas gravity, temperature, and compressibility
  5. Review output: flow in MMSCFD and m³/h (standard conditions), pipe velocity, pressure gradient, Reynolds number, and erosional velocity limit

Worked Example

A 24-inch diameter steel trunk line, 180 miles long, operates with upstream pressure 850 psig and downstream pressure 600 psig. Gas gravity = 0.65, temperature = 60°F. AGA 10 Weymouth calculation yields approximately 285 MMSCFD (47,500 m³/h std), pipe velocity 18.2 m/s, pressure gradient 1.39 kPa/km, and Reynolds number 2,840,000. The erosional velocity limit for dry gas (typically 60 m/s for 24-inch line) is not exceeded, confirming safe operation without liquid dropout risk.

Practical Notes

  1. Erosional velocity limit (~100 × sqrt(rho_gas)) prevents liquid carryover and pipe wall thinning; typical limits are 40–70 m/s for large-diameter lines
  2. Pressure gradient increases nonlinearly with flow; doubling throughput increases gradient 3–4 times due to friction factor dependency
  3. Temperature changes significantly affect gas compressibility factor (Z); winter operation at 32°F reduces capacity ~8–12% versus summer baseline
  4. For wet-gas pipelines, subtract 2–5 psig/100 miles for hydrate-inhibitor circulation pressure drops
  5. AGA 10 assumes fully rough commercial steel; corroded pipes or sand deposition increase friction factor 15–30%, reducing capacity