Heater Treater Sizing — Engineering Fundamentals

1. Emulsion physics

Crude oil emulsions form when produced water becomes finely dispersed in oil and is stabilized by interfacial films of asphaltenes, resins, paraffins, naphthenic acids, fine solids, and (sometimes) production-chemical residues. These films keep water droplets from coalescing into the larger droplets that gravity can settle. Without help, a tight emulsion will sit for days at ambient temperature and never break.

A heater treater attacks this stability with three tools, each of which can be designed independently:

1. Heat. Raising the temperature reduces oil viscosity (Beggs-Robinson predicts a ~3–5× drop for typical crudes going from 80°F to 150°F) and weakens the interfacial film. Higher T → faster Stokes settling and easier coalescence.
2. Chemical (demulsifier). Surfactant blends that displace the natural stabilizers and lower interfacial tension. Dosed continuously at 5–100 ppm in oil.
3. Electrostatic grid (optional). AC or DC fields polarize water droplets and force coalescence. Standard on heavy crudes (< 20° API) and where treating T can't go above ~180°F because of downstream RVP concerns.

2. Heat duty

The bulk of the duty is sensible heating of oil + water from inlet T to treating T. Convert each phase to mass flow:

where 350.5 lb/bbl = 5.615 ft³/bbl × 62.43 lb/ft³ (the density of water at 60°F). Sensible heat:

Add a heat-loss factor to account for shell radiation, foundation losses, and stack draft. 10% is typical for an insulated treater; 20% for a bare-shell unit in cold service.

If you are vaporizing a meaningful slip-stream of light ends (some heavy-treating units do this intentionally to reduce downstream RVP), add a latent term. For most treaters this is small and the sensible-only assumption is fine.

3. Firetube area & flux

The firetube is a U-tube or hairpin pressure-jacket immersed in the liquid pool. Combustion gases pass inside the tube; oil/water/emulsion is on the outside (wetted wall). Required area:

The design flux q″ is the critical knob:

q″ (Btu/hr·ft²)	When to use
6,000–8,000	Conservative — paraffinic or sour service, extended life
10,000	Industry default for clean sweet service
12,000–15,000	API 12L upper bound — coking risk rises sharply
> 15,000	Not allowed by API 12L — switch to forced-circulation

The wetted-wall temperature must stay below the coking point of the heaviest hydrocarbon in the stream. Coking deposits cut heat transfer and create local hot spots that fail the firetube.

4. Burner capacity & fuel gas

Burner heat input (firing rate) accounts for combustion efficiency:

Natural-draft burners run 65–75% efficient; forced-draft can reach 85%. Specify the burner at 1.25× the design duty to give operations turndown headroom for cold mornings, swing in inlet water cut, and gradual firetube fouling.

Fuel-gas consumption at the burner LHV:

Lease gas LHV is typically 950–1,000 Btu/scf; treated residue gas 1,000–1,050; casinghead gas can be 1,100+ if NGL-rich. Always confirm with a recent gas chromatograph.

5. Coalescing section

After heat (and chemical/electrostatic), water droplets must still settle out by gravity. Treaters use a smaller design droplet (100–250 µm vs. 500 µm for FWKO) because the emulsion-broken droplets are smaller and you need to capture them all to meet BS&W spec.

Settling velocity follows the same Stokes' law derivation as the FWKO:

But now μ_o is evaluated at the treating temperature — the whole point of the heat input is to drop μ_o so V_t goes up. By Beggs-Robinson a 25° API crude is ~113 cP at 80°F and ~8.8 cP at 150°F — about a 13× speed-up in settling.

For a horizontal treater the coalescing section sizing is the Arnold-Stewart relation:

This must be checked alongside the retention-time volume constraint (treaters use 20–90 min total retention, much longer than FWKO):

6. Vertical vs horizontal

	Vertical	Horizontal
Typical duty	< 2,000 BOPD	2,000 – 20,000 BOPD
Footprint	Small	Large skid
Firetube length	Limited by vessel height	Easy to extend
Settling check	Downflow velocity ≤ Vt	Arnold-Stewart d × L
Liquid surge	Poor	Good

For a vertical treater, vessel diameter is set so the downward oil velocity does not exceed the upward water droplet rise velocity (so droplets accumulate at the interface):

Coefficient 8.27e-5 = 4 × 5.615/86400 ÷ π, dimensionally exact for the Q→ft³/s conversion.

7. Shell thickness — ASME VIII Div 1 UG-27

Same UG-27 formula as the FWKO. The calculator uses the ASME VIII Div 1 outside-diameter form (below); the inside-radius form t = P·R/(S·E − 0.6·P) is the algebraic equivalent and gives the same wall. SA-516 Gr 70 is the universal plate; at treating temperatures above 400°F the allowable stress de-rates. Specify NACE MR0175 / ISO 15156 if H₂S partial pressure exceeds 0.05 psia.

For heater treaters, also account for:

• Internal lining per NACE SP0186 for heavy / corrosive crudes.
• Refractory at firetube ends to protect the shell from the flame end.
• Stack height 25–40 ft for natural-draft burners (per API RP 12N).

8. Worked example — 2,000 BOPD, 25° API

Validation case from the calculator (handoff Spec 2):

Input	Value
Oil rate Qo	2,000 BOPD
Water cut	25% (Qw = 667 BWPD)
Inlet T → treating T	80°F → 150°F (ΔT = 70°F)
Oil API gravity	25° (SGo = 0.904)
Cp oil / water	0.50 / 1.00 Btu/lb·°F
Heat-loss factor	10%
Fuel LHV	950 Btu/scf
Burner efficiency	75%
Firetube flux q″	10,000 Btu/hr·ft²

Step 1 — Mass flows

W_o = 2000 · 0.904 · 350.5 / 24 = 26,400 lb/hr

W_w = 667 · 1.07 · 350.5 / 24 = 10,400 lb/hr

Step 2 — Sensible duty

Q_s = (26,400 · 0.50 + 10,400 · 1.00) · 70 = (13,200 + 10,400) · 70 = 1.65 MMBtu/hr

Q_total = 1.65 · 1.10 = 1.82 MMBtu/hr ✓ matches spec's "≈ 1.8 MMBtu/hr"

Step 3 — Firetube area

A_ft = 1,820,000 / 10,000 = 182 ft² ✓ matches spec's "≈ 180 ft²"

Typical configuration: two 10"-OD U-tubes about 14 ft long each, or one 12" hairpin.

Step 4 — Burner & fuel

Q_burner = 1.82 / 0.75 = 2.43 MMBtu/hr → rated 1.25× = 3.04 MMBtu/hr burner

V̇_fuel = 2,430,000 / 950 = 2,560 scf/hr = ~61 Mscf/d (spec quotes ~50 Mscf/d at no-turndown basis — small difference from including 10% heat loss vs. excluding it).

Step 5 — Coalescing (horizontal at 150°F)

μ_o at 150°F via Beggs-Robinson with 25° API: y = 10^{(3.0324 − 0.02023·25)} = 10^2.527 = 336.3; X = 336.3 · 150^−1.163 = 336.3 · 0.002946 = 0.991; μ = 10^0.991 − 1 = 8.78 cP.

ΔSG = 1.07 − 0.904 = 0.166

V_t = 1.78e-6 · 200² · 0.166 / 8.78 = 1.35e-3 ft/s = 0.081 ft/min

Settling product: d × L = 1000 · 2000 · 8.78 / (200² · 0.166) = 17,560,000 / 6,640 = 2,645 inch-ft

Retention product (30 min): d² × L = 1.42 · 2,667 · 30 = 113,600 inch²-ft

Try 72": L_settle = 2,645/72 = 36.7 ft; L_reten = 113,600/5,184 = 21.9 ft → settling controls at 36.7 ft; L/D = 36.7/6 = 6.1 (too slender, > 5). Try 84": L_settle = 2,645/84 = 31.5 ft, L_reten = 16.1 → L = 31.5 ft (rounds to 32 ft), L/D = 32/7 = 4.6. Pick 84" ID × 32 ft S/S (settling-governed), matching the calculator.

(A horizontal vessel is the right choice here: the vertical (V-down) option is diameter-limited because the downflow-velocity criterion d = √(8.27×10⁻⁵·Q_o/V_t) drives D to ≈ 11 ft (133") at this rate and viscosity — impractical — so the heat input plus a horizontal coalescing section is the economic design.)

9. References

• API Spec 12L — Specification for Vertical and Horizontal Emulsion Treaters.
• API Spec 12K — Specification for Indirect Type Oil Field Heaters.
• API RP 12N — Recommended Practice for Operation, Maintenance, and Testing of Firebox Flame Arrestors.
• Stewart, M. & Arnold, K. (2008). Surface Production Operations Vol. 1, 3rd ed., Ch. 7 — Heaters and Heat Exchangers.
• Manning, F. S. & Thompson, R. E. (1995). Oilfield Processing of Petroleum Vol. 2, Ch. 4 — Emulsion Treating.
• GPSA Engineering Data Book, Section 19 — Fired Equipment.
• ASME BPVC Section VIII Div 1 — Pressure vessel design.
• NACE SP0186 — Application of Internal Plastic Coatings for Oilfield Production Equipment.
• Beggs, H. D. & Robinson, J. R. (1975). "Estimating the Viscosity of Crude Oil Systems." JPT, Sept 1975.