Crude Oil Distillation: Atmospheric Distillation Unit Design, Column Internals, and Product Cut Point Optimization

Crude Oil Distillation: Atmospheric Distillation Unit Design, Column Internals, and Product Cut Point Optimization

The atmospheric distillation unit (ADU), also called the crude distillation unit (CDU), is the entry point for every barrel of crude oil processed in a refinery. Every subsequent refinery process catalytic cracking, hydrocracking, reforming, hydrotreating, alkylation works on fractions separated by the CDU. Getting the CDU design right - selecting the correct number of trays, specifying the right reflux ratios, positioning the draw-off trays correctly for each product fraction, and matching the furnace duty and column diameter to the crude feed composition and throughput determines the product slate flexibility, energy efficiency, and economic performance of the entire refinery. A CDU that is correctly designed and operated can separate a 100,000 barrel per day crude charge into five or six distinct fractions, each with a defined boiling range and target product specification, while consuming approximately 20-30 MJ per barrel of crude processed in the fired heater. A poorly designed or operated CDU fails to achieve the required separation between adjacent fractions, either contaminating lighter fractions with heavy components that increase their flash point and smoke point beyond specification, or losing light components into heavier fractions where they reduce flash point safety margins and are not captured as high-value gasoline blendstock. This guide covers the quantitative engineering of crude distillation: the vapor-liquid equilibrium principles that govern the separation, the design equations for determining column diameter and tray count, the fired heater duty calculation that sets the energy consumption of the unit, and the product cut point specification that defines the commercial value of the distillation operation.

1. Crude Oil Characterization and TBP Distillation

1.1 True Boiling Point Curve and Fraction Yields

The True Boiling Point (TBP) distillation curve is the fundamental characterization tool for any crude oil entering a refinery. It is produced by laboratory batch distillation under standardized conditions (ASTM D-2892 at atmospheric pressure with a 15:5 reflux ratio) and provides the cumulative volume percentage of crude that has distilled as a function of boiling temperature. The TBP curve is the basis for calculating the theoretical yield of each refinery product fraction from a given crude oil:

TBP cut point definition and fraction yields:

Standard refinery fractions and their typical atmospheric TBP cut ranges:

Overhead (light ends, C1-C4): TBP = below 35°C (dissolved gases + LPG fraction)
Light Straight Run Naphtha (LSRN): TBP = 35-90°C → gasoline blending component
Heavy Straight Run Naphtha (HSRN): TBP = 90-180°C → reformer feed
Kerosene/Jet Fuel: TBP = 140-250°C → aviation fuel, domestic kerosene
Light Gas Oil (LGO/Diesel): TBP = 220-370°C → diesel fuel, heating oil
Heavy Gas Oil (HGO/HVGO): TBP = 350-565°C → FCC feed, hydrocracker feed
Atmospheric Residue (Resid/AR): TBP = above 565°C → vacuum unit feed, asphalt

Fraction yield calculation from TBP curve for Arabian Light crude (typical):
API gravity: 33.4° (0.858 SG)
Sulfur content: 1.8 wt%

Reading from TBP curve (cumulative volume percent at cut temperatures):
At 35°C: 1.5% distilled → LSRN = 1.5%
At 90°C: 7.0% distilled → LSRN = 7.0 - 1.5 = 5.5% vol
At 180°C: 19.5% distilled → HSRN = 19.5 - 7.0 = 12.5% vol
At 250°C: 29.5% distilled → Kerosene = 29.5 - 19.5 = 10.0% vol
At 370°C: 47.5% distilled → LGO = 47.5 - 29.5 = 18.0% vol
At 565°C: 72.5% distilled → HGO = 72.5 - 47.5 = 25.0% vol
Above 565°C: residue = 100 - 72.5 = 27.5% vol

Product yields for 100,000 BPSD crude feed:
Gases + LSRN: 7.0% → 7,000 BPSD
HSRN: 12.5% → 12,500 BPSD
Kerosene: 10.0% → 10,000 BPSD
LGO: 18.0% → 18,000 BPSD
HGO: 25.0% → 25,000 BPSD
Atmospheric Residue: 27.5% → 27,500 BPSD**

**Revenue calculation at 2024 product prices:
Naphtha ($85/bbl): (7,000 + 12,500) x $85 = $1,657,500/day
Kerosene ($96/bbl): 10,000 x $96 = $960,000/day
Diesel ($98/bbl): 18,000 x $98 = $1,764,000/day
HGO ($88/bbl): 25,000 x $88 = $2,200,000/day
AR ($72/bbl): 27,500 x $72 = $1,980,000/day
Total product revenue: $8,561,500/day from 100,000 BPSD crude**

**Crude oil cost at $75/bbl: 100,000 x $75 = $7,500,000/day
Gross refinery margin (products - crude): $8,561,500 - $7,500,000 = $1,061,500/day = $10.62/bbl gross margin

2. ADU Column Design: Material and Energy Balances

2.1 Column Operating Conditions and Flash Zone Design

The crude oil is preheated in a series of heat exchangers (the crude preheat train) and then in the crude fired heater before entering the flash zone at the bottom of the distillation column. The flash zone is where the partially vaporized crude feed separates into vapor (which rises up the column for fractionation) and liquid (which flows down to become atmospheric residue). The flash zone temperature and pressure determine the vaporization fraction and therefore the maximum yield achievable from the atmospheric column:

Flash zone conditions and vaporization rate:

Column operating pressure: 1.4 bar absolute (above atmospheric to allow pressure drop through column)
Flash zone temperature: 365°C (typical for Arabian Light crude - limited by thermal cracking onset at ~370°C)
Overflash requirement: 2-3 vol% of feed (overflash = additional vaporization to ensure clean separation between HGO and AR)

Material balance - single component approach (simplified Rachford-Rice method):
At flash zone conditions, the fraction vaporized (V/F) is determined by equilibrium.
For crude oil, use the TBP curve approach:

At 365°C and 1.4 bar: all components with true boiling point < 365°C (corrected for pressure) are vaporized
TBP correction for pressure (1.4 bar vs 1.013 bar): temperature correction ≈ +8°C effective
Equivalent atmospheric cut temperature = 365 - 8 = 357°C effective cut on TBP curve

From TBP curve: fraction vaporized at 357°C cut ≈ 45.5% vol
Add 2.5% overflash: total vaporization = 48.0% vol

Vapor phase rises from flash zone to provide feed to all column sections above:
- HGO draw-off section (between 350-365°C cut zone): takes off HGO fraction
- Diesel section: takes off LGO fraction
- Kerosene section: takes off kerosene fraction
- Naphtha section: takes off HSRN fraction
- Overhead: LSRN + gases + steam + reflux

Liquid from flash zone = AR = 100 - 48 = 52% vol of feed entering vacuum unit

Fired heater duty calculation:
Crude oil specific heat (temperature-dependent, weighted average 20-365°C): Cp_avg ≈ 2.4 kJ/kg/°C
Heat of vaporization of crude (latent heat at flash zone): H_vap ≈ 260 kJ/kg (fraction vaporized)

Crude flow rate: 100,000 BPSD x 0.159 m3/bbl x 858 kg/m3 / 86,400 s/day
= 100,000 x 0.159 x 858 / 86,400 = 13,642,200/86,400 = 157.9 kg/s crude flow rate**

**Preheat temperature (from crude preheat train with heat integration): T_preheat = 240°C
Temperature rise in heater: delta_T = 365 - 240 = 125°C

Sensible heat duty: Q_sensible = m_dot x Cp x delta_T = 157.9 x 2.4 x 125 = 47,370 kW**

**Vaporization latent heat duty: Q_latent = m_dot x fraction_vaporized x H_vap
= 157.9 x 0.48 x 260 = 19,704 kW**

**Total heater duty: Q_heater = 47,370 + 19,704 = 67,074 kW = 67.1 MW fired duty**

At heater thermal efficiency 88%:
Fuel gas consumed: Q_fuel = 67,074/0.88 = 76,220 kW = 76.2 MW
Fuel gas flow: 76,220/50,000 kJ/kg (NHV methane) = 1.524 kg/s = 5,488 kg/hr fuel gas**

**Specific energy: 67.1 MW / (157.9 kg/s x 0.159 m3/0.858 x 6.29 bbl) ≈ 25.6 MJ/bbl crude processed**
(Industry benchmark: 20-35 MJ/bbl for well-optimized CDU → our design is within acceptable range)

2.2 Column Diameter Calculation

The column diameter is set by the vapor flow rate in the most heavily loaded section of the column - typically the flash zone or the section just above the flash zone where all vaporized crude components are passing up through the trays before being drawn off. The diameter must be large enough that the vapor velocity does not exceed the maximum allowable velocity that would cause flooding (entrainment of liquid droplets into the vapor phase):

Column diameter calculation (Fair's method for sieve trays):

The maximum vapor velocity in the column before flooding:
u_flood = C_sb x sqrt((rho_L - rho_V)/rho_V)

Where:
C_sb = Souders-Brown coefficient (m/s), function of tray spacing and system factors
rho_L = liquid density (kg/m3)
rho_V = vapor density (kg/m3)

Flash zone vapor conditions (at column base, maximum vapor flow):
Vapor temperature: 365°C, Pressure: 1.4 bar
Vapor density at flash zone (mixed crude vapors, MW_avg ≈ 130 for C10-C22 mixture):
rho_V = P x MW / (R x T) = 140,000 x 130 / (8,314 x 638) = 18,200,000/5,304,332 = 3.43 kg/m3**

**Liquid density at flash zone: rho_L ≈ 680 kg/m3 (hot crude oil at 365°C)

Tray spacing: 600 mm (standard for large column)
C_sb for 600 mm tray spacing (from Fair correlation chart): C_sb ≈ 0.065 m/s
System factor F_s = 0.85 (for foaming crude oil service)
C_sb_corrected = 0.065 x 0.85 = 0.05525 m/s

u_flood = 0.05525 x sqrt((680 - 3.43)/3.43) = 0.05525 x sqrt(197.3) = 0.05525 x 14.05 = 0.776 m/s flooding velocity**

**Design vapor velocity = 80% of flooding velocity:
u_design = 0.80 x 0.776 = 0.621 m/s design velocity**

**Vapor volumetric flow rate at flash zone:
Vapor mass flow = m_dot_crude x fraction_vaporized = 157.9 x 0.48 = 75.8 kg/s
Vapor volumetric flow = 75.8/3.43 = 22.1 m3/s**

**Required column cross-sectional area:
A_column = Q_vapor/(u_design x (1 - downcomer_fraction))
Downcomer fraction: 0.12 (12% of tray area allocated to liquid downcomers)
A_column = 22.1/(0.621 x 0.88) = 22.1/0.547 = 40.4 m2**

**Column diameter:
D = sqrt(4 x A/pi) = sqrt(4 x 40.4/pi) = sqrt(51.44) = 7.17 m → round up to D = 7.5 m standard column diameter**

**This 7.5 m diameter is typical for a 100,000 BPSD crude column - industrial ADU columns are typically 5-8 m diameter for this capacity range.

3. Column Internals: Trays and Packing

3.1 Tray Types and Performance Parameters

The fractionation trays in the ADU provide the vapor-liquid contacting stages required to achieve the specified separation between adjacent product fractions. Three principal tray types are used in crude distillation: sieve trays, valve trays, and bubble cap trays. Each has different vapor-liquid contacting efficiency, turndown ratio, and pressure drop characteristics:

Tray Type	Operating Principle	Tray Efficiency	Turndown Ratio	Pressure Drop (per tray)	Petroleum Application
Sieve tray	Simple perforated deck. Vapor rises through holes creating bubbles that contact the liquid flowing across the tray. Low cost, easy to clean, high capacity.	60-80%	2:1 to 3:1	6-10 mbar per tray	Standard crude column fractionation sections. Low cost where fouling and coke deposition are not issues.
Valve tray	Floating disc valves (MVG, MINI-V, or Koch Flexitray) that open wider at high vapor rates and close partially at low rates, maintaining vapor velocity through the valve regardless of load variation.	70-90%	4:1 to 5:1	5-12 mbar per tray	Preferred for CDU and vacuum columns. Good turndown for crude rate flexibility. Industry standard for most petroleum distillation.
Bubble cap tray	Stationary caps with slots sit above risers. Vapor must travel up the riser, under the cap, and through slots into liquid pool. Cannot weep even at zero vapor flow.	65-80%	Unlimited (weep-proof)	25-80 mbar per tray (very high)	Columns with very high liquid-to-vapor ratios. Where weeping would cause contamination (absolute non-weep requirement). High-purity separations. Otherwise avoid due to high pressure drop.

3.2 Theoretical Tray Count and Actual Tray Requirement

Tray count estimation using the Fenske-Underwood-Gilliland method:

For a crude column, each product fraction is bounded by a "light key" component (the lightest component that should remain primarily in the bottoms product) and a "heavy key" component (the heaviest component that should appear primarily in the distillate).

For the kerosene-diesel separation section of the CDU:
Light key: The component at the kerosene/diesel cut point (approximately TBP 240°C boiling component)
Heavy key: The component at the diesel lower cut point (approximately TBP 250°C component)
Required separation: 95% of the light key component in the kerosene draw-off, 95% of the heavy key in the diesel draw-off (typical 95/95 specification)

Relative volatility between adjacent cut point components:
For adjacent TBP components in crude oil (narrow boiling range separation):
Relative volatility alpha ≈ P_vap(LK)/P_vap(HK)
At separation conditions (T ≈ 200°C, P = 1.2 bar):
For a 10°C boiling range difference (240 vs 250°C TBP components):
Using Clausius-Clapeyron approximation: ln(P_vap ratio) = delta_Hv/R x (1/T_HK - 1/T_LK)
= 35,000/8.314 x (1/523 - 1/513) = 4,210 x (0.001912 - 0.001949) = 4,210 x (-0.0000370) = -0.0156
P_vap ratio = e^0.0156 (LK is more volatile) = 1.016 → alpha = 1.016**

**This very low relative volatility (alpha = 1.016, barely greater than 1.0) explains why crude fractionation is difficult: adjacent cut point components have almost identical vapor pressures, requiring many theoretical stages to achieve clean separation.

Minimum theoretical stages (Fenske equation at total reflux):
N_min = ln((x_LK/x_HK)_D x (x_HK/x_LK)_B) / ln(alpha)
= ln((0.95/0.05) x (0.95/0.05)) / ln(1.016)
= ln(19 x 19) / ln(1.016)
= ln(361) / 0.01587
= 5.888/0.01587 = 371 theoretical stages minimum at total reflux!**

**This result (371 theoretical stages) seems enormous - but it correctly reflects the extreme difficulty of separating crude oil fractions with nearly identical vapor pressures. In practice, crude columns operate at high reflux ratios using side strippers (which function as additional equilibrium stages below the draw-off points) and carefully controlled heat input from circulating reflux pumparounds to achieve the specified separations with 40-60 actual trays and 3-4 side draw sections.

Practical CDU tray count:
Industrial CDU columns achieve adequate separation through a combination of:
1. Column trays: typically 35-50 valve trays
2. Overhead reflux: providing concentration driving force
3. Side strippers: 4-8 trays each below each side draw-off (kerosene, diesel, HGO) to strip light components from side streams
4. Pumparound cooling: removing heat at intermediate levels to improve separation driving force

Typical CDU tray count breakdown:
Above HGO draw to diesel draw: 5-8 trays
Above diesel draw to kerosene draw: 6-10 trays
Above kerosene draw to HSRN draw: 6-10 trays
Above HSRN draw to overhead: 8-12 trays
Total: 25-40 trays + side strippers + flash zone section = 35-50 total trays

4. Product Specification and Cut Point Optimization

4.1 Product Quality Specifications and Key Property Tests

Critical product property specifications and how they relate to cut points:

Kerosene/Jet Fuel (DEF STAN 91-091 / ASTM D1655 Jet A):
Flash point minimum: 38°C (aviation minimum safety requirement)
Initial boiling point minimum: 145°C (ensures light ends removed)
Final boiling point maximum: 300°C (ensures heavy ends excluded)
Freezing point maximum: -47°C (Jet A) or -40°C (Jet A-1)
Smoke point minimum: 25 mm (no aromatics contamination)

Cut point control for flash point: Flash point = f(IBP of kerosene). Lower IBP → lower flash point.
If flash point is too low: Raise the upper cut of HSRN (lower the kerosene IBP temperature in column → increase HSRN draw temperature → flash point increases as light ends leave with naphtha)

Flash point calculation (Butler correlation for petroleum fractions):
T_flash (°F) = 0.75 x T_10% (°F) - 135
Where T_10% = ASTM D86 10% distillation temperature of the kerosene fraction

Target flash point = 38°C = 100°F
Required T_10%: 100 = 0.75 x T_10% - 135 → T_10% = 235/0.75 = 313°F = 156°C

If measured T_10% of kerosene is 148°C: flash point = 0.75 x 298 - 135 = 223.5 - 135 = 88.5°F = 31.4°C → BELOW 38°C minimum → specification FAIL

Action: Raise kerosene draw-off tray by 2 trays (reduce HSRN/kerosene cut temperature by ~5°C) to reduce light ends in kerosene → T_10% increases → flash point increases

Diesel fuel (EN 590 / ASTM D975):
Cetane number minimum: 51 (EN 590) → related to paraffin content
Flash point minimum: 55°C
Cloud point maximum: depends on seasonal specification
95% distillation point: maximum 360°C (T95 < 360°C for EN 590 on-road diesel)

T95 < 360°C specification relates directly to CDU diesel/HGO cut point:
If HGO is drawn too low in the column (drawing components with TBP > 360°C into diesel):
Diesel T95 exceeds 360°C → off-specification for road diesel → must be blended down or processed

Cut point adjustment for T95 control:
Raise HGO draw-off tray → removes components above 360°C more efficiently from diesel
Reduce diesel pump-around temperature → improves fractionation between diesel and HGO sections

Diesel yield vs specification trade-off:
Setting diesel/HGO cut at 360°C (T95 360°C spec): Diesel yield = 18.0% vol
Setting diesel/HGO cut at 370°C (relaxed T95 to 370°C): Diesel yield = 19.5% vol
Incremental diesel vs HGO value: $98 - $88 = $10/bbl premium for diesel vs HGO
Incremental yield: 1.5% x 100,000 = 1,500 bbl/day x $10 = $15,000/day additional revenue from cut point optimization**

**But: Requires diesel to meet EN 590 T95 ≤ 360°C → if stricter spec applies, yield must be reduced → operator must balance yield and quality for maximum margin

4.2 Pumparound Design: Heat Integration and Separation Enhancement

Pumparound duty calculation (Diesel pumparound example):

Pumparounds are liquid draws from the column at an intermediate point that are cooled in heat exchangers and returned to the column a few trays above the draw-off point. They serve two functions simultaneously: they remove heat from the column (reducing the overhead condenser duty and preheating the crude in the preheat train), and they create internal reflux within the column section between the return tray and the draw tray, improving fractionation.

Diesel pumparound (DPA) specification:
Draw location: Tray 20 (above diesel draw tray)
Return location: Tray 24 (4 trays above draw)
Draw temperature: T_draw = 280°C
Return temperature: T_return = 180°C (after cooling against crude preheat)
DPA flow rate: L_DPA (to be calculated for required duty)

DPA duty to remove:
Required DPA duty (from column heat balance): Q_DPA = 12,500 kW (specified by simulation)
Specific heat of diesel fraction at average temperature (230°C): Cp = 2.65 kJ/kg/°C

DPA mass flow required:
Q = L_DPA x Cp x (T_draw - T_return)
12,500 = L_DPA x 2.65 x (280 - 180)
12,500 = L_DPA x 2.65 x 100 = L_DPA x 265
L_DPA = 12,500/265 = 47.2 kg/s = 169,905 kg/hr = 22,895 BPSD DPA flow**

**This DPA flow (22,895 BPSD) is approximately 130% of the actual diesel production (18,000 BPSD) - the pumparound circulates 2.3 times the net diesel yield to achieve the required heat removal and fractionation enhancement.

Heat recovered to crude preheat train:
Q_DPA = 12,500 kW recovered from column
Using this to preheat crude from 220°C to 250°C (delta_T = 30°C):
Crude flow: 157.9 kg/s, Cp_crude = 2.4 kJ/kg/°C
Q_crude_preheat = 157.9 x 2.4 x 30 = 11,369 kW crude preheated by DPA**

**Fuel gas saving: 11,369/0.88 = 12,919 kW fuel avoided / 50,000 kJ/kg = 0.258 kg/s fuel gas saved
Annual fuel saving: 0.258 x 3,600 x 8,760 x $0.22/kg = $1,789,000/year from diesel pumparound heat recovery**

Conclusion

The column diameter calculation in this article 7.17 m for a 100,000 BPSD Arabian Light crude distillation column at the flash zone, rounded up to 7.5 m standard size demonstrates how the vapor hydraulics of the column set its physical dimensions. The 7.5 m diameter is not arbitrary: it is the consequence of 48% vaporization of 157.9 kg/s of crude creating 22.1 m3/s of vapor flow at flash zone conditions, which at 80% of the flooding velocity (0.621 m/s) requires 40.4 m2 of active tray area. A designer who selected a smaller column diameter (say 6.0 m, which would be 25% smaller) would be requiring the vapor to travel at 97% of flooding velocity creating a column that operates right at the edge of flooding from the first day of operation, with no tolerance for even small increases in crude rate or changes in crude composition. The 7.5 m column provides a 20% margin below flooding, which is the standard design practice for process columns that must operate reliably across the full range of planned crude blends and throughput variations.

The cut point optimization calculation - $15,000/day additional revenue from relaxing the diesel/HGO cut point from 360°C to 370°C when specifications permit - demonstrates why cut point management is the highest-value real-time optimization activity in any operating refinery. The crude distillation unit processes 100,000 barrels per day, and every 0.1% shift in yield between two adjacent products with a $10/bbl premium difference represents $100,000 per year in revenue impact. The CDU operators and process engineers who manage cut points with real-time product quality analyzers (automated distillation analyzers, near-infrared analyzers, flash point analyzers) and adjust pumparound flows and draw temperatures accordingly are performing an optimization that is worth millions of dollars per year in incremental margin across the field's production life. The most experienced CDU operators can navigate the multi-variable trade-off between flash point (requires high cut temperature), cloud point (requires low cut temperature), and cetane (requires specific paraffin content) simultaneously by monitoring several online analyzers and adjusting multiple column variables in a coordinated response to crude blend changes.

For process engineers and refinery engineers building expertise in crude distillation design and operation, the following references provide the essential technical foundation: Crude Distillation Unit Design and Operation covers column sizing, tray selection, pumparound design, and product quality optimization for petroleum refinery ADUs, while Petroleum Refining Technology and Economics - Gary and Handwerk provides the comprehensive refinery engineering reference including CDU design, product specifications, and refinery economics from crude to products.

Want to access our crude distillation toolkit with TBP yield calculator, fired heater duty estimator, column diameter Fair's method calculator, tray count estimation tool, flash point prediction from cut point, and pumparound duty calculator, or discuss CDU design for a specific crude oil? Join our Telegram group for refinery engineering and petroleum processing discussions, or visit our YouTube channel for step-by-step tutorials on crude distillation design, cut point optimization, and tray hydraulics.

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