Cost-Capacity Coefficients and Exponents for Many Refinery Process Units
The tables that follow are to be used in an equation of the form:
Cost ($ millions, 1991) = Coefficient x (Capacity)Exponent
(EDPI = 1100)
The capacity is in thousands of barrels per day (MBPOD) except where noted.
The data comes from Company projects in the 1970s and from other sources. It has been updated to EDPI = 1100 (mid-1991). Because of the age of the underlying data, the correlations should be used with caution. Costs exclude catalyst, piling, computers, and winterizing, and are on a West Coast (Richmond) basis.
The tables contain adjustment factors that you can use in cases where plants being estimated differ slightly from the basis for the correlations.
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Facility Coefficient at EDPI = 1100
Exponent Adjustments
One-Stage Crude Distillation Unit Contains an atmospheric distillation column, side cut stripping, overhead stabilizer and splitter, and either a one-stage desalter and flash drum or a two-stage desalter without flash drum.
2.837 0.700 To delete the overhead stabilizer and splitter, subtract 14%.
For a two-stage desalter with a flash drum, add 3.6%.
Two-Stage Crude Distillation Unit Adds vacuum distillation to the one-stage unit; also includes vacuum off-gas compression or vent gas scrubbing.
4.073 0.700 To delete the overhead stabilizer and splitter, subtract 10%. For a two-stage desalter with a flash drum, add 2.5%.
Vacuum Distillation Unit
Stand-alone unit similar to the second stage of a two-stage crude distillation unit.
3.300 0.700 Cost of PRCP plant was about 35% higher than this curve.
Deethanizer Depropanizer Debutanizer Deisobutanizer
LSR Splitter (Depentanizer) Gasoline Splitter (Dehexanizer) - These are single-column units that
separate the named component and lighter hydrocarbons from heavier hydrocarbons. 1.505 1.505 1.216 2.837 1.216 1.042
0.600 Units have steam reboilers and water-cooled overhead condensers.
Light Ends Recovery Unit (LER)
Combination of deethanizer and depropanizer columns.
5.836 0.580 Cost of PRCP plant was about 11% higher than this curve.
Gas Recovery Unit (GRU)
An LER with the addition of a debutanizer column.
5.385 0.600
Merox Treating
- Light straight run gasoline or cracked naphtha - Kerosene/jet 1.170 1.505 0.560 0.560 Figure 202-15. Cost-Capacity Coefficients and Exponents: Distillation and Treating Units
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Facility Coefficient at EDPI = 1100
Exponent Adjustments
Naphtha Hydrotreater
Mid-Distillate Hydrotreater (SR) Light Cycle Oil (LCO) Hydrofiner Vacuum Gas Oil (VGO) Desulfurizer
These units remove sulfur and nitrogen from the oil feed by reacting it with hydrogen. The naphtha hydrotreater and mid-distillate hydrofiner include com- pression for make-up hydrogen; the other units require a high pressure hydrogen supply. Units include reactor(s) and re- cycle hydrogen compression.
4.314 4.674 5.142 4.169 0.640 0.670 0.670 0.700 Naphtha hydrotreater:
No make-up compression, subtract 7%. No make-up or recycle compression ("once-through"), subtract 13%.
Rheniformer
The second stage of a traditional catalytic reformer (the first stage is a naphtha hydrotreater); includes four reactors and recycle compression, but no compression for product hydrogen.
5.469 0.650 Curve has been adjusted to include current metallurgy.
For 3 reactors rather than 4, subtract 8%.
Figure 202-16. Cost-Capacity Coefficients and Exponents: Hydrotreating and Reforming Units
Facility Coefficient at EDPI = 1100
Exponent Adjustments
Hydrogen Plant
Process uses steam-methane reforming to produce 95 to 97% pure hydrogen from 100 psig natural gas feed; high-pressure plants have steam turbine-driven shift gas compressors; product is delivered at 1700 psig; cost excludes catalyst. Capacity is millions of standard cubic feet per day (MMSCFD) of product hydrogen.
7.180 0.610 Cost of PRCP plant was about 6% higher than this curve.
For gas turbine drive on shift gas compressor, add 12%. For 900 psig product, subtract 10%. To produce 200-250 psig hydrogen, subtract:
For natural gas feed 21% For LPG feed 17% For naphtha feed 10%
Figure 202-17. Cost-Capacity Coefficients and Exponents: Hydrogen Manufacturing and Compression Units
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Facility Coefficient at EDPI = 1100
Exponent Adjustments
Sour Water Stripper
Separates H2S from water; consists of a
reboiled stripper with a feed degasser and two injection systems; feed storage is off-plot and is excluded from the cost; capacity is gallons per minute (GPM).
The reboiler uses low pressure steam (40 - 50 psig) which requires a condensate drum and pump.
The column overhead includes an air-cooled condenser with a reflux drum and reflux pump.
0.314 0.530 To delete feed sour water cooler, subtract 6%. To delete feed degasser and pumps, subtract 12%.
To delete stripped water (bottoms) trim cooler, subtract 9%.
To delete one injection system (anti-foam for column feed or corrosion inhibitor for column overhead), subtract 1%.
To delete the reboiler (and use live stripping steam), subtract 12%. To use 150 psig steam in the reboiler and delete the condensate drum and pump, subtract 6%.
To use water-cooled condensing and delete the reflux drum and pump (gravity reflux), subtract 5%.
Waste Water Treater (WWT)
Combines a sour water stripper with ammonia recovery facilities (a proprietary Chevron process); capacity is gallons per minute (GPM).
1.372 0.410
H2S Recovery
Amine (usually diethanolamine, or DEA) is used to absorb hydrogen sulfide from a gas stream; the plant contains a 50% capacity absorption column (with DEA being circulated to additional absorbers located in other process units); a regeneration column with steam reboiler and air-cooled condenser; and ammonia and caustic relief scrubbers on the overhead H2S product stream; the plant
capacity used in the cost correlation is thousands of pounds per hour of H2S
recovered.
3.821 0.550 For a 100% capacity absorber in this plant, add 10%.
For a water-cooled regenerator overhead condenser and non-pumped reflux, deduct 5%.
To delete the ammonia scrubber, subtract 10%.
To delete the caustic relief scrubber, subtract 5%.
To substitute ammonia for caustic in the relief scrubber, add 15%.
Figure 202-18. Cost-Capacity Coefficients and Exponents: Hydrogen Sulfide Removal and Sulfur Recovery
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Facility Coefficient at EDPI = 1100
Exponent Adjustments
Fluid Catalytic Cracker (FCC)
Reactor, regenerator, and distillation section to maximize gasoline production.
18.123 0.600
Butane Isomerization
Normal butane feed is catalytically converted (approx. 60%) to isobutane. Plant includes mole sieve driers (for both butane and hydrogen feeds), reactors, and product stabilizer.
6.340 0.588
Figure 202-19. Cost-Capacity Coefficients and Exponents: Cracking and Alkylation
Facility Coefficient at EDPI = 1100
Exponent Adjustments
Delayed Coking
Includes coke drums, on-plot coke handling and product distillation and treating. Capacity is short tons per day of coke produced.
0.832 0.700 The correlation is based on a coke yield to feed rate ratio of 50 short tons per 1000 barrels; for a different ratio of coke yield to feed rate, multiply the calculated cost by
3.02 x
coke make, STPOD Feed rate, MBPOD
−0.281
Figure 202-20. Cost-Capacity Coefficients and Exponents: Other Processes
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Cost-Capacity Coefficients and Exponents for Refinery Offplot Facilities
Figure 202-21 contains cost-capacity coefficients and exponents for offplot facilities. We originally developed this data from 1970s Chevron experience. We updated the data to 1991 (EDPI=1100) without further validation except for adjusting the correlations of boiler plants, cooling towers, and tankfields to match experiences of projects in the early 1980’s. Facility descriptions appear on the following pages.
Facility At EDPI = 1100 Capacity Units Cost Adjustments Coeff. Exponent
Boiler Plant 0.28 0.77 M lbs/hr1 plus 2.5 percent of Onplot Investment Cooling Tower
Over 10 M GPM 0.93 0.75 M GPM1 Under 10 M GPM 2.08 0.4 M GPM1 Electrical Distribution 1.22 0.7 M KVA1 Tankfields
Crude 16.8 0.8 MM Bbl2
Other (ex. sulfur, LPG) 34.7 0.8 MM Bbl2 Sulfur
(incl. loading rack)
0.17 0.8 M Bbl2 Butane 0.38 0.7 M Bbl2 Propane 0.46 0.7 M Bbl2 Interconnecting Pipeways 8 percent of Onplot Investment Site Development 0.078 1.0 Developed Acres
Relief System 2 percent of
Onplot Investment3 Marine Facilities
(Coastal Areas Only)
Grass Roots Refinery 25.9 0.25 MBPOD Crude to Refinery Existing Refinery 0.20 1.0 MBPOD Incremental Crude to Refinery Loading Racks
Marine Location 0.10 1.0 MBPOD Incremental Crude Throughput Inland Location 0.30 1.0 MBPOD Incremental Crude
Throughput Effluent Treating
(Grass Roots Refinery)
9.9 0.3 MBPOD Crude to Refinery
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Use the data in Figure 202-21 in an equation of the form:
Cost ($millions, 1991) = Coefficient x (Capacity)Exponent
The costs are on a West Coast (Richmond) basis. Facility descriptions appear on the following pages.
If you can determine the offplot facility’s size, this method gives better results than using a percentage of onplot cost (see Section 211).
While the locations and projects vary for facilities in each type of offplot plant, the following information summarizes the scope nominally
included in these estimating correlations.
Boiler Plant
Oil-fired boiler(s), with BFW treating, BFW pumps, and deaerator A fuel system (day tank, pumps, and oil heater)
Air systems (utility and instrument air compressors and auxiliaries) The cost equation is for the boiler plant’s own facilities; the additive piece, based on a percentage of the process plant costs, allows for the cost of incremental BFW capacity to support onplot steam generation.
Cooling Tower
Tower and basin, with circulating pumps, main supply and return headers serving multiple plants, and minimal water treatment Pump drivers are motors or back-pressure steam turbines
To delete main supply and return headers, subtract 23 percent. To change to condensing turbines, add 10 percent for 600 psig or 17 percent for 40 psig steam.
Electrical Distribution
Medium voltage wiring and switches, emergency power systems, and communications
No transformers or motor control centers
Assumes that power company provides high-to-medium voltage sub- station, and that plant substations are included in individual plant costs
Tankfields
Tankage and associated facilities within the diked area Tankfield pipeways Transfer pumps
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Blending/metering facilities
Excludes process/utility area pipeways Provides for multiple tanks in each category Pressurized, refrigerated LPG tanks, as appropriate The sulfur storage cost includes sulfur loading racks.
Interconnecting Pipeways
Pipeways in the vicinity of process and utility plants
Excludes cooling water and relief headers, and tankfield pipeways
Site Development Rough grading Filling Roads Paving Bridges
Simple railroad spurs Fencing
Minor landscaping
Relief System
Free-standing elevated flare with molecular seal Knockout drum and pump
Ground flare with water seals Vent gas recovery compressor Main offplot flare header
As an alternative to using a percentage of onplot costs, consider a lump-sum cost per flare system (see Figure 202-21, Note 3).
Marine Facilities
For coastal areas only; includes piping to/from the refinery Provides product wharves for two-thirds of the products
For grass-roots only; provides a single-point mooring for crude receiving
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Loading Racks
Truck and/or rail loading racks for one-third of products (marine location) or 100 percent of products (inland location)
The cost of sulfur loading racks is included in the tankfield cost for sulfur storage.
Effluent Treating
Offplot gathering system for oily water and storm water Oily water separator(s) with skim pump
Air flotation system
Activated sludge or other BOD reduction system No tertiary treatment included