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Crude oil refinery (complexity-based screening)

Whole-refinery screening on three IEAGHG/ReCAP designs (hydroskimming, FCC, deep conversion): crude and product slate, energy, fuel gas, hydrogen demand, CO2, capital requirement, O&M and processing cost in EUR 2015 per barrel, with indicative refining margins.

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CurrencyEUR 2015
Battery limitfully financed
142 documented assumptions
Updated27 Oct 2026

Mass and energy balance

What the asset draws and delivers for the case and load you choose.

Crude utilisation

Crude run as a share of the stream-day capacity, on ReCAP's 350 operating days. 100 % = the ReCAP design basis. 75 % = the 2020 EU low of 72 % (FuelsEurope Statistical Report 2022 from BP data, calendar-day basis) restated on 350 days (72 x 365 / 350 = 75.1). Crude, products, fuel gas, hydrogen, CO2 and chemicals scale linearly with it; capital and fixed O&M do not, so the cost per barrel rises at low utilisation. No part-load efficiency penalty is modelled.

Flows

Annual quantities at the current usage. Band width: share of energy in; non-energy flows are not to scale.

Crude distillation capacity

Crude capacity in barrels per stream day. Valid within 0.5-1.5x the reference of the selected configuration: 50,000-150,000 bpd (hydroskimming), 110,000-330,000 (medium conversion), 175,000-400,000 (high conversion); outside it the inputs are rejected. Flows scale linearly; capital, maintenance and insurance scale with exponent 0.7 (ReCAP D5); labour stays at the configuration's headcount.

Crude processed (mass): — t/year
Electricity demand (self-generated): — MW
On-purpose hydrogen demand: — t/year
Fuel natural gas imported (HHV): — MWh/year

CAPEX

Specific cost at this size, what backs it, and how it behaves with scale.

Specific CAPEX at this size

—

Reference size 220,000 bpd

ReCAP D5 Appendix B

CAPEX source

Model value: ReCAP D3 total capital requirement excl. SMR of the selected configuration, scaled with exponent 0.7 (ReCAP D5). Customized: your own figure per bpd, used as is at every size; the capital cost is then no longer sourced.

Specific capital requirement by crude distillation capacity

Ex-factory
Installed
Fully financed· this figure

CAPEX at the battery limit—

Included

Equipment and installation
Indirect and owner's costs
Contingency

Not included

Nothing

Added at project level

Nothing: project mode uses the figure as is

Project figures

Values passed to project mode when this asset is added to a project.

Crude oil refinery (complexity-based screening)Concept sketch, not to scale · drag to rotate

Hydrogen (on-purpose, beyond the catalytic reformer) in: —
Natural gas, refinery fuel (HHV) in: —
Gasoline outMain product: —
Diesel / gas oil out: —
Jet fuel / kerosene out: —
Fuel oil out: —
CAPEX to the battery limit: —
Fixed O&M: —
Variable O&M, excluding feedstocks: —
Asset lifetime: 25 years

Processing cost (levelised)

A standalone indicator for a quick read. Project mode recomputes it for the whole system.

—

Capital charge per barrel—
Fixed O&M per barrel—
Variable O&M per barrel—
Fuel gas per barrel—
Bought hydrogen per barrel—

Linked to the balance above

Crude utilisation

Refinery configuration

Selects one of three anchored designs: IEAGHG/ReCAP Base Case 1 (100,000 bpd), Base Case 2 (220,000 bpd) or Base Case 4 (350,000 bpd), with the OGJ 1996 product slate of the matching complexity class. Complexity is a class, not a continuous Nelson index: the sources only anchor discrete designs.

Natural gas price (HHV)

EUR/MWh

Price of the imported fuel gas, EUR 2015 per MWh HHV (project key ng_price_eur_per_mwh). Default = ReCAP 6.6 USD/GJ (LHV basis inferred, not printed) converted at 1.1095 USD/EUR and 0.9 LHV/HHV.

Hydrogen price

EUR/kg

Price of the on-purpose hydrogen bought or chained in. Default = IEAGHG 2017-02 SMR LCOH without capture, 11.4 EUR cent/Nm3 at 4Q-2014 EUR (one-year mismatch with the cost base, declared).

Crude price (Brent)

USD/bbl

Crude price in USD per barrel, converted at 1.1095 USD/EUR. Default = EIA Brent spot 2015 annual average. Used for the margins and for the crude purchase exported as variable opex.

Gasoline price

USD/gal

Default = EIA New York Harbor conventional regular gasoline spot, 2015 annual average.

Diesel price

USD/gal

Default = EIA New York Harbor ultra-low sulfur No.2 diesel spot, 2015 annual average.

Jet fuel price

USD/gal

Default = EIA US Gulf Coast kerosene-type jet fuel spot, 2015 annual average.

Fuel oil price

USD/gal

Default = EIA US residual fuel oil wholesale/resale price by refiners, 2015 annual average.

Other products price (incl. LPG)

USD/gal

Value of the 'other' group (refinery gas, LPG, coke, bitumen...). Default = EIA Mont Belvieu propane spot 2015, a declared assumption.

Processing cost (levelised) by crude utilisation

All results

Every model output at the current settings, grouped, with the sensitivity charts.

84 outputs · 7 groups · 19 also shown above, dimmed

Processing cost

Processing cost (levelised): ComputingEUR/bbl
Capital charge per barrel: ComputingEUR/bbl
Fixed O&M per barrel: ComputingEUR/bbl
Variable O&M per barrel: ComputingEUR/bbl
Fuel gas per barrel: ComputingEUR/bbl
Bought hydrogen per barrel: ComputingEUR/bbl
Processing cost per tonne of crude: ComputingEUR/t
Processing cost with a strict CRF: ComputingEUR/bbl
Processing cost on ReCAP's boundary (model path): ComputingEUR/bbl
ReCAP printed processing cost: ComputingEUR/bbl
Total annual processing cost: ComputingEUR/year
Capital share of processing cost: Computing%
Gas and hydrogen share of processing cost: Computing%
Fixed O&M: ComputingEUR/year
Variable O&M (non-fuel): ComputingEUR/year
Fuel gas cost: ComputingEUR/year
Hydrogen supply cost: ComputingEUR/year
ReCAP gas price on the input basis: ComputingEUR/MWh
IEAGHG SMR hydrogen cost: ComputingEUR/kg

Capital

Total capital requirement (excl. SMR): ComputingEUR
Specific capital requirement: ComputingEUR/bpd
Reference capacity of the cost anchor: Computingbpd
Scale exponent applied: Computingratio
Total installed cost (excl. SMR): ComputingEUR
Capital requirement / installed cost: Computingratio
Installed cost per bpd (source basis): ComputingUSD/bpd
Annual capital charge: ComputingEUR/year
Strict capital recovery factor: Computing1/year

Throughput & products

Average crude run: Computingbpd
Crude processed: Computingbbl/year
Crude processed (mass): Computingt/year
Barrels per tonne implied by ReCAP: Computingbbl/t
Operating hours: Computingh/year
On-stream factor: Computing%
Capacity factor: Computing%
Gasoline: Computingbbl/d
Jet fuel / kerosene: Computingbbl/d
Diesel / gas oil: Computingbbl/d
Fuel oil: Computingbbl/d
Other products incl. LPG: Computingbbl/d
Total products: Computingbbl/d
Volume loss (-) or gain (+): Computing% vol of crude
Gasoline (annual volume): Computingm3/year
Diesel (annual volume): Computingm3/year
Jet fuel (annual volume): Computingm3/year
Fuel oil (annual volume): Computingm3/year
Other products incl. LPG (annual volume): Computingm3/year

Energy & losses

Specific energy consumption: ComputingGJ/t
Refinery fuel fired: ComputingTJ/year
Heat and losses: ComputingMWh/year
Fuel drawn from the crude itself: ComputingTJ/year
Energy load vs EU average: Computingratio
Fuel natural gas imported (HHV): ComputingMWh/year
Fuel gas per tonne of crude (HHV): ComputingMWh/t
ReCAP gas NHV (check): ComputingMJ/kg
Electricity demand (self-generated): ComputingMW
Electricity per tonne of crude: ComputingkWh/t
Electricity generated on site: ComputingMWh/year
Steam demand (self-generated): Computingt/h
Steam per tonne of crude: Computingt/t

Hydrogen & CO2

On-purpose hydrogen demand: Computingt/year
Hydrogen per barrel of crude: Computingkg/bbl
CO2 emissions (scope 1, incl. SMR): Computingkt/yr
CO2 intensity: Computingt/t
CO2 intensity excl. hydrogen production: Computingt/t
CO2 attributed to hydrogen production: Computingkg/kg
ReCAP printed CO2 intensity: Computingt/t
CO2 emissions excl. hydrogen production: Computingkt/yr
CO2 excl. hydrogen production (t): Computingt/year
CO2 intensity vs EU average: Computingratio
CO2 per barrel of crude: Computingkg/bbl

Refining margin (indicative)

Product value per barrel of crude: ComputingEUR/bbl
Crude price: ComputingEUR/bbl
Gross refining margin: ComputingEUR/bbl
Cash operating cost: ComputingEUR/bbl
Cash refining margin: ComputingEUR/bbl
Net refining margin: ComputingEUR/bbl
Net refining margin per year: ComputingEUR/year
Variable O&M and crude purchase: ComputingEUR/year

Complexity

Nelson complexity (class midpoint): ComputingNCI
Nelson complexity (class low): ComputingNCI
Nelson complexity (class high): ComputingNCI
EU BREF complexity category (1-4): Computingcategory
Complexity vs 1996 US average: Computingratio

Sensitivities

6 charts

CO2 emissions vs capacity

Processing cost vs capacity

Cost and margin by configuration

Energy and CO2 intensity by configuration

Margins vs crude price

Processing cost components vs crude utilisation

Sources

142 documented assumptions · 12 sources

About

Calculator context

Whole-refinery screening from crude capacity and configuration. Three designs are anchored on the IEAGHG/SINTEF ReCAP reference refineries (Technical Review 2017-TR8 and Deliverable D3): hydroskimming (Base Case 1, 100,000 bpd), medium conversion with FCC (Base Case 2, 220,000 bpd) and high conversion with FCC, hydrocracker and coker (Base Case 4, 350,000 bpd). Complexity is a configuration class, not a continuous Nelson index: the calculator prints the OGJ 1996 class range (NCI 2-3, 5-6, 9-10+) and the EU BREF category for information.

Throughput is capacity x crude utilisation x 350 days, converted at 7.3 bbl/t (BREF). Utilisation (75-100 % of the stream-day capacity, default 100 % = the ReCAP basis; 75 % is the 2020 EU low of 72 % calendar-day restated on 350 days, FuelsEurope 2022) scales crude, products, fuel gas, hydrogen, CO2 and chemicals linearly; capital and fixed O&M do not, and no part-load efficiency penalty is modelled. Product yields are the OGJ 1996 class slates (gasoline, middle distillates split 25/75 into jet and diesel, fuel oil, and 'other' which includes LPG, refinery gas, coke and bitumen). Specific energy (2.51 / 2.99 / 2.94 GJ/t), CO2 intensity (ReCAP prints 0.154 / 0.207 / 0.201 t/t), fuel gas, self-generated power and steam, and on-purpose hydrogen (0 / 0.194 / 0.707 kg/bbl) come from the ReCAP tables, scaled linearly with capacity. Each configuration is valid within 0.5-1.5x its reference capacity (50,000-150,000 / 110,000-330,000 / 175,000-400,000 bpd); outside it the inputs are rejected, so a deep-conversion design is never shrunk to a hydroskimming size.

Hydrogen is an inlet in t/year, so the SMR is removed from the capital cost (42 and 178 MUSD of TIC in BC2 and BC4) and its CO2 from the exported emissions: chain it to an SMR, ATR or electrolyser calculator without double counting. ReCAP's 'From Steam Reformer' line is the feed (process) CO2 only, and only that line is removed (15.7 t/h in BC2, 29.7 t/h in BC4), leaving 0.195 / 0.186 t/t excl. hydrogen at each reference capacity. The reformer furnace burns refinery fuel gas (BC2 54 % refinery gas / 46 % imported gas, BC4 99.8 % refinery gas) that is not bought for the SMR: without the SMR that gas is still burnt in the refinery, so its CO2 (3.7 / 19.8 t/h) stays in the exported direct CO2, as its energy stays in the specific energy and its natural gas share in the gas inlet. The exported CO2 then equals ReCAP's combustion CO2 (fuel gas and natural gas, fuel oil, FCC coke) per unit of fuel energy kept, within 0.05 % at each reference capacity. For the hydrogen CO2 itself, feed + furnace = 19.4 t/h in BC2 and 49.5 t/h in BC4. In BC4 that attribution is 4.8 kg CO2/kg H2, below the 5.46 kg/kg stoichiometric floor of reforming, and ReCAP's per-unit table closes on its total, so BC4 understates its hydrogen CO2: the calculator re-attributes it at the IEAGHG 2017-02 base-case 9.0 kg/kg, which puts configuration 3 at 0.223 t/t incl. hydrogen against ReCAP's printed 0.201. The furnace CO2, already in the excl. figure, is subtracted once from that attribution. The incl. figure is an emissions view: the SMR feed gas behind the feed CO2 is in neither the gas inlet nor the specific energy, as in ReCAP. Fuel natural gas is an inlet in MWh HHV under the key ng_price_eur_per_mwh.

Money is EUR 2015 throughout: ReCAP's USD Q4-2015 costs and EIA's 2015 prices are converted at the Eurostat 2015 average of 1.1095 USD/EUR. The processing cost = (ReCAP total capital requirement excl. SMR / 11.53 + fixed O&M + chemicals, catalyst and raw water + fuel gas + bought hydrogen) / barrels. Capital, maintenance and insurance scale with (capacity / reference)^0.7, the typical exponent of ReCAP's own cost scaling (D5); labour stays at the configuration's headcount. At each reference capacity, full run and the default prices it is 10.02 / 10.96 / 11.56 EUR2015/bbl for configurations 1 / 2 / 3 (configuration 2: capital 5.59 + fixed O&M 2.78 + variable O&M 1.67 + fuel gas 0.68 + hydrogen 0.25); across the valid domain (capacity 0.5-1.5x, utilisation 75-100 %) it spans 8.97-17.39 EUR2015/bbl, higher at the small end and at low utilisation. The scale law is a declared transfer: no source prices one refinery design at two sizes, ReCAP anchors each configuration at a single size, so the law is only used within 0.5-1.5x that size. A customized CAPEX (EUR2015/bpd, TCR all-in excl. SMR) replaces the model value at every size, without the scale law; maintenance and insurance then follow it. On ReCAP's own boundary (SMR capital kept, no bought hydrogen, always on the model CAPEX), the same model gives 10.02 / 10.78 / 10.82 EUR2015/bbl against ReCAP's printed 11.13 / 11.96 / 12.01 USD Q4-2015/bbl = 10.03 / 10.78 / 10.82 EUR2015/bbl. This is a recomputation of ReCAP's Table 3 from its own Tables 1, 2 and 5, not an independent validation. Using a strict CRF(8 %, 25 yr) instead of ReCAP's 11.53 factor adds about 0.4 EUR/bbl.

The refining margins (gross about -0.4 / 3.5 / 10.1 EUR2015/bbl at 2015 prices) rest on 1996 generic yields and US price points: they are indicative only. Crude oil has no chainable commodity in the library, so its purchase is exported once as variable opex. The fuel fired on site (31,492 TJ/yr, 8.75 TWh/yr in configuration 2 at 220,000 bpd) is reported as heat and losses; about 22,600 TJ/yr of it is refinery gas, fuel oil and coke drawn from the crude itself, not priced in the processing cost (ReCAP convention) and paid by the project through the purchase of the whole crude.

Model

278 variables — inputs, calculations and outputs, with their dependencies.

278 variables shown of 278

Value	Unit	Depends on
2	—	—
220000	bpd	—
100	%	—
0	—	—
22500	EUR/bpd	—
19.27	EUR/MWh	—
1.2675	EUR/kg	—
52.32	USD/bbl	—
1.612	USD/gal	—
1.659	USD/gal	—
1.522	USD/gal	—
0.996	USD/gal	—
0.457	USD/gal	—

Variable	Formula	Unit	Depends on
	`/max(,)`	—
	`if((<)+(>)+(<)+(>)>,,)`	flag
	`if((<=)+(<)+(>)+(<=)+(>)+(<)+(>)+(<=)+(<)+(<)+(<=)+(<)+(<)+(<)+(<)+(<)+(>)>,,)`	bool
	`*`	—
	`/max(,)`	t/h
	`if(==,,if(==,,))`	kg/t
	`if(==,,if(==,,))`	t/h
	`*/max(,)`	t/h
	`if(==,,if(==,,))`	% vol of crude
	`if(==,,if(==,,))`	% vol of crude
	`if(==,,if(==,,))`	% vol of crude
	`if(==,,if(==,,))`	% vol of crude
	`**`	bbl/d
	`if(==,,if(==,,))`	Gcal/h
	`if(==,,if(==,,))`	t/h
	`**`	t/h
	`**/`	—
	`if(==,,if(==,,))`	kW
	`if(==,,if(==,,))`	t/h
	`if(==,,if(==,,))`	Nm3/h
	`***`	kg/h
	`if(==,+,if(==,+,+))`	t/h
	`*/`	t/h
	`/max(,)`	kg/kg
	`*/`	t/h
	`if(>=,,max(,))`	t/h
	`if(==,,if(==,,))`	t/h
	`if(==,,if(==,,))`	t/h
	`/max(,)`	t/t
	`if(==,,if(==,,))`	MUSD
	`if(==,,if(==,,))`	MUSD
	`if(==,,if(==,,))`	MUSD
	`*(-/max(,))`	MUSD
	`*/max(,)/`	EUR/bpd
	`^`	ratio
	`*^(-)`	EUR/bpd
	`*/`	—
	`/max(,)`	—
	`*`	1/year
	`*`	EUR/year
	`if(==,,if(==,,))`	MUSD/year
	`if(==,,if(==,,))`	MUSD/year
	`if(==,,if(==,,))`	MUSD/year
	`if(==,,if(==,,))`	MUSD/year
	`(+(-))/`	—
	`**//max(,)`	EUR/year
	`if(==,,if(==,,))`	USD/bbl
	`*/`	EUR/bbl
	`*/`	EUR/bbl
	`*/`	EUR/bbl
	`*/`	EUR/bbl
	`*/`	EUR/bbl
	`*`	EUR/year

Variable	Formula	Unit	Depends on
	`if(==,,if(==,,))`	bpd
	`*`	h/year
	`/*`	%
	`*`	bpd
	`*`	%
	`*`	bbl/year
	`/`	t/year
	`/max(,)`	bbl/t
	`if(==,,if(==,,))`	% vol of crude
	`**`	bbl/d
	`**`	bbl/d
	`-`	bbl/d
	`**`	bbl/d
	`**`	bbl/d
	`+++`	bbl/d
	`**`	m3/year
	`**`	m3/year
	`**`	m3/year
	`**`	m3/year
	`**`	m3/year
	`*/max(,)`	GJ/t
	`*/`	TJ/year
	`*/`	MWh/year
	`/max(,)`	ratio
	`**//max(,)`	MWh/year
	`-`	TJ/year
	`/max(,)`	MWh/t
	`*`	MJ/kg
	`*/`	MW
	`/max(,)`	kWh/t
	`**`	MWh/year
	`*`	t/h
	`/max(,)`	t/t
	`*/`	t/year
	`*/max(,)`	kg/bbl
	`/`	t/t
	`/max(,)`	kg/kg
	`-/max(,)`	t/t
	`+-/max(,)`	t/t
	`*/`	kt/yr
	`*`	t/year
	`/`	kt/yr
	`/max(,)`	ratio
	`*/`	kg/bbl
	`if(>=,,)`	ratio
	`if(>=,,clamp(,,))`	EUR/bpd
	`*`	EUR
	`/max(,)`	ratio
	`/max(,)`	EUR
	`*/max(,)`	USD/bpd
	`if(<,/max(,),(*(+)^)/max((+)^-,))`	1/year
	`/max(,)`	EUR/year
	`(+(-))/`	EUR/year
	`(+)***/`	EUR/year
	`*`	EUR/year
	`**`	EUR/year
	`++++`	EUR/year
	`/max(,)`	EUR/bbl
	`/max(,)`	EUR/bbl
	`/max(,)`	EUR/bbl
	`/max(,)`	EUR/bbl
	`/max(,)`	EUR/bbl
	`/max(,)`	EUR/bbl
	`/max(,)`	EUR/t
	`(-+)/max(,)`	EUR/bbl
	`/max(,)*`	%
	`(+)/max(,)*`	%
	`(+++)/max(,)`	EUR/bbl
	`/`	EUR/bbl
	`/**`	EUR/MWh
	`/max(,)`	EUR/kg
	`/`	EUR/bbl
	`(++++*)/max(,)`	EUR/bbl
	`-`	EUR/bbl
	`(+++)/max(,)`	EUR/bbl
	`-`	EUR/bbl
	`-`	EUR/bbl
	`*`	EUR/year
	`+`	EUR/year
	`if(==,,if(==,,))`	NCI
	`if(==,,if(==,,))`	NCI
	`(+)*`	NCI
	`if(<,,if(<,,if(<=,,)))`	category
	`/max(,)`	ratio

Assumptions

142 assumptions used in the calculations

Protects every division.
Market range Not applicable (numerical or unit constant).
0
OpenJack DSL convention
Unit multiplier (CRF, SMR share of TIC, capex scaling exponent).
Market range Exact by definition.
1
Numerical constant
Lower limit of the input guards and the absent SMR terms of the hydroskimming case.
Market range Exact by definition.
0
Numerical constant
Midpoint of the OGJ complexity range of a class.
Market range Exact by definition.
0.5
Numerical constant
Converts yields, shares and the discount rate from percent to fraction.
Market range Exact.
0.011/%
Unit conversion
Converts fractions to percent for display.
Market range Exact.
100%
Unit conversion
Mass conversion (kg CO2 per t crude, kg H2 per t).
Market range Exact.
1000kg/t
Unit conversion
Reports annual CO2 in kt.
Market range Exact.
1000t/kt
Unit conversion
Reports annual refinery fuel in TJ.
Market range Exact.
1000GJ/TJ
Unit conversion
ReCAP D3 prints costs in kUSD; the brief carries them in MUSD.
Market range Exact.
1000000USD/MUSD
Unit conversion
Power demand in MW.
Market range Exact.
1000kW/MW
Unit conversion
Natural gas energy and price per MWh.
Market range Exact.
3.6GJ/MWh
Unit conversion
ReCAP prints refinery fuel in Gcal/h.
Market range Exact.
4.1868GJ/Gcal
Unit conversion
Converts the ReCAP natural gas NHV (kcal/kg) to MJ/kg for the consistency check against IEAGHG 46.50 MJ/kg.
Market range Exact.
0.004187MJ/kcal
Unit conversion
Operating hours = 350 days x 24 h = 8,400 h, the ReCAP basis of every hourly figure.
Market range Exact.
24h/d
Calendar convention
Converts the 350-day on-stream basis to an on-stream factor.
Market range 365 (366 in leap years).
365d/year
Calendar convention
Converts EIA product prices (USD/gal) to USD per barrel.
Market range Exact by definition.
42gal/bbl
US EIA, refining crude oil
Exports product outlets in m3/year, the volume unit of the meta units policy.
Market range Exact (158.987 L).
0.158987m3/bbl
Unit conversion
Configuration 1 = hydroskimming / low conversion (OGJ NCI 2-3), anchored on ReCAP Base Case 1.
Market range Not applicable.
1
Selector code
Configuration 2 = medium conversion with FCC (OGJ NCI 5-6), anchored on ReCAP Base Case 2.
Market range Not applicable.
2
Selector code
Configuration 3 = high/deep conversion with FCC, hydrocracker and coker (OGJ NCI 9-10+), anchored on ReCAP Base Case 4.
Market range Not applicable.
3
Selector code
Annual crude = capacity x 350 days; all hourly ReCAP intensities are annualised over 8,400 h.
Market range No independent range cited.
350d/year
ReCAP on-stream factor
Converts barrels to tonnes of crude for the per-tonne intensities.
Market range About 6.5-8 bbl/t depending on crude density; 7.3 is the BREF generic figure.
7.3bbl/t
JRC BREF 2015
Hard floor of the capacity input.
Market range Slider 50,000-400,000 bpd; valid only within 0.5-1.5x the configuration's reference capacity.
50000bpd
Calculator domain
Hard ceiling of the capacity input.
Market range Slider 50,000-400,000 bpd; valid only within 0.5-1.5x the configuration's reference capacity.
400000bpd
Calculator domain
Below half the reference capacity the unit list, the number of trains and the headcount of the ReCAP design would change, and no ReCAP case anchors that design: the inputs are rejected (invalid_input).
Market range
0.5
Calculator domain
Above 1.5x the reference capacity the design would need extra trains that no ReCAP case anchors: the inputs are rejected (invalid_input). A 350,000 bpd deep-conversion design is therefore never shrunk to 50,000 bpd.
Market range
1.5
Calculator domain
Every ReCAP flow of configuration 1 (crude, energy, hydrogen, CO2) scales linearly with capacity / 100,000 bpd; capital and capital-linked fixed O&M scale with (capacity / 100,000)^0.7; labour stays at the configuration's headcount.
Market range No independent range cited.
100000bpd
ReCAP Base Case 1
Every ReCAP flow of configuration 2 (crude, energy, hydrogen, CO2) scales linearly with capacity / 220,000 bpd; capital and capital-linked fixed O&M scale with (capacity / 220,000)^0.7; labour stays at the configuration's headcount.
Market range No independent range cited.
220000bpd
ReCAP Base Case 2
Every ReCAP flow of configuration 3 (crude, energy, hydrogen, CO2) scales linearly with capacity / 350,000 bpd; capital and capital-linked fixed O&M scale with (capacity / 350,000)^0.7; labour stays at the configuration's headcount.
Market range No independent range cited.
350000bpd
ReCAP Base Case 4
Scope 1 CO2 per tonne of crude, including the on-site power plant and (cases 2 and 4) the steam reformer.
Market range BREF EU P5-P95: 106-395 kg/t; average 220 kg/t.
154.1kg/t
ReCAP Base Case 1
Derives the reference crude rate in t/h, the denominator of every per-tonne ReCAP intensity.
Market range No independent range cited.
86.8t/h
ReCAP Base Case 1
Scope 1 CO2 per tonne of crude, including the on-site power plant and (cases 2 and 4) the steam reformer.
Market range BREF EU P5-P95: 106-395 kg/t; average 220 kg/t.
207.4kg/t
ReCAP Base Case 2
Derives the reference crude rate in t/h, the denominator of every per-tonne ReCAP intensity.
Market range No independent range cited.
257.4t/h
ReCAP Base Case 2
Scope 1 CO2 per tonne of crude, including the on-site power plant and (cases 2 and 4) the steam reformer.
Market range BREF EU P5-P95: 106-395 kg/t; average 220 kg/t.
200.8kg/t
ReCAP Base Case 4
Derives the reference crude rate in t/h, the denominator of every per-tonne ReCAP intensity.
Market range No independent range cited.
398.8t/h
ReCAP Base Case 4
No SMR CO2 to remove in configuration 1.
Market range Zero by design of Base Case 1.
0t/h
ReCAP D3 Table 4
Process (feed) CO2 of the configuration 2 hydrogen: the only CO2 removed from the CO2 exported to the project, as the SMR feed gas is not in the gas inlet either, so hydrogen chained from an SMR/ATR calculator is not counted twice. The furnace CO2 stays in the export (co2_smr_furnace_t_per_h_cfg2).
Market range No independent range cited.
15.7t/h
ReCAP Base Case 2
The only CO2 removed from the CO2 exported to the project (feed CO2; the furnace CO2 stays, see co2_smr_furnace_t_per_h_cfg3). Because ReCAP's reformer attribution (feed + furnace) is below the physical floor, the hydrogen CO2 of the incl. figure is re-attributed at the IEAGHG 2017-02 intensity (ieaghg_smr_co2_kg_per_nm3_h2).
Market range No independent range cited.
29.7t/h
ReCAP Base Case 4
Reformer furnace CO2 of configuration 1 (no reformer). Check at the reference capacity: exported CO2 / fuel energy = 61.34 kg/GJ against ReCAP's (57.7 + 29.1) t/h / 338 Gcal/h = 61.34 kg/GJ.
Market range Zero by design.
0t/h
ReCAP Base Case 1
BOUNDARY RULE when hydrogen is a bought inlet: only the SMR feed CO2 is removed from the exported direct CO2. The reformer furnace burns fuel gas that is 54 % refinery fuel gas and 46 % imported natural gas (Table 6-7, note 1), plus the tail gas left after hydrogen purification (Table 6-7, note 4); none of it is bought for the SMR. Without the SMR that refinery gas is still burnt in the refinery, so this 3.7 t/h stays in the exported direct CO2, its energy stays in the specific energy (885 Gcal/h) and its natural gas share stays in the gas inlet (22.7 t/h). It still counts in the hydrogen attribution (feed + furnace) and is subtracted once from the incl. figure. Check at the reference capacity: exported CO2 / fuel energy = 65.23 kg/GJ against ReCAP's (133.4 + 64.1 + 44.3) t/h / 885 Gcal/h = 65.26 kg/GJ (0.04 %).
Market range No independent range cited.
3.7t/h
ReCAP Base Case 2
Same boundary rule as configuration 2: the furnace fuel is 99.8 % refinery fuel gas (Table 8-7, note 1), not bought for the SMR, so this 19.8 t/h stays in the exported direct CO2 and its energy in the specific energy (1,393 Gcal/h); the gas inlet is unchanged. It completes ReCAP's reformer attribution (feed + furnace) and is subtracted once from the incl. figure. Check at the reference capacity: exported CO2 / fuel energy = 63.29 kg/GJ against ReCAP's (217.7 + 98.3 + 53.1) t/h / 1,393 Gcal/h = 63.29 kg/GJ.
Market range No independent range cited.
19.8t/h
ReCAP Base Case 4
Test applied to ReCAP's reformer attribution: below it, the attribution is physically incomplete and is replaced.
Market range Not a market value.
5.46kg/kg
Stoichiometry
Hydrogen CO2 of configuration 3, whose ReCAP attribution fails the stoichiometric floor: 114,653 Nm3/h x 0.8091 = 92.8 t/h.
Market range No independent range cited.
0.8091kg/Nm3
IEAGHG 2017-02 Base Case
Refinery fuel fired, converted to GJ per tonne of crude.
Market range BREF EU specific energy 1.5-4.0 GJ/t, average 2.75 GJ/t.
338Gcal/h
ReCAP Base Case 1
Refinery fuel fired, converted to GJ per tonne of crude.
Market range BREF EU specific energy 1.5-4.0 GJ/t, average 2.75 GJ/t.
885Gcal/h
ReCAP Base Case 2
Refinery fuel fired, converted to GJ per tonne of crude.
Market range BREF EU specific energy 1.5-4.0 GJ/t, average 2.75 GJ/t.
1393Gcal/h
ReCAP Base Case 4
Imported natural gas burnt as fuel; configuration 1 has no SMR.
Market range No independent range cited.
14.5t/h
ReCAP Base Case 1
Imported natural gas burnt as fuel, including the 46 % natural gas share of the reformer furnace fuel, which stays in the inlet as the furnace CO2 stays in the direct CO2; the SMR feed gas is excluded because hydrogen is an inlet.
Market range No independent range cited.
22.7t/h
ReCAP Base Case 2
Imported natural gas burnt as fuel (0.1 t/h to the fuel system, 22.9 t/h to the gas turbine); the reformer furnaces burn 99.8 % refinery fuel gas, so nothing is removed for them. The SMR feed gas is excluded because hydrogen is an inlet.
Market range No independent range cited.
23t/h
ReCAP Base Case 4
Converts the natural gas mass flow to energy (LHV).
Market range About 45-50 MJ/kg depending on gas composition.
46.5MJ/kg
IEAGHG 2017-02
Shown converted to MJ/kg next to the LHV used.
Market range No independent range cited.
11103kcal/kg
ReCAP Table 4-8
Natural gas is exported and priced per MWh HHV (key ng_price_eur_per_mwh).
Market range
0.9
US EPA CHP Catalog
On-purpose hydrogen beyond the catalytic reformer, i.e. what an SMR, ATR or electrolyser would supply through the hydrogen inlet.
Market range No independent range cited.
0Nm3/h
ReCAP Base Case 1
On-purpose hydrogen beyond the catalytic reformer, i.e. what an SMR, ATR or electrolyser would supply through the hydrogen inlet.
Market range No independent range cited.
19724Nm3/h
ReCAP Base Case 2
On-purpose hydrogen beyond the catalytic reformer, i.e. what an SMR, ATR or electrolyser would supply through the hydrogen inlet.
Market range No independent range cited.
114653Nm3/h
ReCAP Base Case 4
Converts SMR Nm3/h into kg/h.
Market range 0.0899 kg/Nm3 (0 C, 1 atm).
0.08994kg/Nm3
IEAGHG 2017-02
Informational: electricity demand, not an inlet.
Market range No independent range cited.
26800kW
ReCAP Base Case 1
Informational: steam demand, not an inlet.
Market range No independent range cited.
160t/h
ReCAP Base Case 1
Informational: electricity demand, not an inlet.
Market range No independent range cited.
54648kW
ReCAP Base Case 2
Informational: steam demand, not an inlet.
Market range No independent range cited.
359t/h
ReCAP Base Case 2
Informational: electricity demand, not an inlet.
Market range No independent range cited.
113180kW
ReCAP Base Case 4
Informational: steam demand, not an inlet.
Market range No independent range cited.
414t/h
ReCAP Base Case 4
Removes the SMR share of the capital cost and splits TIC from TCR.
Market range Kaiser 2017: replacement cost new 16,600 +/- 9,800 USD/bpd (2010-2012 USD), a different basis.
1626MUSD
ReCAP D3 Base Case 1
All-in capital requirement, exported to the project as a fully financed figure.
Market range Kaiser 2017: replacement cost 16,600 +/- 9,800 USD/bpd (2010-2012 USD, installed, no financing), below this all-in TCR of 22,556 USD Q4-2015/bpd (contingency, owner cost and IDC included). Different basis and year: qualitative cross-check only.
2,255.6MUSD
ReCAP D3 Base Case 1
Fixed O&M exported to the project.
Market range No independent range cited.
104.713MUSD/year
ReCAP D3 Base Case 1
Labour part of the fixed O&M, held constant inside the configuration's 0.5-1.5x capacity domain (same units, same shifts). Maintenance and insurance, which D3 sets as shares of the plant cost, scale with the capital exponent.
Market range No independent range cited.
29.44MUSD/year
ReCAP D3 Base Case 1
Variable non-fuel O&M.
Market range No independent range cited.
51.48MUSD/year
ReCAP D3 Base Case 1
Variable non-fuel O&M.
Market range No independent range cited.
0.084MUSD/year
ReCAP D3 Base Case 1
Removes the SMR share of the capital cost and splits TIC from TCR.
Market range Kaiser 2017: replacement cost new 16,600 +/- 9,800 USD/bpd (2010-2012 USD), a different basis.
4014MUSD
ReCAP D3 Base Case 2
All-in capital requirement, exported to the project as a fully financed figure.
Market range Kaiser 2017: replacement cost 16,600 +/- 9,800 USD/bpd (2010-2012 USD, installed, no financing), below this all-in TCR of 25,279 USD Q4-2015/bpd (contingency, owner cost and IDC included). Different basis and year: qualitative cross-check only.
5,561.372MUSD
ReCAP D3 Base Case 2
Fixed O&M exported to the project.
Market range No independent range cited.
237.297MUSD/year
ReCAP D3 Base Case 2
Labour part of the fixed O&M, held constant inside the configuration's 0.5-1.5x capacity domain (same units, same shifts). Maintenance and insurance, which D3 sets as shares of the plant cost, scale with the capital exponent.
Market range No independent range cited.
42.96MUSD/year
ReCAP D3 Base Case 2
Variable non-fuel O&M.
Market range No independent range cited.
140.195MUSD/year
ReCAP D3 Base Case 2
Variable non-fuel O&M.
Market range No independent range cited.
2.176MUSD/year
ReCAP D3 Base Case 2
Removes the SMR share of the capital cost and splits TIC from TCR.
Market range Kaiser 2017: replacement cost new 16,600 +/- 9,800 USD/bpd (2010-2012 USD), a different basis.
6555MUSD
ReCAP D3 Base Case 4
All-in capital requirement, exported to the project as a fully financed figure.
Market range Kaiser 2017: replacement cost 16,600 +/- 9,800 USD/bpd (2010-2012 USD, installed, no financing), below this all-in TCR of 25,937 USD Q4-2015/bpd (contingency, owner cost and IDC included). Different basis and year: qualitative cross-check only.
9,078.096MUSD
ReCAP D3 Base Case 4
Fixed O&M exported to the project.
Market range No independent range cited.
380.974MUSD/year
ReCAP D3 Base Case 4
Labour part of the fixed O&M, held constant inside the configuration's 0.5-1.5x capacity domain (same units, same shifts). Maintenance and insurance, which D3 sets as shares of the plant cost, scale with the capital exponent.
Market range No independent range cited.
54.32MUSD/year
ReCAP D3 Base Case 4
Variable non-fuel O&M.
Market range No independent range cited.
240.9MUSD/year
ReCAP D3 Base Case 4
Variable non-fuel O&M.
Market range No independent range cited.
2.436MUSD/year
ReCAP D3 Base Case 4
SMR share of TIC removed from the capital cost.
Market range Zero by design.
0MUSD
ReCAP D3 Table 4
Removed because hydrogen is bought through the inlet.
Market range No independent range cited.
42MUSD
ReCAP D3 Table 4
Removed because hydrogen is bought through the inlet.
Market range No independent range cited.
178MUSD
ReCAP D3 Table 4
Converts every USD Q4-2015 cost and every 2015 USD price to EUR 2015.
Market range Annual average; 1.05-1.20 within 2015 daily data (no independent range cited).
1.1095USD/EUR
Eurostat annual average 2015
Exponent of the capital cost on capacity within one configuration, transferred from ReCAP's utility units (D5 range 0.5-0.85) to the whole refinery: no source prints the CAPEX of one refinery design at two sizes. TCR, TIC and the capital-linked fixed O&M (maintenance, insurance and other) scale with (capacity / reference capacity)^0.7, so the cost per barrel rises below the reference capacity and falls above it. The transfer is only used within 0.5-1.5x the reference capacity of each configuration; outside it the inputs are rejected.
Market range
0.7
ReCAP D5 Appendix B
Clamp floor required by the scaled-capex convention; checked at the corners of the valid domain, it does not bind there.
Market range Not a market value.
5000EUR/bpd
Guard rail
Clamp ceiling required by the scaled-capex convention; checked at the corners of the valid domain, it does not bind there.
Market range Not a market value.
60000EUR/bpd
Guard rail
Annual capital charge = TCR / 11.53, so the processing cost stays on ReCAP's own basis.
Market range No independent range cited.
11.53years
ReCAP D3
Real/nominal basis not stated by ReCAP; costs are constant USD Q4-2015.
Market range No independent range cited.
8%
ReCAP D3
Economic lifetime of the refinery.
Market range No independent range cited.
25years
ReCAP D3
Shown converted next to the gas price input.
Market range No independent range cited.
6.6USD/GJ
ReCAP D3 Table 5
0.114 / 0.08994 = 1.2675 EUR/kg, the default of the hydrogen price input.
Market range No independent range cited.
0.114EUR/Nm3
IEAGHG 2017-02
Reference processing cost on ReCAP's own boundary (with SMR, without bought hydrogen).
Market range No independent range cited.
11.13USD/bbl
ReCAP D3 Table 3
Reference processing cost on ReCAP's own boundary.
Market range No independent range cited.
11.96USD/bbl
ReCAP D3 Table 3
Reference processing cost on ReCAP's own boundary.
Market range No independent range cited.
12.01USD/bbl
ReCAP D3 Table 3
Gasoline volume per volume of crude. The case's cost, energy, CO2 and hydrogen are ReCAP (D3/TR8, USD Q4-2015); its product yields are OGJ 1996. TR8 prints each base case's balance in kt/y by grade, with imported vacuum gasoil, MTBE and bio-components among the raw materials, not as volume yields per barrel of crude, so it is not mapped onto this slate. The yields do not enter the processing cost, only the product outputs and the indicative margins.
Market range No independent range cited.
20% vol of crude
OGJ Johnston 1996
Middle distillates volume per volume of crude.
Market range No independent range cited.
35% vol of crude
OGJ Johnston 1996
Fuel oil volume per volume of crude.
Market range No independent range cited.
30% vol of crude
OGJ Johnston 1996
Other products volume per volume of crude.
Market range No independent range cited.
10% vol of crude
OGJ Johnston 1996
Volume loss (negative) or gain (positive) of the slate.
Market range No independent range cited.
-5% vol of crude
OGJ Johnston 1996
Gasoline volume per volume of crude. The case's cost, energy, CO2 and hydrogen are ReCAP (D3/TR8, USD Q4-2015); its product yields are OGJ 1996. TR8 prints each base case's balance in kt/y by grade, with imported vacuum gasoil, MTBE and bio-components among the raw materials, not as volume yields per barrel of crude, so it is not mapped onto this slate. The yields do not enter the processing cost, only the product outputs and the indicative margins.
Market range No independent range cited.
30% vol of crude
OGJ Johnston 1996
Middle distillates volume per volume of crude.
Market range No independent range cited.
30% vol of crude
OGJ Johnston 1996
Fuel oil volume per volume of crude.
Market range No independent range cited.
30% vol of crude
OGJ Johnston 1996
Other products volume per volume of crude.
Market range No independent range cited.
15% vol of crude
OGJ Johnston 1996
Volume loss (negative) or gain (positive) of the slate.
Market range No independent range cited.
5% vol of crude
OGJ Johnston 1996
Gasoline volume per volume of crude. The case's cost, energy, CO2 and hydrogen are ReCAP (D3/TR8, USD Q4-2015); its product yields are OGJ 1996. TR8 prints each base case's balance in kt/y by grade, with imported vacuum gasoil, MTBE and bio-components among the raw materials, not as volume yields per barrel of crude, so it is not mapped onto this slate. The yields do not enter the processing cost, only the product outputs and the indicative margins.
Market range No independent range cited.
50% vol of crude
OGJ Johnston 1996
Middle distillates volume per volume of crude.
Market range No independent range cited.
30% vol of crude
OGJ Johnston 1996
Fuel oil volume per volume of crude.
Market range No independent range cited.
15% vol of crude
OGJ Johnston 1996
Other products volume per volume of crude.
Market range No independent range cited.
15% vol of crude
OGJ Johnston 1996
Volume loss (negative) or gain (positive) of the slate.
Market range No independent range cited.
10% vol of crude
OGJ Johnston 1996
Splits middle distillates into jet/kerosene and diesel.
Market range
25%
Derived from US EIA
Lower end of the indicative Nelson complexity range.
Market range No independent range cited.
2
OGJ Johnston 1996
Upper end of the indicative Nelson complexity range.
Market range No independent range cited.
3
OGJ Johnston 1996
Lower end of the indicative Nelson complexity range.
Market range No independent range cited.
5
OGJ Johnston 1996
Upper end of the indicative Nelson complexity range.
Market range No independent range cited.
6
OGJ Johnston 1996
Lower end of the indicative Nelson complexity range.
Market range No independent range cited.
9
OGJ Johnston 1996
Upper end of the indicative Nelson complexity range.
Market range No independent range cited.
10
OGJ Johnston 1996
Puts the class midpoint in relation to the 1996 US average.
Market range No independent range cited.
9.5
OGJ Johnston 1996
First EU category limit.
Market range Not applicable (category limit).
3.9
JRC BREF 2015
Second EU category limit.
Market range Not applicable (category limit).
6.1
JRC BREF 2015
Third EU category limit.
Market range Not applicable (category limit).
8.4
JRC BREF 2015
Code of the BREF category 'NCI below 3.9'.
Market range Not applicable.
1
Calculator convention
Code of the BREF category 'NCI 3.9 to below 6.1'.
Market range Not applicable.
2
Calculator convention
Code of the BREF category 'NCI 6.1 to 8.4'.
Market range Not applicable.
3
Calculator convention
Code of the BREF category 'NCI above 8.4'.
Market range Not applicable.
4
Calculator convention
Denominator of the energy load penalty ratio.
Market range
2.75GJ/t
JRC BREF 2015
Denominator of the CO2 intensity ratio to the EU average.
Market range
0.22t/t
JRC BREF 2015
Default of the input ng_price_eur_per_mwh (EUR 2015, HHV).
Market range No independent range cited.
19.27EUR/MWh
Derived from ReCAP D3
Declared so the reader can see both rates.
Market range Not applicable.
1.11USD/EUR
ReCAP D5
ReCAP's highest printed processing cost (BC3, 13.70 USD/bbl = 12.35 EUR2015/bbl at reference capacity and full run). Not modelled; context for the processing cost bound 8.9-17.5 EUR2015/bbl, which also covers reduced capacity and utilisation.
Market range ReCAP BC1-BC4: 11.13-13.70 USD Q4-2015/bbl.
13.7USD/bbl
ReCAP D3 Table 3
Qualitative cross-check of the capital cost level, and the source of the customized CAPEX range: (16,600 -/+ 9,800) USD/bpd = 6,800-26,400 USD 2011/bpd (2010-2012 transactions, taken at 2011), x ReCAP TCR/TIC 1.385 (D3 Table 1, BC2 5,561,372 / 4,014,000) to reach the all-in TCR scope, x CEPCI 2015 / 2011 = 556.8 / 585.7 = 0.9507, / 1.1095 USD/EUR (Eurostat 2015) = 8,070-31,330 EUR2015/bpd, used as 8,100-31,300 on the input.
Market range 16,600 +/- 9,800 USD/bpd (one standard deviation, 2010-2012 USD).
16600USD/bpd
Kaiser 2017
Checked at the corners of the valid domain: 369 kt (configuration 1 at 50,000 bpd) to 4,269 kt (configuration 3 at 400,000 bpd).
Market range 0.15-5.5 Mt/yr.
—Mt/yr
JRC BREF 2015
Defaults of the price inputs, all in 2015 USD converted at 1.1095 USD/EUR.
Market range No independent range cited.
—USD/gal
US EIA spot prices 2015
METHOD. Complexity is a configuration selector, not a continuous NCI. Under Nelson's linear rule cost scales with NCI (OGJ: complexity 12 costs about 26 % more than 9.5), but ReCAP's engineering TIC per bpd rises only about 1.15x from BC1 (100,000 bpd) to BC4 (350,000 bpd). Capacity and complexity change together across these cases, so the two effects cannot be separated from them. A continuous-NCI version would need each ReCAP case's NCI, which the reports show only in a figure. Each case mixes two sources: ReCAP for cost, energy, CO2 and hydrogen, OGJ 1996 for the product yields (see the yield assumptions).
Market range Not applicable.
—
Method note
CHAINING. Hydrogen (t/yr) is an inlet: chain it to an SMR, ATR or electrolyser calculator and the SMR capital (42 / 178 MUSD in BC2 / BC4) and the SMR feed CO2 are already excluded here, so nothing is counted twice. The reformer furnace CO2 stays: its refinery fuel gas is still burnt in the refinery without the SMR. Fuel natural gas is an inlet in MWh HHV under the price key ng_price_eur_per_mwh. Electricity and steam are self-generated inside the refinery and are not exported. Crude oil is not a canonical commodity of the library: its purchase is booked once in costs.opex.variable_excluding_feedstocks, so a project that sells the products does not show a phantom margin. 'Other products incl. LPG' has no single commodity and is not exported as an outlet (its value is only in the margin outputs).
Market range Not applicable.
—
Chaining doctrine
CURRENCY. All outputs are EUR 2015 (currency_year 2015 in the meta). ReCAP costs are USD Q4-2015, EIA prices are 2015 annual averages in USD, both converted at the Eurostat 2015 average 1.1095 USD/EUR. The hydrogen price default is IEAGHG 4Q-2014 EUR and is not re-indexed (one-year mismatch, declared). No figure is compared at parity across currencies or years.
Market range Not applicable.
—
Money basis
BOUND. 8.9-17.5 EUR2015/bbl = the corners of the valid domain (configuration x capacity 0.5 / 1.5x reference x utilisation 75 / 100 %) on the model CAPEX, at ReCAP's gas price and the IEAGHG hydrogen price: 8.97 (configuration 1 at 150,000 bpd, 100 %) to 17.39 (configuration 3 at 175,000 bpd, 75 %); capital and fixed O&M per barrel rise as 1 / utilisation. Crude and product prices do not enter the processing cost. The gas and hydrogen prices legitimately move it outside: at the corners of gas 0-80 EUR/MWh and hydrogen 0-8 EUR/kg it spans 8.01-23.52 EUR/bbl. A customized CAPEX (8,100-31,300 EUR2015/bpd) also moves it: 5.58-18.94 EUR/bbl at the corners. The charts sweep capacity, utilisation, configuration and crude price only, on the model CAPEX.
Market range Not applicable.
—EUR/bbl
Bound note
Index of the Kaiser 2017 replacement cost, used only to bring the customized CAPEX range to 2015.
Market range No independent range cited.
585.7index
CEPCI 2011
Index of the calculator's money year (2015), used only for the customized CAPEX range.
Market range No independent range cited.
556.8index
CEPCI 2015
Range of the crude utilisation input: 75 % = the 2020 EU low restated on 350 days; 100 % = the ReCAP design basis (350 days at stream-day capacity). The 2008-2019 band (78-86 % calendar) is 81-90 % on the same basis.
Market range
75%
FuelsEurope 2022
LIMITS. The asset is a whole refinery (about 15 units). The size is clear (crude distillation capacity, bpd), but no source gives the CAPEX of one configuration at two sizes: ReCAP anchors three designs, each at a single size (BC1 100,000, BC2 220,000, BC4 350,000 bpd), and complexity changes with size. The scale law is therefore a declared transfer (exponent 0.7 of D5, typical of utility units). The minimum reduction that keeps it defensible is the one in place: 0.5-1.5x the reference size of each configuration, inputs rejected (invalid_input) outside. Utilisation scales crude, products, fuel gas, hydrogen, CO2 and chemicals linearly; capital and fixed O&M stay constant; no part-load efficiency penalty is modelled. With a customized CAPEX, the installed cost and the TCR/TIC ratio are derived from the retained CAPEX (ratio held at ReCAP's), maintenance and insurance follow it, and the 'ReCAP boundary' output stays on the model path.
Market range Not applicable.
—
Model limits

Crude oil refinery (complexity-based screening)

Mass and energy balance

CAPEX

Included

Not included

Added at project level

Project figures

Processing cost (levelised)

All results

Processing cost

Capital

Throughput & products

Energy & losses

Hydrogen & CO2

Refining margin (indicative)

Complexity

Sensitivities

Sources

About

Model

User inputs · 13

Constants · 128

Intermediate calcs · 53

Exposed outputs · 84

Assumptions