HP March 2022 eBook—Energy Transition - 38

Special Focus Plant Design, Engineering and Construction
F. BAARS, Fluor, Amsterdam, Netherlands; and
S. ORUGANTI and P. KALIA, Fluor, New Delhi, India
Oil refinery/petrochemical integration
in a CO2
-constrained world-Part 1
Petrochemical demand will increase with gross domestic
product, while motor fuel demand will only show modest
growth and may even decline in certain regions, given environmental/legislative
pressure and the introduction of batterypowered
electric vehicles. Any new oil refinery will likely include
petrochemical facilities, as well. This article evaluates several
configurations, highlighting salient differences between them
(including economics) and assessing their sensitivity to product
and feed price fluctuations, cost of utilities, type of crude and
a carbon dioxide (CO2
) tax. These options are evaluated complex-wide
as the only way to ensure that schemes are compared
on a consistent basis and that all interactions and synergies between
units are considered.
While the scenarios and investment costs are based on new
facilities, the methodology could equally be applied to revamp
projects where options to expand refinery operations with petrochemical
units are being considered, along with the revamp
costs of existing assets.
The base case refinery scheme includes either a residue fluid
catalytic cracking unit (RFCCU) or a hydrocracking unit (HCU).
The feed to the RFCCU comes from an atmospheric residue desulfurization
(ARDS) unit. The hydrocracker schemes include a
delayed coking unit (DCU) or residue HCU (RHCU) as a residue
conversion unit. The complex includes motor fuel (Euro-5
gasoline and diesel) and jet fuel production. Where required,
ethyl tertiary butyl ether (ETBE) is imported as a gasoline pool
component. In some cases, fuel-oil components are produced.
The petrochemical facilities produce base petrochemicals
such as polyethylene (PE), polypropylene (PP), butadiene,
benzene and paraxylene (PX). The complex includes a hydrogen
production unit (HPU)-based on steam reforming-to
balance the refinery's hydrogen demand.
The complex processes 10 MMtpy of Urals crude, priced at
$70/bbl. The complex will only import natural gas (for process
and utility heater service, as well as for hydrogen production),
electric power and raw water.
The economic evaluation depends on the prices of raw materials,
products and utilities, as well as the unit prices of steel
and the costs of construction, labor, etc. The economic analyses
detailed in this article are more representative of the differences
between certain schemes, rather than of being correct in
the absolute sense.
Part 1 introduces the various configurations and how they
compare based on investment cost, gross and net margin, and
internal rate of return (IRR). Part 2, which will be featured in
the August issue of Hydrocarbon Processing, will discuss crude
effects, CO2
emissions and the impact of a CO2
tax on IRR.
RFCCU alternates. The RFCCU is a propylene-optimized
unit, with approximately 17 wt% of C3
= from the RFCCU reactor.
The RFCCU feed is pretreated in an ARDS unit, taking
atmospheric residue directly from the crude distillation unit
(CDU). The complex includes ETBE and alkylation units to
facilitate Euro-5 gasoline manufacturing. In case of isobutane
(iC4
) insufficiency for the alkylation unit, a C4
isomerization unit
processing RFCCU and other refinery butanes is included. The
petrochemical extensions include the addition of a PP unit to
process polymer-grade propylene from the RFCCU (Case A1)
and an aromatics complex (Case A2). The PP unit consists of
two trains. An ethylene recovery unit (ERU)-recovering ethylene
from FCCU dry gas-is included for cases A1 and A2, with
the ethylene co-feed to the PP unit to also produce impact and
random co-polymers; excess ethylene is sold. In Case A2, the reformate
is sent to the aromatics complex. The raffinate from the
aromatics units is used for gasoline blending. TABLE 1 provides
an overview of the units considered under the various schemes.
A graphical depiction of scheme A2 (RFCCU, PP unit and
aromatics complex) is shown in FIG. 1, with traditional refinery
units in green (and blue for the residue conversion units) and
with petrochemical units in yellow or pink (aromatics).
The evaluation results are detailed in TABLE 2. Gross margin
is the value of the products sold minus the cost of all feeds purchased.
Net margin in this article is the gross margin minus the
cost of utilities, catalyst and chemicals. Investment cost includes
the total engineering, procurement and construction (EPC)
cost of the complex, excluding the owner's cost. Simple payback
is the straightforward calculation of the total EPC investment
cost against the net margin, based on a complex operating 8,400
hr/yr. All costs are based on Western European costs in 2019.
IRR is based on an 8% weighted average cost of cash, 2% inflation,
a yearly maintenance cost of 1% of investment costs, a 4-yr
construction period, and a project life of 20 yr. Petrochemicals
output is the sum of polyolefins, benzene, PX, propylene and
ethylene production.
Adding petrochemical units increases the gross margin. Adding
a PP unit increases the gross margin by $52/t and the net margin
by $40/t (Case A1), comfortably paying for the $676 MM
higher capital cost (with the PP unit consisting of two trains), and
Hydrocarbon Processing | JULY 2021 | HydrocarbonProcessing.com
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