Hydrocarbon Processing - August 2022 - 33

Refining Technology
these three streams for a 70,000-NM3
hr H2
/
plant meeting the requirement of
a 100,000-bpd deep-conversion refinery
with a coker.
The stream at the inlet of the PSA
unit has high operating pressure and
high partial pressure of CO2
. CO2
capture
from streams with high partial pressure
of CO2
is proven using methyldiethylamine
(MDEA). Due to the high
pressure, a fan is not required, and piping
and absorber sizes are smaller compared
to low-pressure streams. MDEA is a tertiary
amine with high CO2
absorption
capacity, low regeneration energy compared
to primary amine [such as monoethanolamine
(MEA)], but also has a
slower reaction rate.
Piperazine is typically added as an activator
to MDEA to increase the rate of
reaction. Typically, a recovery of 90% is
achievable. In the above reference plant,
this would give 250,000 tpy of CO2
recovery.
For a deep-conversion refinery
with a residue hydrocracker, applying
CO2
yield 750,000 tpy of CO2
capture on this stream alone can
. This scheme
is similar to that depicted in FIG. 2, except
that a fan is not required.
Recovery from this high-pressure
stream alone yields 52%-55% of the total
CO2
from an SMRU. The PSA outlet
stream is at a lower operating pressure
but higher CO2
content. A compressor
will be required to boost pressure to approximately
10 barg to use the MDEA
process. Equipment
sizes required will
increase and additional energy will be
needed for compression. Design pressures
will reduce compared to Option 1.
A preliminary analysis indicates this option
will be uneconomical at most sites
and is not discussed further here.
Capturing CO2
gases can lead to much higher CO2
from reformer flue
recovery.
Typically for these low-pressure
streams, primary amines such as MEA
or similar solvents are used. These have
limited absorption capacities and usable
solution concentration ranges. The energy
required for regeneration of solvent is
significantly higher compared to MDEA.
Low pressure implies large ducts and absorber
sizes. In the above reference plant,
this option would capture ~500,000 tpy
of CO2
recovery.
CO2 absorption is most efficient at gas
temperatures between 30°C and 50°C.
This implies that when capturing CO2
from flue gas, there will be a cooling requirement
before routing to an absorber.
This adds additional equipment and the
need for either cooling water or additional
energy to use air cooling/a gas-gas
exchanger, significantly impacting the
economics of CO2
recovery.
The above options are applicable for
refineries with existing SMR-based H2
production units. Refineries also have
an option to explore alternate routes for
meeting H2
clude:
* Green H2
requirements. This may in,
which is produced by
electrolyzing water with the use of
renewable energy
* H2 production from alternate fossil
feedstocks, such as petroleum
coke/coal gasification with carbon
capture.
Green H2 is a promising alternative in
areas with abundant and uninterrupted
renewable energy and will become more
attractive as capital costs reduce in the future.
This option is not discussed further
in this article. The option of integrating
petroleum coke/coal gasification with
CO2 capture is another promising alternative
for low-carbon H2
discussed in the next section.
Gasification for H2
production. Gasification
is the partial oxidation of any
fossil fuel to synthesis gas (syngas), in
which the major components are H2
CO. To produce H2
and
, syngas is routed to
the shift unit, where CO is shifted to H2
and CO2
moves hydrogen sulfide (H2
.
Shifted and cleaned syngas is routed to
the PSA unit where H2
the degree of CO2
is recovered, and
the rejected tail gas is available for use as
fuel (FIG. 5). A two-stage shift increases
the H2
content in the fuel and maximizes
removal. Gasification
requires pure oxygen, which is produced
in the air separation unit (ASU).
Feedstock for gasification can be petroleum
coke, coal or heavy liquid ends from
refining. High-pressure steam is co-produced
from heat recovery in syngas and
PSA tail gas as fuel. The gasification system
and refinery operations can share amine
stripper, sulfur block, water treatment and
Hydrocarbon Processing | AUGUST 2022 33
. An acid gas treatment unit reS)
and CO2
, and is briefly
TABLE 4. CO2 streams in SMR H2
Stream
PSA inlet
PSA tail gas
Flue gas
Pressure, barg Temperature, °C
26
1.3
35
30
130
CO2
, mol%
16
50
20
CO2
, tpd
870
870
1,450
FIG. 5. H2 production from gasification.
FIG. 4. H2 production via SMR with three carbon capture options.
Hydrocarbon Processing - August 2022

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