H2Tech - Q3 2021 - 24

SPECIAL FOCUS HYDROGEN INFRASTRUCTURE DEVELOPMENT
sidered to be acceptable with an upper limit of 20 mol% concentration
H2
in natural gas.2
UK National Grid records7
show
an approximately 40% average annual utilization of the South
Hook terminal sending natural gas to the grid. Winter peak demand
is countered by low energy demand during summer.
In this study, average natural gas usage of 6.24 MMtpy is
considered as the baseload, and of this volume 0.541 MMtpy is
converted to H2
to 0.171 MMtpy of H2
, corresponding
product
at the delivery point. Mixing
the H2
with the resulting natural
mixture into the
emissions reduction
gas produces 5.871 MMtpy of
a 20 mol% H2
export pipeline; the resulting
calorific valve is slightly lower at
approximately 98.5%. The estimated
CO2
from the gas is 1.183 MMtpy,
or approximately 7% compared
to that emitted from the 100%
natural gas reference flow.
For all scenarios, the CO2
In this study, the estimated CO2
emissions reduction from the gas is
1.183 MMtpy, or approximately 7%
compared to that emitted from the
100% natural gas reference flow.
produced during the natural gas
is still emitted from various parts of
conversion to H2 is captured for permanent storage in Qatar. It
should be noted that CO2
the overall chain, such as power production and shipping.
To ensure a fair comparison between the processing routes,
study boundaries were set. For all options, the upstream process
boundary was fixed at the point where natural gas feed enters
the system. The costs associated with natural gas production,
front-end purification to remove impurities such as sulfur, and
delivery to Ras Laffan are not included in this study. The downstream
process boundary is set at H2
gas production at 20 bar
before compression for distribution in pipelines.
Four scenarios for H2
transportation to determine the most
economically efficient technical solution for transport are
compared. All scenarios consider the product in liquid form at
atmospheric pressure, based on ship type availability:
* LNG
* LH2
* NH3
* MCH.
Study definitions. Green H2
is generally defined as H2
prois
duced
from renewable power such as wind, solar or hydroelectricity
via electrolysis. No hydrocarbons are used, and no CO2
produced in the process.
Gray H2 is generally defined
as H2 derived from hydrocarbons
where CO2
is produced
and emitted to the atmosphere
in the process.
Blue H2
is generally defined
produced
captured.
as H2 derived from hydrocarbons
where the CO2
in the process is captured and
permanently stored. Blue H2
has a range depending on the
percentage of CO2
pose of this study is to compare four different H2
Methodology. Since the purvectors,
it is
important to ensure that the boundary of each system is the
same and the method of costing is comparable, as the resulting
differentials are key.
The majority of the data used is obtained from the public
domain, papers and other literature available on the internet.
This contains an inherent element of uncertainty, since it is not
always entirely clear what scope is included in CAPEX figures,
or what items are included in total installed costs (TIC). Generally,
the CAPEX used was considered to be the cost of equipment
required fully installed. In-house CAPEX data is used
where available, or as a benchmark against data from literature.
Licensing, regulatory and infrastructure interconnections and
owners' costs are not included, nor are costs for minor utilities,
as all plants need these services.
Where a wide range of data is assimilated for CAPEX vs.
capacity for a particular process or storage, the data is plotted
graphically, outliers are disregarded, and average or specific data
are selected from within the group of data. Where the studied
process required a unit capacity larger than presently available or
referenced, it was assumed that several units would be required
for costing purposes. Since only one full liquid H2
eration as a pilot project8
ing data for LH2
chain is in opand
at a small capacity, all of the costa
noticeable trend was observed for LH2
is based on expectation. While gathering data,
liquefaction plant CAPEX
reduction, which led to a sensitivity case being produced
for the more optimistic data. This case shows potential savings
as the technology is developed, scaled up and commercialized.
Operating costs were generated by a fixed percentage of the
CAPEX to cover fixed operating and maintenance (O&M), and
the major feed streams and utility user annual costs (OPEX) are
based on location prices. Generally, this included the cost of the
natural gas feed, power, demineralized water, cooling water, fuel
gas and transportation (ship) fuel.
Infrastructure to deliver clean natural gas to the first process
FIG. 1. Transport route for LNG produced at Ras Laffan, Qatar to
regasification at Milford Haven, Wales, UK.
24 Q3 2021 | H2-Tech.com
block in Qatar is not included. Storage tank CAPEX and OPEX
are included, as these are different between the four options due
to the different energy densities and ship sizes. Loading systems
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