H2Tech - Q4 2021 - 47

HYDROGEN STORAGE
Salt caverns for the storage of H2
are constructed by the
same methods as other gas storage caverns. Under-saturated
water is injected into a salt formation, where the highly-soluble
halite, natural occurring salt (sodium chloride), will go into solution.
The salt-saturated fluid, brine, is circulated back to the
surface. Approximately 7-10 volumes of water are required for
each volume of salt dissolved.
A solution mining well consists of multiple strings of casing,
steel pipe that are cemented into the drilled hole and that serve
as the barrier between the open volume in the hole (the " annulus " )
and the adjacent rock. Cement fills the void between the
outside wall of the pipe and the rock face to form an impermeable
barrier to prevent brine and/or stored gas from migrating
vertically, and isolates the well contents from any groundwater
resources. The casing is held in place at the top of the cavern by
a cement plug set between the casing and the salt (referred to
as a " shoe " ). For H2
als that are H2
service, care must be taken to select matericompatible.
A
string of pipe hung within the casing is called a " mining
string. " The water is injected via tubing lowered into the mining
string from the surface, which is attached to, or " hung, "
from the wellhead. As water is pumped down the injection
tubing into the cavern void, the newly formed brine in the cavern
is displaced to the space between the mining string and the
injection tubing.
At the initiation of the solution mining operation, an inert
fluid, diesel or nitrogen gas is first pumped down and maintained
as a stagnant layer above the bottom of the mining
string and up the annulus to the wellhead. This " blanket " protects
the salt at the top of the cavern from erosion around the
casing shoe.
Upon completion of the cavern, the cavern integrity is assessed
by a mechanical integrity test (MIT). Fluid is pumped
into the cavern until the permitted maximum operating pressure
is attained and held for a period specified by the regulator.
If the cavern pressure is maintained over the test period, the
cavern is not leaking and can be put into service. Due to the
high mobility of H2
, the best practice is to conduct the MIT for
a longer time period than those used for natural gas.
To put the cavern into service, gas is injected into the cavern,
which displaces the brine to the surface (i.e., " de-brining " ).
Operator
ConocoPhillips
Praxair
Air Liquide
Clemens Dome, TX
Moss Bluff Dome, TX
Spindletop Dome, TX
SABIC Petrochemical Teesside, UK
LDC Town gasa
LDC Town gasa
Kiel, Germany
Bad Lauchstad,
Germany
a Converted to natural gas storage
H2Tech | Q4 2021 47
Year
1986
Eventually, the gas volume displaces all the brine in the cavern.
Until the cavern is de-brined, storage operations are limited
to injection, and withdrawals ( " discharges " ) are limited in
duration and magnitude. Once completely de-brined, storage
operations are unrestricted. Residual moisture in the cavern
requires the withdrawn gas to be dehydrated, but over time
the need for dehydration becomes less necessary.
Insoluble lithic components. Insoluble lithic components
in bedded salts and entrained in salt diapirs present potential
complications for H2
storage due to the reactivity of H2
rock minerals and/or pore fluids, the growth of H2
with
-consuming
microbes and changes in rock properties because of mineral
alteration.24
Based on core testing of the Vosges Sandstone (Triassic age,
France), under a variety of conditions up to 30 bar and 150°C
and in the presence of water and iron, H2
react with quartz or feldspars.23
tential to react directly with sulfur and iron oxide (Fe2
only at higher temperatures and pressures.19
and Ding and Liu27
ers25,26
found that H2
Truche and othdoes
react abiotically
with pyrite, particularly in clay-rich rocks, but only at pressures
and temperatures greater than typically found in salt caverns.
However, kinetic modeling by Hassannayeb and others28
that alkaline pore fluids promoted H2
to pyrrhotite, and loss of H2
found
-induced pyrite reduction
as H2S, at gas storage conditions
but at low volumes. An additional concern is the pyrite oxidation
in the presence of carbonates resulting in the release of
CO2
and acidifying pore fluids, but this appears to be limited
-induced reactions in the presreacts
with dissolved CO2
-bearing pore fluids and methanogenic
in pore fluids to create a
reported induced secondary
report-,
which may promote the
S).
Pressure
2007
2008
1972
1971
1970s
1 × 1.4 Bft3
volume 2,400 H2
W.G. 2.5 Bft3
volume 3,690 H2
1,105-1,958 psi
70-135 bar
566,000 m3
3 Bft3
t
volume 8,230 H2
3 × 0.25 Bft3
(3 × 70,000 m3
1 × 0.01 Bft3
(1 × 32,000 m3
)
W.G. 906,000 m3
t
) 810 H2
t
800-2,200 psi
55-152 bar
(1,646 m)
1,214 ft
(370 m)
1,330 m
(4,363 ft)
820 m
(2,690 ft)
825-2,800 psi
57-193 bar
652 psig
45 bar
1,160-1,450 psig
80-100 bar
2,175 psig
150 bar
to temperatures higher than typical cavern storage operations.29
The greater concern is H2
ence of saline, CO2
bacteria. Carbonate, anhydrite and barite may be dissolved
when H2
weak acid. Henkel and others21
porosity from Permo-Triassic sandstones used for gas storage
in Germany at ambient conditions. Flesch and Pudlo20
ed an increase in porosity in sandstone core samples after saturation
by 100% H2
Barite dissolution22
TABLE 8. Hydrogen salt cavern storage facilities (modified from literature16,17
Location
Size
1 × 1.07 Bft3
580,000 m3
W.G. 2.273 Bft3
total
t
total
)
Depth
2,800 ft
(850 m)
2,700-4,600 ft
(822-1,402 m)
5,400 ft
formation of hydrogen sulfide (H2
under burial conditions and saline fluids.
increased SO4
does not appear to
O3
H2, theoretically, has the po),
but
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