Proceedings, 5th International Offshore and Polar Engineering Conference
The Hague, The Netherlands, June 11-16,1995
TRANSPORT OF NATURAL GAS AS FROZEN HYDRATE
J. S. Gudmundsson and F. Hveding
Norwegian Institute of Technology
Trondheim, Norway
A. Børrehaug
Aker Engineering
Oslo, Norway
ABSTRACT
The capital costs of natural gas hydrate (NGH) and liquefied natural gas (LNG) are compared,
for the transport of 400 MMscf/d (about 4 billion Sm3 per year) of natural gas for a distance
of 5500 km. The NGH chain was found to cost at least one-quarter less than the LNG chain.
Independent studies in Norway, Canada and Russia have shown that frozen hydrates at
atmospheric pressure remain stable long enough to make long-distance transport of natural
gas in the form of hydrate technically feasible.
Figures and Tables at end of paper.
INTRODUCTION
The demand for natural gas in the world is increasing. Two regions are expected to continue
to dominate the increase in gas demand; Europe and Asia Pacific (Commichau 1994, Mellbye
1994, Voigt 1994). Large natural gas resources, however, are not located near the main
population centres in the two regions. The transportation of natural gas over increasingly
longer distances will consequently be required in Europe and Asia Pacific.
The development of the natural gas industry in the next 5-15 years is likely to be dominated
by costs, as evident from statements by Exxon's Voigt "The industry must continue to reduce
project costs, keep gas competitive, and obtain prices in line with full market value" by
Mobil's Commichau "The gas industry faces tremendous challenges, which are mainly of an
economic nature" and by Statoil's Mellbye "...that increasing volumes have to be transported
over increasing distances...can only be profitable if costs are reduced and prices are
increased."
Large-scale transport of natural gas is done in pipelines and by ship in liquefied form. The
cost of natural gas transport is such that pipelines are used for distances up to a few thousand
kilometres, while transport of liquefied natural gas (LNG) by ship is used for greater
distances. The exact distance when pipeline transport and transport by ship are cost effective
depends on a multitude of case-specific factors.
The high cost of LNG technology is a major restraint on the development of natural gas
resources in locations distant from the main population centres in Europe and Asia Pacific.
Because of the worldwide importance of natural gas, considerable effort continues to achieve
cost reductions (Mellbye 1994). However, reductions in the cost of LNG technology is more
likely to be trivial than significant. The use of natural gas hydrates for storing and transport of
natural gas is an interesting alternative to that of using LNG technology. A new method for
the storing and transport of natural gases at atmospheric pressure has been patented by
Gudmundsson (1990). In this new method the natural gas hydrates are refrigerated to about 15 C and then kept at near-adiabatic conditions. The hydrates remain stable, making it
possible to transport natural gas in an insulated bulk carrier to distant gas markets.
The purpose of the present paper is to report a first-order comparison of the capital cost of
natural gas hydrate (NGH) technology to that of established LNG technology. The
comparison shows that the capital cost of a NGH chain is much lower than that of a standard
LNG chain. The details of the work reported in this paper are taken from a Diploma thesis in
petroleum engineering by Hveding (1994).
SNØHVIT CASE STUDY
To facilitate the capital cost comparison of LNG and NGH technology, the Snøhvit offshore
gas field in northern Norway was used as an example. Plans have been presented by Statoil
and its partners to develop the field by piping the natural gas 130 km to an on-shore LNG
facility.
A cost comparison presented by Mellbye (1994) for natural gas transport in northern Europe,
shows that pipeline transport costs are less than LNG transport by ship for distances up to
about 3500 km. The comparison used European prices and conditions and was based on a 48
inches diameter natural gas pipeline and 13 000 m3 LNG ships. Natural gas pipelines from the
North Sea to gas markets in Europe are about 900 kilometres long (Sjøen 1994). Future
natural gas developments in Norway are considerably further north, where transport distances
of up to 6000 kilometres are typical (Mellbye 1994).
It was recently stated by Shell's Nagelvoort and Tijm (1994) that "LNG technology is in
essence mature and since one cannot beat the principles of thermodynamics, it is unrealistic to
expect a dramatic decrease in capital costs from a single process improvement. Therefore,
LNG capital cost reduction needs to he driven by contributions in all aspects of the project."
Nagelvoort and Tijm (1994) concluded that for a total project, taking into consideration likely
improvements in both LNG production and shipping technology, that 5 percent capital cost
reduction was possible.
The Snøhvit offshore field is officially planned to produce up to 12.6 million Sm3 (standard
cubic meters) of natural gas per day. This corresponds to a maximum annual rate of 4.5
billion Sm3. In the present paper, however, an annual production rate of 3.5 billion Sm3 per
year is assumed, based on the capacity of three 125,000 Sm3 LNG ships operating a transport
distance of 3000 nautical miles (about 5500 km). The Snøhvit field is 130 km offshore and
covers an area of 90 km2. Recoverable gas is estimated 103 billion Sm3, recoverable
condensate 9 million Sm3 and recoverable oil 46.7 million Sm3. The water depth in the
Snøhvit field is 330 m and the reservoir depth 2400 m (Falch and Haugen 1992).
NATURAL GAS HYDRATES
Until recently, the use of natural gas hydrates (NGH) for storing and transport purposes has
been a laboratory curiosity, perhaps because most investigators have assumed that high
pressures are required to prevent natural gas hydrates from decomposing (Gudmundsson and
Parlaktuna 1992, Gudmundsson et al. 1994). And because high pressures usually translate into
high equipment costs, the use of natural gas hydrates for large-scale storing and transport of
natural gas has not received much attention. Englezos (1993) has reviewed the literature on
hydrates.
The properties of natural gas hydrates for transport purposes have been presented by Berner
(1992), who proposed that natural gas hydrates be transported by ship at ambient temperature
and having pressure tanks built of reinforced concrete, capable of containing 14.5 bara
pressure. Berner (1992) assumed insulated tanks (12 inches insulation) and estimated that for
a 2500 km voyage (15 knots, 4 days), less than 1 percent of the hydrates would decompose
due to heat transfer from the outside.
Instead of using high pressure to prevent natural gas hydrates from decomposing, it is possible
to refrigerate the hydrates to their equilibrium temperature at atmospheric pressure, which
typically corresponds to -32 C.
This concept was proposed by Benesh (1942) more than 50 years ago. Although the
refrigeration of natural gas hydrates down to -32 C is technically feasible, the storing and
transport of large volumes of hydrates at such a low temperature would not necessarily be
economically feasible.
It was argued by Gudmundsson (1990) that natural gas hydrates need not be refrigerated all
the way down to their equilibrium temperature, to remain stable under large-scale storing and
transport. Instead, it would be sufficient that the hydrates be kept under near-adiabatic
conditions. When large volumes of natural gas hydrates are stored under conditions where
practically no thermal energy is allowed to enter the system, the hydrates will not decompose
rapidly - the decomposition process is basically the same as melting. In effect, the hydrates
are starved of the thermal energy necessary to decompose into natural gas and water. It was
proposed by Gudmundsson (1990) that the natural gas hydrates be stored and transported at
temperatures below the freezing point of water. But above their equilibrium temperature at
atmospheric pressure.
Natural gas hydrates stored adiabatically at atmospheric pressure above the freezing point of
water are expected to decompose slowly into gas and water. For decomposition to occur,
thermal energy is required. The thermal energy can only be extracted from neighbouring
hydrate particles, resulting in gradual cool-down of the hydrates. The decomposition process
is assumed to be slow; the thermal conductivity of natural gas hydrates is relatively low.
Natural gas hydrates stored adiabatically at atmospheric pressure below the freezing point of
water are expected to decompose much slower into gas and ice.
Experimental work reported by Gudmundsson and Parlaktuna (1992) and Gudmundsson et al.
(1994) demonstrated that the rate of decomposition of frozen natural gas hydrates at
atmospheric pressure is negligible. The storage temperatures ranged from -5 C to -15 C. It
was suggested that a natural gas hydrate that decomposes leaves behind a layer of ice that
forms a protective coating, preventing further decomposition. Similar observations were made
in Canada by Davidson et al. (1986) and Handa (1986).
Recently, in Russia, Ershov and Yakushev (1992) and Yakushev and Istomin (1992) reported
unexpected stability of natural gas hydrates stored at atmospheric pressure and temperatures
in the range -1 C to -18 C. One of the hydrate samples was stored for two years at -6 C
without decomposing.
GAS-IN-ICE PROCESS
Three principal technical challenges need to be addressed in the development of a cost
effective natural gas hydrates process. The three challenges are the production, separation and
transport of natural gas hydrates. The production challenge concerns how best to extract the
large amount of thermal energy when natural gas hydrates are formed.
The separation challenge concerns how best to separate the solid hydrates from liquid water
of similar density. The transport challenge concerns how best to store (and transport) large
volumes of natural gas hydrates at near ambient conditions, to avoid the use of high-pressure
and low-temperature conditions. The three principal challenges have been addressed in what
is called the Gas-in-Ice process. The melting of frozen hydrates is not considered difficult and
is consequently not one of the principle technical challenges. The fact that Gas-in-Ice hydrates
are at -15 C provides a temperature driving force that makes it possible to use ambient heat
sinks in the melting process.
The production of natural gas hydrates in the Gas-in-Ice process takes place in a continuous
stirred tank reactor, where natural gas is injected into liquid water. The reactor operates at
about 50 bara pressure and 10 C temperature. An ice/water slurry is also injected into the
reactor to provide the necessary cooling, for the natural gas hydrates to form - the hydrates
form and the ice melts. One to three reactor stages can be used. A schematic flow diagram for
100 MMscf/d of natural gas entering three reactor stages in the Gas-in-Ice process is shown in
Fig. 1.
The mass concentration of the hydrate/liquid mixture leaving each of the reactor stages
increases from about 10 to 30 percent from the first stage to the third. Because an ice/water
slurry is used to provide the enormous amount of cooling, the 50 bara reactor vessels are
simple in design and cost effective - no heat transfer tubes and jackets required. The use of an
ice/water slurry cooling system was a critical step in the development of a cost effective Gasin-Ice process.
The hydrate/liquid water slurry from the last reactor stage needs to be separated. The details
of this part of the Gas-in-Ice process have not yet received much attention. However, it is
anticipated that a combination of cyclone separators and decanters can be used. The use of a
carrying fluid lighter than liquid water is being considered; for example, natural gas
condensate.
The separation part of the Gas-in-Ice process is followed by further dewatering and drying of
the hydrates and then refrigeration to -15 C and pressure reduction. The details of this part of
the process and subsequent pelletization of the hydrates depend on what kind of solids
handling facilities will be selected for storing and ship loading and unloading.
The storing and transport of natural gas hydrates represent the same physical conditions for
the hydrate particles. In the Gas-in-Ice process, these conditions are based on the experimental
results reported by Gudmundsson et al. (1994) that natural gas hydrates remain stable at
atmospheric pressure when kept frozen (-5 to -15 C) at near adiabatic conditions. It is possible
to store natural gas hydrates in rock caverns and other large-volume containers. This kind of
natural gas storage is by far less expensive than LNG storage. In the Gas-in-Ice process,
storage is required to accommodate continuous hydrate production in the time between the
loading of two ships.
CAPITAL COST OF SHIPS
Natural gas hydrates (NGH) take more volume than the equivalent amount of LNG. The
volume of hydrates is about four-times larger than that of LNG, assuming that LNG contains
600 Sm3 and hydrate 150 Sm3 of natural gas. The 150 Sm3 value takes into consideration the
degree of gas filling of the individual hydrate cages, but not the void spaces between hydrate
particles in bulk storage. Therefore, the volume capacity of NGH ships needs to be at least
four-times larger than that of LNG for the same amount of natural gas shipped. This places an
important cost constraint on the ships that will carry frozen hydrates.
Typical LNG ships carry about 125,000 m3 of liquefied natural gas, and 135,000 m3 ships are
under construction (Nagelvoort and Tijm 1994, Hveding 1994). There is no reason why
hydrate ships cannot be at least twice that size; for example, capable of carrying 250,000
m3 of hydrates. The ships used to carry frozen hydrates need be no more than insulated bulk
carriers - the ships need not be refrigerated. Therefore, ships designed to carry hydrates will
be substantially less expensive than an LNG ships.
The capital cost of LNG ships (18 knots) is reported to be 280 million USD for 125,000
m3 ships and 250 million USD for 135,000 m3 ships (Hveding 1994); that is, ranging from
2240 to 1852 USD/m3. Other capital costs have also been reported (Nagelvoort and Tijm
1994). Four 135,000 Sm3 LNG ships being built in Finland are reported to cost in total 6.5
billion NOK (Aftenposten 27.4.93 and Teknisk Ukeblad 6.5.93). Using an exchange rate of
6.8 NOK/USD), the cost per ship becomes about 240 million USD (this cost is highly
uncertain because of changes in exchange rates). In the present study, however, a 125,000
m3 LNG ship was assumed to cost about 250 million USD; that is, 2000 USD/m3. This
assumption implies that the capital cost of future LNG tankers will be determined by general
long-term trends rather than special circumstances.
A hydrate ship capable of transporting one-half that of a 125,000 m3 LNG ship, needs to be
about 250,000 m3, assuming solid hydrate. If the bulk hydrate is assumed to have a porosity of
16.7 percent (=1/6), the total carrying volume of the ships needs to be about 300,000 Sm3. If
the density of the solid hydrate is 928.5 kg/m3, the weight of the hydrate will be 232,125
tonne. Therefore, a 250,000 TDW (tonne dead weight) bulk hydrate carrier was assumed for
capital cost purposes. This over-sizing (about 7 percent) ensures that the capital estimates are
not biased to favour the hydrate ships.
Information obtained about the capital cost of bulk carriers showed that a 207,000 TDW ship
costs about 55 million USD; that is, 265,7 USD per TDW. A 250,000 TDW bulk carrier,
therefore, will cost about 66.4 million USD). The insulation (100 mm thick) of the tanks of
such a bulk carrier was estimated to cost about 3.6 million USD). Furthermore, the loading
and unloading equipment for a hydrate ship was assumed 10 million USD). The total capital
cost of a typical hydrate carrier will be about 80 million USD). The transport distance from
the on-shore processing facility in north Norway (Snøhvit field) is assumed 3500 nautical
miles to delivery point. The speed of the LNG ships is assumed 18 knots; that of the hydrate
ships 15 knots. The loading and unloading of both types of ships and unexpected delays are
assumed to take 6 days. Assuming 350 days operation, 3 LNG ships can deliver about 3.6
billion Sm3 of natural gas, and 7 hydrate ships 3.7 billion Sm3. It should be noted that the
speed of the hydrate ships is assumed 16.7 percent less than that of the LNG ships. Therefore,
the hydrate ships could be operated at speeds less than 15 knots and still deliver the same
volume of natural gas.
The 3 LNG ships will cost 750 million USD and the 7 NGH ships 560 million USD). The
NGH hydrate ships cost 25 percent less than the LNG ships, a saving in Capex of 190 million
USD).
If a transport distance of 3000 nautical miles (5500 km) is used instead of 3500 nautical miles
(6500 Ion), the 3 LNG ships and 7 hydrate ships can transport more natural gas each year.
Each LNG ship will make 18 trips per year and each Gas-in-Ice ship 16 trips per year. The
total transport capacity will then be 4.1 and 4.2 billion Sm3 of natural gas per year,
respectively. The slightly lower capacity of 4 billion Sm3 per year is assumed in the LNG and
NGH production plants below.
CAPITAL COST LNG CHAIN
A generalised procedure to estimate LNG project costs has been presented by DiNapoli
(1986). The capital cost numbers presented were from mid 1985 in terms of natural gas rates
in MMscf/d. A natural gas rate of 4 billion Sm3 per year corresponds to 400 MMscf/d. The
generalised procedure of DiNapoli (1986) was used to estimate the capital cost of two LNG
trains for 200 MMscf/d each. Three 80,000 m3 LNG storage tanks were assumed. The
resulting capital costs are shown in Table 1 in million USD. These costs are appropriate for a
high labour cost area such as Norway. It should be noted that a 400 MMscf/d plant utilising a
single liquefaction train is currently being built in Trinidad (DiNapoli, 1995).
An import/regasification terminal for LNG that handles 400 MMscf/d of natural gas, was
estimated from the DiNapoli (1986) procedure to cost about 350 million USD in mid-1985.
The Nelson-Farrar cost index published in the Oil and Gas Journal can be used to up-date the
capital cost estimate of DiNapoli (1986). From mid-1985 to mid-1994 the cost index
increased by about 25 percent. A LNG chain (production, shipping, regasification) for 4
billion Sm3 of natural gas per year, therefore, was estimated to cost about 2677 million USD
as shown in Table 2.
The LNG production cost in Table 2 equals 886 USD per tonne of annual capacity. The
corresponding capital costs for shipping and regasification are 378 and 221 USD per tonne of
annual capacity. The total capital cost of the LNG chain amounts to 1485 USD per tonne of
annual capacity. The density of LNG was assumed 420 kg/m3.
For an exchange rate of 6.8 NOK/USD), the total capital cost amounts to 10.1 billion NOK
for the LNG plant, 5.1 billion NOK for the LNG ships and 3.0 billion NOK for the import
terminal, representing 56, 28 and 16 percent, respectively. In total 18.2 billion NOK for the
LNG chain. The Snøhvit field development is estimated to cost about 9 billion NOK. It
follows that the LNG chain represents 213 of the total capital costs and the field development
113.
CAPITAL COST NGH CHAIN
The natural gas hydrate (NGH) chain consists of production, transport and melting. Frozen
hydrate at -15 C is similar to ordinary ice and can be formed and handled accordingly. Natural
gas hydrates contain about 15 wt. percent gas and 85 wt. percent water. The volume of natural
gas in one cubic-meter of hydrate is about 150 cubic-meters. Frozen hydrates are safe to
handle and the same regulations and procedures used in the handling and processing of oil and
gas are expected to be applicable in the Gas-in-Ice process. It follows that hydrate technology
is inherently much safer than LNG technology.
The cost base of Aker Engineering was used to estimate the capital cost of a natural gas
hydrate production plant. The total capacity of the plant was assumed 400 MMscf/d (4 billion
Sm3 per year) of natural gas. In the LNG chain this rate was divided between two trains, each
with a capacity of 200 MMscf/d. In the hydrate plant however, the total gas rate was divided
into four trains, each with a capacity of 100 MMscf/d. The smaller train size in the frozen
hydrate plant is due to the much larger liquid volumes involved. The general implication is
also that the smaller unit size of NGH plants makes it possible to construct and operate them
closer to actual increases in natural gas demand.
A schematic flow diagram of the Gas-in-Ice hydrate process is shown in Fig. 2. Water from
an arriving ship is pumped into a storage tank. There are four trains of the same design and
capacity. The water is pumped through an ice-making process where a 50/50 ice/water slurry
is produced. Natural gas arrives under pressure (no compression required) from storage
(optional) and gas/liquid separation. The natural gas and ice/water slurry are injected into the
first stage of the three-stage hydrate reactor system. The reactors are operated at 50 bara
pressure and temperature of 10 C (gives 4-6 C supercooling). The rate of ice/water slurry
injection is balanced against the cooling need of the hydrate heat of formation.
A hydrate/liquid mixture leaves the last reactor stage with a hydrate concentration of about 30
wt. percent. The mixture enters a vertical separator where hydrate concentrate leaves through
the bottom. The hydrate depleted liquid returns to the reactor system by pumping. The details
of the hydrate/liquid separation equipment are not yet completed. It seems that it will be
difficult to separate hydrate from water because of their similar density. The use of natural gas
condensate is being evaluated. Such condensate has low density, facilitating rapid separation.
The hydrate concentrate leaving the vertical separator enters a horizontal decanter system,
where wet hydrate is squeezed out at one end and water the other. The separation efficiency of
this operation is now known. More than one decanter system may be required to attain as low
a water content of the solid hydrate as possible. The almost-dry hydrate is then fed to a
refrigeration system where it is frozen to about -15 C and the pressure reduced. The direct use
of refrigerated natural gas can be used in this operation. In or after the refrigeration system the
solid hydrate can be pelletized or formed in other ways that are deemed suitable for largescale storage and transport. The refrigerated hydrate particles are fed to an insulated storage
tank, until loaded on a hydrate ship.
The capital costs of the hydrate process units are shown in Table 3. The cost of the main
equipment is estimated to be 1600 million NOK. The cost of bulk materials and plant
construction is estimated as 150 percent of the equipment cost, corresponding to recent
offshore cost relationships. Marine facilities as well as engineering and management cost is
added, giving a basic plant cost of 5000 million NOK. Because the process is new, a
contingency of 30 percent is added, giving a total erected plant cost of 6500 million NOK.
This is the Capex of the 4 billion Sm3 per year NGH production process and export facilities.
It assumes a grassroots plant installation, to be comparable to that of an LNG plant.
The regasification of frozen hydrates will take place by simple melting. A schematic flow
diagram of such a process is shown in Fig. 3. The hydrates melt by direct contact with warm
water and the natural gas and liquid water are separated. The gas is compressed and
dewatered, then fed to gas storage (optional) and as required to a gas distribution net. The
separated water is fed to a storage tank. The same amount of water is loaded to a hydrate ship
as the same ship carries of hydrate. This water contains seeds of hydrate crystals that will
facilitate rapid reaction rates in the production plant. A considerable rate of water is circulated
through a heat-exchange system, where it is warmed-up for melting the hydrates.
In both the production and melting of Gas-in-Ice hydrates, natural heat sinks can be used.
Ocean water would be ideal in most situations, but air and hot effluents from power plants can
also be used. The COP (coefficient of performance) of typical heating/cooling systems is in
the range 2-3; that is, the electrical energy used for pumping gives 2-3 times the thermal
energy. The Gas-in-Ice process operates at temperatures so near ambient conditions that the
heating and cooling systems used will be energy efficient.
A capital cost estimate was not carried out for the melting of hydrates in an import terminal
(regasification). The cost of the melting facilities will scale with the capital cost of the
production facilities. In the present work, the capital cost of the melting was assumed to be
equal to 50 percent that of the production; that is, 3250 million NOK. The capital cost of a
NGH chain for 400 MMscf/d over a distance of 5500 km is shown in USD in Table 5. The
Capex comes to 1995 million USD).
The total capital costs for a 4 billion Sm3 natural gas production in the Snøhvit field, will
amount to about 22.55 billion NOK; that is, 9 billion NOK for field development, 6.5 billion
NOK for hydrate production process, 3.8 billion NOK for 5500 km ship transport and 3.25
billion NOK for hydrate melting.
DISCUSSION
The capital costs of the LNG chain and the NGH chain are compared in Table 6. The costs in
million USD are presented to illustrate the savings attainable by using hydrate technology
instead of liquefaction technology. The capital cost values in Table 6 show that NGH costs
much less than LNG. First, hydrate shipping costs 25 percent less than LNG shipping; about
one-quarter less. Second, adding the production process (36 percent less) and regasification (9
percent more) capital costs, shows that NGH technology costs 26 percent less than LNG
technology (LNG 1927 million USD and NGH 1433 million USD); also about one-quarter
less.
In addition to costing significantly less than LNG technology, NGH technology is inherently
much safer. It follows that NGH ships sailing from the far north along the Norwegian coast on
their way to European Union countries represent much safer natural gas transport than LNG
shipping. The same argument applied to the receiving terminal - NGH terminals are much
safer and offer a greater flexibility in location. In general, NGH ships offer much greater
safety than LNG ships in the busy ship-lanes of Europe and Asia Pacific.
The technology associated with NGH is relatively un-complicated. It means that natural gas
hydrate plants can be built using local resources, factories and manpower to a greater extend
than in LNG plants. That is, NGH technology is more likely to provide local employment.
LNG technology is highly specialised and is based on equipment offered by relatively few
manufacturers, especially the high-cost liquefaction heat exchanger. The same argument
applies to LNG ships due to the specialised nature of the cryogenic storage tanks. Hydrate
ships are simple in design -ordinary tank ships with moderate thermal insulation. Such ships
can be built quickly in the numerous large shipyards around the world, making competitive
pricing more likely than expected for specialised LNG ships.
CONCLUSIONS
1. The transport of natural gas at atmospheric pressure in the form of hydrate has been
found to be technically and economically feasible, provided the hydrate reactor
cooling is supplied by an ice/water slurry and the hydrate is stored near-adiabatically
below the freezing point of water, typically at - 15 C.
2. Independent experimental studies in Norway, Canada and Russia have shown that
natural gas hydrates are stable for long times (up to two years) when stored frozen (-15
to -5 C) at atmospheric pressure.
3. The total capital cost of hydrate production and melting processes were estimated to
be about one-quarter less than the equivalent LNG liquefaction and regasification
processes. For the same natural gas carrying capacity, the capital cost of hydrate ships
was also estimated to be about one-quarter less than that of LNG ships.
4. Natural gas hydrate technology is inherently much safer than LNG technology.
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Figures and Tables