Note: Descriptions are shown in the official language in which they were submitted.
CA 02790182 2012-09-17
PROCESS FOR OPTIMIZING REMOVAL OF CONDENSABLE
COMPONENTS FROM A FLUID
[TECHNICAL FIELD]
[0001] The present invention relates to the removal of condensables from
fluid mixtures exhibiting a positive Joule-Thomson effect, and more
particularly the
present invention relates to the removal of, for example, water from acid gas
streams,
for minimizing or substantially eliminating the formation of liquid water
therein so as
to minimize corrosion and formation of hydrates in the gas stream, transported
and
injected for sequestration. A discussion of retrofit and enhanced hydrocarbon
recovery is also provided.
[BACKGROUND ART]
[0002] Gas streams, such as those which result from petroleum
processing or
combustion processes, often contain a gas or gases which form an acid when
mixed
with water. Such gases are typically called "acid gases". The most common
naturally
occurring acid gases resulting from petroleum processing are hydrogen sulfide
(H2S)
and carbon dioxide (CO2). Typical acid gases derived from
combustion/oxidation/pyrolysis processes are carbon dioxide (CO2), sulphur
dioxide
(SO2), and nitrogen oxides (NO, NO2).
[0003] Acid gases typically contain water. Naturally occurring acid
gases are
often saturated with water in the reservoir and combustion-derived gases co-
exist with
the water formed from the reaction of hydrogen and oxygen during combustion.
Virtually all acid gases eventually end up being saturated with water vapour
at some
point during the process of removal or purification of the acid gas. Reducing
the
temperature or increasing the pressure, over a defined range, of an acid gas
containing
water, such as that which occurs when the acid gas is passed through a
compressor,
will result in the condensing of some of the water from a gas to a liquid
phase. At
some temperature, still above the freezing point of water, the water and acid
gas may
begin to form a "solid like" structure called a gas hydrate. The temperature
at which
hydrates may begin to form is called the Hydrate Formation Temperature (HFT)
which varies according to the pressure, composition and water content of the
mixture.
Hydrates are the physical combination of water and small molecules producing a
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CA 02790182 2013-03-14
compound having an "ice like" appearance, but possessing different properties
and
structure than ice. Hydrates may also be known as gas clathrate. Hydrates are
problematic as they can cause reduced heat transfer, excess pressure drops,
blockages,
interruptions in production and are a safety concern.
[0004] The formation of an aqueous phase in any gas system is
undesirable as
it promotes corrosion, can cause gas hydrates to form and can cause mechanical
and
operational problems. An aqueous phase is particularly undesirable in an acid
gas
system as the resulting aqueous phase will be acidic, resulting in a
significant increase
in the corrosion rate andusually resulting in a higher HFT than non-acid
gases.
[0005] Table A illustrates the levels of corrosion which occur in mild
steel at
varying concentrations of acid gas components in water.
Table A
Corrosion of Mild Steel by Carbon Dioxide and Other Gases in Water*
02 conc. ppm H2S
cone. ppm Corrosion mils/yr CO2 Corrosion mils/yr
cone, 200ppm CO2
cone, 600ppm
8.8 0 28 60
4.3 0 18 44
1.6 0 12 34
0.4 0 17 27
<0.5 35 6 6
<0.5 150 15 16
<0.5 400 17 21
*Temperature 80 F, exposure 72hr,
Source: Data of Watkins and Kincheloe (1958) and Watkins and Wright (1953)
zo 100061 Although the discussion has focused on acid gas, it will be
appreciated
by those skilled that the methodology and concept is applicable for removing
condensable components from any fluid stream exhibiting a positive Joule-
Thomson
coefficient. It is well established that the hydrocarbon natural gas contains
methane,
ethane, propane, butane, as well as pentanes C511.12 and c5+compounds.
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[SUMMARY OF THE INVENTION]
(0007] A method for removing condensable components from a fluid
containing said condensable components, comprising: optimizing the temperature
of
s an initial fccd stream including said condensable components through heat
exchange
and cooling to condense liquids there from and removing said liquids to form a
gas
stream; said heat exchange being conducted through a gas liquid heat exchange
operation in sequence with a gas-gas heat exchange operation; compressing and
after
cooling said gas stream to form a high pressure stream; expanding at least a
portion of
o said high pressure stream to form a cooled low pressure stream and mixing
said
cooled low pressure stream with said initial feed stream to augment cooling
and
condensation of condensable components in said initial feed stream.
(0008] Having reference to Figures 1 and 2, water content in an acid
gas is
15 proportional to temperature and up to about 400 psia for 1-12S and 900
psia for CO2, is
inversely proportional to pressure. Within thesc limits, higher pressures and
lower
temperatures favor low water content in acid gases.
[0009] Dehydration is the process of removing water so as to minimize
or
20 prevent hydrate and free water formation. In an acid gas with a
relatively high H2S
concentration, sufficient water is typically removed during cooling between
stages of
conventional multi-stage compression through to dense phase (some pressure
above
the critical pressure of the fluid also known as super critical) such that a
separate
dehydration process is not required. As the CO2 content of the acid gas
increases,
25 sufficient water removal through compression alone becomes less likely
and a
separate dehydration process is usually required_
[00010] Conventional means of gas dehydration are solid desiccant
adsorption,
liquid desiccant absorption, refrigeration, membrane separation, and dry gas
stripping.
30 The most commonly used methods are solid desiccant adsorption and liquid
desiccant
absorption.
[00011] Glycol dehydration, a liquid desiccant absorption process, is
generally
regarded as the favored operational and most economical for most applications.
Such
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liquid desiccant dehydration processes have several drawbacks:
= glycol losses in a high pressure CO2 service can be significant;
= excess oxygen, typically found in combustion-formed acid gases
significantly increases corrosion and accelerates the degradation of the
glycol at higher regeneration temperatures, necessitating the addition
of continuous glycol reclamation process;
= glycol must be monitored and treated to maintain a proper pH range;
= dehydration equipment is typically manufactured from high cost,
corrosion resistant metals such as stainless steel to handle the acidic
liquids produced;
= glycol is typically heated to temperatures up to 400 F for regeneration
resulting in vaporizing of water and venting the absorbed acid gases to
atmosphere and any other contaminants also absorbed by the glycol,
such as volatile organic compounds (VOC's), typically benzene,
toluene, ethyl benzene and xylene (BTEX) and any stripping gases.
Control of these fugitive emissions generally requires the addition of
costly vapor recovery equipment and introduces the potential for
further oxygen contamination;
= utility requirements of such processes are high and include the fuel
used for glycol regeneration and the power required to pump the glycol
and operate the vapor recovery equipment;
= significant total carbon footprint is generated as a result of the
manufacturing of the dehydration equipment, and the CO2 produced
from the utility demands of the system and of the formulation of the
glycol used in the dehydration process.
[00012] Dehydration by refrigeration makes use of a gas's reduced
ability to
hold water as it's temperature is decreased. Temperature reduction can be
achieved
indirectly by heat exchange from external 'refrigeration' or other temperature
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indirect refrigeration unit solely for the purpose of dehydration is typically
cost
prohibitive.
1000131 Both direct isenthalpic and isentropic refrigeration dehydration
methods utilize an expansion device, a low temperature separator and at least
one heat
exchanger to recover as much energy from the process as possible. In their
simplest
form, the entirety of the gas is expanded, either isenthalpically or
isentropically, from
a higher pressure to a lower pressure, resulting in a fluid temperature low
enough for
water condensation to occur. The condensed water is removed from the process
in a
low temperature separator and the residual low temperature, substantially dry
gas is
used to pre-cool incoming fluid to improve the thermal efficiency of the
process. This
is typically referred to as a "Choke Plant" or "Dew Point Control Unit (DPCU)"
in an
upstream oil and gas processing application.
1000141 In the isentropic expansion case, expansion is accomplished with an
expander and the work extracted by the expander is typically used to partially
recompress the outlet dry gas.
1000151 The choice of whether to use isentropic or isenthalpic expansion
is
dependent upon the amount of water removal required, and therefore the amount
of
temperature reduction required. Isentropic expansion is capable of achieving
lower
temperatures. From a capital cost perspective, the isentropic process is
significantly
more costly, but the ability to recover work has an offsetting advantage. From
an
operation and maintenance perspective, the isenthalpic process has an
advantage of
being mechanically and operationally simple and suitable for most
applications. The
offsetting disadvantage of the isenthalpic process is the requirement to
consume
additional work through increased compression requirements.
[000161 The common drawback of any of the refrigeration dehydration
processes is that most applications require the gas stream to be cooled to a
temperature that is near or below the hydrate formation temperature (HFT) to
achieve
the desired level of dehydration. For reliable operation, continuous addition
of a
thermodynamic hydrate inhibitor, such as glycol or methanol, is usually
employed to
lower the HFT. If desired, both glycol and methanol are recoverable, but
require a
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separate regeneration process complete with all of the issues discussed
earlier under
liquid desiccant dehydration. Often the choice is made to use methanol without
recovery as methanol is relatively benign and has less impact on downstream
processes than glycol although this choice typically results in a higher
operating cost.
[00017] Clearly there is a need for a dehydration process for acid gas
streams
[BRIEF DESCRIPTION OF THE DRAWINGS]
[00018] The features of the invention will become more apparent in the
[00019] Figure 1 is a graphical illustration of the saturated water
content of
various fluids, acid gases and methane (CH4) at 100 F over a range of
pressures;
[00020] Figure 2 is a graphical illustration of the saturated water
content of
CO2-rich mixtures and methane (CH4) at 100 F over a range of pressures;
[00021] Figure 3 is a graphical illustration of the glycol losses in a
prior art
[00022] Figure 4A is a schematic of an isenthalpic dehydration process
according to an embodiment of the invention for a water saturated fluid stream
comprising 100% CO2;
[00023] Figure 4B is a schematic of an isenthalpic dehydration process
according to Figure. 4A for a fluid stream comprising 80% CO2 and 20% H2S;
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1000241 Figure 5A and 5B are schematics of an isenthalpic dehydration
process
according to Figures. 4A and 4B incorporating a heat exchanger for heating a
partially
expanded slipstream for preventing hydrate formation in the main process feed
stream
prior to further expansion of the slipstream to achieve the desired
temperature
reduction;
1000251 Figure 6A and 6B are schematics of an isenthalpic dehydration
process
according to Figures 4A and 4B, incorporating a low temperature separator for
removing water from the fluid stream prior to the reintroduction of the
slipstream
thereto and continuous hydrate inhibitor injection;
1000261 Figure 7 is a schematic of a multi-stage isenthalpic process
according
to an embodiment of the invention;
1000271 Figure 8 is a schematic of a multi-stage isentropic process
according to
an embodiment of the invention wherein one of the Joule-Thomson valves is
replaced
with an isentropic fluid expander;
1000281 Figure 9 is a schematic illustration of a further embodiment of
the
present invention; and
1000291 Figure 10 is a schematic illustration of yet another variation
of the
technology embraced by the present invention.
1000301 The examples provided assume steady state performance. Other
considerations are addressed to accommodate start up, in service upsets, and
shut
down for commercial operations. One simple example is that during the first
few
minutes of start up, and during periods of external process upsets, the
temperatures
and slipstream flow rates may not be at the steady state operating condition
dictated
by the process design. Hydrates could potentially start forming without the
provision
of something in the design to mitigate this condition. Embodiments of the
invention
are therefore designed to include the capability of adding a thermodynamic
hydrate
inhibitor, such as methanol, for temporary protection against hydrate
formation in an
unsteady state performance.
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[00031] Similar numerals used in the Figures denote similar elements.
[BEST MODE FOR CARRYING OUT THE INVENTION]
[00032] Embodiments of the invention take advantage of the thermodynamic
property of typical acid gases that make them useful as a 'refrigerant'. Such
gases
exhibit a relatively large temperature reduction for a given pressure
reduction within
the operating region of the process. The large decrease in temperature is used
to cool a
slipstream of the feed stream which is thereafter recycled upstream for
cooling the
[00033] Acid gases processed for commercial applications, such as
Enhanced
Oil Recovery (EOR) applications, or Carbon Capture and Sequestration (CCS)
applications are normally compressed to super-critical pressures, commonly
referred
[00034] Compression is broken into two distinct regions with respect to
the
critical point of the fluid being compressed. The stages of compression in the
first
region are sub-critical and the stages in the second region take the fluid
above it's
critical pressure and may be accomplished by compression and pumping means. An
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CA 02790182 2012-09-17
inlet stream enters the first region of compression, which is sub-critical,
and is
assumed to be water saturated. Some water is naturally removed by compression
through the various stages in the first region.
[00035] In embodiments of the invention, a slipstream of fluid from the
after-
cooled discharge of one stage of compression, typically near or above critical
pressure, is expanded to the suction pressure of that same stage, or to a
preceding
stage should additional temperature reduction be required. The resulting
reduced
temperature of the expanded slip stream is used to cool the upstream main
fluid
stream, firstly by heat exchange, if required, and finally by direct mixing of
the
slipstream with the main fluid stream. The resulting reduction in temperature
of the
mixed stream condenses additional water from the gas. The amount of cooling
required is a function of the minimum water content required for the stream
composition to meet the design criteria for water dew point temperature and/or
hydrate formation temperature.
1000361 The following are examples illustrating embodiments of the
invention,
more particularly:
Example 1 - a basic embodiment;
Example 2 - utilizing a low temperature separator vessel (LTS);
Example 3 - incorporating a heat exchanger (HEX);
Example 4 - a multi-stage isenthalpic embodiment; and
Example 5 - a multi-stage isentropic and isenthalpic embodiment.
Examples 1-3 are shown using different stream compositions; more
particularly a stream having 100% CO2 and a stream having 80% CO2 and 20% H2S.
It will be noted however that embodiments of the invention are applicable to
streams
having varying amounts of H2S and including SO2, NO and any other gaseous
mixtures with relatively large JT Coefficients.
Examples 4 and 5 illustrate the low temperature capabilities of embodiments
of the invention as well as the differences between isenthalpic and isentropic
processes.
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[00037] Example 1 ¨ BASIC
[00038] Having reference to Figures 4A and 4B, in an embodiment of the
invention, a water saturated acid gas feed stream 10 enters a suction stage 12
where it
is compressed 14 to the suction pressure of the next stage 16. The hot
compressed
vapour 14 is cooled 18 with an after-cooler 20 resulting in the condensation
of some
of the water and other condensables in the feed stream. The condensed liquid
containing water is removed 22 in a separator 24 upstream of the final stage
of
compression. The saturated gas 26 from the separator 24 is further compressed
at 28
and is after-cooled again at 30.
[00039] A slipstream 32 from the compressed and after-cooled fluid
stream is
removed and isenthalpically expanded 34 across a Joule-Thomson valve (TCV) 36
to
the lower suction pressure of the same stage 16 of compression. The expansion
results
in a temperature reduction, the magnitude of which is dependent upon the
magnitude
of the pressure reduction and the composition of the fluid stream. The colder
stream
38 is combined with the after-cooled stream 18, exiting the previous stage of
compression, resulting in a combined stream 40 having a temperature reduced
sufficiently to condense the required amount of water.
[00040] As shown in Figure. 4A for a feed stream having 100% CO2, the
temperature is reduced to about 87 F and the final water content is reduced to
about
73 lb/MMscf to result in a hydrate formation temperature (HFT) of 30 F.
[00041] Referring to Figure 4B, wherein the feed stream contained 80% CO2
and 20% H2S, the temperature need only be reduced to about 93 F for a final
water
content of about 89 lb/MMscf to achieve the same hydrate formation temperature
(HFT) of 30 F.
[00042] Example 2 ¨ Heat Exchanger (HEX)
[00043] In cases where the composition of the feed stream, in
combination with
a large pressure reduction, creates a stream temperature which is below the
hydrate
formation temperature of the main undehydrated feed stream, the embodiment
shown
in Figures 4A and 4B can be modified to include a heat exchanger (HEX).
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[00044] In reference to Figures 5A and 5B, the basic embodiment is
modified
so as to avoid the need for continuous injection of hydrate inhibitor, as is
utilized in
conventional refrigeration processes.
[00045] In Figures 5A and 5B, the slipstream 34 is partially expanded 42
across
a second Joule-Thomson Valve (JTV) 44. The temperature of the partially
expanded
stream is thereafter raised in a heat exchanger 46 prior to further expansion
of the
stream 48 across the Joule-Thomson Valve (TCV) 50. Thus, the temperatures of
the
partially and fully expanded streams 42, 48 are maintained above the
respective
hydrate formation temperatures of the main undehydrated feed stream.
[00046] For the purposes of Example 2, the design hydrate formation
temperature was set at 15 F.
[00047] As shown in Figure 5A, for a feed stream having 100% CO2, the
temperature must be reduced to about 73 F to result in a final water content
of about
51 lb/MMscf to achieve the design hydrate formation temperature of 15 F.
[00048] With reference to Figure 5B, and in the case where the feed stream
comprises 80% CO2 and 20% H2S, the temperature was reduced to about 79 F to
result in a final water content of about 64 lb/MMscf to achieve the design
hydrate
formation temperature of 15 F.
[00049] Example 3 ¨Low Temperature Separator (LTS).
[00050] Referring to Figures 6A and 6B, an embodiment of the invention
utilizes an additional separator where temperature reduction is significant,
as an
alternate to the embodiment described in Example 2.
[00051] As shown in Figures 6A and 6B, the 46 and JTV 44 of Figures 5A and
5B are replaced with a second low temperature separator (LTS) 52. A slipstream
54 is
expanded 56 across a Joule-Thomson Valve (TCV) 44. The first separator 24 is
positioned to remove as much water as possible from the feed stream prior to
the
reintroduction of the expanded slipstream 48. The addition of hydrate
inhibitor into
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the expanded slipstream 48 is considered when the process design requires that
the
temperature of the expanded slipstream be below 32 F. The early removal of the
water reduces the amount of cooling required to meet the design conditions
and,
should conditions warrant, reduces the amount of hydrate inhibitor required.
[00052] The design hydrate formation temperature for Example 3 was set
at
0 F.
[00053] As shown in Figure 6A, where the feed stream comprises 100%
CO2,
the temperature had to be reduced to 62 F to result in a final water content
of about 36
lb/MMscf to meet the design hydrate formation temperature of 0 F.
[00054] With reference to Figure 6B, where the feed stream comprises
80%
CO2 and 20% H2S, the temperature had to be reduced to about 67 F to result in
a final
water content of about 45 lb/MMscf to achieve the design hydrate formation
temperature of 0 F.
[00055] Example 4¨ MULTI-STAGE ISENTHALPIC
[00056] In reference to Figure 7, a multi-stage embodiment of the
invention is
employed where the required temperature reduction is very large. The
embodiment
was designed to achieve a hydrate formation temperature of -45 F.
[00057] As shown in Figure 7, this embodiment comprises a heat
exchanger 46,
a low temperature separator 52 and continuous hydrate inhibitor injection 56.
The first
separator 24 is positioned between the heat exchanger 46 and the
reintroduction of the
temperature reduced stream. The early removal of water from the feed stream
reduces
the amount of cooling and hydrate inhibitor required to meet the design
criteria.
[00058] To obtain a lower temperature, the pressure reduction which
results
from the expansion of the slipstream 58 through the Joule-Thomson Valve 44
occurs
over at least two stages of compression. Thus, the partially expanded
slipstream 60 is
heated at the heat exchanger 46 and fully expanded 62 through the Joule-
Thomson
Valve 64 to be reintroduced, along with the injection of hydrate inhibitor, to
the feed
stream two or more stages 66, 68 upstream from the removal of the slipstream
58 for
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cooling the feed stream 28. Condensed water is removed from the cooled feed
stream
28 at the second separator 52 prior to further compression of the cooled feed
stream
28.
[00059] In this example, the low temperature achieved at the fully expanded
slipstream 56 and the cooled feed stream 28 necessitates the addition of the
hydrate
inhibitor, however the amount of hydrate inhibitor is minimized as a result of
the
upstream removal of a significant portion of water at the first separator 24.
[00060] An additional benefit of the low temperature achieved at the cooled
feed stream in this example, is the ability to reduce the number of
compression stages
from five stages to four stages, resulting in a reduction in the overall cost.
[00061] Example 5¨ MULTI-STAGE ISENTROPIC
[00062] With reference to Figure 8, a multi-stage embodiment of the
invention
utilizes an isentropic fluid expander 66, such as a conventional radial-
expansion
turbine or turbo-expander (such as is available from Mafi-Trench, Santa Maria,
CA,
USA) to replace the Joule-Thomson Valve 44 of Figure 7 for expansion of the
slipstream 58.
[00063] In this embodiment, the isentropic fluid expander is capable of
achieving a lower temperature in the expanded slipstream 60 than is possible
using a
Joule-Thompson valve (isenthalpic expansion) for the same reduction in
pressure.
Additionally, the slipstream fraction required is smaller than it is in
Example 4.
[00064] The power requirements for Stage 3 (66) and Stage 4 (68) for
this
embodiment, compared to that in Example 4, are lower by about 2%. The
isentropic
fluid expander produces power, about 1.8% of Stage 3 (66) and Stage 4 (68) for
other
uses. Further, the hydrate inhibitor requirements are minimized.
1000651 The embodiments of the invention, described herein have notable
advantages over and differences from conventional liquid desiccant and
isenthalpic
refrigeration dehydration processes.
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[00066] In comparison to liquid desiccant dehydration processes,
embodiments
of the invention permit elimination of conventional dehydration equipment by
replacement with the expansion valves (TCV, JTV) at a small fraction of the
capital
cost of the conventional dehydration equipment.
[00067] In comparison to conventional isenthalpic expansion
refrigeration
processes, such as a "Choke Plant" or "DPCU", embodiments of the invention may
permit elimination of one stage of compression, a main gas-gas heat exchanger
and
the addition of hydrate inhibitor, providing a significant reduction to the
capital cost.
[00068] The prior art "Choke Plant" or "DPCU" requires that the entire
gas
stream be over-compressed and expanded to the design pressure. This typically
increases the original compression power requirements of the system by 20% to
25%.
Depending upon the composition of the gas and the operating conditions, the
higher
compressor discharge pressure may necessitate the addition of an entire stage
of
compression.
[00069] The cooling slipstream is typically 10% to 30% of the combined
stream flow through a single stage, depending upon the composition of the acid
gas
and the required operating conditions. The increase in throughput through one
stage
of compression theoretically increases the total compression power demand by
2% to
6% (i.e. 1/5 of 10% - 30% for a 5 stage compressor). In comparison however,
this
increase is often comparable to the increase due to the pressure drop through
conventional dehydration equipment. Further, there is an efficiency
improvement, and
therefore a corresponding reduction in compression power, resulting from the
reduced
operating temperature of the compressor. In some instances, the compression
power
requirements end up being less than when using conventional dehydration
equipment.
[00070] Lower suction temperatures, enabled by embodiments of the
invention,
have an additional advantage over both the conventional dehydrator and the
choke
plant. The reduced temperature in one stage provides the opportunity to
rebalance the
compression ratios on each stage, a higher compression ratio where the suction
pressure is cooler thus enabling a reduction of the compression ratio in the
others,
until the discharge temperatures of each stage are relatively equal at some
new lower
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CA 02790182 2012-09-17
value. The reduction in discharge temperature somewhat reduces the additional
power
demand arising from the additional slipstream volume seen in one or more
stages of
compression. The temperature reduction also results in longer valve life,
increased
operational time and lower maintenance costs. The rebalancing can, at some
point,
with lower temperatures, be significant enough to eliminate an entire stage of
compression and thus provide considerable capital cost saving.
[00071] It is believed that the overall carbon footprint of embodiments
of the
invention is significantly lower than conventional methods. The requirement
for
equipment is considerably smaller reducing demand for manufacture, there is no
need
for the formulation of glycol and no additional utilities are required that
produce CO2,
all of which more than offset the marginal increase in power required
(typically about
2%) to compress the slipstream volume. Additionally, the lack of chemical
requirements in embodiments of the invention significantly reduces ecological
risk.
[00072] Acid gases including CO2, H2S, SO2, and NO are fluids well
suited to
the embodiments of the invention. It is believed however that the fluids are
not
limited to those disclosed herein. It is further believed that the
thermodynamic
principles utilized in embodiments of the invention are valid for all fluid
mixtures
exhibiting a positive Joule-Thomson (JT) Coefficient within the desired range
of
process conditions; in other words, the fluid mixtures cool when expanded. As
a
generalization, a fluid with a larger JT Coefficient will get colder than one
with a
smaller JT Coefficient and therefore will require less of the fluid to be
slipstreamed. A
low slip stream requirement is economically desirable.
[00073] Applications for embodiments of the invention lie in carbon
capture
and storage (CCS), the treatment of CO2, SO2, and NO. captured from
combustion,
gasification and industrial chemical processes for sequestration, and in AGI
(acid gas
injection) where H25 and CO2 are captured from oil and gas processes for
sequestration. Another application for embodiments of the invention appears in
the
recovery of hydrocarbon liquids from relatively high acid gas content solution
gas
vapours that are typically processed in Enhanced Oil Recovery (EOR)
applications. A
further application for embodiments of the invention lie in situations where
acid gas
dehydration is required in situations with minimal available space or where
there is a
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CA 02790182 2013-03-14
weight restriction. Such situation might occur in offshore floating production
operations or in retrofit applications, both onshore and offshore. The
configurations of
this invention provide a significant space and weight advantage over other
commercial dehydration means.
1000741 Examples 1-5 provided herein are based upon a single set of
conditions. Embodiments of the invention require optimization for each fluid
and set
of conditions. Optimization involves the selection of the stage of compression
best
suited for initiation of the slipstream and which is best suited for
recombining the
slipstream. Another optimization lies in the selection of the optimum
variation of the
process whether it be Basic, HEX, LTS, Multi-Stage, Multi-Stage Isentropic, or
some
other combination of those described above. Also within any of the choices,
the
optimum instrumentation and control system needs to be included and the
optimum
operating points for the application established_
[000751 Referring to Figure 9, numeral 80 denotes common upstream
operations with numeral 81 denoting the overall schematic process according to
a
further embodiment.
1000761 With respect to the common numerals from the previous embodiments,
a separator 13 is provided for separating a feed into saturated gas feed
stream 10
which enters compressor 12 where it is compressed to the discharge pressure,
compressed vapor 14 is then introduced into after-cooler 20 which results in
the
condensation of some of the water and other condensables in the feed stream.
These
unit operations have been discussed herein and previously with respect to the
other
embodiments.
[00077I In respect of the newly presented schematic upstream acid gas
stream
18 which is typically from a compressor, well, etc. is normally saturated with
water.
As an example, the stream may contain 100% acid gases or some other
concentration
of acid gases with the balance typically being hydrocarbons and low
concentrations of
other inert gases. For purposes of explanation, the stream may be at for
example,
120 F at a pressure of 600 psi. In this circuit, a pair of heat exchangers 84
and 86 are
provided which may be configured in parallel_ In terms of the heat exchangers
84 and
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86, heat exchanger 84 is a gas-liquid heat exchanger which is used to transfer
heat in
fluid 18 to the cold liquid fluid 96_ Stream 90 mixes with the cooled stream
89 exiting
the Joule-Thomson valve 44. The two are mixed in mixing device 92. The so
formed
mixture 93 at a temperature of approximately 50 F, is passed into low
temperature
separator 94. At this point, the liquids that condense at the 600 psi pressure
form a
cold liquid stream 96. Stream 96 will be close to the hydrate formation
temperature of
the mixture of fluids. If the stream were further depressurized this would
most
certainly result in the formation of a hydrate. Stream 96 passes into beat
exchanger
84, exchanges heat with, stream 18 thereby cooling stream 18 and warming
stream
96. It is advantageous for stream 96 to receive some heat from stream 18 to
reduce the
probability of hydrate formation. It is also advantageous to cool stream 18 to
reduce
the amount of additional cooling required. Once stream 96 is warmed via heat
exchange through exchanger 84, stream 98 is possibly at a temperature of 120
F. The
pressure of stream 98 can then be reduced in valve 100 without hydrate
formation, to
maintain a desired liquid level in the low temperature separator 94. As the
liquid level
builds, valve 100 opens and allows a stream 102 to pass into a three phase
separator
104. Stream 102 is possibly comprised of three phases; vapor, hydrocarbon
liquid,
and water. The residence time in the separator 104 is sufficient to facilitate
the
separation of heavier liquids at 106, typically water, vapor at 108 and
lighter liquids at
110, typically hydrocarbons. At this point, the separated hydrocarbon liquids
110 can
be then directed to an oil treating facility for treatment (not shown),
stabilization, and
eventual sale.
100078,1 Returning to the low temperature separator 94, the stream 112
exiting
same is a cold acid gas (typically CO2) vapor stream and can be used as an
additional
source for pre-cooling the main system. Streams 88 and 112 are passed into the
heat
exchanger 86 which, in this case is a gas-gas heat exchanger used to transfer
the beat
in stream 88 to the cold vapor stream 112 exiting the low temperature
separator 94.
This also pre-cools stream 90 exiting the exchanger 86 therby reducing the
amount of
additional cooling required_ The stream 114 at this point has a temperature of
approximately 110 F from the example noted herein. This system is particularly
beneficial in that it allows for hydrocarbon recovery where it is economically
feasible.
[00079] Stream 114 is then passed into the unit operations that have
been
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CA 02790182 2013-03-14
described herein previously with respect to the basic overall system.
[00080] In the event that there is no possibility, or where it is not
economically
feasible to recover liquid hydrocarbons, then the designer would employ the
system
shown in Figure 10 to be discussed in greater detail herein after. This is
also an
attractive system for retrofit applications which could use existing
compressor
arrangements with minimal modifications while also benefiting from the
technology
set forth herein.
JO 100081,1 In an EOR application where CO2 is utilized, make-up
or additional
CO2 is usually mixed with the produced vapor and reinjected into the producing
reservoir. Depending upon the pressure of the make-up CO2 stream, it may be
mixed
with or even replace stream 34 to improve the Joule-Thomson coefficient and to
reduce the RFT. The dry, make-up CO2 could be used to minimize or eliminate
usage
of hydrate inhibitors, such as methanol or glycol, during system start up.
[00082] The process may be designed to condense fluids other than the
hydrocarbons used in this example if so desired.
1000831 Additional stages of pressure reduction and separation (duplicating
100, 102 and 104 with 110 replacing 98) may be considered if improved
hydrocarbon
liquid / vapor separation efficiency is required.
[000841 Further, the system may include thermodynamic simulation
software to
assist in optimizing operating points by predicting water dew point, hydrate
formation
temperature, and hydrocarbon recovery.
[00085] Turning to Figure 10, shown is a further embodiment of the
present
invention. In this embodiment, it is evident that a significant number of unit
operations have been removed relative to that which is shown in Figure 9. The
use of
the three phase separator 104 from Figure 9 is unnecessary in this embodiment
as is
the gas-liquid heat exchanger. The remaining unit operations are similar to
the
functioning of operations in Figure 9 and the overall sequence will be
apparent to one
skilled in the art.
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CA 02790182 2012-09-17
[00086] This embodiment is particularly well suited for existing
arrangements
where a retrofit is possible to take advantage of the benefits of the system
described
herein. With the inclusion of the gas-gas heat exchanger, the cooling
slipstream is
typically reduced to 4% to 10% of the combined stream flow through a single
stage,
depending upon the composition of the acid gas and the required operating
conditions.
The increase in throughput through one stage of compression theoretically
increases
the total compression power demand by 1% to 2% (i.e. 1/5 of 4% - 10% for a 5
stage
compressor). The addition of the LTS is only required where the metallurgy of
the
existing suction scrubber is not compatible with the acidic water produced and
it is
deemed inappropriate to replace the existing scrubber. The capital cost of
this
embodiment is increased accordingly.
[00087] In the embodiment shown in Figure 10, the heavy liquid phase stream
34 in this instance is typically a warm high pressure recycle stream which is
typically
super critical (dense phase) or liquid. This is passed into the Joule-Thomson
valve 44
which reduces the pressure and therefore the temperature of the stream 34.
Cold low
pressure recycle stream 89 is used for mixing with the pre-cooled inlet stream
90 into
the mixing device 92.
[00088] The mixture, as previously discussed with respect to Figure 9,
is
denoted by numeral 93. The liquid phase leaving the low temperature separator
94 at
96 is predominantly water. This stream is typically blended elsewhere into a
water
treatment process.
[00089] As an example, stream 90 may be cooled to approximately 60 to 70
F
depending on how much surface area is available in the heat exchanger 86. The
slipstream 34 (as discussed herein previously with respect to the other
embodiments)
may be at 120 F and possibly at 2,000 psig. This high pressure stream may be
depressured in a Joule-Thomson valve 44. Here it is depressured to
approximately the
same pressure (600 psig) as stream 90. As a result of passing throughthe Joule-
Thomson valve, the stream is expanded and thus cools to approximately 40 F for
purposes of this example. The resulting cold stream 89, is mixed with stream
90 in
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mixing device 92. The so formed mixture 93 at a temperature of approximately
50 F,
is passed into low temperature separator 94. At this point, the liquids that
condense at
the 600 psi pressure form a cold liquid stream 96. The stream 112 exiting
separator 94
is a cold acid gas (typically CO2) vapor stream and can be used as a source
for pre-
cooling the hot inlet stream 18. Streams 18 and 112 are passed into the heat
exchanger
86 which is a gas-gas heat exchanger used to transfer the heat from stream 18
to the
cold vapor stream 112 from the low temperature separator 94. This heat
exchange also
pre-cools stream 90 exiting the exchanger 86 therby reducing the amount of
additional cooling required. The stream 114 at this point has a temperature of
approximately 110 F from the example noted herein.
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