EA042002B1 - METHOD FOR OPTIMIZING REMOVAL OF CONDENSABLE COMPONENTS FROM LIQUID - Google Patents

Description

Technical field

The invention relates to the removal of condensable components from liquid mixtures exhibiting a positive Joule-Thomson effect, and in particular, the present invention relates to the removal of, for example, water from acid gas streams to minimize or substantially eliminate the formation of water in the liquid phase and with thus minimizing corrosion and hydrate formation in the gas stream supplied and injected for sequestration. Improvements and improvements in hydrocarbon recovery are also described.

State of the art

Gas streams, such as those resulting from oil refining or combustion processes, typically contain a gas or gases which, when mixed with water, form an acid. Such gases are commonly referred to as acid gases. The most common naturally occurring acid gases from petroleum refining are hydrogen sulfide (H2S) and carbon dioxide (CO2). Typical acid gases from combustion/oxidation/pyrolysis processes are carbon dioxide (CO ₂ ), sulfur dioxide (SO 2 ) and oxides of nitrogen (NO, NO ₂ ).

Acid gases usually contain water. Acid gases of natural origin are usually saturated with water in the reservoir, and gases formed during combustion are present together with water obtained from the reaction of hydrogen and oxygen in the combustion process. Virtually all acid gases eventually become saturated with water vapor at some point in time during the acid gas removal or purification process. Decreasing the temperature or increasing the pressure of the water-containing acid gas within a certain range, such as that observed when the acid gas is passed through a compressor, causes some water to condense from the gas phase to the liquid phase. At some temperature, still above the freezing point of water, solid-like structures called gas hydrates can begin to form from water and acid gas. The temperature at which hydrate formation can begin is called the Hydrate Formation Temperature (HFT), which varies with the pressure, composition, and water content of the mixture. Hydrates are a physical combination of water and small molecules, resulting in a compound that looks like ice, but has properties and structure different from those of ice. Hydrates are also known as gas clathrates. Hydrates are a problem because they can lead to reduced heat transfer, significant pressure drops, fouling and process interruptions, and are a hazard.

The formation of an aqueous phase in any gas system is undesirable because it promotes corrosion, can lead to the formation of gas hydrates, and can cause mechanical and operational failures. The aqueous phase is particularly undesirable in an acid gas system because the resulting aqueous phase is acidic, which leads to a significant increase in the corrosion rate and generally results in higher HFT values than for non-acidic gases.

In table. A shows the levels of corrosion observed for mild steel at various concentrations of acid gas components in water.

Table A

Corrosion of mild steel by __________ carbon dioxide and other gases in water ___________

About ₂ conc. ppm H ₂ S conc. ppm Corrosion mil/year CO ₂ conc, 200ppt Corrosion mil/yr CO ₂ conc, bOOrrt 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 (26.67°C), exposure time 72 hours.

Source: data from Watkins and Kincheloe (1958) and Watkins and Wright (1953).

Although the description is focused on the acid gas, those skilled in the art will appreciate that the methodology and concept are suitable for isolating condensable components from any liquid stream exhibiting a positive Joule-Thomson coefficient.

Description of the invention

One of the objectives of one of the embodiments of the present invention is to provide a method for removing condensable components from a liquid containing condensable components, including optimizing the temperature of the initial raw material stream containing condensable components, using heat exchange and cooling to ensure the condensation of liquids from

- 1 042002 flow and removal of these liquids to obtain a gas flow; compressing and post-cooling said gas stream to obtain a high pressure stream; expanding at least a portion of the high pressure stream to obtain a cooled low pressure stream; mixing said low pressure chilled stream with said feed stream to improve cooling and condensation of the condensable components in said feed stream to form a mixture; separating said mixture into a liquid stream and a gas stream and bringing said liquid stream and said gas stream into contact with the feedstock stream to provide heat exchange due to gas-liquid heat exchange in series with gas-gas heat exchange.

As shown in FIG. 1 and 2, the water content of the acid gas is proportional to temperature and up to about ⁴⁰⁰ psi (abs.) (27.58 bar) for H ₂ S and 900 psi (abs.) (62.05 bar) for CO ₂ is inversely proportional to pressure. Within these limits, higher pressures and lower temperatures tend to produce lower water content in the acid gases.

Drying is the process of removing water, thereby minimizing or preventing the formation of hydrate and free water. In an acid gas with a relatively high concentration of H ₂ S, sufficient water is usually removed by conducting cooling between the stages of conventional multi-stage compression to obtain a dense phase (a pressure slightly above the critical pressure of the liquid, also known as supercritical), therefore, a separate drying process is not required. As the CO ₂ content of the acid gas increases, it becomes difficult to remove sufficient water in the compression step alone, and a separate drying process is generally required.

Common methods for drying gases are adsorption with a solid desiccant, absorption with a liquid desiccant, cooling, membrane separation, and dry gas stripping. The most common methods are adsorption with a solid desiccant and absorption with a liquid desiccant.

Glycol drying, a liquid desiccant absorption process, is generally considered to be the preferred operating and economic point of view in most applications. These drying methods using a liquid desiccant have several disadvantages:

glycol losses at high CO ₂ pressure can be significant;

excess oxygen, commonly found in acid gases from combustion, greatly increases corrosion and accelerates glycol degradation at higher regeneration temperatures, necessitating the inclusion of a continuous glycol recovery process;

monitoring and treatment of the glycol is required to maintain the pH in the required range;

Drying equipment is usually made from expensive corrosion-resistant metals such as stainless steel to handle acidic fluids that are produced;

the glycol is typically heated up to 400°F (204.4°C) to regenerate, causing the water to evaporate and absorbed acid gases and other contaminants also absorbed by the glycol, such as volatile organic compounds (VOCs), typically benzene, toluene, ethylbenzene and xylene (BTEX), and any stripping gases, are emitted to the atmosphere. The control of these fugitive emissions of contaminants usually requires the use of expensive vapor recovery equipment and is a factor in possible further oxygen pollution;

the energy requirements for these processes are high and include the fuel used to regenerate the glycol and the energy required to pump the glycol and operate the vapor recovery equipment;

there are significant total emissions in terms of carbon dioxide resulting from the production of drying equipment, and CO ₂ generated from energy resources requires the use of such a system and the preparation of glycol used in the drying process.

Drying by cooling uses the reduction in the ability of gases to hold water when their temperature decreases. Temperature reduction can be achieved indirectly by heat transfer from an external cooling process or other method of temperature reduction, or directly by expansion of the gas itself. Direct expansion of the gas is isentropic expansion, eg in a turbo expander, or isenthalpic expansion, eg using a Joule-Thomson (JT) valve used in conventional throttling systems, or by a process of cooling and compressing the gas. Installing specialized indirect cooling units for the sole purpose of dehumidification is usually not economically viable.

Both direct isenthalpic and isentropic refrigeration drying methods use an expansion device, a low temperature separator, and at least one heat exchanger to extract as much energy as possible from the process. In its simplest form, all of the gas expands, isoenthalpically or isentropically, from higher pressures to lower pressures while maintaining a liquid temperature low enough to condense water. 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 the incoming liquid, thereby improving the thermal efficiency of the process. In incoming oil and gas processing applications, this unit is commonly referred to as a throttle unit or dew point control unit (DPCU).

In the case of isentropic expansion, the expansion is carried out by means of an expander, and the energy obtained by means of the expander is usually used to partially recompress the dry off-gas.

The choice to use isentropic or isenthalpic expansion depends on the amount of water that needs to be removed and hence on the amount of temperature reduction required. Isentropic expansion allows lower temperatures to be reached. From the point of view of capital costs, the isentropic process is much more expensive, but the ability to release energy compensates for this disadvantage. From an operation and maintenance point of view, the isenthalpic process has the advantage of being mechanically and operationally simple and suitable for most applications. The leveling disadvantage of the isenthalpy process is the need for additional energy consumption due to the increased requirements for the compression process.

A common disadvantage of any of the cooling-assisted drying processes is that in most applications it is necessary to ensure that the gas stream is cooled to a temperature near or below the Hydrate Formation Temperature (HFT) to achieve the desired level of drying. To ensure reliable operation, continuous addition of a thermodynamic hydrate inhibitor such as glycol or methanol is commonly used to reduce HFT. Glycol and methanol can be recovered if required, but this requires a separate regeneration process, which includes all the problems previously described for drying with a liquid desiccant. Usually, methanol is used without isolating it, since methanol is relatively harmless and has less impact on downstream processes than glycol, although this option usually results in higher operating costs. Interestingly, methanol is not only suitable for use as a hydrate inhibitor, but also further reduces water content compared to simply lowering the temperature. Thus, drying is improved.

Clearly, there is a need for a process for drying acid gas streams that is efficient and cost effective, and free of the problems associated with conventional drying processes.

Brief description of the drawings

Distinctive features of the present invention are more apparent due to the following detailed description with reference to the accompanying drawings, which show:

in fig. 1 is a graphical representation of water content at saturation for various liquids, acid gases and methane (CH ₄ ) at 100°F (37.78°C) over a range of pressures;

in fig. 2 is a graphical representation of water content at saturation for mixtures with a significant content of CO ₂ and methane (CH ₄ ) at 100°F (37.78°C) in the pressure range;

in fig. 3 is a graphical representation of glycol losses in high pressure CO ₂ processes known in the art;

in fig. 4A is a schematic representation of an isenthalpic drying process in accordance with one embodiment of the present invention for a water-saturated liquid stream containing 10°% CO ₂ ;

in fig. 4B is a schematic representation of the isenthalpy drying process according to FIG. 4A for a liquid stream containing 80% CO ₂ and 20% H2S;

in fig. 5A and 5B are schematic representations of isenthalpy drying processes according to FIG. 4A and 4B comprising a heat exchanger for heating the partially expanded effluent to prevent hydrate formation in the main process feed stream before further expansion of the effluent to achieve the desired temperature reduction;

in fig. 6A and 6B are schematic representations of isenthalpy drying processes according to FIG. 4A and 4B comprising a low temperature separator for removing water from the liquid stream prior to reintroducing the effluent stream and continuously introducing a hydrate inhibitor;

in fig. 7 is a schematic representation of a multi-stage isenthalpy process in accordance with one embodiment of the present invention;

in fig. 8 is a schematic representation of a multi-stage isentropic process in accordance with one embodiment of the present invention, in which one of the Joule-Thomson valves is replaced by an isentropic fluid expander;

- 3 042002 in FIG. 9 is a graphical representation of another embodiment of the present invention;

in fig. 10 is a schematic representation of another embodiment of the technology within the scope of the present invention.

The examples given assume operation in a stationary mode. Other aspects are focused on modifying commissioning, troubleshooting operations, and completing work for commercial operations. One simple example is that in the first minutes after start-up and during periods of external troubleshooting, the temperatures and bleed streams may not match the steady-state operating state values provided by the process flowsheet. Without making changes to the technological scheme that level this aspect, there is a possibility of hydrate formation. Thus, embodiments of the present invention provide for the addition of a thermodynamic hydrate inhibitor, such as methanol, for temporary protection against hydrate formation during transient operation.

Like reference numerals used throughout the drawings refer to like elements.

The best embodiment of the present invention

Embodiments of the present invention take advantage of the thermodynamic property of typical acid gases, which allows them to be used as a coolant. Such gases exhibit a relatively large temperature drop for a given pressure drop within the process envelope. The large temperature drop is used to cool the effluent feed stream, which is then reused to cool the feed stream. Thus, in this method, auto-cooling is carried out by means of repeated application. The Joule-Thomson effect is achieved by isenthalpy expansion of the gas using a throttling device, usually a control valve. With isenthalpic expansion, there are no losses due to the external work of the gas. The rate of change of temperature relative to fluid pressure is the Joule-Thomson (Kelvin) coefficient. For example, the Joule-Thomson coefficient (JT) for carbon dioxide at 50°C and 60 atm (60.79 bar) is about 5.6 times greater than for nitrogen under the same conditions. Therefore, the temperature drop for CO2 is about 5.6 times greater than for nitrogen at the same pressure drop under similar conditions. JT coefficient values are also available for H2S, SO2 and other acid gases, as well as for hydrocarbons and inert gases such as nitrogen and oxygen, which may be observed.

Acid gases treated for commercial purposes such as enhanced oil recovery (EOR) or carbon dioxide capture and storage (CCS) for transport and/or sequestration are typically compressed to supercritical pressures to form a so-called dense phase. To obtain a dense phase, compression is usually carried out in more than one stage by compression in a centrifugal compressor, compression in a reciprocating compressor, or impact compression, depending on the initial pressure. The difference in pressure between stages allows the steam properties associated with the JT to be taken advantage of.

The compression process is carried out in two separate areas relative to the critical point of the compressible fluid. In the compression stages in the first region, the liquid is in a subcritical state, and in the compression stages in the second region, the liquid pressure exceeds the critical pressure, and these stages can be carried out using compression equipment and pumping equipment. The incoming stream enters the first compression region, which provides subcritical parameters, and it is believed that the stream is saturated with water. Part of the water is naturally removed during the compression process during the various stages in the first region.

In embodiments of the present invention, the bleed liquid stream after a post-cooling step in one of the compression stages, typically at or above the critical pressure, is expanded to the suction pressure for the same stage, or a previous stage if additional temperature reduction is required. The resulting reduced temperature of the expanded bleed stream is used to cool the main incoming liquid stream, first by heat exchange, if necessary, and then by direct mixing of the bleed stream with the main liquid stream. The resulting decrease in the temperature of the mixed stream leads to the condensation of additional water from the gas. The required cooling depends on the minimum water content required to ensure that the stream composition satisfies the process specifications, such as moisture dew point temperature and/or hydrate formation temperature.

The following are examples illustrating embodiments of the present invention, in particular:

example 1 - basic implementation;

example 2 - using a low temperature separator (LTS);

example 3 - using a heat exchanger (HEX);

example 4 is a multi-stage isenthalpic embodiment; and example 5 is a multi-stage isentropic and isenthalpic embodiment.

- 4 042002

Examples 1-3 show the use of streams of various compositions, in particular a stream containing 100% CO2 and a stream containing 80% CO2 and 20% H2S. However, it should be noted that embodiments of the present invention are suitable for streams containing various amounts of H2S and containing SO ₂ , NO _x and any other gaseous mixtures with relatively large JT coefficients.

Examples 4 and 5 present the low temperature performance of embodiments of the present invention, as well as the differences between isenthalpic and isentropic processes.

Example 1. Basic.

In the embodiment of the present invention shown in FIG. 4A and 4B, the water-saturated acid gas feed stream 10 enters a dilution stage 12 where it is compressed 14 to the suction pressure of the next stage 16. The hot compressed vapor 14 is cooled 18 by an aftercooler 20, whereby a portion of the water is condensed. and other condensable components from the feed stream. The condensed liquid containing water is separated 22 in a separator 24 further in the final compression stage. Saturated gas 26 from separator 24 is subjected to additional compression at stage 28 and re-cooled at stage 30.

The bleed stream 32 from the compressed and sub-cooled liquid stream is separated and isoenthalpically expanded 34 by means of a Joule-Thomson valve (TCV) 36 to the lower suction pressure of said compression stage 16. The expansion results in a decrease in temperature, the magnitude of which depends on the magnitude of the pressure reduction and the composition of the fluid stream. The cold stream 38 is combined with the pre-cooled stream 18 from the previous compression stage to form a combined stream 40 at a temperature reduced enough to condense the required amount of water.

As shown in FIG. 4A, for a feed stream containing 100% CO2, the temperature dropped to about 87°F (30.55°C) and the final water content dropped to about 73 lb/million standard cubic feet (MMscf) (1170 mg/m ³ ) , resulting in a hydrate formation temperature (HFT) of 30°F (-1.11°C).

As shown in FIG. 4B, a feed stream containing 80% CO ₂ and 20% H ₂ S requires only a temperature reduction to about 93°F (33.89°C) to obtain a final water content of about 89 lb/MMscf (1426 mg/m ³ ), resulting in a hydrate formation temperature (HFT) of 30°F (-1.11°C).

Example 2 Heat exchanger (HEX).

In cases where the composition of the feed stream, in combination with a large reduction in pressure, results in a stream temperature that is below the hydrate formation temperature of the main raw feed stream, the embodiment shown in FIG. 4A and 4B can be modified by including a heat exchanger (HEX).

In FIG. 5A and 5B, the basic embodiment has been modified to eliminate the need for continuous addition of a hydrate inhibitor used in conventional refrigeration processes.

In FIG. 5A and 5B, effluent stream 34 is partially expanded 42 by a second Joule-Thomson valve (JTV) 44. The temperature of the partially expanded stream is then raised in heat exchanger 46 before further expansion of stream 48 by a Joule-Thomson valve (TCV) 50. Thus, temperatures the partially and fully expanded streams 42, 48 are maintained above the respective hydrate formation temperatures of the main raw feed stream.

In Example 2, the hydrate temperature was set at 15°F (-9.44°C).

As shown in FIG. 5A, a feed stream containing 100% CO ₂ requires a temperature reduction to about 73°F (22.78°C) to obtain a final water content of approximately 51 lb/MMscf (817 mg/m ³ ), resulting in a temperature hydrate formation 15°F (-9.44°C).

As shown in FIG. 5B, for a feed stream containing 80% CO ₂ and 20% H2S, the temperature was reduced to about 79°F (26.11°C) to give a final water content of about 64 aeyn/MMscf (1026 mg/m ³ ), resulting in to obtain a hydrate temperature of 15°F (-9.44°C).

Example 3 Low Temperature Separator (LTS)

In FIG. 6A and 6B, as an alternative to the embodiment described in Example 2, an embodiment of the present invention using an additional separator is shown, in which a significant decrease in temperature is observed.

As shown in FIG. 6A and 6B, 46 and JTV 44 of FIG. 5A and 5B have been replaced with a second low temperature separator (LTS) 52. The effluent stream 54 is expanded 56 by a Joule-Thomson valve (TCV) 44. The first separator 24 is designed to remove as much water as possible from the feed stream before reintroducing the expanded effluent stream 48. Expanded effluent stream 48 is provided with a hydrate inhibitor if the process flowsheet requires the expanded effluent temperature to be below 32°F (0°C). Early removal of the water results in a reduction in the amount of cooling required to meet specifications and, if conditions permit, in a reduction in the amount of hydrate inhibitor required.

- 5 042002

In Example 3, the hydrate temperature was set at 0°F (-17.78°C).

As shown in FIG. 6A, a feed stream containing 100% CO2 requires a temperature reduction to 62°F (16.67°C) to obtain a final water content of approximately 36 lb/MMscf (577 mg/m ³ ) to meet the target hydrate temperature of 0 °F (-17.78°C).

As shown in FIG. 6B, a feed stream containing 80% CO ₂ and 20% H2S requires a temperature reduction to about 67°F (19.44°C) to obtain a final water content of approximately 45 lb/MMscf (721 mg/m ³ ) to obtain a target hydrate formation temperature of 0°F (-17.78°C).

Example 4. Multi-stage isenthalpic.

In FIG. 7 shows a multi-stage embodiment of the present invention when a very large temperature reduction is required. An embodiment provides a hydrate formation temperature of -45°F (-42.78°C).

As shown in FIG. 7, this embodiment includes the use of a heat exchanger 46, a low temperature separator 52, and continuous injection 56 of a hydrate inhibitor. The first separator 24 is located between the heat exchanger 46 and the step of reintroducing the reduced temperature stream. Early removal of water from the feed stream results in a reduction in the amount of refrigeration and the amount of hydrate inhibitor required to meet specifications.

To obtain a lower temperature, the pressure reduction resulting from the expansion of the effluent stream 58 by means of the Joule-Thomson valve 44 is carried out for at least two stages of compression. Thus, the partially expanded effluent stream 60 is heated in heat exchanger 46 and fully expanded 62 by means of a Joule-Thomson valve 64 for reintroduction together with the introduction of a hydrate inhibitor into the feed stream in two or more stages 66, 68 after separation of the effluent stream 58 to cool the feed stream 28. Condensed water is removed from the cooled feed stream 28 in the second separator 52 before further compression of the cooled feed stream 28.

In this example, the low temperature provided by fully expanding effluent stream 56 and cooling feed stream 28 requires the addition of a hydrate inhibitor; however, the amount of hydrate inhibitor is minimal due to the prior removal of a significant amount of water in the first separator 24.

An additional benefit of maintaining a low temperature while cooling the feed stream in this example is the ability to reduce the number of compression stages from five to four, resulting in a lower overall cost.

Example 5. Multi-stage isentropic.

In FIG. 8 shows a multi-stage embodiment of the present invention in which, instead of the Joule-Thomson valve 44 of FIG. 7, an isentropic fluid expander 66 is used, such as a conventional radial expansion turbine or turboexpander (eg, manufactured by Mafl-Trench, Santa Maria, CA, USA).

In this embodiment, an isentropic fluid expander allows for a lower temperature of the expanded effluent stream 60 compared to using a Joule-Thomson valve (isenthalpic expansion) with a similar pressure drop. In addition, a smaller volume of the effluent fraction is required compared to example 4.

The required amount of energy for stage 3 (66) and stage 4 (68) in this embodiment is about 2% lower compared to example 4. The isentropic fluid expander generates energy in an amount of about 1.8% of the energy required for stage 3 ( 66) and stage 4 (68), which can be used for other purposes. In addition, a minimum amount of hydrate inhibitor is required.

The embodiments described herein have significant advantages and differences over conventional liquid desiccant drying and isenthalpy cooling drying processes.

Compared to liquid desiccant drying processes, embodiments of the present invention eliminate the need for conventional drying equipment by replacing it with expansion valves (TCV, JTV) that cost significantly less than the capital cost of conventional drying equipment.

Compared to conventional isenthalpy expansion refrigeration processes such as a throttling unit or DPCU, embodiments of the present invention eliminate the need for a single compression stage, the use of a main gas-to-gas heat exchanger, and the addition of a hydrate inhibitor, resulting in significant capital cost savings.

In a throttling system or DPCU, the prior art requires that the entire gas flow be overcompressed and expanded to a predetermined pressure. As a rule, this leads to an increase in the initial energy requirements for compression for the system by 20-25%. Depending on the

- 6 042002 gas composition and operating conditions higher pressure at the outlet of the compressor may lead to the need for an additional complete compression stage.

Depending on the composition of the acid gas and the required operating conditions, the cooling bleed stream typically comprises 10 to 30% of the combined stream passing through the unit stage. Increasing throughput in one compression stage theoretically increases the total energy requirement for compression by 2-6% (i.e. 1/5 of 10-30% for 5 compression stages). However, this increase is usually comparable to the increase due to pressure drop when using conventional drying equipment. In addition, there is an increase in efficiency and therefore a corresponding reduction in compression energy, which leads to a decrease in the operating temperature of the compressor. In some cases, the need for compression energy is less than with conventional drying equipment.

The lower suction temperatures provided by the embodiments of the present invention have an additional advantage over a conventional dryer and throttling unit. A lower temperature in one stage allows the equilibrium between the compression ratios in each stage to be restored, with a higher compression ratio corresponding to a lower compression pressure, resulting in a reduction in the compression ratio in the remaining stages until the outlet temperatures for each stage are approximately equal to the new lower value. Lowering the outlet temperature to some extent reduces the need for additional energy due to the presence of additional volume of discharge stream in one or more stages of compression.

Reducing the temperature also extends valve life, increases operating time and reduces operating costs. Re-equilibration at some point in time at certain lower temperatures may be sufficient to eliminate the full compression stage and thus provide a significant reduction in capital costs.

It is believed that the total emissions in terms of carbon dioxide in embodiments of the present invention is significantly lower compared to conventional methods. Equipment requirements are greatly reduced, which also reduces process requirements, with no glycol preparation and no additional CO ₂ generating equipment required, more than offsetting the slight increase in energy (typically about 2%) required to compress the volume. outgoing flow. In addition, the reduced chemical requirements of embodiments of the present invention greatly reduce environmental risks.

Acid gases, including CO ₂ , H ₂ S, SO 2 and NO, are liquids well suited for use in embodiments of the present invention. However, it is believed that liquids are not limited to the examples presented in this application. In addition, it is believed that the thermodynamic principles applied in the embodiments of the present invention are valid for all liquid mixtures that exhibit a positive Joule-Thomson coefficient (JT) over a given range of process operating conditions; in other words, liquid mixtures cool as they expand. In general, a fluid with a higher JT is cooled more than a fluid with a lower JT, and hence less fluid is required to provide bleed flow. The possibility of using a smaller bleed stream is advantageous from an economic point of view.

Applications of embodiments of the present invention include carbon dioxide capture and storage (CCS), treatment of CO ₂ , SO2 and NO _x captured from combustion, gasification and industrial chemical processes for sequestration, and AGI (acid gas injection) in which H2S and CO2 captured during the processing of oil and gas for sequestration. Another field of application of embodiments of the present invention relates to the recovery of liquid hydrocarbons from gas vapor from a solution with a relatively high content of acid gas, which is usually treated in enhanced oil recovery (EOR) processes. Another area of application for embodiments of the present invention covers situations where acid gas dehydration is required under conditions of limited available space or weight constraints. This situation can be observed in the operation of offshore floating oil production systems or when upgrading both onshore and offshore systems. The equipment configurations of the present invention provide significant space and weight advantages over other commercial drying equipment.

Examples 1-5 presented in this application are based on one set of conditions. In embodiments of the present invention, optimization is required for each fluid and set of conditions. The optimization includes selecting the compression stage most suitable for starting the formation of the bleed stream and most suitable for combining the bleed stream. Other optimization includes selecting the optimal process implementation, eg, base, HEX, LTS, multi-stage, multi-stage isentropic, or some other combination of the process implementations described above. Also, in any of the options, it is required to turn on the optimal equipment and control system, as well as to establish the optimal operating mode for a given application.

- 7 042002

In FIG. 9, the number 80 denotes standard upstream operations, and the number 81 denotes a general process flow according to a further embodiment.

With regard to the general numerical designations from the previous embodiments, the separator 13 is designed to separate the saturated gas feed stream 10 entering the compressor 12, in which the stream is compressed to outlet pressure, and then the compressed vapor 14 is fed to the aftercooler 20, which leads to the condensation of some parts of water and other condensable components from the feed stream. These operations are presented earlier in this application in relation to other implementation options.

The again schematically represented acid gas stream 18, which typically comes from a compressor, cell, or the like, is typically saturated with water. For example, the stream may contain 100% acid gases, or may have other concentrations of acid gases, where the remainder up to 100% is typically hydrocarbons, and low concentrations of other inert gases. For example, for purposes of explanation, the stream may have a temperature of 120°F (48.89°C) at a pressure of 600 psi (41.37 bar). This diagram shows a pair of heat exchangers 84 and 86. With regard to heat exchangers 84 and 86, heat exchanger 84 is a gas-liquid heat exchanger used to transfer heat from stream 18 to cold liquid stream 96. Stream 90 mixes with cooled stream 89 exiting through a Joule valve. Thomson 44. These two streams are mixed in a mixer 92. The mixture 93 thus obtained is introduced at a temperature of about 50°F (10°C) into a low temperature separator 94. At this stage, the liquids that condense at a pressure of 600 psi (41.37 bar) , form a cold liquid stream 96. Stream 96 is at a temperature close to the hydrate formation temperature of the mixture of liquids. Further reduction in flow pressure is very likely to result in hydrate formation. Stream 96 enters heat exchanger 84 and heat exchanges with stream 18, whereby stream 18 is cooled and stream 96 is heated. Advantageously, stream 96 receives some of the heat from stream 18 to reduce the likelihood of hydrate formation. It is also useful to cool the stream 18 to reduce the additional cooling required. After stream 96 is heated by heat exchange in heat exchanger 84, stream 98 may have a temperature of 120°F (48.89°C). Valve 100 can then depressurize stream 98 without forming hydrates while maintaining the desired liquid level in low temperature separator 94. After reaching the desired liquid level, valve 100 is opened and stream 102 is introduced into three-phase separator 104. Stream 102 may consist of three phases; steam, liquid hydrocarbon and water. The residence time in separator 104 is sufficient to facilitate separation of heavier liquids in stream 106, typically water, steam in stream 108, and lighter liquids in stream 110, typically hydrocarbons. The liquid hydrocarbons 110 separated at this stage can then be sent to an oil treatment plant for processing (not shown), stabilization and subsequent sale.

With regard to the low temperature separator 94, the stream 112 leaving it is a cold vapor stream of acid gas (typically CO ₂ ) and can be used as an additional source for pre-cooling the main system. Streams 88 and 112 are introduced into heat exchanger 86, which in this case is a gas-to-gas heat exchanger used to transfer heat from stream 88 to cold vapor stream 112 exiting low temperature separator 94. This stream also provides pre-cooling of stream 90 exiting heat exchanger 86 , resulting in a reduction in the required additional cooling. At this stage, stream 114 has a temperature of about 110°F (43.33°C) from the example given in the present description. This system is particularly useful in that it allows the extraction of hydrocarbons, if it is economically feasible.

Stream 114 is then introduced into the block for the operations described earlier in this specification with respect to the base system as a whole.

If it is not feasible or economically feasible to recover liquid hydrocarbons, the flowsheet designer should use the system shown in FIG. 10, which is described in more detail later in this description. This system is also attractive from the point of view of improving applications that use existing compressor configurations with minimal changes while maintaining the benefits provided by the technology presented in this application.

In the case of FOR applications using CO ₂ , make-up or additional CO 2 is usually mixed with the resulting steam and reintroduced into the production vessel. Depending on the pressure of the CO2 make-up stream, it can be mixed with stream 34 or even replaced with said stream to improve the Joule-Thomson coefficient and reduce HFT. Dry make-up CO ₂ can be used to minimize or eliminate the use of hydrate inhibitors such as methanol or glycol during system startup.

If necessary, the process can be used to condense liquids other than the hydrocarbons used in this example.

If an improvement in the separation efficiency of liquid hydrocarbon and vapor is required, additional pressure reduction and separation steps can be carried out (duplication of steps 100, 102 and 104 and

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Claims (1)

replacing step 98 with step 110). Additionally, the system may include the use of thermodynamic modeling software to facilitate optimization of operating conditions by predetermining moisture dew point, hydrate formation temperature, and hydrocarbon recovery. In FIG. 10 shows another embodiment of the present invention. Clearly, this embodiment eliminates a significant number of single operations compared to the embodiment shown in FIG. 9. Application of the three-phase separator 104 of FIG. 9 is optional in this embodiment, as is the use of a gas-liquid heat exchanger. The remaining unit operations are similar in function to those in FIG. 9, and the general sequence of conduct is obvious to a person skilled in the art. This implementation option is particularly well suited to existing configurations, for which improvement is possible to reveal the advantages of the system described in this application. When the gas-to-gas heat exchanger is switched on, the proportion of the cooling bleed stream in the combined stream passing through a single stage is typically reduced to 4-10% depending on the composition of the acid gas and the required operating conditions. Increasing throughput in one compression stage theoretically increases the total energy requirement for compression by 1-2% (i.e. 1/5 of 4-10% for 5 compression stages). The use of an LTS is only required if the material of the metal inlet gas separator used is incompatible with the resulting acidic aqueous solution and replacement of the gas separator used is unacceptable. The capital cost for this implementation option increases accordingly. In the embodiment shown in FIG. 10, heavy liquid phase stream 34 is typically a warm, high pressure recycle stream, typically a supercritical (dense) phase or liquid. It is passed through a Joule-Thomson valve 44 resulting in a decrease in pressure and hence temperature of stream 34. The low pressure cold recycle stream 89 is used to mix with the pre-cooled inlet stream 90 in mixer 92. The mixture previously shown in Fig. 9 is numbered 93. The liquid phase exiting the low temperature separator 94 in step 96 is predominantly water. Said stream is usually mixed at some other stage in the water treatment process. As an example, stream 90 may be cooled to about 60-70°F (15.55-21.11°C) depending on the available surface area in heat exchanger 86. The bleed stream 34 (previously described herein in other embodiments) may be at 120°F (48.89°C) and optionally at 2000 psig (137.9 bar) . Said high pressure stream can be depressurized using a 44 Joule-Thomson valve. the stream expands and thus cools to about 40°F (4.4°C). The resulting cold stream 89 is mixed with stream 90 in a mixer 92. The mixture 93 thus obtained is introduced into a low temperature separator 94 at a temperature of about 50°F (10°C). ) form a cold liquid stream 96. The stream 112 leaving the separator 94 is a cold vapor stream of acid gas (typically CO ₂ ) and can be used as a source for pre-cooling the hot inlet stream 18. Streams 18 and 112 are introduced into the heat exchanger 86, which is a gas-to-gas heat exchanger used to transfer the heat of stream 18 to the cold vapor stream 112 leaving the low temperature separator 94. This heat exchange also pre-cools the stream 90 leaving heat exchanger 86, resulting in a reduction in the required additional cooling. . At this stage, stream 114 has a temperature of about 110°F (43.33°C) from the example given in the present description. CLAIM 1. A method for removing condensable components from a feed stream containing condensable components, comprising: a) optimizing the temperature of said feed stream by heat exchange and cooling to allow liquids to condense therefrom, b) removing condensed liquids to produce a gas stream, c) compressing and cooling said gas stream to form a high pressure stream, d) expanding at least a portion of said high pressure stream to form a cooled low pressure stream, e) mixing said low pressure chilled stream with said feed stream to cool and condense the condensable components in said feed stream to form a mixture, -