JP6357155B2 - A method for optimizing condensable component removal from fluids - Google Patents

Description

Detailed Description of the Invention

[Technical field]
The present invention relates to the removal of condensables from a mixed fluid exhibiting a positive Joule-Thompson effect, and more particularly the present invention minimizes or substantially eliminates the production of internal liquid water, for example. And the removal of water from the acid gas stream to minimize corrosion and hydrate formation in the gas stream transported and injected for sequestration. Considerations for retrofitting older equipment and enhanced hydrocarbon recovery are provided as well.

[Background technology]
Gas streams, such as those produced during petroleum refining and combustion processes, often include a gas that produces an acid when mixed with water. Such a gas is generally called an “acid gas”. The most common acid gases that are naturally generated in the oil refining process are hydrogen sulfide (H ₂ S) and carbon dioxide (CO ₂ ). Typical acid gases generated during the combustion, oxidation, and thermal decomposition processes are carbon dioxide (CO ₂ ), sulfur dioxide (SO ₂ ), and nitrogen oxides (NO, NO ₂ ).

  The acid gas usually contains moisture. Naturally occurring acidic gas is often saturated with moisture in the storage tank, and the gas obtained by combustion coexists with moisture generated by the reaction between hydrogen and oxygen during combustion. Virtually all acid gases substantially saturate the water vapor at some point during the acid gas removal or purification process. When the temperature of the acidic gas containing water falls or the pressure increases over a certain range, such as when the acidic gas passes through the compressor, a part of the moisture is condensed from the gas phase to the liquid phase. At some temperature above the freezing point of water, water and acid gases may begin to form “solid-like” structures called gas hydrates. The temperature at which hydrate formation begins is called the hydrate formation temperature (HFT) and varies with pressure, composition and water content of the mixture. Hydrates are compounds that result from the physical association of water with small molecules, have an “ice-like” appearance, but have different properties and structures from ice. Hydrates are also called gas clathrate. Hydrates are problematic because they can cause reduced heat transfer during production, excessive pressure drops, clogging, interruptions, and safety concerns.

  The formation of the aqueous phase is undesirable in any gaseous system as it promotes corrosion, can generate gas hydrates, and can cause mechanical and operational problems. The aqueous phase is particularly undesirable in acidic gas systems because the resulting aqueous phase becomes acidic, the corrosion rate becomes very high, and usually a higher HFT than non-acidic gases is produced.

  Table A shows the level of corrosion that occurs in mild steel at various acid gas concentrations in water.

酸性ガスに焦点を当てて考察しているが、当業者であれば、正のジュール・トムソン係数を示す全ての流体流から凝縮性成分を除去するために、本方法論と概念とを適用できることを理解することができる。

Although the discussion focuses on acid gases, those skilled in the art will recognize that this methodology and concept can be applied to remove condensable components from all fluid streams that exhibit positive Joule-Thompson coefficients. I can understand.

[Summary of Invention]
One object of an embodiment of the present invention is to provide a method for removing a condensable component from a fluid containing a condensable component, the method comprising the temperature of the initial feed stream containing the condensable component. By cooling and condensing liquid to remove the liquid to form a gas stream, compressing and aftercooling the gas stream to form a high pressure stream, Expanding at least a portion to form a cooled low pressure stream; and mixing the cooled low pressure stream and the initial feed stream to increase cooling and condensation of condensable components in the initial feed stream. Forming the mixture, separating the mixture into a liquid flow and a gas flow, and performing the heat exchange by the gas-liquid heat exchange operation in combination with the gas-gas heat exchange operation in order. And the gas flow for the first time Comprising a step of contacting the feed stream, the.

Referring to FIGS. 1 and 2, the water content in the acid gas is proportional to the temperature and inversely proportional to the pressure up to about 400 psia (27.58 bar) for H ₂ S and 900 psia (62.05 bar) for CO _2. . Within this limit, if the pressure is high and the temperature is low, the water content in the acid gas is low.

Dehydration is a process that removes water to minimize or prevent the formation of hydrates and free water. For acidic gases containing relatively high H ₂ S concentrations, it is usually sufficient during cooling during a conventional multi-stage compression stage to a dense phase (a constant pressure above the critical pressure of the fluid is also known as supercritical). Since no water is removed, no additional dehydration is required. As the CO ₂ content in the acid gas increases, the possibility that sufficient water can be removed by compression alone decreases, and another dehydration treatment is usually required.

  Conventional means of gas dehydration are solid desiccant adsorption, liquid desiccant adsorption, refrigeration, membrane separation, and dry gas stripping. The most commonly used methods are solid desiccant adsorption and liquid desiccant adsorption.

Glycol dehydration, a liquid desiccant adsorption process, is generally considered to be the most economical process that is suitably used in most applications. Such a liquid desiccant adsorption process has several drawbacks.
• Glycol loss may be significant when used in high pressure CO ₂ .
・ Excessive oxygen present in the acid gas typically generated by combustion significantly increases corrosion and requires the addition of a continuous glycol regeneration process to accelerate the degradation of glycol at higher regeneration temperatures. .
• Action should be taken to monitor the glycol to maintain the proper pH range.
-Typically, dehydrators are made of expensive corrosion-resistant metals, such as stainless steel, to cope with the acidic liquid produced.
Glycols are generally heated to 400 ° F. (204.4 ° C.) for regeneration, evaporating water, as well as absorbed acid gases, and other contaminants that are also absorbed by the glycol, eg, volatile Release of organic compounds (VOC), typically benzene, toluene, ethylbenzene and xylene (BTEX), and other stripping gases into the atmosphere occurs. Such a temporary release control generally requires the addition of an expensive steam recovery device, resulting in the possibility of further oxygen contamination.
-The requirements for such treatment are high, including the fuel used for glycol regeneration and the power required for the operation of the steam recovery unit and the pumping of the glycol.
The production of the dehydrator results in a large amount of total carbon dioxide emissions, and the CO ₂ resulting from this utility requires the design of a treatment system and process for glycols used in the dehydration process.

  Dehydration by freezing utilizes the fact that the ability of the gas to retain water decreases as the temperature decreases. The temperature drop can be achieved indirectly by heat exchange by external “refrigeration” or other temperature drop treatment, or directly by expansion of the gas itself. Direct expansion of gas is performed by isentropic expansion as in a turbo expander, isoenthalpy expansion such as a Joule-Thomson (JT) valve used in a conventional choke plant, or gas compression refrigeration. Introducing an indirect refrigeration unit for dehydration purposes is generally prohibitive.

  Both direct isenthalpy dehydration and isentropic freeze dehydration processes use an expansion device, a cryogenic separator and at least one heat exchanger to recover as much energy as possible from the process. In its simplest form, the entire gas expands from high pressure to low pressure with isoenthalpy or isentropic, creating a low fluid temperature sufficient for water condensation to occur. The condensed water is removed from the process in a cryogenic separator, and the remaining cold, sufficiently dry gas is used to precool the incoming fluid to improve the thermal efficiency of the process. This is commonly referred to as a “choke plant” or “dew point controller (DPCU)” in upstream oil and gas processing applications.

In the case of isentropic expansion, the expansion takes place in the expander, and the work removed by the expander is usually used to partially recompress the outlet dry gas.
The choice between using isentropic expansion or isoenthalpy expansion depends on the amount of water removal required and thus the amount of temperature drop required. With isentropic expansion, a lower temperature can be obtained. From the viewpoint of capital costs, isentropic processing is very expensive but is offset by the advantage of recovery work capacity. From an operational and maintenance point of view, isoenthalpy processing has the advantage of mechanical and operational simplicity and is suitable for most applications. The disadvantage of offsetting the isoenthalpy feature is that it requires additional work due to the increased need for compression.

  A common disadvantage with any freeze dehydration is that the gas stream needs to be cooled to a temperature near or below the hydrate formation temperature (HFT) in most applications to achieve the desired level of dehydration. . In order to obtain operational reliability, usually a thermodynamic hydrate inhibitor such as glycol or methanol is continuously added to lower the HFT. If necessary, both glycol and methanol can be recovered, but another regeneration process that meets all of the above-mentioned matters regarding liquid desiccant dehydration is required. Methanol is relatively harmless and has less impact on downstream processing than glycol, so in many cases the choice is made to use methanol without recovery. Interestingly, methanol is not only useful as a hydrate inhibitor, but can further reduce water content than in the case of a simple temperature drop. In this way, dehydration is promoted.

Clearly, there is a need for an acid gas stream dewatering process that is efficient and cost-effective and that avoids the problems noted in conventional dewatering processes.
The features of the present invention will become more apparent from the following detailed description with reference to the accompanying drawings.

FIG. 5 is a graph of the saturated water content of various fluids, acid gases and methane (CH ₄ ) under a series of pressures at 100 ° F. (37.78 ° C.). FIG. 6 is a graph of the saturated moisture content of CO ₂ rich mixture and methane (CH ₄ ) under a series of pressures at 100 ° F. (37.78 ° C.). ₂ is a graph of glycol loss in a prior art high pressure CO ₂ operation. ₂ is a system diagram of an isenthalpy dehydration process according to an embodiment of the present invention for a water saturated fluid stream containing 100% CO ₂ . FIG. 4B is a system diagram of an isoenthalpy dehydration process according to FIG. 4A for a fluid stream containing 80% CO ₂ and 20% H ₂ S. Prior to further expansion of the slipstream, the partially expanded slipstream is heated by the introduced heat exchanger to prevent hydrate formation in the main process feed stream to achieve the desired temperature drop, FIG. It is a systematic diagram of the isoenthalpy dehydration process according to FIG. 4B. FIG. 5 is a system diagram of an isoenthalpy dehydration process according to FIGS. 4A and 4B, with a low temperature separator to remove water from the fluid stream before reintroduction of the slipstream and with continuous hydrate inhibitor input. . It is a systematic diagram of the multistage enthalpy processing by embodiment of this invention. FIG. 4 is a system diagram of multi-stage isentropic processing according to an embodiment of the present invention in which one of the Joule-Thomson valves is replaced with an isentropic fluid expander. FIG. 4 is a system diagram according to a further embodiment of the present invention. It is a systematic diagram of another modification of the technology included in the present invention.

  The provided examples are assumed to have steady state performance. Other considerations are made to accommodate start-ups for commercial operations, malfunctions during operation and shutdowns. One simple example is that during the first few minutes of start-up and during external process upsets, the temperature and slipstream flow rate may not be the steady state operating conditions defined in the process design. Without some design response to alleviate this condition, hydrate formation may begin. Therefore, embodiments of the present invention are designed to incorporate the ability to add a thermodynamic hydrate inhibitor such as methanol to temporarily prevent the formation of hydrates in unsteady state performance. .

In the drawings, like reference numerals refer to similar elements.
[Best Mode for Carrying Out the Invention]
Embodiments of the present invention take advantage of the thermodynamic properties of typical acid gases useful as “refrigerants”. Such gases exhibit a relatively large temperature drop for a given pressure drop within the processing work area. The large temperature drop is used to cool the feed stream slip stream, which is then recycled upstream to cool the feed stream. In this way, the method performs “automatic freezing” by reuse. The Joule-Thompson effect is obtained by expanding the gas with equal enthalpy through a throttle device, usually a control valve. During isoenthalpy expansion, no work can be taken out of the gas. The rate of change of temperature with respect to fluid pressure during Joule-Thomson treatment is the Joule-Thomson (Kelvin) coefficient. For example, the Joule-Thomson (JT) coefficient of carbon dioxide at 50 ° C. and 60 atmospheres (60.79 bar) is about 5.6 times greater than that of nitrogen under the same conditions. Thus, the temperature drop in CO ₂ is about 5.6 times greater than for the same pressure drop under the same conditions in nitrogen. JT coefficient data is also available for H ₂ S, SO ₂ , and other acidic gases, as well as hydrocarbons that may be present, and inert gases such as nitrogen and oxygen.

  Acid gases processed for commercial applications such as enhanced oil recovery (EOR) applications, carbon dioxide capture and blockage (CCS) applications are usually supercritical, commonly referred to as “dense phase” for transport and / or blockade Compressed to pressure. In order to obtain a dense phase, centrifugal force, reciprocation, or impact compression is used depending on the initial pressure, but in either case, compression is usually performed in more than one stage. The pressure difference between the stages can be exploited to take advantage of the favorable JT coefficient nature of the steam.

  The compression is divided into two different regions with the critical point of the fluid to be compressed as a boundary. The compression stage of the first zone is precritical and the stage of the second zone is in a fluid state above its critical pressure, which can be achieved by compression and pumping means. The inlet stream enters the first region of compression, and this inlet stream is precritical and is assumed to be water saturated. Some water is inevitably removed by stages of compression in the first region.

  In an embodiment of the present invention, a single stage of aftercooled discharge fluid slipstream close to or above the critical pressure is compressed to the same stage of intake pressure or additional temperature drop. Is required, the pressure is expanded to the previous pressure. The reduced temperature resulting from the expanded slipstream is used to cool the upstream main fluid stream initially by heat exchange if necessary and ultimately by mixing the slipstream directly into the main fluid stream. It is done. The resulting drop in the temperature of the mixed stream condenses additional water in the gas. The amount of cooling required is a function of the minimum water content required for a flow composition that meets the design criteria for water dew point and / or hydrate formation temperature.

Examples that further illustrate embodiments of the present invention are given below.
Example 1 is a basic embodiment.
Example 2 uses a low temperature separator (LTS).

Example 3 incorporates a heat exchanger (HEX).
Example 4 is an embodiment of multi-stage enthalpy.
Example 5 is an embodiment of multi-stage isentropy and isoenthalpy.

Examples 1-3 are shown using different stream compositions, more specifically a stream containing 100% CO ₂ and a stream containing 80% CO ₂ and 20% H ₂ S. It is. However, it should be noted that embodiments of the present invention are applicable to streams containing various amounts of H ₂ S and streams containing SO ₂ , NO _x and other gas mixtures with relatively large JT coefficients.

Examples 4 and 5 illustrate the low temperature performance of embodiments of the present invention and the difference between the isenthalpy process and the isentropic process.
Example 1-Basic Example Referring to FIGS. 4A and 4B, in an embodiment of the present invention, a water-saturated acid gas feed stream 10 enters an intake stage 12 where the intake of the next stage 16 is taken. Compressed to pressure (14). The hot compressed steam 14 is cooled by an aftercooler 20 (18), resulting in the condensation of some water and other condensables within the feed stream. The condensed liquid, including water, is removed (22) in the separator 24 upstream of the final compression stage. The saturated gas 26 from the separator 24 is further compressed at 28 and aftercooled again at 30.

  Slip stream 32 from the compressed and aftercooled fluid stream is withdrawn and passed through a Joule-Thomson valve (TCV) 36 and expanded isenthalpy to the lower intake pressure of the same compression stage 16 (34). Expansion causes a temperature drop, the magnitude of which depends on the magnitude of the pressure drop and the fluid flow composition. The cooler stream 38 is mixed with the aftercooled stream 18 exiting the pre-compression stage, resulting in a mixed stream 40 having a temperature drop sufficient to condense the required amount of water.

As shown in FIG. 4A, for a feed stream with 100% CO ₂ , the temperature drops to about 87 ° F. (30.55 ° C.) and the final moisture content drops to about 73 pounds / million cubic feet. The hydrate formation temperature (HFT) is 30 ° F. (−1.11 ° C.).

Referring to FIG. 4B, a feed stream containing 80% CO ₂ and 20% H ₂ S has the same hydrate formation temperature (HFT) with a final moisture content of about 89 pounds / million cubic feet. In order to achieve 30 ° F. (−1.11 ° C.), the temperature need only be lowered to about 93 ° F.

Example 2-Heat exchanger (HEX)
In the case of a feed stream composition where the stream temperature is below the hydrate formation temperature of the non-dehydrated main feed stream when combined with a large pressure drop condition, the embodiment shown in FIGS. 4A and 4B is modified. Then, a heat exchanger (HEX) may be incorporated.

In FIGS. 5A and 5B, the basic embodiment is modified to avoid the need for continuous input of hydrate inhibitor as used in conventional refrigeration processes.
5A and 5B, the slip stream 34 is partially expanded (42) through a second Joule-Thomson valve (JTV) 44. The temperature of the partially expanded stream is then raised in heat exchanger 46 prior to further expansion of stream 48 through Joule Thomson valve (TCV) 50. Thus, the temperature of the partially and fully expanded streams 42, 48 is maintained above the respective hydrate formation temperature of the non-dehydrated main feed stream.

In Example 2, the design hydrate formation temperature was set to 15 ° F. (−9.44 ° C.).
As shown in FIG. 5A, for a feed stream having 100% CO ₂ , the designed hydrate formation temperature of 15 ° F. (−9 .9.) With a final water content of about 51 pounds / million cubic feet. To achieve 44 ° C), the temperature must be reduced to about 73 ° F (22.78 ° C).

In FIG. 5B for a feed stream containing 80% CO ₂ and 20% H ₂ S, the final moisture content is about 64 lb / s by reducing the temperature to about 79 ° F. (26.11 ° C.). The design hydrate formation temperature of 15 ° F. (−9.44 ° C.) was achieved to 1 million cubic feet.

Example 3-Low Temperature Separator (LTS)
6A and 6B, the embodiment of the present invention uses an additional separator with a significant temperature drop as an alternative to the embodiment described in Example 2.

  As shown in FIGS. 6A and 6B, the heat exchanger 46 and the JTV 44 in FIGS. 5A and 5B are replaced with a second low temperature separator (LTS) 52. Slip stream 54 is expanded through a Joule-Thomson valve (TCV) 44 (56). The first separator 24 is arranged to remove as much water as possible from the feed stream prior to recharging the expanded slipstream 48. If the process design requires that the temperature of the expanded slip stream be below 32 ° F. (0 ° C.), it is conceivable to add a hydrate inhibitor into the expanded slip stream 48. Early removal of water reduces the amount of cooling required to meet the design requirements and, if conditions are met, the amount of hydrate inhibitor required.

The design hydrate formation temperature of Example 3 was set to 0 ° F.
As shown in FIG. 6A, a feed stream having 100% CO ₂ has a final hydrate content of about 36 pounds / million cubic feet and a design hydrate formation temperature of 0 ° F. (−17.78 ° C.). In order to achieve this, the temperature had to be reduced to about 62 ° F.

In the case of FIG. 6B, the feed stream contains 80% CO ₂ and 20% H ₂ S, with a final moisture content of about 45 pounds / million cubic feet, at a design hydrate formation temperature of 0. In order to achieve ° F (-17.78 ° C), the temperature had to be reduced to about 67 ° F (19.44 ° C).

Example 4 Multi-Stage Enthalpy In FIG. 7, a multi-stage embodiment of the present invention is used when the required temperature drop is very large. The embodiment was designed to achieve a hydrate formation temperature of −45 ° F. (−42.78 ° C.).

  As shown in FIG. 7, this embodiment includes a heat exchanger 46, a cryogenic separator 52, and a continuous hydrate inhibitor charge (56). The first separator 24 is placed between the heat exchanger 46 and the reflow of the temperature-decreased stream. Early water removal from the feed stream reduces the amount of cooling and hydrate inhibitors required to meet design criteria.

  In order to achieve lower temperatures, the pressure drop caused by the expansion of the slip stream 58 through the Joule-Thomson valve 44 occurs through at least two stages of compression. Thus, the partially expanded slipstream 60 is heated in heat exchanger 46 and fully expanded (62) through Joule-Thomson valve 64 to cool feed stream 28 with the addition of hydrate inhibitor. In order to do so, it is re-introduced into the feed stream of the two or more stages 66, 68 upstream from the removal of the slipstream 58. Prior to further compression of the cooling feed stream 28, condensed water is removed from the cooling feed stream 28 in the second separator 52.

  In this example, achieving a low temperature in the fully expanded slip stream 56 and the cooling feed stream 28 requires the addition of a hydrate inhibitor, but most of the water in the first separator 24. As a result of upstream removal, the amount of hydrate inhibitor is minimized.

A further advantage of the low temperature achieved with the cooling feed stream of this embodiment is that the number of compression stages can be reduced from 5 to 4 and the overall cost is reduced.
Example 5 Multi-Stage Isentropy In FIG. 8, the multi-stage embodiment of the present invention replaces the Joule Thomson valve 44 of FIG. Alternatively, an isentropic fluid expander 66 such as a turbo expander (such as that available from Mafi-Trench (Santa Maria, CA, USA)) is used.

  In this embodiment, the isentropic fluid expander can achieve a lower temperature in the expanded slipstream 60 than when using the same pressure drop Joule-Thomson valve (isoenthalpy expansion). Furthermore, the required slip stream proportion is smaller than that of Example 4.

  The power requirements for stage 3 (66) and stage 4 (68) of this embodiment are approximately 2% lower than Example 4. The isentropic fluid inflator provides about 1.8% power for stage 3 (66) and stage 4 (68) for other applications. In addition, the requirement for hydrate inhibitors is minimized.

The embodiments of the invention described herein have significant advantages and differences over conventional liquid desiccants and isoenthalpy freeze dehydration processes.
Compared to liquid desiccant dehydration, the embodiment of the present invention eliminates the conventional dehydrator by replacing the expansion valve (TCV, JTV) with a small part of the capital cost of the conventional dehydrator. Make it possible.

  In an embodiment of the present invention, compared to a conventional isenthalpy expansion refrigeration process such as “Chalk Plant” or “DPCU”, one stage of compression, a main air-to-air heat exchanger, and hydrate inhibitor addition. It can be saved and the capital cost can be greatly reduced.

  In prior art “choke plants” or “DPCUs”, the entire gas stream must be overcompressed and expanded to the design pressure. This generally increases the initial power requirement of the system by 20% to 25%. Depending on the gas composition and operating conditions, it may be necessary to add an entire compression stage due to the high compressor discharge pressure.

  Depending on the composition of the acid gas and the required operating conditions, the cooled slip stream is typically 10% to 30% of the mixed flow rate through one stage. Increasing the throughput through one stage of compression theoretically increases the total compression power demand from 2% to 6% (ie, 1/5 of 10% to 30% of a five stage compressor). However, in comparison, this increase is often comparable to the increase due to the pressure drop of conventional dehydrators. Furthermore, there is an improvement in efficiency due to a decrease in the operating temperature of the compressor, and consequently a reduction in the accompanying compression power. In some cases, the required power for compression was less than when using a conventional dehydrator.

  The low intake air temperature enabled by embodiments of the present invention is an additional advantage over both conventional dehydrators and choke plants. The reduced temperature of one stage provides an opportunity to restore the compression ratio balance of each stage, and the intake pressure is more cooled until the exhaust temperature of each stage is relatively equal at the new lower value. The higher compression ratio in some cases can reduce the compression ratio at the other stages. The reduction in the exhaust temperature somewhat reduces the additional power demand caused by the additional slipstream volume in one or more compression stages. Also, the temperature drop extends the valve life, increases the operating time, and reduces the maintenance cost. At some point, restoring the balance at a lower temperature has the effect of completely omitting one stage of compression, thus allowing for significant capital cost savings.

The total carbon dioxide emissions of embodiments of the present invention are believed to be significantly lower than conventional methods. All of these compress the slipstream volume because the equipment requirements are so small that manufacturing requirements can be reduced, there is no need to design glycol processing methods, and no additional equipment to generate CO ₂ is required. More than compensate for the slight increase in power required (usually about 2%). In addition, the embodiment of the present invention greatly reduces the ecological risk because there is no chemical requirement.

Acid gas containing _{CO 2, H 2 S, SO} 2 and NO _x is a preferred fluid in the embodiments of the present invention. However, the fluid is not limited to that disclosed herein. Furthermore, the thermodynamic principle used in embodiments of the present invention is that all fluid mixtures exhibiting a positive Joule-Thomson (JT) coefficient at processing conditions within a desired range, in other words, a fluid mixture that is cooled upon expansion, It is effective for. In summary, a large JT coefficient fluid is cooled more than a small JT coefficient fluid, and therefore less fluid is slipstreamed. Low slipstream requirements are economically desirable.

Applications of embodiments of the present invention include CO ₂ , SO ₂ , and NO _x treatment from carbon dioxide capture and storage (CCS), combustion, vaporization and sequestration industrial chemical processes, and oil and gas treatment to H ₂ S. and to capture CO ₂ is AGI for sealing (acid gas injection). Another application of embodiments of the present invention is the recovery of hydrocarbon liquids from gas vapors of relatively high acid gas content solutions that are commonly processed in enhanced oil recovery (EOR) applications. A further application of embodiments of the present invention is when acid gas dehydration is required in situations where the available space is very limited or in situations where weight is limited. This situation occurs for floating offshore production operations, or for both land and sea refurbishment applications. The configuration of the present invention provides a large space and weight advantage over other commercially available dewatering means.

  Examples 1-5 provided herein are based on a single set of conditions. Embodiments of the present invention require optimization for each fluid and condition set. Optimization involves selecting the stage of compression that is most appropriate for the start of the slipstream and most suitable for remixing the slipstream. Another optimization consists in selecting the optimal variant of the process, whether basic, HEX, LTS, multi-stage, multi-stage isentropy or any other combination of the above. Also, optimal instrument usage and control systems within all selections need to be included and optimal operating points for application need to be set.

In FIG. 9, the number 80 represents a common upstream operation and the number 81 represents a process according to the overall schematic diagram according to a further embodiment.
With respect to the common numbers from the previous embodiment, a separator 13 is provided for separating the feed into a saturated gas feed stream 10 that enters the compressor 12 where it is compressed to relieve pressure. The compressed steam 14 is then introduced into the aftercooler 20 to cause condensation of some of the water in the feed stream and other condensables. These unit operations are discussed herein and earlier with respect to other embodiments.

  In the newly presented schematic diagram, the upstream acidic gas stream 18 typically derived from a compressor, well, etc. is usually saturated with water. For example, the stream may contain 100% acid gas or a gas composed of a certain concentration of acid gas and usually hydrocarbons and other inert gases at low concentrations. For illustrative purposes, the flow is assumed to be, for example, 120 ° F. (48.89 ° C.) at a pressure of 600 psi (41.37 bar). In this system, a pair of heat exchangers 84 and 86 are installed. Focusing on the heat exchangers 84 and 86, the heat exchanger 84 is a gas-liquid heat exchanger that transfers heat in the fluid 18 to the cold fluid 96. Stream 90 is mixed with cooled stream 89 exiting Joule Thomson valve 44. The two streams are mixed in the mixing device 92. The mixture 93 formed at a temperature of about 50 ° F. (10 ° C.) is sent to a cryogenic separator 94. At this point, the liquid condensed at a pressure of 600 psi (41.37 bar) forms a cold liquid stream 96. Stream 96 is near the hydrate formation temperature of the fluid mixture. Hydrate formation will certainly occur if the flow is further depressurized. Stream 96 enters heat exchanger 84 and 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 likelihood of hydrate formation. It is also advantageous to cool stream 18 to reduce the amount of additional cooling required. When stream 96 is warmed via heat exchange by heat exchanger 84, stream 98 is probably 120 ° F. (48.89 ° C.). The pressure of stream 98 can then be reduced by valve 100 without causing hydrate formation to maintain the desired level in cryogenic separator 94. A liquid level is formed, the valve 100 is opened, and the flow 102 can enter the three-phase separator 104. Stream 102 is composed of three phases: steam, hydrocarbon liquid, and water. The residence time in separator 104 is sufficient to facilitate the separation of 106 heavier liquids, typically water, 108 vapors, and 110 lighter liquids, typically hydrocarbons. At this point, the separated hydrocarbon liquid 110 can then be sent to an oil processing facility for processing (not shown), stabilization, and final sale.

Returning to the cold separator 94, the stream 112 exiting the separator is a cold acid gas (usually CO ₂ ) vapor stream that can be used as an additional source for pre-cooling the main system. Streams 88, 112 are passed through heat exchanger 86, in this case using heat exchanger 86, which is a gas-to-air heat exchanger, to transfer the heat in stream 88 to the cold steam stream exiting cold separator 94. 112. This also pre-cools the stream 90 exiting the exchanger 86, thereby reducing the amount of additional cooling required. At this point, stream 114 has a temperature of about 110 ° F. (43.33 ° C.), as judged from the examples described herein. This system is particularly beneficial in that it allows hydrocarbon recovery where economically feasible.

Thereafter, the stream 114 is sent during the unit operations previously described herein for the basic overall system.
If it is not possible or economically possible to recover the liquefied hydrocarbon, the designer may employ the system shown in FIG. 10 (discussed in more detail below). It is also an attractive system for retrofit applications where existing compressor arrangements can be used with minimal modifications while still benefiting from the techniques presented herein.

In FOR applications where CO ₂ is used, replenishment or additional CO ₂ is typically mixed with the generated steam and reinjected into the production storage tank. Depending on the pressure of the supplemental CO ₂ stream, it can be mixed with or replaced with stream 34 to improve the Joule-Thomson coefficient and lower the HFT. With dry replenishment CO ₂ , the use of a hydrate inhibitor such as methanol or glycol can be minimized or omitted during system startup.

If necessary, the process can be designed to condense fluids other than the hydrocarbons used in this example.
If an improvement in hydrocarbon liquid / vapor separation efficiency is required, additional pressure reduction and separation steps (repeating 100, 102, 104, replacing 98 with 110) can be taken into account.

  In addition, the system can help optimize operating points by introducing thermodynamic simulation software to predict water dew point, hydrate formation temperature, and hydrocarbon recovery.

  Returning to FIG. 10, a further embodiment of the present invention is shown. In this embodiment, it is clear that a significant number of unit operations have been removed compared to the system of FIG. The use of the three-phase separator 104 from FIG. 9 is unnecessary in this embodiment, and a gas-liquid heat exchanger is likewise unnecessary. The remaining unit operations are similar to the function of operation in FIG. 9, and the overall procedure will be obvious to those skilled in the art.

  This embodiment is particularly suitable for existing arrangements where it is possible to take advantage of the system described herein by retrofitting older equipment. With the introduction of a gas-to-air heat exchanger, the cooling slipstream is reduced from 4% to 10% of the mixed flow rate, usually through one stage, depending on the acid gas composition and the required operating conditions. Increasing throughput through one stage of compression theoretically increases the total compression power demand by 1% to 2% (ie, 1/5 of 4% to 10% of a five stage compressor). The addition of LTS is only necessary if the metallurgical properties of the existing suction scrubber are incompatible with the generated acidic water and it is not appropriate to replace the existing scrubber. The capital cost of this embodiment increases accordingly.

  In the embodiment shown in FIG. 10, the heavy liquid phase stream 34 in this case is usually a supercritical (dense phase) or liquid, normally warm, high pressure recycle stream. This stream is sent to the Joule-Thomson valve 44 where the pressure is reduced and thus the temperature of the stream 34 is reduced. The cold and low pressure recycle stream 89 is used for mixing with the precooled inlet stream 90 to the mixing device 92.

  As discussed previously with respect to FIG. 9, the mixture is represented by numeral 93. The liquid phase exiting the cryogenic separator 94 from 96 is mostly water. This stream is usually mixed into the water treatment process somewhere.

As an example, depending on the surface area available in the heat exchanger 86, the stream 90 can be cooled to about 60 ° F. to 70 ° F. (15.55 ° C. to 21.11 ° C.). Slip stream 34 (as discussed hereinbefore with respect to other embodiments) may be 120 ° F. (48.89 ° C.) and optionally 2,000 psig (137.9 bar). This high-pressure flow can be reduced by the Joule-Thomson valve 44. The high pressure stream is now reduced to 600 psig (41.37 bar) at about the same pressure as stream 90. As a result of passing through the Joule Thomson valve, the flow expands and thereby cools to about 40 ° F. (4.4 ° C.). The resulting cold stream 89 is mixed with stream 90 in a mixing device 92. The mixture 93 thus formed at a temperature of about 50 ° F. (10 ° C.) is sent to a cryogenic separator 94. At this point, the liquid condensed at a pressure of 600 psi (41.37 bar) forms a cold liquid stream 96. The stream 112 exiting the separator 94 is a cold acid gas (usually CO ₂ ) vapor stream that can be used as a source for precooling the hot inlet stream. Streams 18 and 112 are passed through heat exchanger 86, which is a gas-to-air heat exchanger, using the heat exchanger to transfer heat from stream 18 to cold steam stream 112 from cold separator 94. Move. This heat exchanger pre-cools the stream 90 exiting the exchanger 86, thereby reducing the amount of additional cooling required. At this point, stream 114 has a temperature of about 110 ° F. (43.33 ° C.) from the examples described herein.

Claims (11)

A method for removing condensable components from a fluid containing condensable components and recovering hydrocarbons present in the fluid,
Optimizing the temperature of the initial feed stream containing the condensable component by heat exchange, cooling and condensing the liquid therefrom, removing the liquid to form a gas stream;
Compressing and aftercooling the gas stream to form a high pressure stream;
Expanding at least a portion of the high pressure stream to form a cooled low pressure stream;
Mixing the cooled low pressure stream and the initial feed stream to increase the cooling and condensation of condensable components in the initial feed stream to form a mixture;
Separating the mixture into a liquid stream and a gas stream;
Gas - liquid heat exchange operation and the gas - to perform the air heat exchange operation successively to heat exchange, and to cause the front Symbol liquid stream and the gas stream is contacted with an initial feed stream,
Manipulating the composition of all streams during the process to prevent hydrate formation;
Recovering hydrocarbons;
Including methods.   The method of claim 1, comprising measuring the hydrocarbon and water content of the initial feed stream.   3. The method of claim 1 or 2, further comprising the step of performing the method at a temperature outside the range where hydrates are formed.   4. A method according to any one of claims 1 to 3, further comprising the step of processing the feed stream for moisture content reduction unit operation.   The method of any one of claims 1 to 4, further comprising recovering hydrocarbons from the stream produced from the method.   6. The method of any one of claims 1-5, further comprising recovering an acidic gas component from the stream generated from the method.   The method of claim 6, further comprising recycling the acid gas component.   The method according to claim 1, wherein the fluid has a positive Joule-Thomson coefficient. The condensable components A method according to any one of claims 1 to 8 comprising the C ₅ H ₁₂ and heavier hydrocarbons.   The method of any one of claims 1 to 9, further comprising adding a hydrate inhibitor to the fluid.   The method according to claim 1, wherein the hydrate inhibitor is methanol.

Images