CN102597671B - From hydrocarbon stream, remove sour gas and remove the cryogenic system of hydrogen sulfide - Google Patents

From hydrocarbon stream, remove sour gas and remove the cryogenic system of hydrogen sulfide Download PDF

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CN102597671B
CN102597671B CN201080049495.7A CN201080049495A CN102597671B CN 102597671 B CN102597671 B CN 102597671B CN 201080049495 A CN201080049495 A CN 201080049495A CN 102597671 B CN102597671 B CN 102597671B
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gas
stream
flow
tower
solvent
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CN102597671A (en
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P·S·诺斯罗普
B·T·凯莱
C·J·马特
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ExxonMobil Upstream Research Co
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Exxon Production Research Co
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    • F25J—LIQUEFACTION, SOLIDIFICATION OR SEPARATION OF GASES OR GASEOUS OR LIQUEFIED GASEOUS MIXTURES BY PRESSURE AND COLD TREATMENT OR BY BRINGING THEM INTO THE SUPERCRITICAL STATE
    • F25J3/00—Processes or apparatus for separating the constituents of gaseous or liquefied gaseous mixtures involving the use of liquefaction or solidification
    • F25J3/02—Processes or apparatus for separating the constituents of gaseous or liquefied gaseous mixtures involving the use of liquefaction or solidification by rectification, i.e. by continuous interchange of heat and material between a vapour stream and a liquid stream
    • F25J3/0204—Processes or apparatus for separating the constituents of gaseous or liquefied gaseous mixtures involving the use of liquefaction or solidification by rectification, i.e. by continuous interchange of heat and material between a vapour stream and a liquid stream characterised by the feed stream
    • F25J3/0209—Natural gas or substitute natural gas
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10L—FUELS NOT OTHERWISE PROVIDED FOR; NATURAL GAS; SYNTHETIC NATURAL GAS OBTAINED BY PROCESSES NOT COVERED BY SUBCLASSES C10G, C10K; LIQUEFIED PETROLEUM GAS; ADDING MATERIALS TO FUELS OR FIRES TO REDUCE SMOKE OR UNDESIRABLE DEPOSITS OR TO FACILITATE SOOT REMOVAL; FIRELIGHTERS
    • C10L3/00—Gaseous fuels; Natural gas; Synthetic natural gas obtained by processes not covered by subclass C10G, C10K; Liquefied petroleum gas
    • C10L3/06—Natural gas; Synthetic natural gas obtained by processes not covered by C10G, C10K3/02 or C10K3/04
    • C10L3/10—Working-up natural gas or synthetic natural gas
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10L—FUELS NOT OTHERWISE PROVIDED FOR; NATURAL GAS; SYNTHETIC NATURAL GAS OBTAINED BY PROCESSES NOT COVERED BY SUBCLASSES C10G, C10K; LIQUEFIED PETROLEUM GAS; ADDING MATERIALS TO FUELS OR FIRES TO REDUCE SMOKE OR UNDESIRABLE DEPOSITS OR TO FACILITATE SOOT REMOVAL; FIRELIGHTERS
    • C10L3/00—Gaseous fuels; Natural gas; Synthetic natural gas obtained by processes not covered by subclass C10G, C10K; Liquefied petroleum gas
    • C10L3/06—Natural gas; Synthetic natural gas obtained by processes not covered by C10G, C10K3/02 or C10K3/04
    • C10L3/10—Working-up natural gas or synthetic natural gas
    • C10L3/101—Removal of contaminants
    • C10L3/102—Removal of contaminants of acid contaminants
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    • F25J3/00—Processes or apparatus for separating the constituents of gaseous or liquefied gaseous mixtures involving the use of liquefaction or solidification
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    • F25J2200/00—Processes or apparatus using separation by rectification
    • F25J2200/74—Refluxing the column with at least a part of the partially condensed overhead gas
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    • F25J2200/00—Processes or apparatus using separation by rectification
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    • F25J2200/00—Processes or apparatus using separation by rectification
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    • F25J2205/00—Processes or apparatus using other separation and/or other processing means
    • F25J2205/02—Processes or apparatus using other separation and/or other processing means using simple phase separation in a vessel or drum
    • F25J2205/04—Processes or apparatus using other separation and/or other processing means using simple phase separation in a vessel or drum in the feed line, i.e. upstream of the fractionation step
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    • F25J2205/00—Processes or apparatus using other separation and/or other processing means
    • F25J2205/40—Processes or apparatus using other separation and/or other processing means using hybrid system, i.e. combining cryogenic and non-cryogenic separation techniques
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    • F25J2205/00—Processes or apparatus using other separation and/or other processing means
    • F25J2205/50—Processes or apparatus using other separation and/or other processing means using absorption, i.e. with selective solvents or lean oil, heavier CnHm and including generally a regeneration step for the solvent or lean oil
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    • F25J2205/00—Processes or apparatus using other separation and/or other processing means
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    • F25J2205/00—Processes or apparatus using other separation and/or other processing means
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    • F25J2205/66—Regenerating the adsorption vessel, e.g. kind of reactivation gas
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    • F25J2215/00—Processes characterised by the type or other details of the product stream
    • F25J2215/04—Recovery of liquid products
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    • F25J2220/00—Processes or apparatus involving steps for the removal of impurities
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    • F25J2260/00—Coupling of processes or apparatus to other units; Integrated schemes
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    • F25J2270/00—Refrigeration techniques used
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    • F25J2280/00—Control of the process or apparatus
    • F25J2280/40—Control of freezing of components
    • Y—GENERAL TAGGING OF NEW TECHNOLOGICAL DEVELOPMENTS; GENERAL TAGGING OF CROSS-SECTIONAL TECHNOLOGIES SPANNING OVER SEVERAL SECTIONS OF THE IPC; TECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS
    • Y02—TECHNOLOGIES OR APPLICATIONS FOR MITIGATION OR ADAPTATION AGAINST CLIMATE CHANGE
    • Y02C—CAPTURE, STORAGE, SEQUESTRATION OR DISPOSAL OF GREENHOUSE GASES [GHG]
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Abstract

From flow of feed gas, remove the system of sour gas, comprise sour gas and remove system (AGRS) and sulfur component removal system (SCRS).Sour gas is removed system acceptance acid flow and it is separated into the main overhead gas stream containing methane with main containing acid gas stream at the bottom of the tower of carbon dioxide.Sulfur component is removed system and is placed in upstream or the downstream that sour gas removes system.SCRS receives air-flow and is the first fluid stream containing hydrogen sulfide and the second fluid stream containing carbon dioxide substantially by flow separation.When SCRS in AGRS upstream, second fluid stream is also mainly containing methane.When SCRS in AGRS downstream, second fluid stream mainly carbon dioxide.Various types of sulfur component can be utilized to remove system.

Description

From hydrocarbon stream, remove sour gas and remove the cryogenic system of hydrogen sulfide
The cross reference of related application
This application claims the name submitted on November 2nd, 2009 and be called cryogenic system (the CRYOGENICSYSTEMFORREMOVINGACIDGASESFROMAHYDROCARBONGASST REAM removing sour gas and removal hydrogen sulfide from hydrocarbon stream, WITHREMOVALOFHYDROGENSULFIDE) U.S. Provisional Patent Application 61/257, the rights and interests of 277, the full content of this application is incorporated to by reference at this.
Background
These chapters and sections are intended to the various aspects introducing this area, and it may be relevant with illustrative embodiments of the present disclosure.Believe that this discussion contributes to for promoting that the better understanding of concrete aspect of the present disclosure provides framework.Therefore, be to be understood that and read these chapters and sections with this angle, and need not admit it is prior art.
Field
The present invention relates to fluid separation field.More specifically, the present invention relates to separate hydrogen sulfide and other sour gas from hydrocarbon fluid flow.
Technical discussion
From reservoir, recovery of hydrocarbons carries the subsidiary product of non-hydrocarbon gas often with it.This gas comprises as hydrogen sulfide (H 2and carbon dioxide (CO S) 2) pollutant.Work as H 2s and CO 2when part as hydrocarbon stream (as methane or ethane) produces, this air-flow is called " acid gas " sometimes.
Acid gas is usually processed to remove CO 2, H 2s and other pollutant, then by its fed downstream to process further or to sell.The removal of sour gas produces " desulfurization " hydrocarbon stream.Desulfurization stream can be used as the raw material that environment can receive fuel or be used as chemicals or solution-air converting apparatus.Desulfurization air-flow can be cooled to form liquefied natural gas or LNG.
Gas separation process creates the problem about disposing the pollutant be separated.In some cases, dense sour gas is (primarily of H 2s and CO 2composition) be sent to sulfur recovery unit (" SRU ").SRU transforms H 2s is optimum elementary sulfur.But in some areas (as region, the Caspian Sea), because limited market, it is undesirable that extra elementary sulfur is produced.Therefore, the sulphur of millions of tons has left in the large region, ground in some areas, the world, is Canada and Kazakhstan the most significantly.
Although sulphur is stored in land, the carbon dioxide invariably relevant with sour gas is discharged in air.But, carry out discharge CO 2sometimes be less desirable.Reduce CO 2a suggestion of discharge is called as the method that sour gas injects (" AGI ").AGI means unwanted acid gas and is refilled to subsurface formations (subterraneanformation) under stress and the isolated application later in order to possibility.Alternatively, carbon dioxide, for the formation of artificial reservoir pressure, operates for improving oil recovery.
In order to promote AGI, expect to have such gas processing device, it effectively isolates acid gas component from the hydrocarbon gas.But, for " peracidity " stream, namely containing being greater than about 15% or 20%CO 2and/or H 2the production stream of S, design, structure and operation can economically from required hydrocarbon the equipment of separating contaminants may have challenge.Many natural gas reservoirs contain relatively low hydrocarbon percentage composition (being such as less than 40%) and high sour gas percentage composition, mainly carbon dioxide, but also have hydrogen sulfide, carbonyl sulfide, carbon disulfide and various mercaptan.In these cases, cryogenic gas process can advantageously be adopted.
Cryogenic gas process is sometimes for the distillating method of gas separaion.Cryogenic gas produces cooling tower top air-flow under being separated in moderate pressure (such as 350-550 pound per square inch gage (psig)).In addition, the sour gas that liquefies produces as " at the bottom of tower " product.Because liquefaction sour gas has relatively high density, hydrostatic head is advantageously used in AGI well, to assist injection process.This means that the energy needed for energy Ratios compression and low pressure sour gas to reservoir pressure needed for pump liquefied sour gas to stratum is low.Need compressor and the pump of less level.
Also challenge is there is about acid gas low temperature distillation.When in pending gas, stagnation pressure is less than CO under about 700psig 2when the concentration existed is greater than about 5mol.%, it freezes in the cryogenic distillation apparatus of standard for solid.As the CO of solid 2formation interrupted low temperature distillation process.In order to overcome this problem, this assignee had previously devised various " control freezing district tM" (CFZ tM) method.CFZ tMmethod utilizes carbon dioxide to form the tendency of solid particle, by making freezing CO 2particle is formed in the opening portion of destilling tower, and then in thawing tower tray, catches this particle.As a result, produce clean methane stream (together with any nitrogen existed in unstrpped gas or helium) at tower top end, at the bottom of tower, produce cooling liquid CO simultaneously 2/ H 2s flows.Under the pressure higher than about 700psig, " overall fractionation (bulkfractionation) " distillation can be carried out, and need not CO be worried 2freeze; But the methane that tower top produces will have the CO of at least several percentage wherein 2.
At United States Patent (USP) 4,533,372, United States Patent (USP) 4,923,493, United States Patent (USP) 5,062,270, United States Patent (USP) 5,120,338 and United States Patent (USP) 6,053, describe CFZ in 007 tMsome aspect of method and relevant device.
Describe as general in above United States Patent (USP), comprise the distillation zone of bottom and middle control freezing district for the destilling tower of cryogenic gas process or post.Preferably, the distillation zone on top is also comprised.By being provided in a part of post of that pressure at temperatures scope below carbon dioxide freezing point but more than methane boiling temperature, post running is to form solid CO 2particle.More preferably, making methane and the evaporation of other light hydrocarbon gases, cause CO simultaneously 2this control freezing district is operated under the temperature and pressure of formation is freezed (solid) particle.
When gas raw material stream rises along post, freeze CO 2particle is broken away from feed stream and is relied on gravity to drop to thawing tower tray from control freezing district.There, particle liquefaction.Then carbon dioxide enriched liquid stream runs underneath to the distillation zone, bottom of column bottom from melting tower tray.Maintain distillation zone, bottom substantially without carbon dioxide solid formation but under the methane temperature and pressure that can seethe with excitement of dissolving.On the one hand, acid flow at the bottom of tower is formed at 30 ℉ to 40 ℉.
In one embodiment, the tower tray bottom frozen region can collect some or all and freeze CO 2particle.Then particle is exported from destilling tower to process further.
Control freezing region comprises the liquid spray of cooling.This is the methane-rich liquid stream being called " backflow ".Along with light hydrocarbon gases and the steam stream carrying acid gas secretly move upwardly through post, steam stream runs into liquid spray.The liquid spray help of cooling separates solid CO 2particle make simultaneously methane gas evaporate and in post on flowing.
In distillation zone, top, catch methane (or overhead gas) and pipe is sent from out to sell or can be used as fuel.On the one hand, tower top methane stream are discharged at about-130 ℉.Overhead gas is by other cooling by partial liquefaction, and liquid is back to post as backflow.Liquid backflow is injected into the spray section in control freezing district as chilling spray, usually after the tower tray of rectifying section flowing through post or filler.
The methane produced in distillation zone, top meets most of standard that pipeline transports.Such as, if if produce sufficient backflow and/or have enough segregation section with the filler in distillation zone, top or tower tray, methane can meet the pipeline CO being less than 2mol.% 2the H of standard and 4ppm 2s standard.But if original raw material air-flow contains hydrogen sulfide (or other sulfur-containing compound), these are reached home in the liquid column underflow of carbon dioxide and hydrogen sulfide.
Hydrogen sulfide is heavier-than-air toxic gas.Its corrosion well and ground installation.When contact with hydrogen sulfide metallic conduit and valve in the presence of water, iron sulfide corrosion can be there is.Therefore, expect from flow of feed gas, remove hydrogen sulfide and other sulfur component, then make it enter cooling distillation column.Gas stream that this makes " more low-sulfur " is to post.Therefore, the CO produced by low temperature method 2there is no H 2s, and such as can be used to improve oil recovery.
Need to reduce H from raw natural gas stream 2the content of S and mercaptan, then makes it carry out low temperature distillation to remove the system of acid gas.Alternatively, need from sour gas tower bottom flow, extract the cryogenic gas piece-rate system of hydrogen sulfide and adjoint technique in CFZ tower downstream.
General introduction
Provide the system removing sour gas from acid flow.In one embodiment, this system comprises sour gas removal system.Sour gas is removed system utilization and acid flow is separated into the main overhead gas stream containing methane and the main low temperature distillation tower containing acid gas stream at the bottom of the liquefaction tower of carbon dioxide.This system also comprises sulfur component and removes system.Sulfur component is removed system and is placed on sour gas removal system upstream.Sulfur component is removed system acceptance flow of feed gas and substantially flow of feed gas is separated into the fluid stream and acid flow with hydrogen sulfide.
Acid flow preferably includes the sulfur component between about 4ppm and 100ppm.This component can be hydrogen sulfide, carbonyl sulfide and various mercaptan.
Preferably, low temperature acid gas removal system comprises the refrigeration system entering destilling tower front cooling acid flow.Preferably, it is " CFZ " system that low temperature acid gas removes system, and wherein destilling tower has the distillation zone of bottom and middle control freezing district.Middle control freezing district or " spray section " receive the main cooling liquid containing methane and spray.Chilling spray is the liquid backflow produced from the overhead circulation in destilling tower downstream.There is provided refrigeration plant using cooling tower top methane stream in low temperature distillation tower downstream and return a part of tower top methane stream and reflux as cooling liquid to low temperature distillation tower.
Should be appreciated that other sour gas that can adopt except low temperature distillation system removes system.Such as, it can be physical solvent system that sour gas removes system, and it tends to remove H equally 2s is together with CO 2.Sour gas removes system also can adopt overall fractionation.
Various types of sulfur component can be adopted to remove system.These comprise the system adopting physical solvent separate sulphur component from acid flow.These also can comprise oxide-reduction method and use so-called scavenger.These also can comprise so-called " CrystaSul " method.
On the one hand, sulfur component removal system comprises at least one solid adsorbent bed.At least one solid adsorbent bed absorption at least some hydrogen sulfide, makes methane gas and carbon dioxide pass through as acid flow simultaneously.Solid adsorbent bed is passable, and such as, (i) is manufactured by zeolitic material, or (ii) comprises at least one molecular sieve.Solid adsorbent bed can incidentally adsorb at least some water.
At least one solid adsorbent bed can be that adsorption dynamics adsorption kinetics is separated bed.Alternatively, at least one solid adsorbent bed can comprise at least three solid adsorbent beds, first wherein in (i) at least three solid adsorbent beds for adsorbing sulfur component, (ii) second at least three solid adsorbent beds regenerates, and the 3rd of (iii) at least three solid adsorbent beds the maintenance is for subsequent use with first that replaces at least three adsorbent beds.Regeneration can be the part of temperature swing adsorption process, the part of pressure-swing absorption process or its combination.
In another embodiment, sulfur component removes system employing chemical solvent as selective amine.In this case, sulfur component removal system preferably utilizes multiple and flows contact device.
Replace physical solvent or chemical solvent system or other type sulfur component can be utilized except physical solvent or chemical solvent system to remove system.This system can comprise oxidation-reduction system, and the use of at least one solid adsorbent bed or at least one absorption power are separated the use of bed.
Also provide the piece-rate system for removing sour gas from acid flow herein.Within the system, remove system downstream at sour gas and substantially remove hydrogen sulfide and other sulfur-containing compound.Design this system to process acid gas stream.Acid gas stream is obtained from the initial flow of feed gas containing sulfur component between about 4ppm and 100ppm.
In one embodiment, system comprises sour gas removal system.Sour gas is removed system acceptance flow of feed gas and flow of feed gas is separated into the main overhead gas stream containing methane and the liquid column bottoms acid gas stream mainly containing carbon dioxide.Hydrogen sulfide also will be present in acid gas stream at the bottom of tower.This system also comprises sulfur component and removes system.Sulfur component is removed system and is placed on sour gas removal system downstream.Sulfur component removes the separated flow that acid gas stream at the bottom of tower is also separated into carbon dioxide stream and mainly has sulfur-containing compound by acid gas stream substantially at the bottom of system acceptance tower.
Preferably, sour gas removes system is that low temperature acid gas removes system.Low temperature acid gas is removed system and is comprised the destilling tower receiving flow of feed gas and the refrigeration system cooling flow of feed gas before entering destilling tower.Preferably, it is " CFZ " system that low temperature acid gas removes system, and wherein destilling tower has the distillation zone of bottom and middle control freezing district.Middle control freezing district or " spray section " receive the main cooling liquid containing methane and spray.Chilling spray is the liquid backflow produced from the overhead circulation in destilling tower downstream.There is provided refrigeration plant using cooling tower top methane stream in low temperature distillation tower downstream and return a part of tower top methane stream to low temperature distillation tower as backflow, it is liquid.
Various types of sulfur component can be utilized to remove system.On the one hand, sulfur component removal system comprises at least one solid adsorbent bed.This at least one solid adsorbent bed adsorbs at least some sulfur component and substantially makes carbon dioxide pass through from acid gas stream at the bottom of tower.Solid adsorbent bed is passable, such as, uses absorption power to be separated (AKS).AKS bed can incidentally adsorb at least some carbon dioxide.In this case, preferably, AKS sulfur component removal system also comprises separator as gravity separator.Such as, gravity separator is from gaseous state CO 2middle separation of liquid heavy hydrocarbon components and hydrogen sulfide.
Alternatively, solid adsorbent bed can be that sponge iron (ironsponge) is with direct and H 2s reacts and passes through to form iron sulfide and removes it.
On the other hand, sulfur component removal system comprises extractive distillation process.Extractive distillation process adopts at least two solvent-recovery columns.Acid gas stream at the bottom of tower is also separated into the main first fluid stream containing carbon dioxide and the main second fluid stream containing solvent and sulfur-containing compound by acid gas stream at the bottom of first post reception tower.
Accompanying drawing is sketched
In order to better understand mode of the present invention, some figure, table and/or flow chart are attached to this.But, should be noted that figure illustrate only embodiment that the present invention selects and therefore can not be considered to the restriction of scope, because the present invention can allow effective embodiment and the application of other equivalence.
Fig. 1 is the side view of illustrative CFZ destilling tower in one embodiment.Cooling flow of feed gas is injected into the middle control freezing district of tower.
Fig. 2 A is the top view melting tower tray in one embodiment.Melt tower tray existence to control below freezing zone in tower.
Fig. 2 B is the sectional view that Fig. 2 A melts tower tray 2B-2B intercepting along the line.
Fig. 2 C is the sectional view that Fig. 2 A melts tower tray 2C-2C intercepting along the line.
Fig. 3 is the enlarged side view of the steam stripping plate in the distillation zone, bottom of destilling tower in one embodiment.
Fig. 4 A is the perspective view of the jet tray that can be used for destilling tower bottom distilling period or top distilling period in one embodiment.
Fig. 4 B is the side view of one of perforate in Fig. 4 A jet tray.
Fig. 5 is the side view in the middle control freezing district of Fig. 1 destilling tower.In this view, two illustrative perforated baffles have been added to middle control freezing district.
Fig. 6 is the schematic diagram showing the gas processing device removing sour gas in one embodiment according to the present invention from air-flow.This gas processing device is removed system upstream at sour gas and is adopted solvent method.
Fig. 7 A provides the detailed maps of the solvent system of Fig. 6 in one embodiment.Herein, solvent system is that operation is to contact dehydrated gas stream thus the physical solvent system of removal hydrogen sulfide.
Fig. 7 B provides the detailed maps of the solvent system of Fig. 6 in alternate embodiments.Herein, solvent system is that operation is to contact dehydrated gas stream thus the chemical solvent system of removal hydrogen sulfide.
Fig. 8 is the schematic diagram showing the gas processing device removing sour gas in one embodiment according to the present invention from air-flow.In this is arranged, remove system upstream by oxidation-reduction process at sour gas and remove hydrogen sulfide from air-flow.
Fig. 9 is the schematic diagram showing the gas processing device removing sour gas in one embodiment according to the present invention from air-flow.In this is arranged, remove system upstream by scavenger at sour gas and remove hydrogen sulfide from air-flow.
Figure 10 is the schematic diagram showing the gas processing device removing sour gas in one embodiment according to the present invention from air-flow.In this is arranged, remove system upstream by CrystaSulf method at sour gas and remove hydrogen sulfide from air-flow.
Figure 11 is the schematic diagram showing the gas processing device removing sour gas in one embodiment according to the present invention from air-flow.In this is arranged, remove system upstream by temperature swing adsorption system at sour gas and remove hydrogen sulfide from air-flow.
Figure 12 is the schematic diagram showing the gas processing device removing sour gas in one embodiment according to the present invention from air-flow.In this is arranged, remove system upstream by pressure swing adsorption system at sour gas and remove hydrogen sulfide from air-flow.
Figure 13 is the schematic diagram showing gas processing device of the present invention in another embodiment.In this is arranged, the adsorbent bed be separated by utilizing absorption power is removed system upstream at sour gas and remove hydrogen sulfide from air-flow.
Figure 14 is the schematic diagram showing gas processing device of the present invention in another embodiment.In this is arranged, the adsorbent bed be separated by utilizing absorption power is removed system downstream at sour gas and remove hydrogen sulfide from air-flow.
Figure 15 A is the schematic diagram showing gas processing device of the present invention in another embodiment.In this is arranged, remove system downstream by extractive distillation process at sour gas and remove hydrogen sulfide from air-flow.
Figure 15 B is the detailed maps of Figure 15 A for the gas processing device of extractive distillation process.
The detailed description of some embodiment
Definition
As used herein, the organic compound of element hydrogen and carbon that term " hydrocarbon " refers to mainly comprise---if not exclusively---.Hydrocarbon is divided into two classes usually: aliphatic or straight-chain hydrocarbons and ring-type or closed-ring hydrocarbons, comprise cyclic terpene.The example of hydrocarbonaceous material comprises natural gas, oil, coal and can be used as fuel or improve the arbitrary form that quality is the pitch of fuel.
As used herein, term " hydrocarbon fluid " refers to the hydrocarbon of gas or liquid or the mixture of hydrocarbon.Such as, under hydrocarbon fluid can be included in formation condition, under processing conditions or at ambient conditions (15 DEG C and 1 atmospheric pressure) gas or the hydrocarbon of liquid or the mixture of hydrocarbon.Hydrocarbon fluid can comprise the thermal decomposition product of such as oil, natural gas, coalbed methane, shale oil, pyrolysis oil, cracking gas, coal and other hydrocarbon of gaseous state or liquid state.
Term " mass transfer apparatus " finger is received fluid to be contacted and is transmitted these fluids to any object on other object as flowed by gravity.A limiting examples is the tower tray that stripping goes out some component.Grid packing is another example.
As used herein, term " fluid " refers to the combination of gas, liquid, liquids and gases, also refers to the combination of gas and solid and the combination of liquid and solid.
As used herein, term " condensation of hydrocarbons " refers to those hydrocarbon in about 15 DEG C and one strict atmospheric pressure condensations.Condensation of hydrocarbons can comprise the mixture of the hydrocarbon such as with the carbon number being greater than 4.
As used herein, term " heavy hydrocarbon " refers to the hydrocarbon with more than one carbon atom.Main example comprises ethane, propane and butane.Other example comprises pentane, aromatic compounds and diamantane (diamondoids).
As used herein, term " closed-loop refrigeration system " refers to that wherein operate outside fluid such as propane or ethene is used as cooling agent with any refrigeration system of cooling tower top methane stream." open-loop refrigeration system " that this and wherein a part of tower top methane stream self are used as working fluid is formed and contrasts.
As used herein, in contact device, the container of (i) gas flow and (ii) separated from solvent stream is received the while that term " and flowing contact device " or " and flowing contactor " referring to air-flow and solvent stream are contacted with each other in the mode of direction identical substantially flowing.Limiting examples comprises the additional liquid device (deliquidizer) that disappears of injector and coalescer or static mixer.
" non-absorbing gas " to refer in gas sweetening process not by gas that solvent significantly absorbs.
As used herein, term " natural gas " refers to from crude oil well (associated gas) or the multicomponent gas that obtains from underground gas-bearing formation (irrelevant gas).The composition of natural gas and pressure can marked changes.Typical natural gas flow contains methane (C 1) as important component.Natural gas flow also can contain ethane (C 2), the hydrocarbon of higher molecular weight and one or more sour gas.Natural gas also can containing a small amount of pollutant as water, nitrogen, wax and crude oil.
As used herein, " sour gas " refers to be dissolved in water the arbitrary gas producing acid solution.The limiting examples of sour gas comprises hydrogen sulfide (H 2and carbon dioxide (CO S) 2).Sulfur-containing compound comprises carbon disulfide (CS 2), carbonyl sulfide (COS), mercaptan or their mixture.
Term " liquid flux " refers to preferential absorption sour gas thus by removing in air-flow or the fluid being essentially liquid phase of " washing off " at least part of acid gas components.Air-flow can be hydrocarbon stream or other air-flow, as having the air-flow of nitrogen.
" desulfurization air-flow " refers to the fluid stream being essentially gas phase making at least part of acid gas components remove.
As used herein, from air-flow, remove selected gas component about absorbing fluid, term " poor " is relative with " richness ", only infers content that is less or selected gas component largely respectively.Each term " poor " and " richness " need not point out or require that absorbing fluid does not have selected gas component maybe can not absorb more selected gas components completely respectively.In fact, as will be obviously visible hereinafter, preferably, so-called " richness " absorbing fluid produced in first contactor of a series of two or more contactor retains remarkable or a large amount of residual absorbant abilities.On the contrary, " poor " absorbing fluid will be understood to fully to absorb, but can retain and be removed gas component compared with small concentration.
Term " flow of feed gas " refers to hydrocarbon fluid flow, wherein fluid mainly gas phase, and it does not experience the step removing carbon dioxide, hydrogen sulfide or other acidic components.
Term " acid flow " refers to hydrocarbon fluid flow, wherein fluid mainly gas phase, and containing the carbon dioxide of at least 3 molar percentages and/or the hydrogen sulfide more than 4ppm.
As used herein, term " underground " refers to the geological stratification that below earth surface exists.
Detailed description of the invention describes
Fig. 1 present in one embodiment can with the explanatory view of low temperature distillation tower 100 of the present invention about using.Low temperature distillation tower 100 is called " low temperature distillation tower ", " post ", " CFZ post " in this article interchangeably or is " tower ".
The low temperature distillation tower 100 of Fig. 1 receives initial fluid stream 10.Fluid stream 10 forms primarily of extraction gas (productiongas).Usually, fluid stream represents the dry gas stream from well head or well head collection (not shown), and the methane containing about 65% to about 95%.But fluid stream 10 can comprise the methane of lower percentage, as about 30% to 65%, or be even low to moderate 20% to 40%.
Methane can occur together with ethane with the trace constituent of other hydrocarbon gas.In addition, trace helium and nitrogen can be there is.In this application, fluid stream 10 also will comprise some pollutant.These comprise as CO 2and H 2the sour gas of S.
Initial fluid stream 10 can be in after the extraction of about 600 pound per square inches (psi) under pressure.In some cases, the pressure of initial fluid stream 10 can reach about 750psi or even 1,000psi.
Usually, fluid stream 10 is cooled before entering destilling tower 100.For initial fluid stream 10 provides the heat exchanger 150 as shell-tube exchanger.Refrigerating plant (not shown) provides cooling fluid (as petrogas) to be down to approximately-30 ℉ to-40 ℉ to heat exchanger 150 to make the temperature of initial fluid stream 10.Then the fluid flow of cooling can be made dynamic by expansion gear 152.Expansion gear 152 can be such as joule-Tang Pusen (" J-T ") valve.
The work of expansion gear 152 quenchers is in order to obtain the additional cooling of fluid stream 10.Preferably, the partial liquefaction of fluid stream 10 is realized.Joule-Tang Pusen (or " J-T ") valve is preferably used for the gas raw material stream being easy to form solid.Preferably, and if expansion gear 152 closes on low temperature distillation tower 100 install to be minimized in some components of thermal loss in feed pipe (as CO 2or benzene) be down to below their freezing point, minimize the chance of solid blocking.
One as J-T valve is replaced, and expansion gear 152 can be turbine type quencher.Turbine type quencher provides larger cooling and forms the source of shaft work, as above-mentioned refrigerating plant for process.Heat exchanger 150 is parts of refrigerating plant.In this way, operator can minimize the total energy demand of still-process.But turbine type quencher process frozen particles may be good not as J-T valve.
In arbitrary situation, heat exchanger 150 and chilling apparatus 152 change the unstrpped gas in initial fluid stream 10 into chilled fluid flow 12.Preferably, the temperature of chilled fluid flow 12 is approximately-40 ℉ to-70 ℉.On the one hand, under the pressure of about 550psi, operate low temperature distillation tower 100, and chilled fluid flow 12 is at about-62 ℉.Under these conditions, chilled fluid flow 12 is liquid phase substantially, although inevitably may carry some vapor phases secretly in chilled fluid flow 12.Most possibly, CO 2existence do not cause solid to be formed.
CFZ low temperature distillation tower 100 is divided into three major parts.These are the distillation zone of bottom or " stripping section " 106, the distillation zone on middle control freezing district or " spray section " 108 and top or " rectifying section " 110.In the tower of Fig. 1 is arranged, introduce in the control freezing district 108 of chilled fluid flow 12 to destilling tower 100.But, alternatively, near the top can introducing distillation zone, chilled fluid flow 12 to bottom 106.
It should be noted that distillation zone, bottom 106, middle spray section 108, distillation zone, top 110 and associated component are placed in single container 100 in the layout in figure 1.But, consider the height of tower 100 and the coastal waters application of motion considerations for wherein needing, or for wherein transporting the remote location that restriction is a problem, optionally tower 110 can be divided into two independently pressure vessel (not shown)s.Such as, distillation zone, bottom 106 and control freezing district 108 can be placed in a container, and distillation zone, top 108 is in another container.Then outside pipe is used to be connected to each other by two containers.
In arbitrary embodiment, the temperature of distillation zone, bottom 106 is higher than the feeding temperature of chilled fluid flow 12.The temperature of design distillation zone, bottom 106, makes more than the boiling point of its suitable methane in chilled fluid flow 12 under the operating pressure of post 100.In this way, preferentially from comparatively heavy hydrocarbon and liquid acidic gas componant, methane is extracted.Certainly, the liquid understood in destilling tower 100 is mixture by those of ordinary skill in the art, and meaning liquid will at pure methane and pure CO 2between some medium temperatures " boiling ".Further, if there is heavier hydrocarbon (as ethane or propane) in the mixture, this will increase the boiling temperature of mixture.Item is considered in the design that these factors become operating temperature in destilling tower 100.
In distillation zone, bottom 106, CO 2gravity is relied on to drop to the bottom of low temperature distillation tower 100 with other liquid phase fluid any.Meanwhile, methane and other vapor phase fluid are overflowed and rise on the top of tower 100.This separation completes mainly through the density variation between gas phase and liquid phase.But this separation process is assisted optionally by the intraware in destilling tower 100.Following description, these comprise and melt tower tray 130, the mass transfer apparatus 126 of multiple favourable configuration and optional heater wire 25.Side reboiler (see 173) can be added to distillation zone, bottom 106 equally so that remove methane.
Referring again to Fig. 1, the near top of the distillation zone, bottom 106 of chilled fluid flow 12 to post 100 can be introduced.Alternatively, may expect to introduce feed stream 12 to the control freezing district 108 of melting above tower tray 130.The decanting point of chilled fluid flow 12 is design problems that a composition primarily of initial fluid stream 10 determines.
In the temperature of chilled fluid flow 12 enough high (as being greater than-70 ℉) so that do not expect and the situation having solid directly chilled fluid flow 12 can be injected into distillation zone, bottom 106 preferably by two-phase flash distillation box-type device (or vapor distributor) 124 in post 100.The use of flash tank 124 is used for being separated at least in part the vapour-liquid mixture of two-phase in chilled fluid flow 12.Flash tank 124 can be slotted to make the baffle plate in two-phase fluid impact flash tank 124.
If because the expection of low inlet temperature has solid, chilled fluid flow 12 can need part in container 173 to be separated before supply post 100 described above.In this case, chilled fluid flow 12 can be separated to minimize the possibility of the intraware of solid blocking suction line and post 100 in two phase separator 173.Gas vapor leaves phase separator 173 by container entrance pipeline 11, enters post 100 at suction line 11 by inlet dispenser 121.Then gas is upwards advanced through post 100.Liquid/stereoplasm material 13 is released from phase separator 173.By vapor distributor 124, liquid/stereoplasm material is caused post 100 also to melting tower tray 130.By gravity or by pump 175, liquid/stereoplasm material is supplied to post 100.
In arbitrary layout, be that is with or without two phase separator 173, chilled fluid flow 12 (or 11) enters post 100.Liquid component leaves flash tank 124 and the steam stripping plate 126 marched to downwards in distillation zone, bottom 106 is gathered.Steam stripping plate 126 comprises a series of weir plate 128 and downspout 129.More fully these are described below together with Fig. 3.The temperature that steam stripping plate 126 is warmmer in distillation zone, bottom 106 is combined and causes methane to overflow from solution.Any carbon dioxide molecule carried secretly that gained steam carries methane and cooked.
Steam upwards continues run and arrive freeze space 108 by the air-lift tube or riser (chimneys) 131 (see Fig. 2 B) melting tower tray 130 further.The work of riser 131 vapor distributors is in order to be uniformly distributed in whole freeze space 108.Then steam by contact from the cooling fluid of spray thrower 120 with " freezing out " CO 2.In other words, CO 2to freeze and then precipitation or " snowing " be back to melt tower tray 130.Then solid CO 2melt and rely on gravity to flow down and by the distillation zone, bottom 106 below it from thawing tower tray 130 in liquid form.
As will be more fully discussed below, spray section 108 will be middle freezing zones of low temperature distillation tower 100.With interchangeable structure---wherein chilled fluid flow 12 was separated before entering tower 100 in container 173, introduced a part for the liquid/stereoplasm material 13 be separated to tower 100, just in time above thawing tower tray 130.Therefore, sour gas and the liquid-solid mixture compared with heavy hydrocarbon component will flow from distributor 121, and solid and liquid drop to and melts on tower tray 130.
Configuration melts tower tray 130 to rely on gravity reception from the liquid in middle control freezing district 108 and solid matter, is mainly CO 2and H 2s.Melt tower tray 130 play warm liquid and solid matter and guide they downwards in liquid form by distillation zone, bottom 106 to be further purified.Melt tower tray 130 with a beach liquid accumulation and the warm solid-liquid mixtures from control freezing district 108.Design is melted tower tray 130 and is back to control freezing district 108 with disengaged vapor stream, provides applicable heat transfer to melt solid CO 2, and post 100 bottom of melting below tower tray 130 is distilled or distillation zone, bottom 106 to promote liquid/slurry to drain into.
Fig. 2 A provides the top view melting tower tray 130 in one embodiment.Fig. 2 B provides and melts the sectional view of tower tray 130 along Fig. 2 A taken along B-B.Fig. 2 C shows the sectional view melting tower tray 130 C-C along the line and intercept.Jointly will describe referring to these three figure and melt tower tray 130.
First, melt tower tray 130 and comprise substrate 134.Substrate 134 can be plane body substantially.But in the preferred embodiment of Fig. 2 A, 2B and 2C display, substrate 134 adopts the profile being substantially non-planar.Nonplanar be configured to contact to land from control freezing district 108 provide the surface area of increase at the liquid melted tower tray 130 and solid.This for increasing the steam upwards transmitted from distillation zone, post 100 bottom 106 to liquid with melt the heat transfer of solid.On the one hand, substrate 134 is undulatory.On the other hand, substrate 134 is sinusoidal substantially.This aspect of tray design shows in fig. 2b.Should be appreciated that and other nonplanar geometry can be adopted alternatively to increase the heat transfer area melting tower tray 130.
Preferably, melting tower tray substrate 134 is tilt.This inclination is shown in the side view of Fig. 2 C.Although most solid should be melted, this inclination is for guaranteeing that in liquid mixture, any solid that do not melt to be got rid of and to the distillation zone 106 below it from melting tower tray 130.
In the view of Fig. 2 C, visible pond or pipeline 138 are in the central authorities of melting tower tray 130.Melt tower tray substrate 134 to slope inwardly to transport solid-liquid mixtures towards pipeline 138.Substrate 134 can tilt to promote the fluid removal relying on gravity by any way.
As United States Patent (USP) 4,533, described in 372, melt tower tray and be called as " riser tower tray (chimneytray) ".This is owing to there is single exhaust riser.Riser provides opening, and steam can move upwardly through riser tower tray by this opening.But the existence of single riser means, all gas moved up by riser tower tray has to be discharged by single opening.On the other hand, in the thawing tower tray 130 of Fig. 2 A, 2B and 2C, provide multiple riser 131.The use of multiple riser 131 provides the vapor distribution of improvement.This to be conducive in middle control freezing district 108 better heat transfer/mass transfer.
Riser 131 can be any profile.Such as, riser 131 can be circle, rectangle or make steam pass through to melt other shape any of tower tray 130.Riser 131 also can be narrow and extend upwardly in control freezing district 108.This makes can to realize when steam rises to CFZ control freezing district 108 useful pressure drop with distribute vapor equably.Preferably, riser 131 be positioned at corrugated substrate 134 peak on to provide extra heat transfer area.
Preferably, the top end opening of riser 131 seals with cap or lid 132.This minimize the solid fallen from control freezing district 108 can avoid falling into the chance of melting tower tray 130.In Fig. 2 A, 2B and 2C, visible lid 132 on each riser 131.
Also can design thawing tower tray 130 and there is bubble-cap.Bubble-cap defines from melting the outstanding impression on substrate 134 risen below tower tray 130.Bubble-cap further increases and melts surface area on tower tray 130 with to rich CO 2liquid carrying is for extra heat transfer.With this design, suitable liquid should be provided to discharge, as the angle of inclination increased, to guarantee the steam stripping plate 126 guiding liquid to below.
Again referring to Fig. 1, also can design thawing tower tray 130 and there is outside liquid transmission system.This transmission system is used for guaranteeing the essentially no solid of all liq and provides sufficient heat transfer.First transmission system comprises gets rid of nozzle 136.In one embodiment, get rid of nozzle 136 and be arranged in eliminating pond or pipeline 138 (Fig. 2 C shows).The liquid assembled in pipeline 138 is delivered to feed-line 135.The flowing by feed-line 135 is controlled by control valve 137 and liquid-level controller " LC " (see Fig. 1).By feed-line 135 Returning fluid to distillation zone, bottom 106.If liquid level is too high, control valve 137 is opened; If liquid level is too low, control valve 137 is closed.If operator selects not adopt transmission system in distillation zone, bottom 106, so closed control valve 137 also guides " steam stripping plate " 126 below fluid to mass transfer apparatus or thawing tower tray 130 to pass through spilling downspout 139 stripping immediately.
No matter whether utilize external transport system, warm solid CO on thawing tower tray 130 2and change rich CO into 2liquid.By the heating and melting tower tray 130 from below of the steam from distillation zone, bottom 106.Supplemental heat is melted on tower tray 130 or only in thawing tower tray substrate 134 as heater wire 25 is optionally added to by various mode.Heater wire 25 utilizes the heat energy obtained from bottom reboiler 160 to promote that solid melts.
Rich CO 2liquid under level control from thawing tower tray 130 discharge and rely on gravity to be introduced into distillation zone, bottom 106.As described in, provide multiple steam stripping plate 126 melting in the distillation zone, bottom 106 below tower tray 130.Preferably, steam stripping plate 126 is parallel relation substantially, a limit on the other.Alternatively, can with very small each steam stripping plate 126 of slant setting of weir plate to maintain liquid level on tower tray.Fluid relies on gravity along the flowing of each tower tray, flows through weir plate and then run underneath to next tower tray by downspout.
Steam stripping plate 126 can become various layout.Steam stripping plate 126 can arrange to form reciprocal, waterfall type liquid flow with less horizontal relation.But, preferably arrange that steam stripping plate 126 is to be formed by the basic waterfall type liquid flow separated along the independent steam stripping plate of same horizontal plane.This shows in the layout in figure 3, and wherein liquid flow is at least by separately once to make liquid flow pass independent tower tray and to fall into two relative downspouts 129.
Fig. 3 provides the side view that steam stripping plate 126 is in one embodiment arranged.Each steam stripping plate 126 receives and assembles the fluid from top.Preferably, each steam stripping plate 126 has weir plate 128, and its work playing dam is in order to make the little beach fluid collection on each steam stripping plate 126.This accumulation can be 1/2 to 1 inch, although can adopt any height.Water fall effect is defined by weir plate 128 when fluid drops down onto next lower tower tray 126 from a tower tray 126.On the one hand, do not provide the inclination of steam stripping plate 126, but cause water fall effect by the structure of higher weir plate 128.Fluid contacts with the rising steam of enrichment in light hydrocarbon, extract methane with this " contact zone " at tower tray 126 from the liquid of cross flow one.Weir plate 128 seals downspout 129 and walks around downspout 129 to help prevent steam with being used for dynamics, and promotes the effusion of the hydrocarbon gas further.
Along with liquid moves downwards through distillation zone, bottom 106, in liquid, the percentage of methane diminishes gradually.The degree of distillation depends on the quantity of tower tray 126 in distillation zone, bottom 106.On the top of distillation zone, bottom 106, in liquid, methane content may be up to 25mol.%, and at bottom steam stripping plate, methane content is low to moderate 0.04mol.%.Methane content goes out along steam stripping plate 126 (or other mass transfer apparatus) rapid flash.Quantity for the mass transfer apparatus of distillation zone, bottom 106 is the design alternative problem of the composition based on flow of feed gas 10.But, such as, generally only need to utilize the steam stripping plate 126 of some levels to remove at the methane to 1% liquefied in sour gas or less desired level.
Can adopt and promote that the various independent steam stripping plate 126 of methane effusion constructs.Steam stripping plate 126 can represent the panel with sieve aperture or bubble-cap simply.But, in order to provide heat transfer to fluid further and prevent the undesirably obstruction because solid causes, can adopt so-called " jet tray " below thawing tower tray.Replace tower tray, also can adopt random filler or structured packing.
Fig. 4 A provides the top view of illustrative jet tray 426 in one embodiment.Fig. 4 B provides the sectional view of the jet tab 422 of jet tray 426.As display, each jet tray 426 has main body 424, in main body 424, form multiple jet tab 422.Each jet tab 422 comprises the tab member 428 of the inclination hiding perforate 425.Like this, jet tray 426 has multiple little perforate 425.
In operation, one or more jet tray 426 can be placed in distillation zone, bottom 106 and/or the distillation zone, top 110 of tower 100.Can as the pattern of steam stripping plate in Fig. 3 126, multiple channel arrangement tower tray 426.But, can utilize and promote that any tower tray of methane gas effusion or filler are arranged.Fluid stepwise flows down on each jet tray 426.Then fluid flows along main body 424.Best, make tongue piece 422 be oriented to fast and effectively move fluid through tower tray 426.Optionally, adjacent downspout (not shown) can be provided with moving liquid to a rear tower tray 426.Perforate 425 also allows the gas vapor discharged in the fluid moving process of distillation zone, bottom 106 more effectively upwards to march to melt tower tray 130 by riser 131.
On the one hand, tower tray (as tower tray 126 or 426) can be manufactured by anti-pollution material, namely stop the material of Solid build ups.The accumulation of anti-pollution material prevents corrosive metallic particles, polymer, salt, hydrate, catalyst fines or other chemical solids compound is utilized in some treatment facilities.When low temperature distillation tower 100, anti-pollution material can be used in tower tray 126 or 426 to limit CO 2the adhesion of particle.Such as, can by Teflon tMapplication of paints is on the surface of tower tray 126 or 426.
Alternatively, structural design can be provided to guarantee CO 2accumulation is not started in solid form along the internal diameter of post 100.In this respect, the wall that jet tab 422 can be oriented to along post 100 promotes liquid, therefore stops the buildup of solids along the wall of post 100 and guarantees good vapor-liquid contact.
In arbitrary tower tray is arranged, when the liquid bump flowed down bumps against steam stripping plate 126, there is feed separation.Methane gas is overflowed and is moved up in vapour form from solution.But, CO 2normally enough cold and under sufficiently high concentration so that its major part exist with its liquid form and march to the bottom of distillation zone, bottom 106 downwards, although some CO must be evaporated in this process 2.Then liquid shifts out from low temperature distillation tower 100, as bottom stream stream 22 in discharge pipe.
After discharging destilling tower 100, bottom stream stream 22 enters reboiler 160.In FIG, reboiler 160 is tank vessel, and it provides the steam boiled again to steam stripping plate.Vapor line boil again see 27.In addition, thawing tower tray 130 provides supplemental heat to carry the steam that boils again to think by heater wire 25.Supplemental heat is controlled by valve 165 and temperature controller TC.Alternatively, can by heat exchanger as heat siphon type heat exchanger (not shown) be used for cooling initial fluid stream 10 to save energy.In this respect, under the liquid entering reboiler 160 remains on relatively low temperature, such as about 30 ℉ to 40 ℉.By the heat be combined with initial fluid stream 10, operator can be warm and part boils cooling bottom stream stream 22 from destilling tower 100, pre-cooled extraction fluid stream 10 simultaneously.For this situation, the fluid of supplemental heat is provided to be the vapor phase returned from reboiler 160 by line 25.
Consider in some conditions, melt tower tray 130 can without during heater wire 25 operation.In such cases, thawing tower tray 130 can be designed and there is inner heater block as electric heater.But, preferably, provide the heating system utilizing the heat energy obtained in bottom stream stream 22.Warmed fluid in heater wire 25 exists with 30 ℉ to 40 ℉ on the one hand, and therefore they contain suitable heat energy.Therefore, in FIG, the warm steam flow be presented in the heater wire 25 heating coil (not shown) crossed on thawing tower tray 130 is directed to melts tower tray 130.Alternatively, warm steam stream can be connected to transfer line 135.
In operation, to introduce the major part steam that boils again in the bottom of post by pipeline 27 to flow on the liquid level of bottom and in the end on steam stripping plate 126 or below it.Along with the steam that boils again upwards passes through each tower tray 26, go out residual methane from liquid stripping.This steam moves up along tower along with it and cools.When the steam from pipeline 27 flow to reach corrugated melt tower tray 130 time, temperature can be down to approximately-20 ℉ to 0 ℉.But, this with may be approximately-50 ℉ to-70 ℉ thawing tower tray 130 on thawing solid-phase quite hotter than still.When it contacts with thawing tower tray 130, this steam still has enough heat contents to melt solid CO 2.
Later referring to reboiler 160, alternatively, the fluid of discharging in liquid form in the tower bottom flow 24 of reboiler 160 can be passed through expansion valve 162.Expansion valve 162 reduces the pressure of tower bottom liquid product, effectively provides refrigeration.Therefore, cooling tower underflow 26 is provided.Discharge the rich CO of reboiler 160 2liquid can to pumped downhole by one or more AGI well (schematically see in Fig. 1 250).In some cases, can be used as the part improving oil recovery process, pumping liquid CO 2to the oil reservoirs that part is gathered.Therefore, CO 2it can be miscible infusion.Alternatively, CO 2can be used as the miscible flooding agent (floodagent) improving oil recovery.
Again referring to the distillation zone, bottom 106 of tower 100, gas moves upwardly through distillation zone, bottom 106, passes through to melt the riser 131 of tower tray 130, and arrives control freezing district 108.Control freezing district 108 defines the room opened wide with multiple spray spout 122.When steam moves upwardly through control freezing district 108, the temperature of steam becomes lower.Steam contacts with the liquid methane (" backflow ") from spray spout 122.This liquid methane is by comprising the external refrigeration device cooling of heat exchanger 170, colder than the steam moved up.In one arrangement, liquid methane is to be approximately the temperature of-120 ℉ to-130 ℉ from spray spout 122 out.But along with liquid methane evaporation, it absorbs heat, because this reducing the temperature of the steam that moves up from its environment.Due to its low-density (relative to liquid methane) and the barometric gradient in destilling tower 100, the methane of vaporization also upwards flows.
Along with methane steam moves up further along low temperature distillation tower 100, they leave middle control freezing district 108 and enter distillation zone, top 110.Steam continues to move up together with other light gas of overflowing from initial chilled fluid flow 12.In conjunction with hydrocarbon vapour move out from the tower top of low temperature distillation tower 100, become tower top methane stream 14.
The hydrocarbon gas in tower top methane stream 14 moves in external refrigeration device 170.On the one hand, refrigerating plant 170 uses ethylene refrigerant that tower top methane stream 14 maybe can be made to be cooled to other cold-producing medium of approximately-135 ℉ to-145 ℉.This is used for the tower top methane stream 14 that liquefies at least partly.Then the methane stream 14 cooled moves to reflux condenser or separation chamber 172.
Separation chamber 172 is for the divided gas flow 16 that---is sometimes referred to as " liquid backflow " 18---from liquid.Gas 16 represents the light hydrocarbon gases from original raw material air-flow 10, mainly methane.Also nitrogen and helium may be there is.Certainly, methane gas 16 and any traces of ethane finally seek to catch " product " sold with business.This non-liquefaction portion of tower top methane stream 14 also can be used as (on-site) fuel in device.
The a part of tower top methane stream 14 leaving refrigerating plant 170 is condensations.This part is separated in separation chamber 172 and is returned to the liquid backflow 18 of tower 100.Pump 19 can be used to be back to tower 100 with moving liquid backflow 18.Alternatively, separation chamber 172 is installed above tower 100 to provide the gravity charging of liquid backflow 18.Liquid backflow 18 will comprise any carbon dioxide of overflowing from distillation zone, top 110.But most of liquid backflow 18 is methane, be generally 95% or more, and nitrogen (if existing in initial fluid stream 10) and trace hydrogen sulfide (if same existence in initial fluid stream 10).
In one cooling is arranged, tower top methane stream 14 is obtained by open-loop refrigeration system, as shown in together with Fig. 6 and as described in refrigeration system.In this arrangement, tower top methane stream 14 obtains the returning part tower top methane stream being used as liquid backflow 18 with cooling by intersection-heat exchanger.Thereafter, tower top methane stream 14 is forced into about 1,000psi to Isosorbide-5-Nitrae 00psi, and then utilizes surrounding air and may external propane refrigeration agent cool.Then direct pressurized and cooling air-flow by quencher to cool further.Turbine type quencher can be used to reclaim even more liquid and some shaft works.The United States Patent (USP) 6 that name is called " be separated containing at least one can the method (ProcessForSeparatingaMulti-ComponentGasSteamContainingat LeastOneFreezableComponent) of multi-component gas stream of frozen composition ", 053,007 cooling describing tower top methane stream, is incorporated to by reference of text at this.
Be to be understood that the present invention does not limit by the cooling means of tower top methane stream 14 herein.Also be to be understood that the cooling degree between refrigerating plant 170 and initial refrigerating plant 150 is changeable.In some cases, under higher temperature may be desirably in, operate refrigerating plant 150, but cooling tower top methane stream 14 is stronger in refrigerating plant 170.In addition, the invention is not restricted to these design alternative types.
Again get back to Fig. 1, liquid backflow 18 is back to distillation zone, top 110.Then rely on gravity carrying of liquids backflow 18 by one or more mass transfer apparatus 116 of distillation zone, top 110.In one embodiment, mass transfer apparatus 116 is to provide the weir plate 118 of stepwise series connection and the rectifying tower tray of downspout 119, similar with above-mentioned tower tray 126.
When the fluid from liquid reflux stream 18 moves downwards through rectifying tower tray 116, extra methane is evaporated from distillation zone, top 110.Methane gas is added to the part that tower top methane stream 14 becomes gaseous product flow 16 again.But the residual liquid phase of liquid backflow 18 falls into collects on tower tray 140.Like this, liquid reflux stream 18 hydrocarbon that inevitably obtains little percentage and the sour gas that moves up from control freezing district 108.The liquid mixture of methane and carbon dioxide is collected at collection tower tray 140.
Preferably, collect tower tray 140 and limit the main body being substantially plane, to collect liquid.But, the same with thawing tower tray 130, collect tower tray 140 also have one and preferably multiple riser to discharge the gas from control freezing district 108.Can adopt as in Fig. 2 B and 2C by assembly 131 and 132 the riser that presents and drop cloth put.In the zoomed-in view of Fig. 5, show the riser 141 and lid 142 of collecting tower tray 140, discuss further hereinafter.
Should be noted that herein in distillation zone, top 110, the H of any existence 2s dissolves in a liquid relative to tendency preferential in gas at processing temperatures.In this respect, H 2s has lower relative volatility.By with more liquid comes into contact residual vapor, low temperature distillation tower 100 makes H 2s concentration drops in the limit of a few millionths (ppm) of expectation, as 10 or the specification of even 4ppm.When fluid moves the mass transfer apparatus 116 by distillation zone, top 110, H 2s contact liq methane also leaves vapor phase and becomes the part of liquid stream 20.Therefrom, H 2s moves downwards through distillation zone, bottom 106 in liquid form and the final part as liquefaction sour gas tower bottom flow 22 leaves low temperature distillation tower 100.For little H 2s is to not having H 2if S is present in feed stream or by upstream process optionally remove H 2those situations of S, do not have H in fact 2s will be present in overhead gas.
In low temperature distillation tower 100, the liquid of catching at collection tower tray 140 is discharged from distillation zone, top 110 as liquid stream 20.Liquid stream 20 mainly comprises methane.On the one hand, liquid stream 20 is by the methane of about 93mol.%, the CO of 3% 2, 0.5% H 2the N of S and 3.5% 2composition.Now, liquid stream 20 is about-125 ℉ to-130 ℉.This is only slightly hot than liquid reflux stream 18.Guided liquid-flow 20 to reflux accumulator 174.The purposes of reflux accumulator 174 is for pump 176 provides the ability of surging.After discharging from reflux accumulator 174, form spray stream 21.In pump 176, pressurized spray stream 21 is to be again introduced into low temperature distillation tower 100.In this case, pumping spray stream 21 is discharged by nozzle 122 to middle control freezing district 108.
The some parts of spray stream 21, especially methane, vaporization and evaporation after discharge nozzle 122.Therefrom, methane rises through control freezing district 108, by collecting the riser in tower tray 140 and the mass transfer apparatus 116 by distillation zone, top 110.Methane leaves destilling tower 100 as tower top methane stream 14 and finally becomes a part of commercial product in air-flow 16.
Spray stream 21 from nozzle 122 also causes carbon dioxide to sublimate from gas phase.In this respect, the CO in liquid methane is dissolved at first 2can at once enter gas phase and move up together with methane.But due to the low temperature in control freezing district 108, the rapid nucleation of carbon dioxide of any gaseous state and assembly become solid phase and start " snowing ".This phenomenon is called desublimation.Like this, some CO 2liquid phase will never be entered again until tower tray 130 is melted in its contact.This carbon dioxide " snows " and extremely melts on tower tray 130 and be melted into liquid phase.Therefrom, rich CO 2liquid with from the liquid CO cooling as above raw material gas flow 12 2waterfall type flows down along the mass transfer apparatus of distillation zone, bottom 106 or tower tray together.At that time, should overflow rapidly from any residual methane of the spray stream 21 of nozzle 122 and become steam.These steams move up and enter distillation zone, top 110 again in low temperature distillation tower 100.
Expect cooling liquid is contacted with the gas moved up along tower 100 as much as possible.If steam gets around the spray stream 21 coming from nozzle 122, the CO of higher level 2the distillation zone, top 110 of tower 100 can be arrived.In order to improve gas/liquid contacting efficiency in control freezing district 108, multiple nozzles 122 with design structure can be adopted.Therefore, do not adopt the single spray source with one or more liquid levels of reflux fluid stream 21, the spray thrower 120 being designed with multiple spray spout 122 can be adopted alternatively.Therefore, the structure of spray spout 122 has impact to the heat transfer occurred in control freezing district 108 and mass transfer.Equally, nozzle itself can be designed to produce best drop size and the area distribution of those drops.
Assignee herein first proposes various arrangement of nozzles in the CO-PENDING WO Patent Publication 2008/091316 with international filing date on November 20th, 2007.This application and Fig. 6 A and 6B thereof are incorporated to instruct nozzle structure at this by reference.Nozzle is sought to guarantee that interior 360 ° cover and provide good vapor/liquid contact and heat transfer/mass transfer in control freezing district 108.This more effectively cools again any gaseous carbon dioxide moving upwardly through low temperature distillation tower 100.
Multiple collectors 120 for covering completely also minimize reverse mixing with the use of corresponding overlap joint nozzle 122 device.In this respect, covering prevents thin, low-quality CO completely 2particle also enters distillation zone, top 110 again along destilling tower 100 is oppositely mobile.Then these particles will mix with methane again and enter tower top methane stream 14 again, be only again circulate.
It is useful that the above sour gas described together with Fig. 1 removes system for the business methane product 16 producing substantially no acidic gas.Preferably liquiefied product 16 and deliver to pipeline with sell.Preferably, liquid gas product meets the pipeline CO of 1 to 4mol.% 2standard, produces sufficient backflow in this case.Carbon dioxide and hydrogen sulfide are removed by tower bottom flow 22.
In some cases, a small amount of H 2s and relative a large amount of CO 2be present in original initial fluid stream 10.In this case, low temperature distillation tower can be desirably in before optionally remove H 2s is can produce " cleaning " liquid CO at tower bottom flow 22 2stream.Like this, CO 2can be injected directly into reservoir to carry out raising oil recovery (" EOR ") operation.Therefore, the system and method for the part for removing the sulfur component produced with initial fluid stream 10 before carry out sour gas removal in low temperature distillation tower is as tower 100 is proposed herein.
Propose the many H for removing sulfur component from air-flow herein 2s process for selective.Describe water to become to become method with non-water.Preferably, the method removes any mercapto compound as hydrogen sulfide (H 2s) and have the organosulfur compound of sulfydryl (-SH), it is called mercaptan (mercaptan), and also referred to as mercaptan (thiol) (R-SH), wherein R is alkyl.
The first method removing sulfur component for removing system upstream at sour gas adopts the use of solvent.Some solvent has compatibility to hydrogen sulfide and can be used for H 2s and methane separation.Solvent can be physical solvent or chemical solvent.
Fig. 6 is the schematic diagram showing the gas processing device 600 removing sour gas in one embodiment from air-flow.This gas processing device 600 is removed system upstream at sour gas and is adopted solvent method.Sour gas is removed overall system and is represented with 650, and solvent method represents with frame 605 simultaneously.Sour gas removes the separation container that system 650 is included in frame 100.Frame 100 refers generally to the control freezing district tower 100 of Fig. 1.But frame 100 also can represent any low temperature distillation tower as overall fractionating column.
In figure 6, with 612 display extraction air-flows.Extraction air-flow 612 comes from the hydrocarbon occurred in reservoir exploitation district or " oil field " 610 and to gather activity.Should be appreciated that oil field 610 can represent any position producing gaseous hydrocarbon.
Oil field 610 can be land, coastal waters or sea.Oil field 610 can be operated maybe can experience by initial reservoir pressure improves recovery ratio method recovery process.The oil-field structure of system and method claimed herein not in Limit exploitation, as long as it is producing the hydrocarbon of cure hydrogen and carbon dioxide pollution.This hydrocarbon mainly will comprise methane, but also can comprise the ethane of 2mol.% to 10mol.% and other heavy hydrocarbon as propane or the even butane of trace and aromatic hydrocarbon.
Air-flow 612 is " original ", refers to that it does not experience sour gas and removes process.Flow of feed gas 612 such as can be transferred to gas processing device 600 from oil field 610 by pipeline.Arrival gas processing device 600 after, bootable air-flow 612 by dehydration as glycol dehydration container.Dewatering container is show schematically show 620.Because flow of feed gas 612 is by dewatering container 620, create current 622.In some cases, flow of feed gas 612 can mix to prevent water from running out of the formation with hydrate with ethylene glycol (monoethyleneglycol, MEG).Such as, can spray MEG to cooler, and collect liquid, to be separated into water, denseer MEG and some possible heavy hydrocarbons, this depends on temperature and the inlet gas composition of cooler.
Current 622 can deliver to water treatment facilities.Alternatively, current 622 can reinject to subsurface formations.Subsurface formations represents with frame 630.Still alternatively, the current 622 of removing can be processed to meet environmental standard and to be then released into local basin (not shown) as processed water.
Equally, owing to making extraction air-flow 612 by dewatering container 620, create the methane gas stream 624 of basic dehydration.The methane gas stream 624 of dehydration can contain trace nitrogen, helium and other inert gas.About native system and method, dehydrated gas stream 624 also comprises carbon dioxide and a small amount of hydrogen sulfide.Air-flow 624 can comprise other sulfur component as carbonyl sulfide, carbon disulfide, sulfur dioxide and various mercaptan.
Optionally, dehydrated gas stream 624 is by preliminary refrigerating plant 625.Refrigerating plant 625 cooled dehydrated air-flow 624 is to the temperature of about 20 ℉ to 50 ℉.Refrigerating plant 625 can be such as aerial cooler or ethene or propane refrigerator.
Expect from dehydrated gas stream 624, to remove sulfur component to prevent iron sulfide corrosion.According to gas processing device 600, provide solvent system 605.Dehydrated gas stream 624 enters solvent system 605.Solvent system 605 with solvent contacts air-flow 624 to remove hydrogen sulfide by absorption process.This relatively low temperature being greater than Methane solubility in acid gas components solubility occurs with under relative high pressure.
Note, solvent system 605 can be physical solvent system or chemical solvent system.Fig. 7 A provides the schematic diagram of physical solvent system 705A in one embodiment.Operating physical solvent system 705A contacts dehydrated gas stream 624 to remove sulfur component.
The example of physical solvent be applicable to comprises the methyl alcohol of 1-METHYLPYRROLIDONE, propylene carbonate, malonic methyl ester nitrile and cooling.The preferred embodiment of physical solvent is sulfolane, and its chemical name is tetramethylene sulfone.Sulfolane is the organosulfur compound containing sulphonyl functional group.Sulfonyl group is that sulphur atom double bond is bonded to two oxygen atoms.Sulphur-oxygen double bond is high-polarity, allows its high-dissolvability in water.Meanwhile, four-carbocyclic ring provides the compatibility to hydrocarbon.These character make sulfolane be all miscible in water and hydrocarbon, make it be widely used as the solvent of purifying hydrocarbon mixture.
Preferred physical solvent is Selexol tM.Selexol tMit is the trade name of the treating products with gas of the subsidiary UnionCarbide of DowChemical company.Selexol tMit is the mixture of the dimethyl ether of polyethylene glycol.The example of a this composition is dimethoxy tetraethylene glycol (dimethoxytetraethyleneglycol).Selexol also by any heavy hydrocarbon in the initial fluid stream 10 of acquisition and some water.The situation quite dry when initial fluid stream 10 starts, Selexol tMuse can remove needs to other dehydration.Note, if Selexol herein tMsolvent is cooled, then with CO 2presaturation, then Selexol tMsolvent will to H 2s has selective.
Referring to Fig. 7 A, visible dehydrated gas stream 624 enters entrance separator 660.Should be appreciated that and expect to keep air-flow 624 cleaning to prevent the foaming of liquid flux in sour gas removal process.Therefore, entrance separator 660 is used to filter out liquid impurity as oil base drilling fluid and mud.Also some particle filterings can be carried out.Preferably, use upstream dewatering container 620, be separated salt solution.But entrance separator 660 can remove any condensation of hydrocarbons.
Liquid such as drilling fluid and condensation of hydrocarbons are left by the bottom of entrance separator 660.Liquid impurity stream is see 662.Usually, water base impurity is delivered to water treatment facilities (not shown), maybe can refill to stratum 630 to maintain reservoir pressure or to dispose.Hydrocarbon liquid is sent to condensation process equipment usually.Gas is discharged from the top of entrance separator 660.Cleaning gas tream is see 664.
Optionally, cleaning gas tream 664 to gas-gas interchanger 665 is guided.Gas in the pre-cooled cleaning gas tream 664 of gas-gas interchanger 665.Then guide clean air to absorber 670.Preferably, absorber 670 is the column for counter-currently contacting receiving absorbent.In the layout of Fig. 7 A, cleaning gas tream 664 enters bottom tower 670.Meanwhile, physical solvent 696 enters at tower 670 top.Tower 670 can be Pu Panta, packed tower or other type tower.
Should be appreciated that alternatively, the many non-tower apparatus being designed for solution-air contact can be utilized.These can comprise static mixer and and flow contact device.The countercurrent tower 670 of Fig. 7 A is only used for illustrative object.Note, for the small-sized of solution-air contacting container (one or more) and the use of flowing contactor is preferred, because can reduce total floor space (footprint) and the weight of physical solvent system 705A.
Absorbent can be such as mix with cleaning gas tream 664 with " isolating " H 2s and some subsidiary CO 2solvent.Absorbent can specifically as discussed above Selexol .As the result of the contact process with absorbent, create light gas stream 678.Light gas stream 678 from tower 670 top out.Light gas stream 678 is containing methane and carbon dioxide.Light gas stream 678 experiences process of refrigerastion, is then directed to low temperature distillation tower, schematically shows with the frame 100 in Fig. 6.
At once referring back to Fig. 6, light gas stream 678 is discharged from physical solvent system 705A and is passed through cooler 626.Cooler 626 cools the temperature of light gas stream 678 to about-30 ℉ to-40 ℉.Cooler 626 can be such as ethene or propane refrigerator.
Preferably, light gas stream 678 is next mobile by expansion gear 628.Expansion gear 628 can be such as joule-Tang Pusen (" J-T ") valve.The work of expansion gear 628 quenchers is in order to obtain the further cooling to light gas stream 678.Expansion gear 628 reduces the temperature of light gas stream 678 further to such as about-70 ℉ to-80 ℉.Preferably, at least part of liquefaction of air-flow 678 is also completed.Cooling acid flow produces at pipeline 611.
Refer again to Fig. 7 A, contact tower 670 will obtain sulfur component.These discharge bottom tower 670 as " richness " solvent.Visible solvent-rich stream 672 discharges tower 670.Solvent-rich stream 672 also can comprise some carbon dioxide.
In the layout of Fig. 7 A, conveying solvent-rich stream 672 is by energy recovery turbine 674.This allows for physical solvent system 705A and produces electric energy.Therefrom, carry solvent-rich stream 672 by a series of flash separator 680.In the illustrative layout of Fig. 7 A, with 682,684 and 686 displays, three separators.According to physical solvent process, separator 682,684,686 runs under the temperature and pressure reduced gradually.
Such as, the first separator 682 can run at the temperature of the pressure of 500psi and 90 ℉.First separator 682 discharges the light gas be entrained in solvent-rich stream 672.Mainly comprise methane and carbon dioxide with these light gas of 681 displays, but trace H can be had 2s.Bootable light gas 681 to low temperature distillation tower 100 (not showing in fig. 7).These gases can be combined with light gas stream 678.Preferably, light gas 681 is advanced through compressor 690 to increase as the pressure in stream 611 to low temperature distillation tower 100 process.If operate destilling tower 100 under the pressure that is the first separator 682 is lower of the first flash stage than solvent method 705A, compression can not be needed.In that situation, pressure drop will be needed for overhead streams 678 so that in conjunction with stream 681 and 678.Pressure drop is caused by the J-T valve near low temperature distillation tower 100.Certainly, flow 681 to introduce in J-T valve downstream.
Ideally, catch with solvent-rich stream 672 from all hydrogen sulfide of cleaning gas tream 664 and any heavy hydrocarbon.The solvent stream of enrichment is discharged by from each separator 682,684,686 gradually.The stream of these enrichments gradually indicates with pipeline 683,685 and 687.Therefore, generally make physical solvent regeneration by pressure drop, cause the methane and carbon dioxide of any dissolving from solvent flashing out.
Pipeline 687 is " half is poor " solvent stream, because some CO 2be removed, but solvent stream 687 does not also have holomorphosis.Carry a part for this solvent stream 687 by booster pump 692 and be introduced into contact tower 670 as half lean solvent again at the intermediate altitude of contact tower.Guide with the residual fraction of 693 displays to regeneration container 652.
About second 684 and the 3rd 686 of three separators, each that it should be noted that these separators 684,686 also discharges very small amount of light gas.These light gas mainly will comprise carbon dioxide, subsidiary a small amount of methane.With two independent pipelines at 689 these light gas of display.Light gas 689 can be compressed and is combined with pipeline 611, is then directed to low temperature distillation tower 100.Alternatively, can directly transport from the light gas of pipeline 689 to liquefaction acid gas stream at the bottom of the towers of 642 displays in Fig. 6.
Physical solvent is used to be used for upstream H 2the advantage that S removes is solvent normally moisture absorption.This can eliminate the needs for gas dewatering container 620, especially when initial fluid stream 10 substantially dry.For this purpose, preferably, the solvent of selection itself is anhydrous.Like this, solvent can be used for making original natural dewater further.In this case, water can from regenerator 652 with steam stream 655 out.
The shortcoming of this process is some light hydrocarbons and CO 2will to a certain extent by eutectoid content in physical solvent.The use of multiple separator 682,684,686 eliminates most of methane really from solvent-rich stream 672, but is not generally the whole of it.
Refer again to regeneration container 652, container 652 plays stripper.Drive 2 S component to make them as dense H 2s flows through steam stream 655 and leaves regeneration container 652.Dense H in display steam stream 655 2s leaves physical solvent system 705A.It is also shown in the pipeline 655 in Fig. 6.
Preferably, the dense H in steam stream 655 2s is sent to sour gas and injects (AGI) equipment.Optionally, the second physical solvent process can be used in advance to remove any CO 2and steam.Separator is shown 658.Separator 658 is that recovery condensed water and solvent make gas arrive the reflux vessel of tower top simultaneously.Condensed water and solvent are back to regeneration container 652 by tower bottom tube line 659.Meanwhile, overhead gas is sent to sour gas injection (schematically show at the frame 649 of Fig. 6, and discuss hereinafter) by pipeline 691.
Steam stream 655 also will comprise carbon dioxide.Carbon dioxide and any steam will together with H 2s leaves separator 658 by overhead line 691.Preferably, H 2s delivers to AGI equipment 649 to downstream, or optionally, can be sent to sulfur recovery unit (SRU) (not shown).
The regeneration container 652 described in Fig. 7 A can utilize stripping gas separate sulphur component from solvent.Regeneration container 652 can with many stripping gas chargings.Example has high CO 2the fuel gas stream of content.Preferred high CO 2the fuel gas of content is used for stripping gas 651, because it can help with CO 2" presaturation " solvent, thus cause obtaining less CO from clean gas flow 664 2.Visible stripping gas is fed to regeneration container 652 by pipeline 651 '.Stripping gas 651 ' can be a part of light gas stream 689 such as from minimum pressure flash stage and separator 686.This makes to reclaim some hydrocarbon.
Regenerated solvent is derived bottom regeneration container 652.Regenerated solvent is discharged as 653.Conveying regenerated solvent 653 is by booster pump 654.Optionally, the pressure in the further pipeline improving conveying regenerated solvent 653 of the second booster pump 694 is utilized.Thereafter, preferably, the heat exchanger 695 by having refrigerating plant cools regenerated solvent 653.Then the solvent 696 of cooling and regeneration is recycled to contactor 670.
Part regenerated solvent is by obtaining bottom regeneration container 652 and being sent to reboiler 697.Reboiler is warm solvent.Warm solvent passes through pipeline 651 as part evaporation current " be back to regeneration container 697.
Fig. 7 A indicates the embodiment of physical solvent system 705A.But note, alternatively, solvent system 605 can be chemical solvent system.Chemical solvent system uses chemical solvent, particularly H 2the selective amine of S.The example of this selective amine comprises methyl diethanolamine (MDEA) and Flexsorb race's amine.Flexsorb it is the trade name of the chemical absorbent for removing sulfurous gas from acid gas mixture.Flexsorb absorbent or other amine contact with hydrocarbon stream 624 or cleaning gas tream 664 in low temperature distillation tower upstream.
Amine type solvent relies on the chemical reaction with the acid gas components in hydrocarbon stream.Course of reaction is sometimes referred to as " gas sweetening ".This chemical reaction is usually more effective than physical solvent, particularly when material pressure is lower than about 300psia (2.07MPa).
Flexsorb amine is for from containing CO 2optionally H is removed in air-flow 2the preferred chemical solvent of S.Flexsorb amine utilizes H 2s absorbs and CO 2absorb the advantage comparing relatively fast speed.Fast absorption rate helps prevent the formation of carbamate.The hydrogen sulfide produced by the process based on amine usually under low pressure.The H exported 2s will carry out sulfur recovery or carry out needing the remarkable disposal compressed.
Selective amine is used to remove hydrogen sulfide by dewater and the fluid stream 624 cooled has contacted with chemical solvent.This completes by air-flow 624 is injected into " absorber ".Absorber makes gas from air-flow 624 by Flexsorb tMor the container of other liquid amine contact.When these two kinds of flowing materials interact, amine absorbs H from acid gas 2s is to produce desulfurization air-flow.Desulfurization air-flow is mainly containing methane and carbon dioxide.This " desulfurization " gas flows out from the top of absorber.
On the one hand, absorber is large-scale, column for counter-currently contacting.In this is arranged, flow of feed gas 624 is injected into the bottom of contact tower, and chemical solvent or " lean solvent stream " are injected into the top of contact tower simultaneously.Behind the inside of column for counter-currently contacting, the gas from air-flow 624 moves upwardly through absorber.Normally, one or more tower tray or other internals (not shown) are provided in absorber to form multiple flow path of natural gas and form interface zone between gas phase and liquid phase.Meanwhile, the liquid from lean solvent stream moves down and passes the tower tray step by step in absorber.Tower tray helps the interaction of natural gas and solvent stream.This process is called that with regard to name Fig. 1 of the patent application of " by removing sour gas (RemovalofAcidGasesFromaGasStream) in air-flow " is illustrated.That section application was submitted on October 14th, 2008 temporarily, and was designated as United States serial 61/105,343.The appropriate section of Fig. 1 and description is incorporated to by reference at this.
" richness " amine aqueous solution is left by the bottom of column for counter-currently contacting.This comprises liquid amine together with the H absorbed 2s.Rich amine aqueous solution is obtained by regenerative process, and this regenerative process can seem the regeneration module described in above Fig. 7 A that extraordinary image is relevant with physical solvent system 705A, although it only has the single flash chamber operated under 100-200psig usually.
As washing H off 2the column for counter-currently contacting of the absorber of S is often very large and heavy.Special difficulty is caused in this oil and gas extraction application at sea.Therefore, propose herein subsidiary reclaim in oil and gas from hydrocarbon stream, remove H 2the Alternate embodiments of S.It relates to less and flows the use of contact device.These devices by reducing time of contact, thus reduce CO 2absorbed chance, improves the selective of amine.These less absorption plants also can reduce the size of total floor space of process 605.
Fig. 7 B shows the illustrative embodiment of the chemical solvent system 705B that can be used to Fig. 6 dissolving agent process 605.Chemical solvent system 705B adopt a series of and flow contact device CD1, CD2 ..., CD (n-1), CDn.These devices are used to selective amine and air flow contacts.
And stream concept utilizes two or more contactors of series connection, wherein acid flow moves together with in contactor with liquid flux.In one embodiment, acid flow and liquid flux move substantially together with the longitudinal axis of respective contactor.And flow contactor and can operate under very high fluid velocity.As a result, and flow contactor trend towards Billy's packed tower or paving Pan Ta counter-current contactors less.
As Fig. 7 A, visible dehydrated gas stream 624 enters entrance separator 660.Entrance separator 660 is for filtering out liquid impurity as oil base drilling fluid and mud.The upstream dewatering container 620 shown in Fig. 6 is used preferentially to be separated salt solution.Also some particle filterings can be carried out in entrance separator 660.Should be appreciated that and expect to keep air-flow 624 cleaning to prevent the foaming of liquid flux in Sour gas disposal process.
Liquid such as condensation of hydrocarbons and drilling fluid are left by the bottom of entrance separator 660.Liquid impurity stream is shown in 662.Aqueous impurities generally delivers to water treatment facilities (not shown), maybe can refill to stratum 630 with pipeline 622 to maintain reservoir pressure or to dispose.Hydrocarbon liquid generally removes condensation process device.Gas is discharged from the top of entrance separator 660.Clean acid flow is see 664.
Clean acid gas guides to a series of absorber.Herein, absorber be and flow contact device CD1, CD2 ..., CD (n-1), CDn.Each contactor CD1, CD2 ..., CD (n-1), CDn remove part H from air-flow 664 2s content, thus the air-flow discharging desulfurization gradually.Final contactor CDn provides the final desulfurization air-flow 730 (n) consisting essentially of methane and carbon dioxide.The pipeline 678 that air-flow 730 (n) is Fig. 6.
In operation, air-flow 664 enters first and flows absorber, or contact device CD1.There, gas mixes with liquid flux 720.Preferably, solvent 720 by amine aqueous solution as methyl diethanolamine (MDEA) or Flexsorb amine forms.Liquid flux also can comprise hindered amine, tertiary amine or its combination.Flexsorb be the example of hindered amine, and MDEA is the example of tertiary amine.In addition, solvent stream 720 is the partial regeneration or " half is poor " solvent that are produced by regenerator 750." half is poor " solvent 720 is helped to move into the first contactor CD1 by pump 724.Under applicable pressure, pump 724 moves half lean solvent 720 and enters the first contactor CD1.The example being applicable to pressure is about 15psia to 1,500psig.
Behind the first contactor CD1 inside, air-flow 664 and chemical solvent stream 720 move along the longitudinal axis of the first contactor CD1.When they are advanced, liquid amine (or other solvent) and the H in air-flow 664 2s-phase mutual effect, causes H 2s chemistry is connected to amine molecule or is adsorbed by amine molecule.First " richness " solvent solution 740 (1) leaves the bottom of the first contactor CD1.Meanwhile, Part I desulfurization air-flow 730 (1) is shifted out by the first contactor CD1 and is released into the second contactor CD2.
Second contactor CD2 also represents and flow splitting device.Optionally, after the second contactor CD2, the 3rd is provided and flow splitting device CD3.Second and the 3rd each in contactor CD2, CD3 produces respective partial desulfurization air-flow 730 (2), 730 (3).In addition, the second and the 3rd each in contactor CD2, CD3 produces the gas treatment solution 740 (2), 740 (3) of respective fractional load.When amine is used as solvent, the gas treatment solution 740 (2), 740 (3) of fractional load will comprise rich amine aqueous solution.In example systems 705B, the second supporting gas Treatment Solution 740 (2) ties merga pass regenerative process with the first supporting gas Treatment Solution 740 (1), comprises by regenerator 750.
It should be noted that when gas 664 move by the air-flow 730 (1) of desulfurization gradually on downstream direction, 730 (2) ... time 730 (n-1), the pressure in system will reduce usually.When it happens, the amine (or other liquid flux) richened gradually in the upstream direction flow 740 (n), 740 (n-1) ... pressure in 740 (2), 740 (1) needs to increase substantially to mate air pressure.Therefore, preferably one or more small-sized booster pump (not shown) is placed in system 705B each contactor CD1, CD2 ... between.This will be used for increasing intrasystem fluid pressure.
In system 705B, stream 740 (1), 740 (2) comprises first mobile " richness " solvent solution by flash tank 742.Flash tank 742 operates under the pressure of about 100 to 150psig.Flash tank 742 generally has and causes depositional inner body or the bending flow path for wherein solvent stream 740.By pipeline 744 from solvent stream 740 flash distillation residual gas as methane and CO 2.Such as, if contacted with a small amount of fresh amine from pipeline 720, the residual gas of catching in pipeline 744 can be reduced to the content of acid gas of about 100ppm.This concentration is enough little, makes the fuel gas that residual gas can be used as in system 705B.
By pipeline 744 from the remaining natural gas of solvent stream 740 flash distillation.Gained solvent-rich stream 746 is directed to regenerator 750.
Before moving into regenerator 750, preferably, solvent-rich stream 746 moves by heat exchanger (not shown).Relatively cold (close to environment temperature) solvent stream 746 is by being heated with warm lean solvent stream 760 thermo-contact left bottom regenerator 750.This is used for again cooling lean solvent stream 760 valuably, is then delivered to lean solvent cooler 764, and then to final contactor CDn.
Regenerator 750 defines the stripper section 752 comprising tower tray or other internals (not shown) above reboiler 756.There is provided thermal source to reboiler 756 to produce heat.Regenerator 750 produces and is recycled with the regeneration reused in final contactor CDn or " poor " solvent stream 760.From containing dense H 2the stripping overhead gas of the regenerator 750 of S leaves regenerator 750 as trash flow 770.
Rich H 2s trash flow 770 moves into condenser 772.Condenser 772 is used for cooling trash flow 770.The trash flow 770 of cooling moves by return tank 774, and it is separated any residual liquid (being mainly condensed water) from trash flow 770.Then formed and mainly comprise H 2the acid gas stream 776 of S.Acid gas stream 776 is the same with the pipeline 655 of Fig. 6.
Some liquid can fall from return tank 774.This forms residual solution stream 775.Preferably, carry residual solution stream 775 to improve pressure by pump 778, there, then it is reintroduced into regenerator 750.Some residual liquids will leave regenerator 750 in bottom, as a part for lean solvent stream 760.Optionally, some water yields can be added to lean solvent stream 760 and lose with balance to the steam of desulfurization air-flow 730 (n-1), 730 (n).This water can be added at the entrance of reflux pump 778 or suction place.
Under poor or regenerated solvent 760 is in low pressure.Therefore, the liquid stream of regenerated solvent 760 is represented by booster pump 762 conveying.Pump 762 is referred to as lean solvent booster 762.From there, lean solvent 760 is by cooler 764.Cool solvent by cooler 764 and guarantee that lean solvent 760 will absorb sour gas effectively.The lean solvent 760 of cooling is used as the solvent stream being finally separated contactor CDn.
Optionally, close to contact device CD1, CD2 ..., CD (n-1), CDn provide solvent tank 722.Lean solvent 760 is by solvent tank 722.More preferably, solvent tank 722 is off-line and provides the storage pond of solvent, because it may be needed by gas apparatus 705B.
Referring again to multiple and flow contact device CD1, CD2 ..., CD (n-1), CDn, each contact device receives the air-flow comprising the hydrocarbon gas and hydrogen sulfide.Operate each contact device CD1, CD2 ..., CD (n-1), CDn sequentially remove H 2s and produce the air-flow of desulfurization gradually.And flow contact device CD1, CD2 ..., CD (n-1), CDn can be any one of various short contacting time mixing arrangement.Example comprises static mixer and centrifugal mixer.Liquid is separated by injector by some mixing apparatus.Injector conveying gas is by promoting the venturi shape pipe that liquid flux enters pipe successively.Due to Venturi effect, liquid flux is drawn into and is split into droplet, allows to contact with gas large surface area.
A kind of preferred contact device is ProsCon tMcontactor.This contactor has the injector of centrifugal coalescer after utilizing.Centrifugal coalescer causes large centrifugal force with the liquid flux again in conjunction with small size.In no matter which kind of embodiment, preferably adopt small containers technology, hardware compared with large contact tower is reduced.
First contactor CD1 receives flow of feed gas 664.In the first contactor CD1, flow of process air 664 is to remove hydrogen sulfide.Then discharge first, partial desulfurization air-flow 730 (1).The first, partial desulfurization air-flow 730 (1) is delivered to the second contactor CD2.There, the first desulfurization air-flow 730 (1) is further processed to remove hydrogen sulfide, to discharge second, the air-flow 730 (2) of more abundant desulfurization.Continue this pattern with the air-flow 730 (3) making the 3rd contactor CD3 produce more abundant desulfurization; 4th contactor CD4 still produces the air-flow 730 (4) of desulfurization even more; And penultimate contact device still produces the air-flow CD (n-1) of desulfurization more.Each in these can be called as " continuously (subsequent) " desulfurization air-flow.
Final desulfurization air-flow 730 (n) is discharged by final contactor CDn.Primarily of the H needed for the standard of meeting the expectation 2s removal level determines the quantity (being at least two) of the contact device before final contactor CDn.In the system 705B of Fig. 7 B, final desulfurization air-flow 730 (n) is still containing carbon dioxide.Therefore, desulfurization air-flow 730 (n) must the removed CFZ tower 100 by Fig. 6.Desulfurization air-flow 730 (n) is identical with the pipeline 678 of Fig. 6.
On the one hand, in each contactor, adopt the combination of mixing arrangement and corresponding coalescing devices.Therefore, such as, a CD1 and the 2nd CD2 contactor can use static mixer as their mixing arrangement, and the 3rd CD3 and other CD4 contactor can use injector, and CDn-1 and CDn contactor can use centrifugal mixer.Each contactor has relevant coalescing devices.In arbitrary embodiment, air-flow 664,730 (1), 730 (2) ... the liquid flux stream of 730 (n-1) and concurrent flow with equidirectional flow through contactor CD1, CD2 ... CDn.This time durations that processing reaction is occurred is short, is perhaps even as short as 100 milliseconds or less.This is for optionally H 2s removes (relative to CO 2) may be favourable, because some amine and H 2s ratio and CO 2react more quickly.
Except receiving except air-flow, each and flow contactor CD1, CD2 ..., CD (n-1), CDn also receive liquid flux stream.In system 705B, the solvent stream 720 of the first contactor CD1 receiving unit regeneration.Thereafter, contactor CD2, CD3, CD (n-1) subsequently, CDn receive the solvent solution of the load of release in respective contactor in succession.Therefore, the second contactor CD2 receives the solvent solution 740 (3) of release from the fractional load of the 3rd contactor CD3; 3rd contactor CD3 receives the solvent solution 740 (4) of release from the fractional load of the 4th contactor CD4; And penultimate contact device CD (n-1) receives the solvent solution 740 (n) from the fractional load of final contactor CDn.In other words, the liquid flux that the second contactor CD2 receives comprises the solvent solution 740 (3) of release from the fractional load of the 3rd contactor CD3; The liquid flux that 3rd contactor CD3 receives comprises the solvent solution 740 (4) of release from the fractional load of the 4th contactor CD4; And the liquid flux that penultimate contact device CD (n-1) receives comprises the solvent solution 740 (n) of the fractional load from final contactor CDn.Therefore, with with the air-flow 730 (1) of desulfurization gradually, 730 (2), 730 (3) ... the process direction that 730 (n-1) are contrary, the solvent solution of fractional load is introduced into contactor CD1, CD2, CD3 ... CDn.
Last separation contactor CDn also receives liquid flux.This liquid flux is the solvent stream 760 of regeneration.The solvent stream 760 of regeneration is very poor.
The chemical solvent system 705B of Fig. 7 B is intended to be illustrative.Can use and adopt multiple and flow contact device other layout as this system of absorber.The example of other system this in United States serial 61/105 cited above, the CO in 343 2describe in the context removed.The appropriate section of Fig. 2 B and description is also incorporated to by reference at this.
In the system 705B of Fig. 7 B, solvent solution 740 (1) and 740 (2) regenerates.The solvent 780 of partial regeneration from regeneration container 750 out.By booster pump 782, solvent 780 is placed under stress.From there, in heat exchanger 784, cool solvent 780 to become solvent stream 720.Be introduced into first and flow contactor CD1 as solvent stream 720 before solvent 780 by booster pump 724 by further supercharging.
Referring again to Fig. 6, light gas stream 678 (it is also the pipeline 678 in Fig. 7 A and the pipeline 730 (n) in Fig. 7 B) leaves solvent system 605, by dehydrator, and by cooler 626.Cooler 626 cools the temperature of light gas stream 678 to about-30 ℉ to-40 ℉.Cooler 626 can be such as ethene or propane refrigerator.
Preferably, light gas stream 678 is next mobile by expansion gear 628.Expansion gear 628 can be such as joule-Tang Pusen (" J-T ") valve.Expansion gear 628 is used as quencher to obtain the further cooling to light gas stream 678.Expansion gear 628 reduces the temperature of light gas stream 678 further to such as about-70 ℉ to-80 ℉.Preferably, at least part of liquefaction of air-flow 678 is also realized.Cooling acid flow is indicated at pipeline 611.
Cooling acid gas in pipeline 611 enters low temperature distillation tower 100.Low temperature distillation tower 100 can be that operation is to pass through to freeze CO wittingly 2the process of particle distills any tower of methane from sour gas.Low temperature distillation tower can be the CFZ of such as Fig. 1 tMtower 100.The cooling acid gas of pipeline 611 enters the tower under about 500 to 600psig.
As just Fig. 1 explains, sour gas is removed from destilling tower 100 as liquefaction sour gas tower bottom flow 642.In this case, sour gas tower bottom flow 642 mainly comprises carbon dioxide.Sour gas tower bottom flow 642 comprises considerably less hydrogen sulfide or other sulfur component, to catch and as dense H because it removes system (it is solvent system 605) by sulfur component 2s stream 655 conveying is to process further.Sulfur recovery unit (not shown) can be used H 2s changes elementary sulfur into.Sulfur recovery unit can be so-called Claus method.This can realize more effective sulfur recovery for a large amount of sulphur.
At least part of tower bottom flow 642 is sent by reboiler 643.From there, the fluid containing methane is guided to return tower 100 as air-flow 644 again.The carbonated residual fluid of main bag passes through CO 2pipeline 646 discharges.CO in pipeline 646 2it is liquid form.By booster 648 and then preferably, the carbon dioxide in pipeline 646 injects (AGI) wells by one or more sour gas that such as frame 649 represents and is injected into subsurface formations.
Methane discharges from destilling tower 100 as tower top methane stream 112.Preferably, tower top methane stream 112 is by containing the carbon dioxide being not more than about 2mol.%.Under this percentage, tower top methane stream 112 can be used as fuel gas or can be used as natural gas sales to some market.But, according to some method herein, it is desirable that, tower top methane stream 112 experiences further process.More specifically, tower top methane stream 112 passes through open-loop refrigeration system.
First, tower top methane stream 112 is by cross exchanger 113.Cross exchanger 113 is for the pre-cooled liquid reflux stream 18 by being introduced into low temperature distillation tower 100 after expansion gear 19 expansion again.Next tower top methane stream 112 is delivered to compressor 114 to increase its pressure.
Next, pressurization methane stream 112 is made to cool.This is by such as completing methane stream 112 by gas cooler 115.To cool and the methane stream 16 of pressurizeing is produced.Preferably, liquefied methane stream 16 is to produce commercial product.
The part leaving cooler 115 is cooled and the methane stream 116 of pressurizeing be split into backflow stream 18.Backflow stream 18 cools further in heating heat exchanger 113, then expands by expansion gear 19 the chilling spray stream 21 finally producing Fig. 1.Chilling spray stream 21 enters destilling tower 100, and wherein it is used as cooling liquid spray.This liquid spray or backflow reduce the temperature in control freezing district (with 108 of Fig. 1 displays) and help to freeze out CO from dehydrated gas stream 624 as above 2with other sour gas particle.
To understand, Fig. 6 illustrates the rough schematic view of the selection aspect being intended to only clearly show gas handling system 600.Gas handling system will generally include other assemblies many such as heater, cooler, condenser, liquid pump, gas compressor, air blast, other type and be separated and/or fractionation apparatus, valve, switch, controller, together with pressure, temperature, liquid level, flow measurement device.
There is provided herein other method removing sulfur component from flow of feed gas.A kind of this method belongs to " redox " method.Term " redox " represents reduction-oxidation reaction.Redox describes its Atom and makes their oxidation number or the chemical reaction of oxidation state change.In this oxidation-reduction process, the metal of oxidation is as chelated iron and H 2s directly reacts with forming element sulphur.
The metal of oxidation is the metal chelate catalyst aqueous solution.In operation, the air-flow containing hydrogen sulfide contacts with metal chelate catalyst, realizes absorbing.There is Oxidation of Hydrogen Sulfide subsequently and be elementary sulfur and simultaneously metallic reducing is comparatively low-oxidation-state.Then make burning be back to higher oxidation state to carry out recovered catalyst solution, to reuse by catalyst solution is contacted with oxygen-containing gas.
Fig. 8 is that display is for removing the schematic diagram of the gas processing device 800 of sour gas from flow of feed gas.In this is arranged, remove system 650 upstream by oxidation-reduction process at sour gas and remove hydrogen sulfide from flow of feed gas.Oxidation-reduction process, based on water, this means that the dehydration of flow of feed gas need not at H 2carry out before S removal step starts.
Fig. 8 shows the gas processing device 800 receiving extraction air-flow 812.Extraction air-flow 812 comes from the hydrocarbon occurred in reservoir exploitation district or " oil field " 810 and to gather activity.Should be appreciated that oil field 810 can represent any position producing gaseous hydrocarbon.Hydrocarbon will comprise methane and hydrogen sulfide.Hydrocarbon also can comprise ethane and carbon dioxide.
In gas processing device 800, air-flow 812 is fed to sulfur component and removes system 850.Sulfur component is removed system 850 and is utilized oxidation-reduction process.Sulfur component is removed system 850 and is first comprised contactor 820.Contactor 820 limits the room 825 received from the original hydrocarbon gas in oil field 810.After entering inside, room 825, carry out the chemical reaction isolating hydrogen sulfide and other sulfur component from flow of feed gas 812.
In order to produce this chemical reaction, room 820 also receives the oxidized metal of chelating.The example of this oxidized metal is chelated iron.Chelated iron is the form of metal-chelating agent solution.Metal-chelator is delivered to room 825 by pipeline 842.
After entering inside, room 825, the hydrogen sulfide in metal chelate solution and flow of feed gas 812 reacts.Reduction-oxidation reaction occurs.As a result, chelating reducing metal mixture is released by tower bottom tube line 822 together with elementary sulfur.Meanwhile, gas is overflowed by overhead line 824.Fundamental reaction is S --+ 2Fe +++→ S 0+ 2Fe ++.
Gas in pipeline 824 mainly comprises methane and carbon dioxide.Traces of ethane, nitrogen or other component also can be present in pipeline 824.Jointly, the gas in pipeline 824 represents acid gas.
Illustrative sulfur component is removed system 850 and is also comprised oxidator 830.Oxidator 830 is defined for the room 835 of redox metal mixture.Oxidator 830 receives the metal mixture of reduction by pipeline 822.The pressure of the metal mixture in pipeline 822 is controlled by valve 828.
Oxidator 830 also admission of air.By pipeline 834, air is introduced into oxidator 830.Increase pressure in pipeline 834 by air blast 838 and run through room 835 in oxidator 830 to make air.After entering inside, room 835, air contact chelated mineral mixture, causes the metal mixture of reduction oxidized.By discharge pipe 836, air is discharged from oxidator 830.
Oxidation reaction produces oxidation chelated mineral mixture.The sulphur of chelate mix also containing colloidal form.The chelate mix with sulphur is left from oxidator 830 by pipeline 832.
Illustrative sulfur component is removed system 850 and is also comprised separator 840.The separator 840 of Fig. 8 is shown as centrifuge.But, other type of separator can be adopted.The water-based chelant mix with sulphur is separated into two kinds of components by centrifuge 840.A kind of component is elementary sulfur.Elementary sulfur is removed continuously, as having highly purified solid product from this process.Preferably, owing to having the blocking of the equipment of sulikol, contact process is limited to lower pressure (300psig or less).Can storage element sulphur, or sell more preferably as commercial product.
Elementary sulfur is discharged at pipeline 844.Preferably, sulphur is directed to sulphuring treatment unit (not shown).Which leaves the metal-chelator aqueous solution that there is no elementary sulfur.
The metallic catalyst aqueous solution in removal system 850 is the chelated iron of regeneration.Chelated iron is guided by pipeline 842 to be back to contactor 820 again.Pump 844 can be provided with the pressure increased in pipeline 842 and transport chelant mix to contacting container 825.Like this, renewable and reuse chelated iron (or other oxidized metal).
Again referring to gas line 824, the acid gas in gas line 824 is taken to dewatering container 860.Because oxidation-reduction process uses based on the material of water to be separated H from flow of feed gas 812 2s, needed gas dewatering in pipeline 824 subsequently before low temperature acid gas is removed.Because the acid gas from gas line 824 is by dewatering container 860, create current 862.Current 862 can deliver to water treatment facilities.Alternatively, current 862 can reinject to subsurface formations, as the subsurface formations 630 of Fig. 6.Still alternatively, the current 862 of removing can be processed to meet environmental standard and to be then released into local basin (not shown) as processed water.
Equally, because the acid gas of pipeline 824 is by dewatering container 860, abundant dehydrated gas stream 864 is produced.Dehydrated gas stream 864 comprises methane, and also can comprise trace nitrogen, helium and other inert gas.With regard to native system and method, dehydrated gas stream 864 also comprises carbon dioxide.
Dehydrated gas stream 864 leaves dewatering container 860 and by cooler 626.Cooler 626 cooled dehydrated air-flow 864 is to the temperature of about-30 ℉ to-40 ℉.Cooler 626 can be such as ethene or propane refrigerator.Thus produce cooling light gas stream 678.
Preferably, light gas stream 678 is next mobile by expansion gear 628.Expansion gear 628 can be such as joule-Tang Pusen (" J-T ") valve.The work of expansion gear 628 quenchers is in order to obtain the further cooling to light gas stream 678.Expansion gear 628 reduces the temperature of light gas stream 678 further to such as about-70 ℉ to-80 ℉.Preferably, at least part of liquefaction of gas flow 678 is also realized.Cooling acid flow indicates with pipeline 611.
Cooling acid gas in pipeline 611 is directed to destilling tower.Such as, destilling tower can be the CFZ tower 100 of Fig. 1 and 6.Then the acid gas in system processing pipeline 611 is removed by sour gas.Sour gas removes system such as can remove system 650 according to the sour gas of Fig. 6.
The other method removing sulfur component from flow of feed gas is by the scavenger in use scavenger bed.In gas processing industry, being used as of known scavengers removes H from air-flow 2the method of S and mercaptan.Scavenger can be solid, and they can be liquid forms, or they can be catalyst solutions.
Mercapto compound and other sulfur-containing compound are converted into harmless compounds as metal sulfide by scavenger.Can safely and process compound in the mode of environmental protection (environmentallysoundmanner).As the H in flow of feed gas 2when low the so that conventional amine process of S component is infeasible economically, scavenger has special effectiveness.An example is H 2s component is less than about 300ppm.
The example of known liquid-type scavenger is triazine.Example is 1 more specifically, and the water of 3,5 three-(2-ethoxy)-six hydrogen-S-triazine becomes preparation.Another example of liquid-type scavenger is nitrite solution.
The example of solid scavenger is iron oxide (FeO, Fe 20 3or Fe 3o 4) and zinc oxide (ZnO).Solid scavenger is normally non-renewable.After non-renewable scavenger bed loses usefulness, must replace.Iron oxide needs some moisture to come into force usually, and zinc oxide does not need.Therefore, if acid flow dewaters, the use of ZnO will be favourable, because at CO 2remove process upstream and not necessarily need other dehydration.But water can produce from oxidizing process.Therefore, H is depended on 2the initial level of S, may need subsequent dewatering.
The most commonly, by the one application hydrogen sulfide scavenger in three kinds of methods.First, the batch applications of alveolar fluid clearance agent can be used for spray tower contactor.Secondly, the batch applications of solid scavenger can be applicable to fixed bed contactor.3rd, alveolar fluid clearance agent can be adopted directly to be injected into container continuously.This is prevailing application.
Conventional directly injects H 2s removes and uses pipeline as contactor.In this applications, liquid H 2s scavenger such as triazine is injected into air-flow.By H 2s absorbs to removing in solution.Make H 2s reaction is removed and the accessory substance abandoned subsequently to be formed from flow of feed gas.H 2an optional method of the direct injection that S removes relates under high pressure forces the Liquid inject of scavenger to pass through aperture.Usually, atomizer is used to be atomized as very little drop to make alveolar fluid clearance agent.For many application, direct method for implanting has the potential of minimum totle drilling cost, because low relative to its capital cost of batch applications.
Fig. 9 shows in one embodiment according to the schematic diagram removing the gas processing device 900 of sour gas from air-flow of the present invention.In this is arranged, remove system 950 upstream by scavenger at sour gas and remove hydrogen sulfide from flow of feed gas 912.
Fig. 9 shows the gas processing device 900 receiving extraction air-flow 912.Extraction air-flow 912 comes from the hydrocarbon occurred in reservoir exploitation district or " oil field " 910 and to gather activity.Should be appreciated that oil field 910 can represent any position producing gaseous hydrocarbon.Hydrocarbon will comprise methane and hydrogen sulfide.Hydrocarbon also can comprise ethane and carbon dioxide.
In gas processing device 900, extraction air-flow 912 is fed to sulfur component and removes system 950.Sulfur component is removed system 950 and is used H 2s scavenger.Any one of above-mentioned sweep-out method can be adopted.Illustrative sulfur component is removed system 950 and is used the third method above-mentioned, and namely alveolar fluid clearance agent is injected into separation container 920 continuously.
In order to remove sulfur component from flow of feed gas 912, flow of feed gas 912 is directed to pipeline 922.Meanwhile, alveolar fluid clearance agent such as triazine is introduced into pipeline 922 by scavenger pipeline 944.Triazine is injected by atomizer 923, and then mixes with the flow of feed gas 912 in static mixer 925.From there, the flow of feed gas 912 of contact enters separation container 920.
Separation container 920 delimit chamber 926.Liquid enters the bottom of room 926, and gaseous component leaves at the top of room 926 simultaneously.Liquid is discharged by liquid line 927.Liquid comprises spent scavenger material.Partially liq from pipeline 927 is removed as efflux refuse.Efflux refuse guides to by waste line 942 preserves groove (not shown) or other refuse storage area.Refuse leaves by truck or by processing pipeline transport.If scavenger does not lose usefulness completely, the residual fraction from the liquid of pipeline 927 can be guided to be back to scavenger pipeline 944 to contact flow of feed gas 912 again.
Sulfur component is removed system 950 and is also comprised scavenger container 930.Liquid scavenger preserved by scavenger container 930.As needs, the alveolar fluid clearance agent of scavenger container 930 is passed into scavenger pipeline 944 by operator.There is provided pump 946 to increase the pressure for alveolar fluid clearance agent being injected into pipeline 922.
Again referring to separation container 920, separation container 920 can comprise demister (misteliminator) 924.Demister 924 helps prevent liquid particles along with overflowing at the top of gaseous component by separation container 920.This phenomenon is called carries secretly.Demister 924 is similar to net or film, and it forms the crooked route of steam when steam upwards runs in separation container 920.Demister is known.A source of demister is the SeparationProducts company of Texas Alfven.It is Amistco that SeparationProducts company manufactures trade name tMdemister.
Gaseous component leaves separation container 920 by overhead gas pipeline 945.Gaseous component is mainly methane and carbon dioxide.Also the ethane of trace constituent, nitrogen, helium and aromatic compound can be there is.Gas in pipeline 945 can be described as acid gas.Acid gas in gas line 945 is brought to dewatering container 960.
Because scavenger method uses based on the material of water to be separated H from flow of feed gas 912 2s, needed the gas dewatering in pipeline 945 before low-temperature carbon dioxide is removed.Due to the acid gas in gas line 945 is passed through dewatering container 960, produce current 962.Current 962 can be sent to water treatment facilities.Alternatively, current 962 can be injected again to subsurface formations, as the subsurface formations 630 of Fig. 6.Still alternatively, the current 962 of removing can be processed to meet environmental standard and to be then released into local basin (not shown) as processed water.
Equally, because the acid gas in pipeline 945 is by dewatering container 960, produce the air-flow 964 of basic dehydration.Dehydrated gas stream 964 is by cooler 626.Cooler 626 cooled dehydrated air-flow 964 is to the temperature of about-30 ℉ to-40 ℉.Cooler 626 can be such as ethene or propane refrigerator.Thus produce the light gas stream 678 of cooling.
Preferably, light gas stream 678 is next mobile by expansion gear 628.Expansion gear 628 can be such as joule-Tang Pusen (" J-T ") valve.The work of expansion gear 628 quenchers is in order to obtain the further cooling to light gas stream 678.Expansion gear 628 reduces the temperature of light gas stream 678 further to such as about-70 ℉ to-80 ℉.Preferably, at least part of liquefaction of air-flow 678 is also realized.Cooling acid flow indicates with pipeline 611.
Cooling acid gas in pipeline 611 guides to destilling tower.Such as, destilling tower can be the CFZ tower 100 of Fig. 1 and 6.Then system is removed by sour gas, process cooling blast.Sour gas removes system such as can remove system 650 according to the sour gas of Fig. 6.
Other method for removing the organosulfur compound with sulfydryl (--SH) in this paper is the method by being called CrystaSulf method.CrystaSulf method is developed by the CrystaTech company of Austin, TX.CrystaSulf method utilizes the liquid-phase claus reaction method improved to remove H from flow of feed gas 2s.
" Claus method " is the method reclaiming elementary sulfur from gas stream containing hydrogen sulphide sometimes by natural gas and rendering industry use.In brief, the Claus method producing elementary sulfur comprises two major sections.First paragraph is hot arc, wherein at about 1,800 ℉ to 2, and combustion parts H under 200 ℉ 2s is SO 2, and the SO formed 2with residual H 2s reaction produces elementary sulfur.Catalyst is there is not at hot arc.Second segment is catalytic section, wherein on the catalyst be applicable to, produces elementary sulfur at (as aluminium oxide) temperature between 400 ℉ to 650 ℉.The reaction producing elementary sulfur is balanced reaction; Therefore, carrying out being separated to improve H 2s has several sections to the Claus method of the total conversion of elementary sulfur.Each section relates to heating, reaction, cooling and is separated.
Term " CrystaSulf " not only refers to method, and refers to for the solvent in this process.CrystaSulf be the non-water physical solvent of dissolved hydrogen sulfide and sulfur dioxide, can directly react for elementary sulfur to make them.CrystaSulf solvent is sometimes referred to as liquid (liquor) or eccysis liquid (scrubbingliquor).In CrystaSulf method, use non-washing to remove liquid and remove hydrogen sulfide from air-flow.Eccysis liquid can be that the organic solvent of elementary sulfur is as phenyl xylyl ethane.Normally, nonaqueous solvents can be selected from the naphthalene that alkyl replaces; Diaryl alkane; Comprise phenyl xylyl ethane, as phenyl-ortho-xylene base ethane, phenyltoluene base ethane, phenyl napthyl ethane, phenylaryl alkane, benzyl ether, diphenyl ether; Partially hydrogenated terphenyl, partially hydrogenated diphenylethane, partially hydrogenated naphthalene; And their mixture.
Usually, CrystaSulf solvent adopts SO 2as oxidant.This makes claus reaction (2H 2s+SO 2->3S+2H 2o) in solvent middle generation mutually.In other words, sulfur dioxide is added into solvent solution to obtain better H 2s removes.
At United States Patent (USP) 6,416, describe CrystaSulf method in 729.Should ' 729 patent names be " method (ProcessforRemovingHydrogenSulfidefromGasStreamsWhichIncl udeorareSupplementedwithSulfurDioxide) removing hydrogen sulfide from the air-flow comprised or be supplemented with sulfur dioxide ".Should ' 729 patents be incorporated to by reference of text at this.At United States Patent (USP) 6,818, other embodiment of CrystaSulf method is disclosed in 194, its name is called " by with non-water absorbent eccysis; remove the method (ProcessforRemovingHydrogenSulfideFromGasStreamsWhichIncl udeorAreSupplementedwithSulfurDioxide, byScrubbingwithaNonaqueousSorbent) of hydrogen sulfide from the air-flow comprised or be supplemented with sulfur dioxide ".Should ' 194 patents also be incorporated to by reference at this.
Figure 10 is the schematic diagram showing the gas processing device 1000 removing sour gas in another embodiment from air-flow.In this is arranged, remove system 650 upstream by CrystaSulf method at sour gas and remove hydrogen sulfide from flow of feed gas 1012.CrystaSulf process is a part for the sulfur component removal system 1050 for removing hydrogen sulfide.
Figure 10 shows the gas processing device 1000 receiving extraction air-flow 1012.Extraction air-flow 1012 comes from the hydrocarbon occurring in reservoir exploitation district or " oil field " 1010 and to gather activity.Oil field 1010 and above-mentioned oil field 810 and 910 synonym.Hydrocarbon produces from oil field 1010.Hydrocarbon will comprise methane and hydrogen sulfide.Hydrocarbon also can comprise ethane and carbon dioxide.
In gas processing device 1000, extraction air-flow 1012 is fed to sulfur component and removes system 1050.Sulfur component is removed system 1050 and is utilized above-mentioned CrystaSulf method.In order to remove sulfur component according to CrystaSulf method from flow of feed gas 1012, flow of feed gas 1012 is directed to absorber 1020.Meanwhile, liquid SO 2absorber 1020 is introduced into by pipeline 1084.Add liquefaction sulfur dioxide as oxidizing gas.
Liquid SO 2be kept at first in reservoir vessel 1080.As needs, SO 2pipeline 1082 is by the liquid SO from reservoir vessel 1080 2be delivered to pipeline 1084.There is provided pump 1076 for increasing pressure so that by liquid SO along pipeline 1082 2move to absorber 1020.
Absorber 1020 delimit chamber 1025.In absorber 1020, flow of feed gas 1012 with from pipeline 1084 containing SO 2liquid flux contact.Liquid sinks to the bottom of room 1025, and gaseous component leaves at the top of room 1025 simultaneously.Be called that the liquid of absorbent is left by liquid line 1022.Absorbent generally include sulphur and water solution, together with the methane of trace constituent and remaining hydrogen sulfide and/or sulfur dioxide.
Guide liquid to bottle 1030 by pipeline 1022.Bottle 1030 is for from solvent flashing water outlet and any hydrocarbon gas carried secretly.Sulphur-containing solution leaves bottle by tower bottom flow 1036.Meanwhile, the hydrocarbon gas and trace water steam leave overhead line 1032.
Overhead line 1032 is conducted through compressor 1034.The pressure increasing overhead line 1032 helps water to leave the hydrocarbon gas.Then the hydrocarbon gas is guided to separation container 1040.Usually, separation container 1040 is gravity separators, although also can use cyclone hydraulic separators or Vortistep separator.Water leaves separation container 1040 at pipeline 1044.Preferably, the water in pipeline 1044 guides to treatment facility (not shown).
The hydrocarbon gas is discharged from separation container 1040 by pipeline 1042.The hydrocarbon gas in pipeline 1042 and flow of feed gas 1012 merge.From there, the hydrocarbon gas enters absorber 1020 again.
Again referring to bottle 1030, note, bottle discharges sulphur-containing solution by tower bottom flow 1036.Sulphur-containing solution moves into cooling circuit 1038.Sulphur-containing solution merges with the part clarified solution from pipeline 1058.Clarified solution can comprise such as other physical solvent.
When sulphur-containing solution moves the pressure by increasing during centrifugal pump 1052 in cooling circuit 1038.From there, in PTFE heat exchanger 1054, cool sulphur-containing solution.When sulphur-containing solution is by heat exchanger 1054, below the saturation temperature that it is cooled to the sulphur of dissolving.Sulphur-containing solution becomes supersaturation, therefore crystallization for the sulphur dissolved.
The sulphur-containing solution cooling also crystallization enters crystallizer 1055.Particularly, the bottom of crystallizer 1055 is directed into from the sulphur-containing solution of pipeline 1038.Sulphur-containing solution and the sulphur crystal contact in the decanting zone 1059 be present in crystallizer 1055 of cooling.Crystal rises to the work of supersaturation sulphur solution inoculum in order to realize the precipitation of the sulphur dissolved.This forms sulphur slurry.
Sulphur slurry leaves crystallizer 1055 by sulphur slurry pipeline 1056.Sulphur slurry in pipeline 1056 is delivered to filter 1060.Sulphur slurry is separated into pure solid-state sulphur and clarified solution by filter 1060.The removal of solid-state sulphur is represented by pipeline 1062.Clarified solution is discharged as filtrate by pipeline 1064 and is recycled and is back to crystallizer 1055.Preferably, pump 1066 is provided to be back to crystallizer 1055 for mobile clarified solution.
Clarified solution rises to the top of crystallizer.Part clarified solution is derived from crystallizer 1055 by pipeline 1058.The clarified solution of pipeline 1058 merges to form cooling circuit 1038 with the sulphur solution 1036 from bottle, as discussed above.Extracted the separate section of clarified solution from the top of crystallizer 1055 by pipeline 1072.The extract of pipeline 1072 is heated by heat exchanger 1074.The liquid of heat and the sulfur dioxide of pipeline 1082 merge.Obtained the liquid 1074 of heat by booster pump 1076, and and then guide to the room 1025 of absorber 1020.
Should be appreciated that the CrystaSulf method described in conjunction with sulfur component removal system 1000 is only illustrative.Can use as at the United States Patent (USP) 6,416,729 be incorporated to and United States Patent (USP) 6,818, those other CrystaSulf methods described in 194.Regardless of method, from absorber 1020, produce overhead gas stream 1045.
Overhead gas stream 1045 is mainly containing methane and carbon dioxide.Also the ethane of trace constituent, nitrogen, helium and aromatic compounds can be there is.Sulfur component has been extracted and has been transported by pipeline 1062 and left.Overhead gas stream 1045 can be called as acid gas.Preferably, the acid gas in air-flow 1045 brings to dewatering container 1060.But, because CrystaSulf method is non-water, can enters before sulfur component removes system 1050 in flow of feed gas 1012 and dewater.
Overhead gas stream 1045 is by cooler 626.Air-flow 1045 is cooled to the temperature of approximately-30 ℉ to-40 ℉ by cooler 626.Cooler 626 can be such as ethene or propane refrigerator.Thus, produce the light gas stream 678 of cooling.
Preferably, light gas stream 678 is next mobile by expansion gear 628.Expansion gear 628 can be other device that such as joule-Tang Pusen (" J-T ") valve or composition graphs 6 describe.Expansion gear 628 reduces the temperature of light gas stream 678 further to such as about-70 ℉ to-80 ℉.Preferably, at least part of liquefaction of air-flow 678 is also realized.Cooling blast is moved by pipeline 611.
Cooling acid gas in pipeline 611 is directed to destilling tower.Such as, destilling tower can be the CFZ tower 100 of Fig. 1 and 6.Then system is removed by sour gas, the cooling acid gas of processing pipeline 611.Sour gas removes system can such as according to the sour gas removal system 650 for removing carbon dioxide of Fig. 6.
Be used in the use that two kinds of other methods removing the hydrogen sulfide of at least appropriate level in low temperature distillation tower upstream relate to adsorbent bed.One method adopts Temp .-changing adsorption, and another kind utilizes pressure-variable adsorption.Adsorbent bed is molecular sieve.In each case, described molecular sieve is regenerated.
Molecular sieve, usually for dehydration, also can be used for removing H 2s and mercaptan.Usually, in conjunction with these operations in single packed bed, this single packed bed has the layer of 4A molecular screen material at top, for dehydration, and has the layer of 13X molecular screen material in bottom, for removing H 2s and mercaptan.Thus, flow of feed gas not only dried but also desulfurization.
Figure 11 presents the schematic diagram of the gas processing device 1100 removing sour gas in another embodiment from air-flow.In this is arranged, by temperature swing adsorption system 1150 from the hydrogen sulfide sour gas removal system 650 upstream removal flow of feed gas 624.
Gas processing device 1100 operates according to the gas processing device 600 of Fig. 6 substantially.In this respect, dehydrated gas stream 624 is delivered to sulfur component and removes system.From there, the acid gas mainly comprising methane and carbon dioxide is cooled and is transported to sour gas by pipeline 611 and removes system 650.But, replace using solvent system 605 to remove system together with absorber as sulfur component, use temperature swing adsorption system 1150.Temperature swing adsorption system 1150 provides at least part of separate hydrogen sulfide from dehydrated gas stream 624.
Temperature swing adsorption system 1150 uses adsorbent bed 1110 with optionally adsorption of hydrogen sulfide and other sulfur component, makes the light gas containing methane and carbon dioxide flow through simultaneously.Show light gas stream at pipeline 1112 to be released.Light gas stream 1112 is delivered to destilling tower if the tower 100 of Fig. 1 is with by carbon dioxide and methane separation as acid flow.
Preferably before entering low temperature distillation tower 100, provide pre-cooled to light gas stream 1112.In illustrative gas processing device 1100, then light gas stream 1112 by refrigerating plant 626, and pass through expansion gear 628.Expansion gear 628 can be such as joule-Tang Pusen (" J-T ") valve.Preferably, at least part of liquefaction of light gas stream 1112 is realized together with cooling.Create cooling acid flow, it guides to sour gas by pipeline 611 and removes system 650.
Again referring to temperature swing adsorption system 1150, preferably, the adsorbent bed 1110 in temperature swing adsorption system 1150 is the molecular sieves manufactured by zeolite.But, other adsorbent bed can be adopted as the bed manufactured by silica gel.The those of ordinary skill of hydrocarbon gas separation field will be understood, and the selection of adsorbent bed is generally depended on the composition of the pollutant be removed.In this situation, pollutant is hydrogen sulfide mainly.
In operation, adsorbent bed 1110 will be placed in compression chamber.Adsorbent bed 1110 receives dehydrated gas stream 624 adsorption of hydrogen sulfide and other sulfur component together with a certain amount of carbon dioxide.Basic H is become at bed 2after S is saturated, the adsorbent bed 1110 in adsorption system 1150 will be replaced by Regenerative beds.Owing to using dry this bed of heated gas heats, H 2s will discharge from bed 1110.The gas be applicable to comprises a part for tower top methane stream 112, the nitrogen of heating or the obtainable fuel gas of alternate manner.
Frame 1140 describes the regeneration room of adsorbent bed.Regeneration room 1140 receives dry heated air 1132.In the layout of Figure 11, receive dry gas 1132 from tower top methane stream 112.Tower top methane stream 112 mainly comprises methane, but also can comprise trace nitrogen and helium.Compressible tower top methane stream 112 is to raise the gas pressure in regeneration room.At 1130 display boosters.But the temperature regenerated mainly through raising occurs, although it is strengthened by lower pressure usually.
The tower top methane stream 112 of 10 to 15 percentages can need to be used for regenerating fully.Regeneration room 1140 discharges the drying fluid stream 1142 of heating.Drying fluid stream 1142 is directed to solid adsorbent bed 1110 and plays recovery stream.Dry fluid stream 1142 mainly comprises methane, but also comprises some CO 2.
For alternating temperature regeneration cycle, preferably adopt at least three adsorbent beds: first for absorption, as in 1110 displays; Second regenerates in regeneration room 1140; Be reproduced with the 3rd and for subsequent use with when first 1110 become abundant saturated time in adsorption system 1150 use.Therefore, in order to more effective operation, minimum three beds of parallel use.These beds can such as with silicone filler.
As shown in Figure 11, from adsorption system 1110, dense H is discharged by pipeline 1114 2s air-flow.Dense hydrogen sulfide stream 1114 also plays recovery stream.Recovery stream 1114 mainly comprises CH 4and H 2s, but probably also comprise traces of carbon dioxide and some possible heavy hydrocarbons.On the one hand, refrigerating plant 1116 is used to cool recovery stream 1114.This causes at least part of liquefaction of recovery stream 1114.Then recovery stream 1114 is introduced separator 1120.Preferably, separator 1120 is gravity separators, and the water in recovery stream 1114 is separated with light gas by it.Light gas comprises methane, hydrogen sulfide and carbon dioxide usually.
Light gas discharges (schematically showing at pipeline 1122) from the top of separator 1120.Light gas from the pipeline 1122 that separator 1120 discharges is back to dehydrated gas stream 624.Meanwhile, water, heavy hydrocarbon (being mainly ethane) and dissolve hydrogen sulfide discharge (schematically showing at pipeline 1124) from the bottom of separator 1120.In some perform, the recyclegas in pipeline 1122 may need to process H 2s is to guarantee that it does not pass through system recirculates.
Note, optionally, gas processing device 1100 can not comprise dewatering unit 620.Water will leave solid adsorbent bed 1110 and will not transfer to the acid flow of pipeline 611 together with recovery stream 1114.Water leaves separator 1120 further by together with the hydrogen sulfide of pipeline 1124.Then by using such as sewage stripping device or other separator (not shown) to complete being separated of water and sulfur-containing compound.
In one application, incendivity from the waste gas of regeneration gas heaters 1140 to drive turbine (not shown).Turbine can drive again open loop compressor (compressor 176 as Fig. 1).Regeneration gas heaters 1140, by obtaining used heat from this turbine and using it to preheat regeneration gas (as in pipeline 1132) for heavy hydrocarbon removal process, removes process further combined with to sour gas.Similarly, the heat from tower top compressor 114 can be used for preheating the regeneration gas for hydrogen sulfide removal process.
Can be observed, regeneration gas contains from the H of Solid Bed 1110 desorb herein 2s.That gas can with solvent contacts to remove H 2s also reclaims methane and other hydrocarbon any.Like this, the BTU value of gas can be remedied.
Note, pressure-variable adsorption is also used in acid gas removal facility upstream and removes hydrogen sulfide and other sulfur component.Pressure-variable adsorption or " PSA " are often referred to the process be wherein adsorbed on by pollutant on solid adsorbent bed.After saturated, by reducing its pressure regenerated solids absorbent.Reducing pressure causes pollutant to be released as lowpressure stream.
Figure 12 provides the schematic diagram using pressure-variable adsorption to remove the gas processing device 1200 of hydrogen sulfide.Gas processing device 1200 operates according to the gas processing device 600 of Fig. 6 substantially.In this respect, cooled dehydrated air-flow 624 and then by acid gas pipeline 611 be delivered to sour gas remove system 650.But, replace using physical solvent contact system 605 to remove hydrogen sulfide together with contact tower 670, use pressure swing adsorption system 1250.Pressure swing adsorption system 1250 provides from flow of feed gas 624 separate hydrogen sulfide at least partly.
As temperature swing adsorption system 1150, pressure swing adsorption system 1250 uses adsorbent bed 1210 optionally to adsorb H 2s discharges methane gas simultaneously.Preferably, adsorbent bed 1210 is the molecular sieves manufactured by zeolite.But, other adsorbent bed can be adopted as the bed manufactured by silica gel.The selection again understanding adsorbent bed will be depended on the composition of flow of feed gas 624 by the those of ordinary skill of hydrocarbon gas separation field usually.
As shown in Figure 12, adsorption system 1250 discharges methane gas by light gas stream 1212.Before entering low temperature distillation tower 100, conveying light gas 1212 is by refrigerating plant 626 and then preferably by joule-Tang Pusen valve 628.Meanwhile, dense hydrogen sulfide stream is discharged by pipeline 1214 from adsorbent bed 1210.
In operation, the adsorbent bed 1210 in pressure swing adsorption system 1250 is present in compression chamber.Adsorbent bed 1210 receives dehydrated gas stream 624 and adsorbs H 2s and any residual water and any heavy hydrocarbon.Also adsorbable traces of carbon dioxide.Bed 1210 become with hydrogen sulfide and other sulfur component saturated after, adsorbent bed 1210 will be replaced.Owing to reducing the pressure in compression chamber, H 2s (and heavy hydrocarbon, if yes) will be released from bed.Then dense hydrogen sulfide stream 1214 is produced.
As a rule, the most hydrogen sulfide caused in dense hydrogen sulfide stream 1214 and other pollutant are discharged from adsorbent bed 1210 to environmental pressure by the Pressure Drop in compression chamber.But, in some extreme cases, by using vacuum chamber to apply the pressure extremely dense hydrogen sulfide stream 1214 lower than environment, help pressure swing adsorption system 1250.This indicates with frame 1220.Under power at low pressure exists, sulfur component and heavy hydrocarbon are by the solid matrix desorb from formation adsorbent bed 1210.
The mixture of water, heavy hydrocarbon and hydrogen sulfide will leave vacuum chamber 1220 by pipeline 1222.Mixture will enter separator 1230.The gravity separator that heavy hydrocarbon is preferably separated with hydrogen sulfide with water by separator 1230.From bottom releasing liquid component (schematically showing at pipeline 1234).At the H that process is dissolved 2after S, any heavy hydrocarbon in pipeline 1234 can be conveyed to commercial distribution.From the hydrogen sulfide (schematically showing at pipeline 1232) of the top release gaseous form of separator 1230.The H of pipeline 1232 2s is sent to sulfur recovery unit (not shown) or injects subsurface formations as a part for sour gas.
Pressure swing adsorption system 1250 can rely on multiple parallel bed.First 1210 for absorption.This is called as use bed.Second (not shown) is regenerated by decompression.3rd be reproduced and for subsequent use with when first 1210 become complete saturated time in adsorption system 1250 use.Therefore, in order to more effective operation, can walk abreast and use minimum three beds.These beds can such as with active carbon or molecular sieve filled.
Pressure swing adsorption system 1250 can be rapid cycle pressure swing adsorption systems.In so-called " Rapid Circulation " method, can lack circulation timei to several seconds.Because Rapid Circulation PSA (" RCPSA ") unit is very little relative to normal PSA device, therefore it is by advantageous particularly.Note, inlet gas may need pretreatment.Alternatively, the sacrifice layer of material can be used with prolection material at the top of packed bed.
On the one hand, the combination of alternating temperature regeneration and pressure swing regeneration can be used.
Another method at sour gas removal system upstream removal heavy hydrocarbon in this paper is the method being called as adsorption dynamics adsorption kinetics separation or AKS.AKS adopts the solid absorbent of relative New raxa, and it depends on some kind and is attracted to speed on structuring adsorbent relative to other kind.This is formed with the change adsorption method of wherein selective conventional balanced-control of giving mainly through the equilibrium adsorption performance of solid absorbent and contrasts.In the case of the latter, in adsorbent micropore or free volume, the competitive Adsorption thermoisopleth of lighter products is disadvantageous.
In the change adsorption method of dynamics Controlling, the selective diffusion mainly through adsorbent and the transport diffusion coefficient passed through in micropore are given.Adsorbent has " kinetic selectivity " for one or more gas components.As used herein, term " kinetic selectivity " is defined as two kinds of variety classeses, and one-component diffusion coefficient D is (with m 2/ sec count) ratio.These one-component diffusion coefficients are also referred to as Si Difen-Maxell transport diffusion coefficient, and it is measured for given pure gas component, given adsorbent.Therefore, such as, component A will equal D relative to the kinetic selectivity of the concrete adsorbent of B component a/ D b.The one-component diffusion coefficient of material is determined by the well-known test in sorbing material field.
The method for optimizing measuring dynamics diffusion coefficient is at " frequency modulating method (FrequencyModulationMethodsforDiffusionandAdsorptionMeasu rementsinPorousSolids) that in porosu solid, diffusion and absorption are measured " with people such as Reyes, the frequency response technology described in J.Phys.Chem.B.101, pp.614-622 (1997).In the separation of dynamics Controlling, preferably the first component (such as component A) is relative to kinetic selectivity (the i.e. D of the selected adsorbent of second component (such as B component) a/ D b) be greater than 5, be more preferably greater than 20, and be even more preferably greater than 50.
Preferred adsorbent is zeolitic material.The limiting examples with the zeolite in applicable aperture for removing heavy hydrocarbon comprises MFI zeolite, faujasite, MCM-41 zeolite and β zeolite.Preferably, be about 20 to about 1,000 for the zeolite Si/Al ratio removed in the inventive method embodiment of heavy hydrocarbon, preferably about 200 to about 1,000, to prevent excessively silting up (fouling) of adsorbent.Other technical information being separated hydrocarbon gas component about use adsorption dynamics adsorption kinetics is U.S. Patent Publication 2008/0282884, and its whole disclosure is incorporated to by reference at this.
Figure 13 is the schematic diagram showing gas processing device 1300 of the present invention in another embodiment.In this is arranged, remove at sour gas the adsorbent bed 1310 passing through to utilize absorption power to be separated in system 650 upstream and remove hydrogen sulfide from air-flow.
Gas processing device 1300 operates according to the gas processing device 600 of Fig. 6 substantially.In this respect, dehydrated gas stream 624 cools and is then delivered to sour gas by the acid flow in pipeline 611 and removes system 650 in preliminary refrigerating plant 625.But, replace removing system 650 upstream at sour gas and use physical solvent contact system 605 together with contact tower 670 to remove hydrogen sulfide, use AKS solid adsorbent bed 1310.Adsorbent bed 1310 Preferential adsorption hydrogen sulfide.
Be separated in application in current adsorption dynamics adsorption kinetics, 2 S component will be retained by adsorbent bed 1310.This means H 2s will reclaim at low pressures.Adsorbent bed 1310 can be used together with pressure-variable adsorption or Rapid Circulation pressure-variable adsorption.After pressure reduces, under low pressure natural gas liquids stream 1314 discharges from solid adsorbent bed.Natural gas liquids stream 1314 containing the most of sulfur component in dehydrated gas stream 624, and also can contain heavy hydrocarbon and traces of carbon dioxide.
In order to be separated with heavy hydrocarbon with carbon dioxide by hydrogen sulfide, need other distillation column.At 1320 display distil containers.Distil container 1320 can be the paving dish or the filled column that are such as used as pollutant scavenge system.Hydrogen sulfide and carbon dioxide is discharged by overhead line 1324.Preferably, pipeline 1324 and sour gas pipeline 646 merge that sour gas is injected into reservoir 1349.Acid heavy hydrocarbon and most of hydrone leave distil container 1320 by bottom line 1322.Heavy hydrocarbon can be the form of natural gas liquids, i.e. ethane and possible propane.Process natural gas liquids is to remove H 2s also catches to sell.
It should be noted that the adsorption dynamics adsorption kinetics separation method of system 1300 is for reclaiming hydrogen sulfide and heavy hydrocarbon may be more useful from the natural gas flow produced under large excess pressure.In this case, the acid gas of pipeline 611 has suitable pressure to be processed by low temperature distillation tower 100.The example of excess pressure can be the pressure being greater than 400psig.
Adsorbent bed 1310 discharges light gas stream 1312.Gas in stream 1312 forms primarily of methane and carbon dioxide.Preferably entering low temperature distillation tower 100 prerequisite for the light gas be cooled in stream 1312.In illustrative gas processing device 1300, then the light gas in stream 1312 by refrigerating plant 626, and passes through expansion gear 628.In pipeline 611, produce cooling acid flow, it is directed to sour gas and removes system 650.
For removing in another commonsense method of heavy hydrocarbon, from tower bottom flow 646, extract heavy hydrocarbon at destilling tower 100 " downstream ".In an example, absorption power separation method is adopted in low temperature distillation tower downstream.
Figure 14 presents the schematic diagram of the gas processing device 1400 adopting absorption power separation method.This gas processing device 1400 is substantially according to the gas processing device 1300 of Figure 13.But, when this substitutes in sour gas removal system 650 upstream use AKS solid adsorbent bed 1310, remove system 100 downstream at sour gas and use AKS solid adsorbent bed 1410.
Visible in fig. 14, from destilling tower 100, remove sour gas and hydrogen sulfide and carbon dioxide, as the acid gas stream 642 that liquefies at the bottom of tower.Optionally, this liquid stream 642 is by reboiler 643, and the gas containing trace amounts of methane at reboiler 643 place is guided as air-flow 644 to be back to tower 100 again.The main residual liquid containing sour gas is discharged by sour gas pipeline 646.
Sour gas from pipeline 646 is transported to AKS solid adsorbent bed 1410.When they are by bed 1410, sour gas is still cold and exists with liquid phase.Hydrogen sulfide and any heavy hydrocarbon are removed and are discharged by pipeline 1412 as natural gas liquids stream 1412 from sour gas.Meanwhile, sour gas to be discharged as acid gas stream at the bottom of tower 1414 by AKS solid adsorbent bed 1410.
Sour gas in acid gas stream 1414 at the bottom of tower still mainly liquid phase.Liquefaction sour gas mainly CO in pipeline 1414 2, and can be evaporated.Alternatively, the liquefaction sour gas of pipeline 1414 is injected into subsurface formations by one or more sour gas injection (AGI) well indicated as frame 649.In this case, the sour gas in pipeline 646 is preferably by booster 648.
It should be noted that natural gas liquids stream 1412 is containing heavy hydrocarbon and hydrogen sulfide and traces of carbon dioxide.Therefore, still-process is carried out to be separated H from natural gas liquids stream 1412 2s and CO 2.At 1420 display distil containers.H 2s and trace CO 2gas is discharged from distil container 1420 by overhead line 1424.Preferably, pipeline 1424 merges with acid gas stream 1414 at the bottom of tower, to inject sour gas to reservoir 649.Heavy hydrocarbon leaves container 1420 by bottom line 1422 and is captured to sell.
Figure 15 A is the schematic diagram of gas processing device of the present invention 1500 in another embodiment.In this is arranged, remove system 650 downstream by extractive distillation process at sour gas and remove hydrogen sulfide from air-flow.Extractive distillation process is represented by frame 1550.
This illustrative gas processing device 1500 is substantially according to the gas processing device 600 of Fig. 6.In this respect, dehydrated gas stream 624 is cooled and is then transported to sour gas by acid gas pipeline 611 and removes system 650.But, replace removing system 650 upstream at sour gas and use solvent contacts system 605 together with contact tower, remove system 650 downstream at sour gas and use extractive distillation process.
Visible in Figure 15 A, cooling acid gas by pipeline 611 and enter sour gas remove system 650.Cooling acid gas in pipeline 611 has the composition the same with dehydrated feed gas stream 624.Acid gas in pipeline 611 comprises methane and hydrogen sulfide and carbon dioxide.Also the nitrogen of ethane and trace constituent, helium and aromatic compound can be there is.
First acid gas in pipeline 611 enters post 100.This is identical with the CFZ tower 100 of 6 with Fig. 1.As discussed above, acid gas is separated into acid gas stream 642 at the bottom of tower top methane stream 112 and tower by CFZ tower 100.In this case, at the bottom of tower, acid gas stream 642 comprises carbon dioxide and hydrogen sulfide.
Optionally, tower bottom flow 642 sends by reboiler 643.From there, the fluid containing methane is guided as hydrocarbon stream 644 to be back to tower 100 again.The main residual fluid containing hydrogen sulfide and carbon dioxide is discharged by sour gas pipeline 646.Material in sour gas pipeline 646 is liquid form, and enters extractive distillation system 1550.
Figure 15 B is the detailed maps of the gas processing device 1550 for extractive distillation process.Sour gas is brought to extractive distillation equipment 1550 by visible pipeline 646.In the illustrative layout of Figure 15 B, show three extractive distillation posts 1510,1520 and 1530.But, be to be understood that the post that can adopt more than three.
Extractive distillation post 1510 is propane recovery posts.Propane recovery post 1510 is hydrocarbon mixture solvent and acid gas stream 646 in container.Temperature in first post 1510 is substantially-100 ℉ to 50 ℉.In propane recovery post 1510, solvent absorption hydrogen sulfide, makes solvent leave post 1510 as solvent column underflow 1514.It also will containing some carbon dioxide and heavy hydrocarbon.Meanwhile, the light hydrocarbon of carbon dioxide and trace leaves post 1510 by overhead streams 1554.Carbon dioxide in stream 1554 can inject pipeline 1552 with sour gas and be combined to be injected into subsurface formations (649 of Figure 15 A).
Solvent column underflow 1514 enters the second extractive distillation post 1520.Second extractive distillation post 1520 is CO 2remove post.CO 2the temperature removed in post 1520 is substantially 0 ℉ to 250 ℉, and it is higher than the temperature in propane recovery post 1510.At CO 2remove in post 1520, solvent and heavy hydrocarbon leave post 1520 as the second solvent column underflow 1524.Meanwhile, carbon dioxide leaves the second post 1520 as tower top CO 2stream 1552.Preferably, tower top CO 2stream 1552 is for improving oil recovery.
Most terminal cylinder 1530 shows in Figure 15 B.Most terminal cylinder 1530 is that additive reclaims post.Additive reclaims post 1530 and utilizes distillation principle from solvent, be separated the heavy hydrocarbon components being called " natural gas liquids ".Temperature in 3rd post 1530 is substantially 80 ℉ to 350 ℉, and it is higher than the temperature in the second post 1530.Natural gas liquids leaves post 1530 by pipeline 1532 and is taken to for removing any residual H 2s and CO 2processing unit.Such as, this processing unit can be wherein amine for removing H 2s/CO 2liquid-liquid extractor.
Solvent leaves additive as tower base solvent stream 1534 and reclaims post 1530.Tower base solvent stream 1534 represents the additive of regeneration.Most of tower base solvent stream 1534 is reintroduced into the first post 1510 for extractive distillation process.Optionally, flow automatically 1534 excessive solvent can be combined to be processed by pipeline 1536 with natural gas liquids stream 1532.
Again referring to Figure 15 A, preferably, the carbon dioxide in pipeline 1554 and the CO in pipeline 1552 2in conjunction with and by booster 648 and then inject (AGI) well by one or more sour gas represented as frame 649 and be injected into subsurface formations.
Visible, many methods can be used for removing sulfur component in conjunction with sour gas minimizing technology.Normally, the method for selection depends on the situation of original natural or pending gas.Such as, if H 2s concentration is less than about 0.1%, in conjunction with molecular sieve (molesieve) method may be best, in any case because need dehydration.Molecular sieve has removes some CO 2additional benefits, this can be beneficial to " impure (dirty) " start.
For 0.1% to 10%H about in inlet gas 2the situation of S, physical solvent is as Selexol tMit may be best selection.Solvent is dry is desirable, because it may be used for inlet gas to be dried to some levels.For CFZ process, gas can need to be dewatered further by (less) mol sieve unit.From the dense H of Selexol unit 2s stream can process in the sulfur recovery unit (SRU), or can be compressed and be combined with CFZ tower bottom flow and dispose for down-hole.
Should be appreciated that and in conjunction with any sour gas minimizing technology, just can not utilizing the method for " control freezing district " tower, applying the said method for removing hydrogen sulfide.Other low temperature distillation posts can be adopted.Further, other cryogenic distillation method can be used as overall fractionation.Overall fractionating column is similar to the CFZ tower 100 of Fig. 1, but does not have middle freezing zone.Overall fractionating column generally operates under the pressure higher than CFZ tower 100, as more than 700psig, thus avoids CO 2solid is formed.But tower top methane stream 112 can contain the CO of significant quantity 2.In arbitrary situation, when dehydrated gas stream 624 is containing the C being greater than about 3% 2or more heavy hydrocarbon time, utilize separation process remove hydrogen sulfide be expect.
Although invention as herein described is fully prepared to realize benefit proposed above and advantage significantly, will understand, the present invention can carry out when not departing from its spirit improving, change and changing.Provide the improvement using the sour gas in control freezing district to remove the operation of process.These improve to provide removes H in product gas 2s is to very low-level design.

Claims (9)

1. from acid flow, remove the system of sour gas, it comprises:
The sour gas receiving described acid flow removes system, described acid flow comprises the sulfur component being less than 10%, and wherein said sour gas is removed system utilization and described acid flow is separated into the main overhead gas stream containing methane and the main low temperature distillation tower containing the liquid column bottoms acid gas stream of carbon dioxide and sulfur component; And
The sulfur component that described sour gas removes system downstream removes system, wherein said sulfur component is removed liquid column bottoms acid gas stream described in system acceptance and described liquid column bottoms acid gas stream is separated into CO 2 fluid stream and hydrogen sulfide stream, and wherein said sulfur component removal system comprises at least one solid adsorbent bed, overall fractionating system, chemical solvent system, physical solvent system, oxidation-reduction system, scavenger system or the system for implementing CrystaSulf method.
2. system according to claim 1, wherein said sour gas removal system comprises the heat exchanger for cooling described acid flow before entering described low temperature distillation tower further.
3. system according to claim 2, wherein said low temperature distillation tower comprises:
Distillation zone, bottom and middle control freezing district, described middle control freezing district receives the main cooling liquid containing methane and sprays, and described low temperature distillation tower receives described acid flow and then described acid flow is separated into the main overhead gas stream and the liquid column bottoms acid gas stream that contain methane; And
The refrigeration plant in described low temperature distillation tower downstream, it is for cooling described overhead gas stream and returning a part for described overhead gas stream to described low temperature distillation tower, as liquid backflow.
4. system according to claim 1, wherein said sulfur component is removed system and is comprised:
At least one solid adsorbent bed of remarkable absorbing hydrogen sulphide from described liquid column bottoms acid gas stream, when regenerating at least one solid adsorbent bed described, described hydrogen sulfide is released as described hydrogen sulfide stream; And
At least one solid adsorbent bed described makes the sour gas comprising carbon dioxide pass through substantially, as described CO 2 fluid stream.
5. system according to claim 4, at least one solid adsorbent bed wherein said comprises at least one absorption power and is separated bed.
6. from acid flow, remove the system of sour gas, it comprises:
The sour gas receiving described acid flow removes system, described acid flow comprises the sulfur component being less than 10%, and wherein said sour gas is removed system utilization and described acid flow is separated into the main overhead gas stream containing methane and the main low temperature distillation tower containing the liquid column bottoms acid gas stream of carbon dioxide and sulfur component; And
The sulfur component that described sour gas removes system downstream removes system, wherein said sulfur component is removed liquid column bottoms acid gas stream described in system acceptance and described liquid column bottoms acid gas stream is separated into CO 2 fluid stream and hydrogen sulfide stream, and wherein said sulfur component removal system comprises the extractive distillation system with at least two extractive distillation posts.
7. system according to claim 6, wherein said extractive distillation system comprises:
As the first extractive distillation post of propane recovery post, solvent is mixed to absorb sour gas with described acid gas stream by described propane recovery post, makes described solvent leave described propane recovery post as solvent column underflow, discharges described carbon dioxide stream separately simultaneously;
As CO 2remove the second extractive distillation post of post, described CO 2removing post makes solvent and heavy hydrocarbon leave described CO as the second solvent column underflow 2remove post, discharge CO separately simultaneously 2; And
The 3rd extractive distillation post of post is reclaimed as additive, described additive reclaims post and utilizes distillation principle from solvent, be separated the heavy hydrocarbon components being called " natural gas liquids ", to make tower base solvent stream discharge as regenerated additive, natural gas liquids leaves separately described additive and reclaims capital simultaneously.
8. system according to claim 1, wherein said acid flow comprises the sulfur component being less than 1%.
9. system according to claim 1, wherein said acid flow comprises the sulfur component between 4ppm and 100ppm.
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