CN102597671A - Cryogenic system for removing acid gases from a hydrocarbon gas stream, with removal of hydrogen sulfide - Google Patents

Cryogenic system for removing acid gases from a hydrocarbon gas stream, with removal of hydrogen sulfide Download PDF

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CN102597671A
CN102597671A CN2010800494957A CN201080049495A CN102597671A CN 102597671 A CN102597671 A CN 102597671A CN 2010800494957 A CN2010800494957 A CN 2010800494957A CN 201080049495 A CN201080049495 A CN 201080049495A CN 102597671 A CN102597671 A CN 102597671A
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flow
gas
stream
tower
hydrogen sulfide
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CN102597671B (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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    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F25—REFRIGERATION OR COOLING; COMBINED HEATING AND REFRIGERATION SYSTEMS; HEAT PUMP SYSTEMS; MANUFACTURE OR STORAGE OF ICE; LIQUEFACTION SOLIDIFICATION OF GASES
    • 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
    • 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
    • F25J3/0228—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 separated product stream
    • F25J3/0233—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 separated product stream separation of CnHm with 1 carbon atom or more
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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
    • 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
    • F25J3/0228—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 separated product stream
    • F25J3/0266—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 separated product stream separation of carbon dioxide
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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
    • 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
    • F25J3/0295—Start-up or control of the process; Details of the apparatus used, e.g. sieve plates, packings
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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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    • 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
    • F25J2200/00—Processes or apparatus using separation by rectification
    • F25J2200/76—Refluxing the column with condensed overhead gas being cycled in a quasi-closed loop refrigeration cycle
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
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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
    • F25J2200/00—Processes or apparatus using separation by rectification
    • F25J2200/90—Details relating to column internals, e.g. structured packing, gas or liquid distribution
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
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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
    • 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
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F25—REFRIGERATION OR COOLING; COMBINED HEATING AND REFRIGERATION SYSTEMS; HEAT PUMP SYSTEMS; MANUFACTURE OR STORAGE OF ICE; LIQUEFACTION SOLIDIFICATION OF GASES
    • 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
    • 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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    • 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
    • F25J2205/00—Processes or apparatus using other separation and/or other processing means
    • F25J2205/60—Processes or apparatus using other separation and/or other processing means using adsorption on solid adsorbents, e.g. by temperature-swing adsorption [TSA] at the hot or cold end
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    • F25J2205/00—Processes or apparatus using other separation and/or other processing means
    • F25J2205/60—Processes or apparatus using other separation and/or other processing means using adsorption on solid adsorbents, e.g. by temperature-swing adsorption [TSA] at the hot or cold end
    • 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
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F25—REFRIGERATION OR COOLING; COMBINED HEATING AND REFRIGERATION SYSTEMS; HEAT PUMP SYSTEMS; MANUFACTURE OR STORAGE OF ICE; LIQUEFACTION SOLIDIFICATION OF GASES
    • 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
    • F25J2220/00—Processes or apparatus involving steps for the removal of impurities
    • F25J2220/60—Separating impurities from natural gas, e.g. mercury, cyclic hydrocarbons
    • F25J2220/66—Separating acid gases, e.g. CO2, SO2, H2S or RSH
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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
    • F25J2260/00—Coupling of processes or apparatus to other units; Integrated schemes
    • F25J2260/80—Integration in an installation using carbon dioxide, e.g. for EOR, sequestration, refrigeration etc.
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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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    • Y02C20/40—Capture or disposal of greenhouse gases of CO2

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  • Engineering & Computer Science (AREA)
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  • General Engineering & Computer Science (AREA)
  • General Chemical & Material Sciences (AREA)
  • Organic Chemistry (AREA)
  • Gas Separation By Absorption (AREA)
  • Separation By Low-Temperature Treatments (AREA)
  • Separation Of Gases By Adsorption (AREA)
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Abstract

A system for removing acid gases from a raw gas stream includes an acid gas removal system (AGRS) and a sulfurous components removal system (SCRS). The acid gas removal system receives a sour gas stream and separates it into an overhead gas stream comprised primarily of methane, and a bottom acid gas stream comprised primarily of carbon dioxide. The sulfurous components removal system is placed either upstream or downstream of the acid gas removal system. The SCRS receives a gas stream and generally separates the gas stream into a first fluid stream comprising hydrogen sulfide, and a second fluid stream comprising carbon dioxide. Where the SCRS is upstream of the AGRS, the second fluid stream also includes primarily methane. Where the SCRS is downstream of the AGRS, the second fluid stream is principally carbon dioxide. Various types of sulfurous components removal systems may be utilized.

Description

The cryogenic system of from hydrocarbon stream, removing sour gas and removing hydrogen sulfide
The cross reference of related application
The name that the application requires on November 2nd, 2009 to submit to is called cryogenic system (the CRYOGENIC SYSTEM FOR REMOVING ACID GASES FROM A HYDROCARBON GAS STREAM that from hydrocarbon stream, removes sour gas and remove hydrogen sulfide; WITH REMOVAL OF HYDROGEN SULFIDE) U.S. Provisional Patent Application 61/257; 277 rights and interests, the full content of this application is incorporated at this by reference.
Background
These chapters and sections are intended to introduce the various aspects of this area, and it maybe be relevant with illustrative embodiments of the present disclosure.Believe that this discussion helps for the better understanding that promotes concrete aspect of the present disclosure framework to be provided.Therefore, be to be understood that and read these chapters and sections with this angle, and needn't admit it is prior art.
The field
The present invention relates to the fluid separation field.More specifically, the present invention relates to separate hydrogen sulfide and other sour gas from hydrocarbon fluid stream.
Technical discussion
Recovery of hydrocarbons carries the subsidiary product of non-hydrocarbon gas often with it from reservoir.This gas comprises like hydrogen sulfide (H 2S) and carbon dioxide (CO 2) pollutant.Work as H 2S and CO 2When producing as the part of hydrocarbon stream (like methane or ethane), this air-flow is called " acid gas " sometimes.
Acid gas is processed to remove CO usually 2, H 2S and other pollutant, then with its fed downstream with further processing or sale.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.The desulfurization air-flow can be cooled to form liquefied natural gas or LNG.
Gas separation process has produced about disposing the problem of the pollutant that separates.In some cases, dense sour gas is (mainly by H 2S and CO 2Composition) is sent to sulfur recovery unit (" SRU ").SRU transforms H 2S is optimum elementary sulfur.But in some areas (like zone, the Caspian Sea), because limited market, extra elementary sulfur production is undesirable.Therefore, millions of tons sulphur has left in the big zone, ground in some areas, the world, is Canada and Kazakhstan the most significantly.
Though sulphur is stored in the land, the carbon dioxide invariably relevant with sour gas drained in the atmosphere.But, carry out discharging CO 2Sometimes do not expect.Reduce CO 2A suggestion of discharging is to be called as the method that sour gas injects (" AGI ").AGI means unwanted acid gas and under pressure, is refilled to subsurface formations (subterranean formation) and quilt isolated in order to the later application of possibility.Alternatively, carbon dioxide is used to form artificial reservoir pressure, is used to improve recovery ratio method oil-recovery operations.
In order to promote AGI, expectation has such gas processing device, and it effectively isolates acid gas component from the hydrocarbon gas.But,, promptly contain greater than about 15% or 20%CO for " peracidity " stream 2And/or H 2The production of S stream, design, structure and operation can be economically from required hydrocarbon the equipment of separating contaminants possibly have challenge.Many natural gas reservoirs contain low relatively hydrocarbon percentage composition (for example being less than 40%) and high sour gas percentage composition, mainly are carbon dioxide, but hydrogen sulfide, carbonyl sulfide, carbon disulfide and various mercaptan are also arranged.In these cases, can advantageously adopt cryogenic gas to handle.
It is to be used for the distillating method that gas separates sometimes that cryogenic gas is handled.Cryogenic gas is separated in and produces the cooling overhead gas stream under the moderate pressure (for example 350-550 pound per square inch gage (psig)).In addition, the liquefaction sour gas produces as " at the bottom of the tower " product.Because the liquefaction sour gas has high relatively density, hydrostatic head is advantageously used in the AGI well, to assist injection process.This means that the required energy in pump liquefied sour gas to stratum is lower to the required energy of reservoir pressure than compression low pressure sour gas.The compressor and the pump that need less level.
Also there is challenge about the acid gas low temperature distillation.When stagnation pressure in pending gas is less than CO under about 700psig 2The concentration that exists is during greater than about 5mol.%, and it will freeze to be solid in the cryogenic distillation apparatus of standard.CO as solid 2Formation interrupted the low temperature distillation process.In order to overcome this problem, that this assignee had before designed was various " control freezing zones TM" (CFZ TM) method.CFZ TMMethod is utilized the tendency of carbon dioxide formation solid particle, through making freezing CO 2Particle forms in the opening portion of destilling tower, and in melting tower tray, catches this particle then.As a result, produce clean methane stream (together with any nitrogen or the helium that in unstrpped gas, exist), at the bottom of tower, produce cooling liquid CO simultaneously at the cat head end 2/ H 2S stream.Be higher than under the pressure of about 700psig, can carrying out " whole fractionation (bulk fractionation) " distillation, and needn't worry CO 2Freeze; But the methane that cat head produces will have the CO of several at least percentages therein 2
At United States Patent (USP) 4,533,372, described CFZ in United States Patent (USP) 4,923,493, United States Patent (USP) 5,062,270, United States Patent (USP) 5,120,338 and the United States Patent (USP) 6,053,007 TMSome aspect of method and relevant device.
Like general description the in above United States Patent (USP), be used for distillation zone and middle control freezing zone that destilling tower that cryogenic gas handles or post comprise the bottom.Preferably, the distillation zone that also comprises top.Through being provided under that pressure temperature range below the carbon dioxide freezing point but a part of post more than the methane boiling temperature, the post running is to form solid CO 2Particle.More preferably, making methane and other light hydrocarbon gases evaporation, cause CO simultaneously 2Formation is freezed the temperature and pressure of (solid) particle and is operated this control freezing zone down.
When gas raw material stream when post rises, freeze CO 2Particle is broken away from feed stream and is relied on gravity to drop to the thawing tower tray from the control freezing zone.There, particle liquefaction.Carbon dioxide enriched then flow runs underneath to the distillation zone, bottom of column bottom from the thawing tower tray.Keep the distillation zone, bottom under the temperature and pressure that the methane that does not have carbon dioxide solid formation basically but dissolve can seethe with excitement.On the one hand, acid flow at the bottom of 30 ℉ to 40 ℉ form tower.
In one embodiment, can on the tower tray of frozen region bottom, collect some or freeze all CO 2Particle.Then particle is exported with further processing from destilling tower.
The control frozen region comprises the liquid spraying of cooling.This is the methane rich flow that is called " backflow ".Along with light hydrocarbon gases and the steam flow of carrying acid gas secretly move up through post, steam flow runs into liquid spraying.The liquid spraying of cooling helps to tell solid CO 2Particle make methane gas evaporation simultaneously and in post on flow.
In the distillation zone, top, catch methane (or overhead gas) and pipe and send and leave to sell or to can be used as fuel.On the one hand, discharge the cat head methane stream at about-130 ℉.Overhead gas can be through other cooling by partial liquefaction, and liquid is back to post as backflow.Liquid refluxes and to be injected into the spray section of control freezing zone as chilling spray, usually after the tower tray or filler of the rectifying section through post that flow.
The methane that produces in the distillation zone, top satisfies most of standard that pipeline transports.For example, if if produce sufficient backflow and/or with filler or tower tray in the distillation zone, top enough segregation section is arranged, methane can satisfy the pipeline CO that is less than 2mol.% 2The H of standard and 4ppm 2The S standard.But if the original raw material air-flow contains hydrogen sulfide (or other sulfur-containing compound), these will be 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 hydrogen sulfide contacting metal pipeline and valve in the presence of water, the iron sulfide corrosion can take place.Therefore, hydrogen sulfide and other sulfur component are removed in expectation from flow of feed gas, make it get into the cooling distillation column then.Gas stream that this makes " more low-sulfur " is to post.Therefore, the CO that produces by low temperature method 2Basically there is not H 2S, and for example can be used to improve the oil recovery of recovery ratio method.
Need from raw natural gas stream, reduce H 2The content of S and mercaptan makes it carry out low temperature distillation to remove the system of acid gas then.Alternatively, the cryogenic gas piece-rate system that need from the sour gas tower bottom flow, extract hydrogen sulfide in CFZ tower downstream with follow technology.
General introduction
The system of from acid flow, removing sour gas is provided.In one embodiment, this system comprises sour gas removal system.The utilization of sour gas removal system is separated into the overhead gas stream that mainly contains methane with acid flow and the low temperature distillation tower of acid gas stream at the bottom of the liquefaction tower that mainly contains carbon dioxide.This system also comprises sulfur component removal system.Sulfur component removal system is placed on sour gas and removes the system upper reaches.Sulfur component removal system receives flow of feed gas and substantially flow of feed gas is separated into fluid stream and the acid flow with hydrogen sulfide.
Acid flow preferably includes the sulfur component between about 4ppm and the 100ppm.This component can be hydrogen sulfide, carbonyl sulfide and various mercaptan.
Preferably, low temperature sour gas removal system comprises the refrigeration system that gets into the preceding cooling of destilling tower acid flow.Preferably, low temperature sour gas removal system is " CFZ " system, and wherein destilling tower has the distillation zone and middle control freezing zone of bottom.Middle control freezing zone or " spray section " receive the cooling liquid spray that mainly contains methane.Chilling spray is the liquid backflow from the overhead circulation generation in destilling tower downstream.Provide refrigeration plant to cool off the cat head methane stream and to return a part of cat head methane stream to low temperature distillation tower and reflux as cooling liquid in low temperature distillation tower downstream.
Should be appreciated that other sour gas removal system that can adopt except that low temperature distillation system.For example, it can be the physical solvent system that sour gas is removed system, and it tends to remove H equally 2S is together with CO 2Sour gas is removed system also can adopt whole fractionation.
Can adopt various types of sulfur component to remove system.These comprise the system that adopts 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 at least some hydrogen sulfide of solid adsorbent bed absorption makes methane gas and carbon dioxide pass through as acid flow simultaneously.Solid adsorbent bed can, for example,, or (ii) comprise at least a molecular sieve (i) by the zeolitic material manufacturing.Solid adsorbent bed can attach at least some water of absorption.
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; Wherein first in (i) at least three solid adsorbent beds is used to adsorb sulfur component; (ii) second at least three solid adsorbent beds regenerates, and (iii) the 3rd of at least three solid adsorbent beds keeps subsequent use with at least three adsorbent beds of replacement first.Regeneration can be the part of alternating temperature adsorption process, part or its combination of pressure-swing absorption process.
In another embodiment, sulfur component removal system adopts chemical solvent such as selectivity amine.In this case, sulfur component removal optimum system choosing utilizes a plurality of and the stream contact device.
Alternative physical solvent or chemical solvent system or except physical solvent or chemical solvent system, can utilize other type sulfur component 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 separate the use of bed.
This paper also provides the piece-rate system that is used for removing from acid flow sour gas.In this system, remove system downstream at sour gas and remove hydrogen sulfide and other sulfur-containing compound basically.Design this system to handle acid gas stream.From the flow of feed gas that contains sulfur component between about 4ppm and the 100ppm at first, obtain acid gas stream.
In one embodiment, system comprises sour gas removal system.Sour gas removal system receives flow of feed gas and flow of feed gas is separated into overhead gas stream that mainly contains methane and the liquid column bottoms acid gas stream that mainly contains carbon dioxide.Hydrogen sulfide also will be present at the bottom of the tower in the acid gas stream.This system also comprises sulfur component removal system.Sulfur component removal system is placed on sour gas and removes system downstream.Acid gas stream also was separated into carbon dioxide stream and the separated flow that mainly has sulfur-containing compound with acid gas stream at the bottom of the tower substantially at the bottom of sulfur component removal system received tower.
Preferably, sour gas removal system is that the low temperature sour gas is removed system.Low temperature sour gas removal system comprises destilling tower that receives flow of feed gas and the refrigeration system of before getting into destilling tower, cooling off flow of feed gas.Preferably, low temperature sour gas removal system is " CFZ " system, and wherein destilling tower has the distillation zone and middle control freezing zone of bottom.Middle control freezing zone or " spray section " receive the cooling liquid spray that mainly contains methane.Chilling spray is the liquid backflow from the overhead circulation generation in destilling tower downstream.Provide refrigeration plant to cool off the cat head methane stream and to return a part of cat head methane stream to low temperature distillation tower as backflow in low temperature distillation tower downstream, it is a liquid.
Various types of sulfur component capable of using is removed system.On the one hand, sulfur component removal system comprises at least one solid adsorbent bed.This at least one solid adsorbent bed at least some sulfur component of absorption and carbon dioxide is passed through the acid gas stream at the bottom of the tower.Solid adsorbent bed can, for example, use absorption power to separate (AKS).The AKS bed can attach at least some carbon dioxide of absorption.Under this situation, preferably, the AKS sulfur component is removed system and is also comprised separator such as gravity separator.For example, gravity separator is from gaseous state CO 2Middle liquid heavy hydrocarbon component and the hydrogen sulfide of separating.
Alternatively, solid adsorbent bed can be that sponge iron (iron sponge) is with direct and H 2The S reaction is also passed through to form iron sulfide and is removed it.
On the other hand, sulfur component removal system comprises extractive distillation process.Extractive distillation process adopts at least two solvent-recovery columns.First post receives at the bottom of tower acid gas stream and acid gas stream at the bottom of the tower is separated into first fluid stream that mainly contains carbon dioxide and second fluid that mainly contains solvent and sulfur-containing compound and flows.
The accompanying drawing summary
For better understanding mode of the present invention, some figure, table and/or flow chart are attached to this.But, should be noted that figure has only set forth embodiment that the present invention selects and the restriction that therefore can not be considered to scope, because the present invention can allow other effective embodiment and application of equal value.
Fig. 1 is the side view of illustrative in one embodiment CFZ destilling tower.The cooling flow of feed gas is injected into the intermediate controlled freezing zone of tower.
Fig. 2 A is the vertical view that melts tower tray in one embodiment.Melt tower tray and exist in below, tower inner control freezing zone.
Fig. 2 B is the cutaway view that Fig. 2 A melts tower tray 2B-2B intercepting along the line.
Fig. 2 C is the cutaway 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 that can be used for the jet tray of 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 of the intermediate controlled freezing zone of Fig. 1 destilling tower.In this view, two illustrative perforated baffles have been added to the intermediate controlled freezing zone.
Fig. 6 is presented in the embodiment according to the present invention the sketch map of from air-flow, removing the gas processing device of sour gas.This gas processing device is removed the system upper reaches 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.Here, thus solvent system is hydrogen sulfide is removed in operation with contact dehydration air-flow a physical solvent system.
Fig. 7 B provides the detailed maps of the solvent system of Fig. 6 in optional embodiment.Here, thus solvent system is hydrogen sulfide is removed in operation with contact dehydration air-flow a chemical solvent system.
Fig. 8 is presented in the embodiment according to the present invention the sketch map of from air-flow, removing the gas processing device of sour gas.In this is arranged, remove the system upper reaches through oxidation-reduction process at sour gas and from air-flow, remove hydrogen sulfide.
Fig. 9 is presented in the embodiment according to the present invention the sketch map of from air-flow, removing the gas processing device of sour gas.In this is arranged, remove the system upper reaches through scavenger at sour gas and from air-flow, remove hydrogen sulfide.
Figure 10 is presented in the embodiment according to the present invention the sketch map of from air-flow, removing the gas processing device of sour gas.In this is arranged, remove the system upper reaches through the CrystaSulf method at sour gas and from air-flow, remove hydrogen sulfide.
Figure 11 is presented in the embodiment according to the present invention the sketch map of from air-flow, removing the gas processing device of sour gas.In this is arranged, remove the system upper reaches through temperature swing adsorption system at sour gas and from air-flow, remove hydrogen sulfide.
Figure 12 is presented in the embodiment according to the present invention the sketch map of from air-flow, removing the gas processing device of sour gas.In this is arranged, remove the system upper reaches through pressure swing adsorption system at sour gas and from air-flow, remove hydrogen sulfide.
Figure 13 shows the sketch map of gas processing device of the present invention in another embodiment.In this is arranged, remove the system upper reaches through the adsorbent bed that utilizes absorption power to separate at sour gas and from air-flow, remove hydrogen sulfide.
Figure 14 shows the sketch map of gas processing device of the present invention in another embodiment.In this is arranged, remove system downstream through the adsorbent bed that utilizes absorption power to separate at sour gas and from air-flow, remove hydrogen sulfide.
Figure 15 A shows the sketch map of gas processing device of the present invention in another embodiment.In this is arranged, remove system downstream through extractive distillation process at sour gas and from air-flow, remove hydrogen sulfide.
Figure 15 B is the detailed maps that Figure 15 A is used for the gas processing device of extractive distillation process.
The detailed description of some embodiment
Definition
The organic compound of element hydrogen and carbon that use like this paper, term " hydrocarbon " refers to mainly comprise---if not exclusively---.Hydrocarbon is divided into two types usually: aliphatic or straight-chain hydrocarbons and ring-type or closed-ring hydrocarbons, comprise cyclic terpene.The instance of hydrocarbonaceous material comprises natural gas, oil, coal and can be used as fuel or improve quality is the arbitrary form of the pitch of fuel.
Use like this paper, term " hydrocarbon fluid " refers to the hydrocarbon of gas or liquid or the mixture of hydrocarbon.For example, hydrocarbon fluid can be included under the formation condition, (15 ℃ and 1 atmospheric pressure) gas or the hydrocarbon of liquid or mixture of hydrocarbon under treatment conditions or under environmental condition.Hydrocarbon fluid can comprise for example thermal decomposition product and gaseous state or other liquid hydrocarbon of oil, natural gas, coalbed methane, shale oil, pyrolysis oil, cracking gas, coal.
Term " mass transfer apparatus " finger is received and is treated fluid in contact and transmit any object on these fluids to other object as passing through gravity flow.A limiting examples is the tower tray that stripping goes out some component.Grid packing is another instance.
Use like this paper, 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.
Use like this paper, term " condensation of hydrocarbons " refers to those hydrocarbon of condensation under about 15 ℃ and absolute atmosphere.Condensation of hydrocarbons can comprise the mixture that for example has greater than the hydrocarbon of 4 carbon number.
Use like this paper, term " heavy hydrocarbon " refers to have the hydrocarbon more than a carbon atom.Main instance comprises ethane, propane and butane.Other instance comprises pentane, aromatic compounds and diamantane (diamondoids).
Use like this paper, term " closed-loop refrigeration system " refers to that wherein operate outside fluid such as propane or ethene are as any refrigeration system of cooling agent with cooling cat head methane stream.This forms contrast with " open-loop refrigeration system " that a part of cat head methane stream wherein self is used as working fluid.
Use like this paper, term " and flowing contact device " or " and flowing contactor " refer to that so that air-flow and solvent streams the contact with each other mode that in contact device, flows with identical substantially direction simultaneously receives the container that (i) gas stream and (ii) separated from solvent flow.Limiting examples comprises the additional liquid device (deliquidizer) that disappears of injector and coalescer or static mixer.
" non-absorption gas " refers in the gas sweetening process not by the remarkable gas that absorbs of solvent.
Use like this paper, term " natural gas " refers to from crude oil well (associated gas) or the multicomponent gas that obtains from underground gas-bearing formation (irrelevant gas).But the composition of natural gas and pressure marked change.Typical natural gas flow contains methane (C 1) as important component.Natural gas flow also can contain ethane (C 2), hydrocarbon and one or more sour gas of higher molecular weight.Natural gas also can contain small amounts of contamination such as water, nitrogen, wax and crude oil.
Use like this paper, " sour gas " refers to be dissolved in the arbitrary gas that produces acid solution in the water.The limiting examples of sour gas comprises hydrogen sulfide (H 2S) and carbon dioxide (CO 2).Sulfur-containing compound comprises carbon disulfide (CS 2), carbonyl sulfide (COS), mercaptan or their mixture.
Term " liquid flux " thus refer to that the preferential absorption sour gas is by removing in the air-flow or " washing off " fluid that is essentially liquid phase of part acid gas components at least.Air-flow can be hydrocarbon stream or other air-flow, as has the air-flow of nitrogen.
" desulfurization air-flow " refers to make the fluid stream that is essentially gas phase of part acid gas components removal at least.
Use like this paper, from air-flow, remove selected gas component about absorbing liquid, term " poor " and " richness " are relative, only infer less respectively or the content of selected gas component largely.Each term " poor " and " richness " needn't point out or require to absorb liquid do not have selected gas component maybe can not absorb more how selected gas component fully respectively.In fact, as obviously visible with hereinafter, preferably, so-called " richness " that in first contactor of a series of two or more contactors, produces absorbs liquid and keeps remarkable or a large amount of residual absorbabilities.On the contrary, " poor " absorbs liquid and will be understood that and can fully absorb, but can keep the gas component that is removed than small concentration.
Term " flow of feed gas " refers to hydrocarbon fluid stream, and wherein fluid mainly is a gas phase, and it does not experience the step of removing carbon dioxide, hydrogen sulfide or other acidic components.
Term " acid flow " refers to hydrocarbon fluid stream, and wherein fluid mainly is a gas phase, and contains the carbon dioxide of at least 3 molar percentages and/or more than the hydrogen sulfide of 4ppm.
Use like this paper, term " underground " refers to the geological stratification of existence below the earth surface.
The specific embodiment is described
Fig. 1 has presented in one embodiment the explanatory view of low temperature distillation tower 100 that can relevant use with the present invention.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 mainly is made up of extraction gas (production gas).Usually, fluid stream is represented the dry gas stream from well head or well head collection (not shown), and contains about 65% to about 95% methane.But fluid stream 10 can comprise the methane of lower percentage, as about 30% to 65%, or even is low to moderate 20% to 40%.
Methane can occur with the trace constituent such as the ethane of other hydrocarbon gas.In addition, trace helium and nitrogen can appear.In this application, fluid stream 10 also will comprise some pollutant.These comprise like 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 the 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 getting into destilling tower 100.The heat exchanger 150 that provides like the shell-and-tube interchanger for initial fluid stream 10.Cooling fluid (like petrogas) to heat exchanger 150 is provided the refrigerating plant (not shown) so that the temperature of initial fluid stream 10 is reduced to approximately-30 extremely-40 ℉ of ℉.Can make the fluid of cooling drift moving then through expansion gear 152.Expansion gear 152 can be joule-Tang Pusen (" J-T ") valve for example.
The work of 152 quenchers of expansion gear is in order to obtain the additional cooling of fluid stream 10.Preferably, realize the partial liquefaction of fluid stream 10.Joule-Tang Pusen (or " J-T ") valve is preferably used for being easy to form the gas raw material stream of solid.Preferably, if closing on low temperature distillation tower 100, installs by expansion gear 152 to be minimized in thermal loss and some components in the feed pipe (like CO 2Or benzene) reduce to below their freezing point, minimize the chance that solid stops up.
As a kind of replacement of J-T valve, expansion gear 152 can be the turbine type quencher.The turbine type quencher provides bigger cooling and for process forms the source of shaft work, like above-mentioned refrigerating plant.Heat exchanger 150 is parts of refrigerating plant.In this way, the operator can minimize the total energy demand of still-process.But the turbine type quencher is handled frozen particles maybe be good not as the J-T valve.
In arbitrary situation, heat exchanger 150 changes the unstrpped gas in the initial fluid stream 10 into chilled fluid flow 12 with chilling apparatus 152.Preferably, the temperature of chilled fluid flow 12 is approximately-40 ℉ to-70 ℉.On the one hand, operate low temperature distillation tower 100 down, and chilled fluid flow 12 is at about-62 ℉ at the about pressure of 550psi.Under these conditions, chilled fluid flow 12 is liquid phase basically, though possibly carry some vapor phases inevitably secretly in chilled fluid flow 12.Most possibly, CO 2Existence do not cause that solid forms.
CFZ low temperature distillation tower 100 is divided into three major parts.These are distillation zone or " stripping section " 106, the control freezing zone of centre or the distillation zone or " rectifying section " 110 on " spray section " 108 and top of bottom.In the tower of Fig. 1 is arranged, introduce in the control freezing zone 108 of chilled fluid flow 12 to destilling tower 100.But, alternatively, can introduce chilled fluid flow 12 near the top of distillation zone, bottom 106.
It should be noted that distillation zone, layout middle and lower part 106, middle spray section 108, distillation zone, top 110 and associated component at Fig. 1 are placed in the single container 100.But, use for the coastal waters of the height that wherein need consider tower 100 and motion Consideration, or be the remote location of a problem for transport restrictions wherein, randomly can tower 110 be divided into two independently pressure vessel (not shown)s.For example, distillation zone, bottom 106 can be placed in the container with control freezing zone 108, and distillation zone, top 108 is in another container.Use outside pipe that two containers are connected mutually then.
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 it suitable in chilled fluid flow 12 more than the boiling point of methane the operating pressure of post 100 under.In this way, preferentially from than extracting methane heavy hydrocarbon and the liquid acidic gas componant.Certainly, the liquid that those of ordinary skill in the art will understand in the destilling tower 100 is mixture, and meaning liquid will be at pure methane and pure CO 2Between some medium temperatures " boiling ".Further, if in mixture, there is heavier hydrocarbon (like ethane or propane), this will increase the boiling temperature of mixture.These factors become the design of operating temperature in the destilling tower 100 and consider item.
In distillation zone, bottom 106, CO 2Rely on gravity to drop to the bottom of low temperature distillation tower 100 with any other liquid phase fluid.Simultaneously, methane is overflowed with other vapor phase fluid and on the top of tower 100, is risen.This separates main through the completion of the density variation between gas phase and the liquid phase.But this separation process is randomly assisted through the intraware in the destilling tower 100.The following description, these comprise mass transfer apparatus 126 and the optional heater wire 25 that melts tower tray 130, a plurality of favourable configurations.Side reboiler (referring to 173) can be added to distillation zone, bottom 106 equally so that remove methane.
Referring again to Fig. 1, can introduce near the top of distillation zone, bottom 106 of chilled fluid flow 12 to post 100.Alternatively, possibly expect to introduce feed stream 12 to the control freezing zone 108 of melting tower tray 130 tops.The decanting point of chilled fluid flow 12 is one and is mainly flowed 10 the design problem of forming decision by initial fluid.
In the temperature of chilled fluid flow 12 enough high (as greater than-70 ℉) so that do not expect that the situation of solid is arranged, can preferably directly chilled fluid flow 12 be injected into distillation zone, bottom 106 through post 100 interior two phase flash distillation box-type devices (or vapor distributor) 124.The use of flash tank 124 is used for separating at least in part the vapour-liquid mixture of two phases in the chilled fluid flow 12.Can be with flash tank 124 flutings so that two-phase fluid impacts the baffle plate in the flash tank 124.
If because the expection of low inlet temperature has solid, chilled fluid flow 12 can part be separated in container 173 before supplying with like above-mentioned post 100.In this case, can in two phase separator 173, separate chilled fluid flow 12 and stop up intraware possible of suction line and post 100 to minimize solid.Gas vapor is left phase separator 173 through container entrance pipeline 11, gets into post 100 at suction line 11 through inlet dispenser 121.Gas is upwards advanced through post 100 then.Liquid/stereoplasm material 13 is emitted from phase separator 173.Through vapor distributor 124 liquid/stereoplasm material is caused post 100 also to melting tower tray 130.Can liquid/stereoplasm material be supplied to post 100 through gravity or through pump 175.
In arbitrary layout, that is to say to be with or without two phase separator 173 that chilled fluid flow 12 (or 11) gets into post 100.Liquid component leaves flash tank 124 and marches to steam stripping plate 126 set in the distillation zone, bottom 106 downwards.Steam stripping plate 126 comprises a series of weir plates 128 and downspout 129.Together with Fig. 3 these are described more fully below.In steam stripping plate 126 and the distillation zone, bottom 106 temperature of heat combine to cause that methane overflows from solution.Any carbon dioxide molecule of carrying secretly that the gained steam is carrying methane and cooking.
Steam further upwards continues operation and arrives freeze space 108 through air-lift tube or the riser (chimneys) 131 (referring to Fig. 2 B) that melts tower tray 130.The work of 131 vapor distributors of riser is in order to evenly to distribute in whole freezing district 108.Steam will contact cooling fluid from spray thrower 120 with " freezing out " CO then 2In other words, CO 2To freeze and deposition or " snowing " are back to and melt tower tray 130 then.Solid CO then 2Thawing also relies on gravity to flow down and pass through the distillation zone, bottom 106 of its below from thawing tower tray 130 with liquid form.
As below will more fully discussing, spray section 108 is middle freezing zones of low temperature distillation tower 100.With interchangeable structure---wherein chilled fluid flow 12 was separated in container 173 before entering tower 100, introduced a part to the tower 100 of the liquid/stereoplasm material 13 that separates, just in time above thawing tower tray 130.Therefore, sour gas and will flow from distributor 121 than the liquid-solid mixture of heavy hydrocarbon component, solid and liquid drop on the thawing tower tray 130.
Configuration is melted tower tray 130 and is received liquid and solid matter from intermediate controlled freezing zone 108 to rely on gravity, is mainly CO 2And H 2S.Melt tower tray 130 play warm liquid and solid matter and guide they downwards with liquid form through distillation zone, bottom 106 to be further purified.Melt that tower tray 130 is assembled with a beach liquid and the warm solid-liquid mixtures that comes Self Control freezing zone 108.Design is melted tower tray 130 and is back to control freezing zone 108 with disengaged vapor stream, provides suitable heat transfer to melt solid CO 2And promote liquid/slurry to drain into the distillation of post 100 bottoms or the distillation zone, bottom 106 of thawing tower tray 130 belows.
Fig. 2 A provides the vertical view that melts tower tray 130 in one embodiment.Fig. 2 B provides and has melted the cutaway view of tower tray 130 along Fig. 2 A center line B-B intercepting.Fig. 2 C has shown the cutaway view that melts tower tray 130 C-C interceptings along the line.To describe referring to these three figure jointly and melt tower tray 130.
At first, melt tower tray 130 and comprise substrate 134.Substrate 134 can be a plane body substantially.But in the preferred implementation that Fig. 2 A, 2B and 2C show, the profile that is substantially non--plane is adopted in substrate 134.Nonplanar be configured to contact land from control freezing zone 108 surface area of increase is provided melting liquid and solid on the tower tray 130.This is used to increase by 106 steam to liquid that upwards transmits and the heat transfers of melting solid from distillation zone, post 100 bottom.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. 2 B.Should be appreciated that and to adopt other nonplanar geometry alternatively to increase the heat transfer area that melts tower tray 130.
Preferably, melting tower tray substrate 134 tilts.In the side view shows of Fig. 2 C this inclination.Although most solid should be melted, this inclination is used for guaranteeing that any solid that do not melt of liquid mixture is from melting tower tray 130 and get rid of and to the distillation zone 106 of its below.
In the view of Fig. 2 C, visible pond or pipeline 138 are in the central authorities of melting tower tray 130.Melting tower tray substrate 134 slopes inwardly to transport solid-liquid mixtures towards pipeline 138.Substrate 134 can be tilted to promote to rely on the fluid removal of gravity by any way.
Like United States Patent (USP) 4,533, described in 372, melt tower tray and be called as " riser tower tray (chimney tray) ".This is owing to there is single exhaust riser.Riser provides opening, and steam can move up through the riser tower tray through this opening.But the existence of single riser means, has to discharge through single opening through all gas that the riser tower tray moves up.On the other hand, in the thawing tower tray 130 of Fig. 2 A, 2B and 2C, a plurality of riseies 131 are provided.The use of a plurality of riseies 131 provides the vapor distribution of improving.This helps in intermediate controlled freezing zone 108 better heat transfer/mass transfer.
Riser 131 can be any profile.For example, riser 131 can be circle, rectangle or make steam through melting any other shape of tower tray 130.Riser 131 also can be narrow and extend upward to control freezing zone 108.This makes can realize that useful pressure drop is with the steam that distributes equably when steam rises to CFZ control freezing zone 108.Preferably, riser 131 is positioned on the peak of corrugated substrate 134 so that extra heat transfer area to be provided.
Preferably, the top end opening of riser 131 is with cap or cover 132 and seal.This has minimized the solid that falls from control freezing zone 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 have bubble-cap.Bubble-cap has formed from melting the outstanding impression in substrate 134 that rise tower tray 130 belows.Bubble-cap has further increased the surface area that melts on the tower tray 130 with to rich CO 2Liquid provides extra heat transfer.With this design, should provide suitable liquid to discharge, like the angle of inclination that increases, with the steam stripping plate 126 of guaranteeing guiding liquids to below.
Referring to Fig. 1, also can design thawing tower tray 130 and have the outside liquid transmission system once more.This transmission system is used for guaranteeing that all liq has basically no solid and sufficient heat transfer is provided.Transmission system at first 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 that in pipeline 138, assemble is delivered to feed-line 135.Can be through control valve 137 and liquid-level controller " LC " (referring to Fig. 1) control flowing through feed-line 135.Through feed-line 135 Returning fluids 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 the operator 106 selects not adopt transmission system in the distillation zone, bottom, so closed control valve 137 and immediately directed flow body to mass transfer apparatus or " steam stripping plate " 126 that melt tower tray 130 belows with through overflowing downspout 139 strippings.
No matter whether utilize the external transmission system, melting warm solid CO on the tower tray 130 2And change rich CO into 2Liquid.Through from the steam of distillation zone, bottom 106 from the below heating and melting tower tray 130.Supplemental heat can randomly be added on the thawing tower tray 130 or only through variety of way such as heater wire 25 is melting in the tower tray substrate 134.Heater wire 25 utilizes the heat energy that has obtained from bottom reboiler 160 to promote solid to melt.
Rich CO 2Liquid under level control, discharge and rely on gravity to be introduced into distillation zone, bottom 106 from melting tower tray 130.As said, in the distillation zone, bottom 106 below melting tower tray 130 a plurality of steam stripping plates 126 are provided.Preferably, steam stripping plate 126 is parallel relation basically, and one in another top.Alternatively, can be to place each steam stripping plate 126 on tower tray, to keep liquid level with the very small inclination of weir plate.Fluid relies on gravity to flow, flow through weir plate and run underneath to next tower tray through downspout then along each tower tray.
Steam stripping plate 126 can become various layouts.Steam stripping plate 126 can be arranged, waterfall type liquid flow reciprocal to form with horizontal relationship substantially.But, preferably arrange the waterfall type liquid flow that steam stripping plate 126 separates with the independent steam stripping plate that forms by the same horizontal plane in basic edge.This shows that in the layout of Fig. 3 wherein liquid flow is separated once so that liquid flow passes independent tower tray and falls into two relative downspouts 129 at least.
Fig. 3 provides the side view of steam stripping plate 126 layouts in one embodiment.Each steam stripping plate 126 reception and gathering are from the fluid of top.Preferably, each steam stripping plate 126 has weir plate 128, and its effect of playing the dam is so that the little beach fluid collection on each steam stripping plate 126.This accumulation can be 1/2 to 1 inch, though can adopt any height.When fluid has formed water fall effect through weir plate 128 when a tower tray 126 drops down onto next lower tower tray 126.On the one hand, the inclination of steam stripping plate 126 is not provided, but has caused water fall effect through the structure of higher weir plate 128.Fluid contacts with the rising steam of enrichment in the light hydrocarbon, from the liquid of cross flow one, extract methane with this " contact zone " at tower tray 126.Weir plate 128 sealing downspout 129 is walked around downspout 129 to help prevent steam with being used for dynamics, and further promotes the effusion of the hydrocarbon gas.
Along with liquid moves down through distillation zone, bottom 106, the percentage of methane diminishes gradually in the liquid.The degree of distillation depends on the quantity of tower tray 126 in the distillation zone, bottom 106.On the top of distillation zone, bottom 106, methane content may be up to 25mol.% in the liquid, and in the bottom steam stripping plate, methane content is low to moderate 0.04mol.%.Methane content flashes off along steam stripping plate 126 (or other mass transfer apparatus) fast.The quantity that is used for the mass transfer apparatus of distillation zone, bottom 106 is based on the design alternative problem of the composition of flow of feed gas 10.But, for example, generally only need utilize the steam stripping plate 126 of some levels to remove methane to 1% or littler desired level in the liquefaction sour gas.
Can adopt various independent steam stripping plate 126 structures that promote that methane is overflowed.Steam stripping plate 126 can represent to have the panel of sieve aperture or bubble-cap simply.But, can below melting tower tray, adopt so-called " jet tray " because not expecting of causing of solid blocks for further convection cell provides to conduct heat and prevent.Replace tower tray, also can adopt random filler or structured packing.
Fig. 4 A provides the vertical view of illustrative jet tray 426 in one embodiment.Fig. 4 B provides the cutaway view of the jet tab 422 of jet tray 426.Like what show, each jet tray 426 has main body 424, in main body 424, forms a plurality of jet tabs 422.Each jet tab 422 comprises the tab member 428 of the inclination that hides perforate 425.Like this, jet tray 426 has a plurality of little perforates 425.
In operation, can one or more jet traies 426 be placed the distillation zone, bottom 106 and/or the distillation zone, top 110 of tower 100.Can be like the pattern of steam stripping plate among Fig. 3 126, a plurality of channel arrangement tower trays 426.But any tower tray that promotion methane gas capable of using is overflowed or filler are arranged.The fluid stepwise flows down on each jet tray 426.Fluid flows along main body 424 then.Best, tongue piece 422 is oriented to fast and moves fluid effectively and pass tower tray 426.Randomly, can provide adjacent downspout (not shown) with moving liquid to a back tower tray 426.The gas vapor that perforate 425 also allows in the fluid moving process of distillation zone, bottom 106, to discharge more effectively upwards marches to thawing tower tray 130 and passes through riser 131.
On the one hand, can promptly stop the material of solid accumulation by anti-pollution made tower tray (like tower tray 126 or 426).In some treatment facilities, utilize the anti-pollution material to prevent the accumulation of corrosion metals particle, polymer, salt, hydrate, catalyst fines or other chemical solid chemical compound.Under the situation of low temperature distillation tower 100, in tower tray 126 or 426, can use the anti-pollution material with restriction CO 2The adhesion of particle.For example, can be with Teflon TMApplication of paints is to the surface of tower tray 126 or 426.
Alternatively, can provide structural design to guarantee CO 2Do not begin to accumulate with the internal diameter of solid form along post 100.In this respect, jet tab 422 can be oriented to along the wall of post 100 and promote liquid, and therefore prevention is guaranteed good steam-liquid contact along the solid volume coalescence of the wall of post 100.
In tower tray is arranged arbitrarily, when the liquid bump that flows down bumps against steam stripping plate 126, feed separation takes place.Methane gas is overflowed from solution and is moved up with the steam form.But, CO 2Normally enough cold and under sufficiently high concentration so that its major part have and march to the bottom of distillation zone, bottom 106 downwards with its liquid form, though in this process, must evaporate number of C O 2Liquid shifts out from low temperature distillation tower 100 then, in discharge pipe, flows 22 as bottom stream.
After discharging destilling tower 100, bottom stream stream 22 gets into reboiler 160.In Fig. 1, reboiler 160 is still formula containers, and it provides steam to the steam stripping plate that boils again bottom.Vapor line boil again referring to 27.In addition, can carry the steam that boils again to think that thawing tower tray 130 provides supplemental heat through heater wire 25.Through valve 165 and temperature controller TC control supplemental heat.Alternatively, can heat exchanger such as thermal siphon formula heat exchanger (not shown) be used to cool off initial fluid stream 10 with conserve energy.In this respect, the liquid of entering reboiler 160 remains under the low relatively temperature for example about 30 ℉ to 40 ℉.Through the heat that combines with initial fluid stream 10, the operator can cooling bottom stream warm and that part is boiled from destilling tower 100 flow 22, simultaneously pre-cooled extraction fluid stream 10.For this situation, through line 25 fluid of supplemental heat being provided is the vapor phase of returning from reboiler 160.
Consideration is under some conditions, and melting tower tray 130 can operate when no heater wire 25.In these situation, can design and melt heater block such as the electric heater that tower tray 130 has inside.But, preferably, the heating system that is utilized in the heat energy that obtains in the bottom stream stream 22 is provided.Warmed fluid in the heater wire 25 exists with 30 ℉ to 40 ℉ on the one hand, so they contain suitable heat energy.Therefore, in Fig. 1, the warm steam flow that is presented in the heater wire 25 is directed to thawing tower tray 130 through the heating coil (not shown) on thawing tower tray 130.Alternatively, warm steam flow can be connected to transfer line 135.
In operation, introducing major part in the bottom of post through pipeline 27 boils on the liquid level of steam flow to bottom and in the end on the steam stripping plate 126 or below it again.Along with upwards each tower tray 26 of process of steam that boils again, go out residual methane from the liquid stripping.This steam is along with it moves up and cool off along tower.When the steam flow from pipeline 27 arrived corrugated thawing tower tray 130, temperature can be reduced to approximately-20 ℉ to 0 ℉.But, this with possibly compare still quite hot to the thawing solid on the thawing tower tray 130 of-70 ℉ for about-50 ℉.When it contacted with thawing tower tray 130, this steam still had enough heat contents to melt solid CO 2
Later referring to reboiler 160, alternatively, the tower bottom flow 24 interior fluids of discharging reboiler 160 with liquid form can pass through expansion valve 162.Expansion valve 162 has reduced the pressure of tower bottom liquid product, and refrigeration is provided effectively.Therefore, cooling tower underflow 26 is provided.Discharge the rich CO of reboiler 160 2Liquid can be to pumped downhole through one or more AGI wells (in schematically referring to Fig. 1 250).In some cases, can be used as the part that improves recovery ratio method oil recovery process, pumping liquid CO 2To the oil reservoirs of partly gathering.Therefore, CO 2It can be miscible infusion.As a kind of possibility, CO 2Can be used as and improve the miscible flooding agent (flood agent) that the recovery ratio method is recovered the oil.
Referring to the distillation zone, bottom 106 of tower 100, gas moves up through distillation zone, bottom 106, passes through to melt the riser 131 of tower tray 130, and arrives control freezing zone 108 once more.Control freezing zone 108 defines the chamber of opening wide with a plurality of spray spouts 122.When steam moved up through control freezing zone 108, the temperature of steam became lower.Steam contacts with liquid methane (" backflow ") from spray spout 122.This liquid methane is through comprising the external refrigeration device cooling of heat exchanger 170, and is colder than the steam that moves up.In one arrangement, liquid methane comes out from spray spout 122 to the temperature of-130 ℉ to be approximately-120 ℉.But along with the liquid methane evaporation, it absorbs heat from its environment, has therefore reduced the temperature of the steam that moves up.Because its low-density (with respect to liquid methane) and the barometric gradient in destilling tower 100, the methane of vaporization also upwards flow.
Along with the methane steam further moves up along low temperature distillation tower 100, they leave intermediate controlled freezing zone 108 and get into distillation zone, top 110.Steam continues to move up with other light gas of overflowing from initial chilled fluid flow 12.In conjunction with hydrocarbon vapour move out from the cat head of low temperature distillation tower 100, become cat head methane stream 14.
The hydrocarbon gas in cat head methane stream 14 moves in the external refrigeration device 170.On the one hand, refrigerating plant 170 uses ethylene refrigerant maybe can make cat head methane stream 14 be cooled to approximately extremely other cold-producing medium of-145 ℉ of-135 ℉.This is used for partial liquefaction cat head methane stream 14 at least.The methane stream 14 of cooling moves to reflux condenser or separation chamber 172 then.
Separation chamber 172 is used for from liquid---being sometimes referred to as " liquid backflow " 18---divided gas flow 16.Gas 16 representatives mainly are methane from the light hydrocarbon gases of original raw material air-flow 10.Also possibly there are nitrogen and helium.Certainly, methane gas 16 is finally to seek to catch and commercial " product " sold with any traces of ethane.The non-liquefaction part of this of cat head methane stream 14 also can be used as (on-site) fuel in the device.
A part of cat head methane stream 14 of leaving refrigerating plant 170 is condensations.This part is that liquid separated and that be returned to tower 100 refluxes 18 in separation chamber 172.Can use pump 19 to be back to tower 100 with moving liquid backflow 18.Alternatively, separation chamber 172 is installed so that the gravity charging of liquid backflow 18 to be provided above tower 100.Liquid backflow 18 will comprise any carbon dioxide of 110 effusions from the distillation zone, top.But most of liquid backflow 18 is a methane, is generally 95% or more, and nitrogen (if in initial fluid stream 10, existing) and trace hydrogen sulfide (if existing in the fluid stream 10 at first equally).
In a kind of cooling was arranged, cat head methane stream 14 was obtained through open-loop refrigeration system, such as together with Fig. 6 demonstration and described refrigeration system.In this layout, cat head methane stream 14 is obtained with the returning part cat head methane stream of cooling as liquid backflow 18 through intersection-heat exchanger.Thereafter, cat head methane stream 14 is forced into about 1,000psi to 1,400psi, and utilize then surrounding air with maybe external propane refrigeration agent cooling.Direct pressurized and cooled gas flow are passed through quencher with further cooling then.Can use the turbine type quencher to reclaim even more liquid and some shaft works.Name is called the United States Patent (USP) 6 of " but separation contains the method (Process For Separating a Multi-Component Gas Steam Containing at Least One Freezable Component) of the multi-component gas stream of at least a frozen composition "; 053; 007 has described the cooling of cat head methane stream, incorporates in full by reference at this.
Be to be understood that here the present invention is not limited by the cooling means of cat head methane stream 14.Be to be understood that also the cooling degree between refrigerating plant 170 and initial refrigerating plant 150 is changeable.In some cases, possibly be desirably in operation refrigerating plant 150 under the higher temperature, but cooling cat head methane stream 14 is stronger in refrigerating plant 170.In addition, the invention is not restricted to these design alternative types.
Get back to Fig. 1 once more, liquid backflow 18 is back to distillation zone, top 110.Rely on gravity to carry the one or more mass transfer apparatus 116 of liquid backflow 18 then through distillation zone, top 110.In one embodiment, mass transfer apparatus 116 provides the weir plate 118 of stepwise series connection and the rectifying tower tray of downspout 119, and is similar with above-mentioned tower tray 126.
When the fluid from liquid reflux stream 18 moved down through rectifying tower tray 116, extra methane was evaporated from distillation zone, top 110.Methane gas is added to the part that cat head methane stream 14 becomes gaseous product flow 16 again.But the residual liquid phase of liquid backflow 18 falls into collects on the tower tray 140.Like this, liquid reflux stream 18 obtains the hydrocarbon of little percentage and the sour gas that moves up from control freezing zone 108 inevitably.At the liquid mixture of collecting tower tray 140 collection methane and carbon dioxide.
Preferably, collect tower tray 140 and limit the main body that is substantially the plane, to collect liquid.But tower tray 130 is the same with melting, and collecting tower tray 140 also has one and preferably a plurality of riser to discharge from the control freezing zone 108 next gases.Can adopt like the riser and the drop cloth that are appeared by assembly 131 and 132 among Fig. 2 B and the 2C and put.In the zoomed-in view of Fig. 5, shown the riser 141 and lid 142 of collecting tower tray 140, further discussed hereinafter.
Should be noted that in distillation zone, top 110 H of any existence here 2S is dissolved in the liquid with respect to preferential tendency in gas under treatment temperature.In this respect, H 2S has lower relative volatility.Through with more liquid 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 even the specification of 4ppm.When fluid moves through the mass transfer apparatus 116 of distillation zone, top 110, H 2S contact liq methane also leaves vapor phase and becomes the part of flow 20.Therefrom, H 2S moves down through distillation zone, bottom 106 with liquid form and finally leaves low temperature distillation tower 100 as the part of liquefaction sour gas tower bottom flow 22.For H seldom 2S is to there not being H 2If being present in the feed stream or through upstream process, S optionally removes H 2Those situation of S do not have H in fact 2S will be present in the overhead gas.
In low temperature distillation tower 100,110 discharge from the distillation zone, top as flow 20 collecting liquid that tower tray 140 catches.Flow 20 mainly comprises methane.On the one hand, flow 20 is by the methane of about 93mol.%, 3% CO 2, 0.5% H 2S and 3.5% N 2Form.At this moment, flow 20 is that about-125 ℉ are to-130 ℉.This is only hot slightly than liquid reflux stream 18.Guided liquid-flow 20 to reflux accumulator 174.The purposes of reflux accumulator 174 is for pump 176 ability of surging to be provided.After reflux accumulator 174 discharges, form spray stream 21.Pressurization spray stream 21 is to be introduced into low temperature distillation tower 100 once more in pump 176.Under this situation, pumping spray stream 21 is to the intermediate controlled freezing zone 108 and discharge through nozzle 122.
Some parts, the especially methane of spray stream 21 are in discharge nozzle 122 back vaporization and evaporations.Therefrom, methane rises through control freezing zone 108, through collecting riser and the mass transfer apparatus 116 through distillation zone, top 110 in the tower tray 140.Methane leaves destilling tower 100 and finally becomes a part of commercial product in the air-flow 16 as cat head methane stream 14.
Cause also that from the spray of nozzle 122 stream 21 carbon dioxide sublimates from gas phase.In this respect, be dissolved in CO in the liquid methane at first 2Can get into gas phase at once and move up with methane.But because the low temperature in the control freezing zone 108, rapid nucleation of the carbon dioxide of any gaseous state and assembly become solid phase and begin " snowing ".This phenomenon is called desublimation.Like this, number of C O 2Will never get into liquid phase again and melt tower tray 130 until its contact.This carbon dioxide " snows " to melting on the tower tray 130 and being melted into liquid phase.Therefrom, rich CO 2Liquid with from the liquid CO of aforesaid cooling raw material gas flow 12 2Waterfall type flows down along the mass transfer apparatus or the tower tray of distillation zone, bottom 106 together.At that time, should overflow rapidly from any residual methane of the spray of nozzle 122 stream 21 and become steam.These steams move up in low temperature distillation tower 100 and get into distillation zone, top 110 again.
Expectation makes cooling liquid contact with the gas that moves up along tower 100 as much as possible.If steam gets around the spray stream 21 that comes from nozzle 122, the CO of higher level 2Can arrive the distillation zone, top 110 of tower 100.In order to improve gas/liquid contacting efficiency in the control freezing zone 108, can adopt a plurality of nozzles 122 with design structure.Therefore, do not adopt single spray source, can adopt the spray thrower 120 that is designed with a plurality of spray spouts 122 alternatively with one or more liquid levels of reflux fluid stream 21.Therefore, the structure of spray spout 122 is influential to the heat transfer and the mass transfer that in control freezing zone 108, take place.Equally, can design nozzle itself to produce the area distribution of best drop size with those drops.
The assignee of this paper has proposed various arrangement of nozzles earlier in having the international filing date common unsettled WO patent public publication 2008/091316 on November 20th, 2007.This application and Fig. 6 A thereof and 6B incorporate into instruction nozzle structure at this by reference.Nozzle is sought to guarantee controlling freezing zone 108 interior 360 ° of coverings and good vapor/liquid contact and heat transfer/mass transfer is provided.This more effectively cools off again and moves up through any gaseous carbon dioxide of low temperature distillation tower 100.
The a plurality of collectors 120 that are used for covering have fully also minimized reverse mixing with the use of corresponding overlap joint nozzle 122 devices.In this respect, covering prevents thin, low-quality CO fully 2Particle also gets into distillation zone, top 110 again along destilling tower 100 reverse moving.These particles will mix with methane again and get into cat head methane stream 14 more then, only be to circulate once more.
Removing system together with the above sour gas of Fig. 1 description is useful for the commercial methane product 16 that produces no acidic basically gas.Liquiefied product 16 and deliver to pipeline preferably to sell.Preferably, the liquid gas product satisfies 1 to 4mol.% pipeline CO 2Standard produces sufficient backflow in this situation.Carbon dioxide and hydrogen sulfide are removed through tower bottom flow 22.
In some cases, small amount of H 2S and a large amount of relatively CO 2Be present in the original initial fluid stream 10.In this case, can be desirably in the low temperature distillation tower and optionally remove H before 2S is so that can produce " cleaning " liquid CO at tower bottom flow 22 2Stream.Like this, CO 2Can directly be injected into reservoir to improve recovery ratio method oil recovery (" EOR ") operation.Therefore, this paper has proposed to be used for to carry out the system and method that sour gas is removed a part of removing the sulfur component that produces with initial fluid stream 10 before at low temperature distillation tower such as tower 100.
This paper has proposed to be used for removing from air-flow many H of sulfur component 2The S process for selective.Having described water becomes to become method with non-water.Preferably, this method is removed any mercapto compound such as hydrogen sulfide (H 2S) and have sulfydryl (organosulfur compound SH), it is called mercaptan (mercaptan), is also referred to as mercaptan (thiol) (R-SH), wherein R is an alkyl.
Be used for removing the use that the first method of removing sulfur component in the system upper reaches adopts solvent at sour gas.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 presented at the sketch map of from air-flow, removing the gas processing device 600 of sour gas in the embodiment.This gas processing device 600 is removed the system upper reaches at sour gas and is adopted solvent method.Sour gas is removed overall system with 650 expressions, and solvent method is with frame 605 expressions simultaneously.Sour gas is removed the separation container that system 650 is included in frame 100.Frame 100 refers generally to the control freezing zone tower 100 of Fig. 1.But frame 100 also can be represented any low temperature distillation tower such as whole fractionating column.
In Fig. 6, show the extraction air-flow with 612.Extraction air-flow 612 comes from the hydrocarbon that occurs in reservoir exploitation district or " oil field " 610 activity of gathering.Should be appreciated that oil field 610 can represent any position that produces gaseous hydrocarbon.
Oil field 610 can be land, the coastal waters or marine.Oil field 610 can maybe can be experienced by initial reservoir pressure operation improves recovery ratio method recovery process.The system and method that this paper requires to protect does not limit the oil-field structure in the exploitation, as long as it is producing the hydrocarbon of cure hydrogen and carbon dioxide pollution.This hydrocarbon will mainly comprise methane, but the ethane that also can comprise 2mol.% to 10mol.% and other heavy hydrocarbon such as propane or even the butane and the aromatic hydrocarbon of trace.
Air-flow 612 is " original ", refers to that it does not experience sour gas and removes process.Can be with flow of feed gas 612 for example from the oil field 610 through pipeline transmission to gas processing device 600.After arriving gas processing device 600, but steering current 612 is through dehydration such as glycol dehydration container.Schematically shown dewatering container 620.Because flow of feed gas 612 has produced current 622 through dewatering container 620.In some cases, flow of feed gas 612 can (monoethylene glycol MEG) mixes to prevent that water from running out of the formation with hydrate with ethylene glycol.For example, can spray MEG to cooler, and collect liquid, to be separated into water, denseer MEG and some possible heavy hydrocarbons, this depends on the temperature and inlet gas composition of cooler.
Current 622 can be delivered to water treatment facilities.Alternatively, current 622 can reinject to subsurface formations.Subsurface formations is with frame 630 expressions.Still alternatively, can handle the current 622 removed to satisfy environmental standard and to be released into local basin (not shown) as the water of having handled then.
Equally, owing to make extraction air-flow 612, produced the methane gas stream 624 of basic dehydration through dewatering container 620.The methane gas stream 624 of dehydration can contain trace nitrogen, helium and other inert gas.About native system and method, dehydration air-flow 624 also comprises carbon dioxide and a small amount of hydrogen sulfide.Air-flow 624 can comprise other sulfur component such as carbonyl sulfide, carbon disulfide, sulfur dioxide and various mercaptan.
Randomly, dehydration air-flow 624 is through preliminary refrigerating plant 625.Refrigerating plant 625 cooled dehydrated air-flows 624 are to the temperature of about 20 ℉ to 50 ℉.Refrigerating plant 625 can be for example aerial cooler or ethene or propane refrigeration device.
Expectation is removed sulfur component to prevent the iron sulfide corrosion from dehydration air-flow 624.According to gas processing device 600, solvent system 605 is provided.Dehydration air-flow 624 gets into solvent system 605.Solvent system 605 usefulness solvents contact air-flow 624 is to remove hydrogen sulfide through absorption process.This takes place under greater than the low relatively temperature of methane solubility and high relatively pressure in acid gas components solubility.
Notice that solvent system 605 can be physical solvent system or chemical solvent system.Fig. 7 A provides the sketch map of the 705A of physical solvent system in one embodiment.Operating physical solvent system 705A contact dehydration air-flow 624 is to remove sulfur component.
The instance of the physical solvent that is fit to comprises the methyl alcohol of N-methyl pyrrolidone, propylene carbonate, malonic methyl ester nitrile and cooling.The preferred embodiment of physical solvent is a sulfolane, and its chemical name is a tetramethylene sulfone.Sulfolane is the organosulfur compound that contains sulphonyl functional group.Sulfonyl group is that the two keys of sulphur atom are bonded to two oxygen atoms.The two keys of sulphur-oxygen are height polarity, allow its high-dissolvability in water.Simultaneously, four-carbocyclic ring provides the compatibility to hydrocarbon.It all is miscible in water and hydrocarbon that these character make sulfolane, makes it be widely used as the solvent of purifying hydrocarbon mixture.
Preferred physical solvent is Selexol TMSelexol TMIt is the trade name of treating products with gas of the Union Carbide of subsidiary of Dow Chemical company.Selexol TMIt is the mixture of the dimethyl ether of polyethylene glycol.The instance of a this composition is dimethoxy tetraethylene glycol (dimethoxy tetraethylene glycol).Selexol
Figure BDA0000159581960000241
also will obtain any heavy hydrocarbon and some water in the initial fluid stream 10.Suitable dry situation when initial fluid stream 10 beginnings, Selexol TMUse can remove needs to other dehydration.Note, if Selexol here TMSolvent is cooled, then with CO 2Presaturation, then Selexol TMSolvent will be to H 2S has selectivity.
Referring to Fig. 7 A, visible dehydration air-flow 624 gets into entrance separator 660.Should be appreciated that expectation keeps air-flow 624 clean so that prevent the foaming of liquid flux in the sour gas removal process.Therefore, entrance separator 660 is used to filter out liquid impurity such as oil base drilling fluid and mud.Also can carry out some particles filters.Preferably, use upper reaches dewatering container 620, separate salt solution.But entrance separator 660 can be removed 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 referring to 662.Usually, water base impurity is delivered to the water treatment facilities (not shown), maybe can refill to the stratum 630 to keep 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 referring to 664.
Randomly, guiding cleaning gas tream 664 to gas-gas interchanger 665.Gas in gas-gas interchanger 665 pre-cooled cleaning gas treams 664.Guide clean air to absorber 670 then.Preferably, absorber 670 is the column for counter-currently contacting that receive absorbent.In the layout of Fig. 7 A, cleaning gas tream 664 gets in tower 670 bottoms.Simultaneously, physical solvent 696 gets at tower 670 tops.Tower 670 can be Pu Panta, packed tower or other type tower.
Should be appreciated that alternatively the many non--tower apparatus that is designed for the solution-air contact capable of using.These can comprise static mixer with and flow contact device.The countercurrent tower 670 of Fig. 7 A is only used for two locking projections and notches.Notice that the use that is used for the small-sized of solution-air contacting container (one or more) and flows contactor is preferred, because can reduce total floor space (footprint) and the weight of the 705A of physical solvent system.
Absorbent can be for example to mix with " isolating " H with cleaning gas tream 664 2S and subsidiary number of C O 2Solvent.Absorbent can specifically be the Selexol that as above discusses.As result, produced light gas stream 678 with the contact process of absorbent.Light gas stream 678 comes out from tower 670 tops.Light gas stream 678 contains methane and carbon dioxide.Light gas stream 678 experience process of refrigerastions are directed to the low temperature distillation tower then, schematically show with the frame among Fig. 6 100.
At once return with reference to Fig. 6, light gas stream 678 is from the 705A of physical solvent system discharge and through cooler 626.Cooler 626 cooling light gas stream 678 to about-30 ℉ to the temperature of-40 ℉.Cooler 626 can be for example ethene or propane refrigeration device.
Preferably, next light gas stream 678 move through expansion gear 628.Expansion gear 628 can be joule-Tang Pusen (" J-T ") valve for example.The work of 628 quenchers of expansion gear is in order to obtain the further cooling to light gas stream 678.The temperature that expansion gear 628 further reduces light gas stream 678 to for example approximately-70 ℉ to-80 ℉.Preferably, also accomplished the partial liquefaction at least of air-flow 678.The cooling acid flow produces at pipeline 611.
Refer again to Fig. 7 A, contact tower 670 will obtain sulfur component.These discharge from tower 670 bottoms as " richness " solvent.It is thus clear that solvent-rich stream 672 is discharged tower 670.Solvent-rich stream 672 also can comprise some carbon dioxide.
In the layout of Fig. 7 A, carry solvent-rich stream 672 through energy recovery gas turbine 674.This allows for the 705A of physical solvent system and produces electric energy.Therefrom, carry solvent-rich stream 672 through a series of flash separators 680.In the illustrative layout of Fig. 7 A, show three separators with 682,684 and 686.According to physical solvent process, separator 682,684,686 is operation under the temperature and pressure that reduces gradually.
For example, first separator 682 can move under the temperature of the pressure of 500psi and 90 ℉.First separator 682 discharges and is entrained in the light gas in the solvent-rich stream 672.These light gas with 681 demonstrations mainly comprise methane and carbon dioxide, but can have trace H 2S.Can guide light gas 681 to low temperature distillation tower 100 (in Fig. 7 A, not showing).These gases can flow 678 with light gas and combine.Preferably, light gas 681 is advanced through compressor 690 to increase as the pressure in stream 611 to low temperature distillation tower 100 processes.If operation destilling tower 100 under than first flash stage of the solvent method 705A pressure that promptly first separator 682 is lower can not need compression.In the sort of situation, pressure drop will be needed so that combine stream 681 and 678 for overhead streams 678.Can cause pressure drop through near the J-T valve the low temperature distillation tower 100.Certainly, stream 681 must be introduced in J-T valve downstream.
Ideally, catch from all hydrogen sulfide and any heavy hydrocarbon of cleaning gas tream 664 with solvent-rich stream 672.The solvent streams of enrichment is discharged from each separator 682,684,686 gradually.These gradually enrichment stream with pipeline 683,685 and 687 the indication.Therefore, generally make physical solvent regeneration, cause that the methane of any dissolving and carbon dioxide come out from solvent flashing through pressure drop.
Pipeline 687 is " half is poor " solvent streams, because number of C O 2Be removed, but solvent streams 687 does not also have holomorphosis.Carry the part of this solvent streams 687 to be introduced into contact tower 670 again at the intermediate altitude of contact tower through booster pump 692 and as half lean solvent.Guiding is with residual fraction to the regeneration container 652 of 693 demonstrations.
About second 684 and the 3rd 686 of three separators, each that should be noted that these separators 684,686 also discharges very small amount of light gas.These light gas will mainly comprise carbon dioxide, subsidiary a small amount of methane.Show these light gas with two independent pipelines 689.Light gas 689 can be compressed and combine with pipeline 611, is directed to low temperature distillation tower 100 then.Alternatively, can directly transport from the light gas of pipeline 689 liquefaction acid gas stream at the bottom of 642 towers that show in Fig. 6.
Use physical solvent to be used for upper reaches H 2The advantage that S removes is normally moisture absorption of solvent.This can eliminate the needs for gas dewatering container 620, especially at initial fluid stream 10 in the situation of substantially dry.For this purpose, preferably, the solvent of selection itself is anhydrous.Like this, solvent can be used for further making original gas dehydration.In this case, water can come out with steam flow 655 from regenerator 652.
The shortcoming of this process is some light hydrocarbons and CO 2To be adsorbed in the physical solvent altogether to a certain extent.Most of methane have been removed in the use of a plurality of separators 682,684,686 really from solvent-rich stream 672, but are not the whole of it generally.
Refer again to regeneration container 652, container 652 plays stripper.Drive 2 S component so that they are as dense H 2S stream leaves regeneration container 652 through steam flow 655.Show the dense H in the steam flow 655 2S leaves the 705A of physical solvent system.It is also shown in the pipeline 655 among Fig. 6.
Preferably, the dense H in the steam flow 655 2S is sent to sour gas and injects (AGI) equipment.Randomly, can use the second physics dissolving agent process to remove any CO in advance 2And steam.Shown separator 658.Separator 658 is that recovery condensed water and solvent make gas arrive the reflux vessel of cat head simultaneously.Condensed water and solvent can be back to regeneration container 652 through tower bottom tube line 659.Simultaneously, overhead gas can be sent to sour gas injection (frame 649 at Fig. 6 schematically shows, and discusses hereinafter) through pipeline 691.
Steam flow 655 also will comprise carbon dioxide.Carbon dioxide and any steam will be together with H 2S leaves separator 658 through overhead 691.Preferably, H 2S delivers to AGI equipment 649 downstream, or randomly, can be sent to sulfur recovery unit (SRU) (not shown).
Regeneration container 652 stripping gases capable of using separate sulphur component from solvent of describing among Fig. 7 A.Regeneration container 652 can be used many stripping gas chargings.Instance is to have 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 from clean gas flow 664, obtaining less CO 2It is thus clear that stripping gas is through pipeline 651 ' be fed to regeneration container 652.Stripping gas 651 ' can be for example to be a part of light gas stream 689 of separator 686 from the minimum pressure flash stage.This makes possibly reclaim some hydrocarbon.
Derive regenerated solvent from regeneration container 652 bottoms.Regenerated solvent is discharged as 653.Carry regenerated solvent 653 through booster pump 654.Randomly, utilize second booster pump 694 further to improve the pressure in the pipeline of carrying regenerated solvent 653.Thereafter, preferably, through the heat exchanger 695 cooling regenerated solvents 653 that possibly have refrigerating plant.The solvent 696 that will cool off and regenerate then is recycled to contactor 670.
Part regenerated solvent obtains and is sent to reboiler 697 by regeneration container 652 bottoms.Reboiler is warm solvent.Warm solvent as the part evaporation current through pipeline 651 " be back to regeneration container 697.
Fig. 7 A has shown the embodiment of the 705A of physical solvent system.But, notice that alternatively, solvent system 605 can be a chemical solvent system.Chemical solvent system is used chemical solvent, particularly H 2S selectivity amine.The instance of this selectivity amine comprises methyl diethanolamine (MDEA) and Flexsorb
Figure BDA0000159581960000271
family's amine.Flexsorb
Figure BDA0000159581960000272
is the trade name that is used for removing from the acid gas mixture chemical absorbent of sulfurous gas.Flexsorb
Figure BDA0000159581960000273
absorbent or other amine contact with hydrocarbon stream 624 or cleaning gas tream 664 at the low temperature distillation tower upper reaches.
The chemical reaction of the acid gas components in dependence of amine type solvent and the hydrocarbon stream.Course of reaction is sometimes referred to as " gas sweetening ".This chemical reaction is more effective than physical solvent usually, particularly when material pressure is lower than about 300psia (2.07MPa).
Flexsorb
Figure BDA0000159581960000274
Amine is to be used for from containing CO 2Optionally remove H in the air-flow 2The preferred chemical solvent of S.Flexsorb Amine utilizes H 2S absorbs and CO 2The advantage of fast relatively speed is compared in absorption.Fast absorption rate helps prevent the formation of carbamate.By the hydrogen sulfide that produces based on the process of amine usually under low pressure.The H of output 2S will carry out sulfur recovery or need the significantly disposal of compression.
Use selectivity amine to remove fluid stream that hydrogen sulfide can be through dehydration and cooling 624 and contact completion with chemical solvent.This can accomplish through air-flow 624 being injected into " absorber ".Absorber is to make gas from air-flow 624 by Flexsorb TMOr the container of other liquid amine contact.When these two kinds of flowing materials interacted, amine absorbed H from acid gas 2S is to produce the desulfurization air-flow.The desulfurization air-flow mainly contains 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 was arranged, flow of feed gas 624 was 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, move up through absorber from the gas of air-flow 624.Normally, one or more tower trays or other internals (not shown) are provided in the absorber with a plurality of flow paths of forming natural gas and between gas phase and liquid phase, form interface zone.Simultaneously, the liquid from lean solvent stream moves down and passes the tower tray step by step in the absorber.Tower tray helps the interaction of natural gas and solvent streams.This process is illustrated with regard to Fig. 1 that name is called the patent application of " by removing sour gas (Removal of Acid Gases From a Gas Stream) in the air-flow ".That piece of writing application was submitted to by interim on October 14th, 2008, and was designated as United States serial 61/105,343.The appropriate section of Fig. 1 and specification is incorporated at this by reference.
" richness " amine aqueous solution is left by the bottom of column for counter-currently contacting.This comprises that liquid amine is together with the H that absorbs 2S.Rich amine aqueous solution obtains through regenerative process, and this regenerative process can seem the regeneration assembly described among extraordinary image above Fig. 7 A relevant with the 705A of physical solvent system, although it only has the single flash chamber of under 100-200psig, operating usually.
As washing H off 2The column for counter-currently contacting of the absorber of S is often very big and heavy.This oil and gas extraction has at sea caused special difficulty in using.Therefore, this paper has proposed to attach and from hydrocarbon stream, has removed H in oil and Gas Recovery 2The optional embodiment of S.It relates to use less and that flow contact device.These devices can pass through to reduce time of contact, thereby reduce CO 2Absorbed chance, the selectivity of raising amine.These less absorption plants also can reduce the size of total floor space of process 605.
Fig. 7 B has shown the illustrative embodiment that can be used to the chemical solvent system 705B of Fig. 6 dissolving agent process 605.Chemical solvent system 705B adopts a series of and stream contact device CD1, CD2 ..., CD (n-1), CDn.These devices are used to selectivity amine is contacted with air-flow.
And two or more contactors of stream concept utilization series connection, wherein acid flow and liquid flux move in contactor together.In one embodiment, acid flow and liquid flux move along the longitudinal axis of contactor separately substantially together.And the stream contactor can be operated under very high fluid velocity.As a result, and stream contactor trend towards Billy with packed tower or the shop Pan Ta the counter current contacting device littler.
As Fig. 7 A, visible dehydration air-flow 624 gets into entrance separator 660.Entrance separator 660 is used to filter out liquid impurity such as oil base drilling fluid and mud.Use the upper reaches dewatering container 620 preferential salt solution that separate that show among Fig. 6.Also can in entrance separator 660, carry out some particles filters.Should be appreciated that expectation keeps air-flow 624 clean so that prevent the foaming of liquid flux in the sour gas processing procedure.
Liquid such as condensation of hydrocarbons and drilling fluid are left by the bottom of entrance separator 660.Liquid impurity stream sees 662.Water-based impurity is generally delivered to the water treatment facilities (not shown), maybe can refill to the stratum 630 to keep reservoir pressure or to dispose with pipeline 622.Hydrocarbon liquid generally removes the condensation process device.Gas is discharged from the top of entrance separator 660.The acid flow of cleaning is referring to 664.
The acid gas of cleaning guides to a series of absorbers.Here, absorber be and stream contact device CD1, CD2 ..., CD (n-1), CDn.Each contactor CD1, CD2 ..., CD (n-1), CDn remove section H from air-flow 664 2S content, thus the air-flow of desulfurization gradually discharged.Final contactor CDn provides the final desulfurization air-flow 730 (n) that consists essentially of methane and carbon dioxide.Air-flow 730 (n) is the pipeline 678 of Fig. 6.
In operation, air-flow 664 entering first are also flowed absorber, or contact device CD1.At there, gas mixes with liquid flux 720.Preferably, solvent 720 is made up of amine aqueous solution such as methyl diethanolamine (MDEA) or Flexsorb amine.Liquid flux also can comprise hindered amine, tertiary amine or its combination.Flexsorb
Figure BDA0000159581960000292
is the instance of hindered amine, and MDEA is the instance of tertiary amine.In addition, solvent streams 720 is partial regeneration or " half the is poor " solvents that produce through regenerator 750.Help " half is poor " solvent 720 to move into the first contactor CD1 through pump 724.Pump 724 moves half lean solvent, 720 entering, the first contactor CD1 under the pressure being fit to.The instance that is fit to pressure is about 15psia to 1,500psig.
Behind the first contactor CD1 inside, air-flow 664 moves with chemical solvent stream 720 longitudinal axis along the first contactor CD1.When they are advanced, the H in liquid amine (or other solvent) and the air-flow 664 2S interacts, and causes H 2The S 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.Simultaneously, first's desulfurization air-flow 730 (1) shifts out and is released into the second contactor CD2 by the first contactor CD1.
The second contactor CD2 also representes and flow point leaves device.Randomly, after the second contactor CD2, provide the 3rd and flow point from device CD3.Among the second and the 3rd contactor CD2, the CD3 each produces partial desulfurization air-flow 730 (2), 730 (3) separately.In addition, each among the second and the 3rd contactor CD2, the CD3 produces the gas treatment solution 740 (2), 740 (3) of fractional load separately.As in the situation of solvent, the gas treatment solution 740 (2), 740 (3) of fractional load will comprise rich amine aqueous solution at amine.In example systems 705B, the second supporting gas Treatment Solution 740 (2) combines with the first supporting gas Treatment Solution 740 (1) and through regenerative process, comprises through regenerator 750.
Should be noted that when gas 664 move through desulfurization gradually on downstream direction air-flow 730 (1), 730 (2) ... During 730 (n-1), the pressure in the system will reduce usually.When this takes place, the amine that on updrift side, richens gradually (or other liquid flux) stream 740 (n), 740 (n-1) ... Pressure in 740 (2), 740 (1) need increase with coupling air pressure substantially.Therefore, in the 705B of system preferably with one or more small-sized booster pump (not shown)s place each contactor CD1, CD2 ... Between.This will be used for increasing intrasystem fluid pressure.
In the 705B of system, stream 740 (1), 740 (2) comprises " richness " solvent solution that at first moves through flash tank 742.Flash tank 742 is operated under about pressure of 100 to 150psig.Flash tank 742 generally has and causes depositional inner body or be used for the wherein crooked flow path of solvent streams 740.Through pipeline 744 from solvent streams 740 flash distillation residual gas such as methane and CO 2For example, if contact with a small amount of fresh amine from pipeline 720, the residual gas of catching in the pipeline 744 can be reduced to the content of acid gas of about 100ppm.This concentration is enough little, makes residual gas can be used as the fuel gas among the 705B of system.
Can be through pipeline 744 from the remaining natural gas of solvent streams 740 flash distillations.Gained solvent-rich stream 746 is directed to regenerator 750.
Before moving into regenerator 750, preferably, solvent-rich stream 746 moves through the heat exchanger (not shown).Cold relatively (near environment temperature) solvent streams 746 can be through being heated with warm lean solvent stream 760 thermo-contacts of leaving regenerator 750 bottoms.This is used for cooling off valuably lean solvent stream 760 again, is delivered to lean solvent cooler 764 then, and then to final contactor CDn.
Regenerator 750 defines the stripper part 752 that above reboiler 756, comprises tower tray or other internals (not shown).Provide thermal source to reboiler 756 to produce heat.Regenerator 750 produces and is recycled regeneration or " poor " solvent streams 760 that reuses with in final contactor CDn.From containing dense H 2The stripping overhead gas of the regenerator 750 of S leaves regenerator 750 as trash flow 770.
Rich H 2 S trash flow 770 moves into condenser 772.Condenser 772 is used for cooling off trash flow 770.The trash flow 770 of cooling moves through return tank 774, and it separates any residual liquid (being mainly condensed water) from trash flow 770.Form then 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 remaining flow 775.Preferably, carry remaining flow 775 to improve pressure through pump 778, it is introduced into regenerator 750 again then at there.Some residual liquids will leave regenerator 750 in the bottom, as the part of lean solvent stream 760.Randomly, some water yields can be added to the steam loss of lean solvent stream 760 with balance to desulfurization air-flow 730 (n-1), 730 (n).Can add this water in the inlet or suction place of reflux pump 778.
Poor or regenerated solvent 760 is under the low pressure.Therefore, carry the flow of representing regenerated solvent 760 through booster pump 762.Pump 762 is known as lean solvent booster 762.From there, lean solvent 760 is through cooler 764.Guarantee that through cooler 764 cooling solvents lean solvent 760 will absorb sour gas effectively.The lean solvent 760 of cooling is used as the solvent streams of last separation contactor CDn.
Randomly, near contact device CD1, CD2 ..., CD (n-1), CDn provide solvent tank 722.Lean solvent 760 can pass through solvent tank 722.More preferably, solvent tank 722 is storage ponds off-line and that solvent is provided, because it possibly needed by gas apparatus 705B.
Once more with reference to a plurality of and stream contact device CD1, CD2 ..., CD (n-1), CDn, each contact device receives the air-flow that comprises the hydrocarbon gas and hydrogen sulfide.Operate each contact device CD1, CD2 ..., CD (n-1), CDn come sequentially to remove H 2S and produce the air-flow of desulfurization gradually.And stream contact device CD1, CD2 ..., CD (n-1), CDn can be any of various short contacting time mixing arrangements.Instance comprises static mixer and centrifugal mixer.Some mixing apparatus separate liquid through injector.Injector carries gas through promoting the venturi shape pipe that liquid flux gets into pipe successively.Because Venturi effect, liquid flux is drawn in and is split into droplet, allows to contact with the gas large surface area.
A kind of preferred contact device is ProsCon TMContactor.This contactor utilization has the injector of centrifugal coalescer at the back.Centrifugal coalescer causes that big centrifugal force is to combine the liquid flux of small size again.In which kind of embodiment, preferably adopt the small containers technology no matter, make that comparing hardware with big contact tower reduces.
The first contactor CD1 receives flow of feed gas 664.Flow of process air 664 is to remove hydrogen sulfide in the first contactor CD1.Discharge first then, partial desulfurization air-flow 730 (1).The first, partial desulfurization air-flow 730 (1) is delivered to the second contactor CD2.At there, the first desulfurization air-flow 730 (1) is further handled removing hydrogen sulfide, with discharge second, the more abundant air-flow 730 (2) of desulfurization.Continue this pattern so that the 3rd contactor CD3 produces the more fully air-flow 730 (3) of desulfurization; The 4th contactor CD4 still produces even the air-flow 730 (4) of desulfurization more; And the penult contactor still produces the air-flow CD (n-1) of desulfurization more.In these each can be called as " (subsequent) continuously " desulfurization air-flow.
Discharge final desulfurization air-flow 730 (n) through final contactor CDn.Main by the required H of the standard of meeting the expectation 2S removal level determines the quantity (being at least two) of the contact device before the final contactor CDn.In the system 705B of Fig. 7, final desulfurization air-flow 730 (n) still contains carbon dioxide.Therefore, desulfurization air-flow 730 (n) must be taken away the CFZ tower 100 through 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 coalescence device.Therefore, for example, a CD1 and the 2nd CD2 contactor can use the mixing arrangement of static mixer as them, and the 3rd CD3 can use injector with other CD4 contactor, and CDn-1 and CDn contactor can use centrifugal mixer.Each contactor has relevant coalescence device.In arbitrary embodiment, air-flow 664,730 (1), 730 (2) ... The liquid flux of 730 (n-1) and concurrent flow stream with equidirectional flow through contactor CD1, CD2 ... CDn.This time durations that makes processing reaction take place is short, perhaps even be as short as 100 milliseconds or still less.This is for H optionally 2S removes (with respect to CO 2) possibly be favourable, because some amine and H 2S ratio and CO 2Reaction more quickly.
Except receiving air-flow, each also flow contactor CD1, CD2 ..., CD (n-1), CDn also receive liquid flux stream.In the 705B of system, the solvent streams 720 of first contactor CD1 receiving unit regeneration.Thereafter, subsequently contactor CD2, CD3, CD (n-1), CDn receives the solvent solution that discharges the load in contactor separately in succession.Therefore, the second contactor CD2 receives the solvent solution 740 (3) that discharges from the fractional load of the 3rd contactor CD3; The 3rd contactor CD3 receives the solvent solution 740 (4) that discharges from the fractional load of the 4th contactor CD4; And penult contactor CD (n-1) receives the solvent solution 740 (n) from the fractional load of final contactor CDn.In other words, the liquid flux of second contactor CD2 reception comprises the solvent solution 740 (3) of release from the fractional load of the 3rd contactor CD3; The liquid flux that the 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 penult contactor CD (n-1) receives comprises the solvent solution 740 (n) from the fractional load of final contactor CDn.Therefore, with the air-flow 730 (1), 730 (2), 730 (3) of desulfurization gradually ... The processing direction that 730 (n-1) are opposite, with the solvent solution of fractional load be introduced into contactor CD1, CD2, CD3 ... CDn.
Last separation contactor CDn also receives liquid flux.This liquid flux is the solvent streams 760 of regeneration.The solvent streams 760 of regeneration is very poor.
It is illustrative that the chemical solvent system 705B of Fig. 7 B is intended to.Can use and adopt a plurality of and stream contact device other layout as this system of absorber.The CO of the instance of this other system in the above United States serial of quoting 61/105,343 2Describe in the context of removing.The appropriate section of Fig. 2 B and specification is also incorporated at this by reference.
In the system 705B of Fig. 7 B, solvent solution 740 (1) and 740 (2) is regenerated.The solvent 780 of partial regeneration comes out from regeneration container 750.Through booster pump 782 solvent 780 is placed under the pressure.From there, cooling solvent 780 is to become solvent streams 720 in heat exchanger 784.Be introduced into first and flow contactor CD1 as solvent before the solvent streams 720 780 through booster pump 724 by further superchargings.
Once more with reference to Fig. 6, light gas stream 678 (it also is the pipeline 730 (n) among pipeline 678 and Fig. 7 B among Fig. 7 A) leaves solvent system 605, through dehydrator, and through cooler 626.Cooler 626 cooling light gas stream 678 to about-30 ℉ to the temperature of-40 ℉.Cooler 626 can be for example ethene or propane refrigeration device.
Preferably, next light gas stream 678 move through expansion gear 628.Expansion gear 628 can be joule-Tang Pusen (" J-T ") valve for example.Expansion gear 628 flows 678 further cooling to light gas with acquisition as quencher.The temperature that expansion gear 628 further reduces light gas stream 678 to for example approximately-70 ℉ to-80 ℉.Preferably, also realize the partial liquefaction at least of air-flow 678.At pipeline 611 indication cooling acid flows.
Cooling acid gas in the pipeline 611 gets into low temperature distillation tower 100.Low temperature distillation tower 100 can be that operation is with through freezing CO wittingly 2The process of particle is distilled any tower of methane from sour gas.The low temperature distillation tower can be the CFZ of Fig. 1 for example TMTower 100.The cooling acid gas of pipeline 611 gets into the tower under about 500 to 600psig.
Like what explain with regard to Fig. 1, 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, because it removes through sulfur component that system's (it is a solvent system 605) catches and as dense H 2S stream 655 is carried with further processing.Can use the sulfur recovery unit (not shown) with 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 tower bottom flow 642 sends through reboiler 643.From there, the fluid that contains methane is guided to return tower 100 as air-flow 644 once more.The residual fluid that mainly comprises carbon dioxide is passed through CO 2Pipeline 646 discharges.CO in the pipeline 646 2It is liquid form.Preferably, the carbon dioxide in the pipeline 646 is through booster 648 and inject (AGI) wells through the one or more sour gas like frame 649 expression then and be injected into subsurface formations.
Methane discharges from destilling tower 100 as cat head methane stream 112.Preferably, cat head methane stream 112 will contain the carbon dioxide that is not more than about 2mol.%.Under this percentage, cat head methane stream 112 can be used as fuel gas or can be used as natural gas and is sold to some market.But, according to some method of this paper, expectation be that cat head methane stream 112 experience are further handled.More specifically, cat head methane stream 112 is passed through open-loop refrigeration system.
At first, cat head methane stream 112 is through cross exchanger 113.Cross exchanger 113 is used for pre-cooled through being introduced into the liquid reflux stream 18 of low temperature distillation tower 100 after expansion gear 19 expansions again.Next cat head methane stream 112 is delivered to compressor 114 to increase its pressure.
Next, make 112 coolings of pressurization methane stream.This can be through for example accomplishing methane stream 112 through gas cooler 115.The methane stream 16 of cooling and pressurization is able to produce.Preferably, liquefied methane stream 16 is to produce commercial product.
The part cooling of leaving cooler 115 and the methane stream 116 of pressurization are split into reflow stream 18.Reflow stream 18 is further cooling in heating heat exchanger 113, expands with the chilling spray stream 21 of final generation Fig. 1 through expansion gear 19 then.Chilling spray stream 21 gets into destilling tower 100, and wherein it is used as the cooling liquid spray.This liquid spraying or the temperature that reduces control freezing zone (showing with 108 of Fig. 1) that refluxes also help to freeze out CO from aforesaid dehydration air-flow 624 2With other sour gas particle.
To understand, Fig. 6 has represented to be intended to only to clearly show the rough schematic view of the selection aspect of gas handling system 600.Gas handling system will generally include many other assemblies such as heater, cooler, condenser, liquid pump, gas compressor, air blast, other type separation and/or fractionation apparatus, valve, switch, controller, together with pressure, temperature, liquid level, flow measurement device.
This paper provides other method of removing sulfur component from flow of feed gas.A kind of this method belongs to " redox " method.Reduction-oxidation reaction represented in term " redox ".Redox has been described wherein, and atom makes their oxidation number or the chemical reaction of oxidation state change.In this oxidation-reduction process, the metal of oxidation such 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 that contains hydrogen sulfide contacts with metal chelate catalyst, realizes absorbing.Take place subsequently hydrogen sulfide be oxidized to elementary sulfur and simultaneously metallic reducing for than low-oxidation-state.Through being contacted with oxygen-containing gas, catalyst solution makes burning be back to higher oxidation state to come the regeneration catalyzing agent solution then, to reuse.
Fig. 8 shows the sketch map that is used for removing from flow of feed gas the gas processing device 800 of sour gas.In this is arranged, remove system 650 upper reaches through oxidation-reduction process at sour gas and from flow of feed gas, remove hydrogen sulfide.Oxidation-reduction process is based on water, this means that the dehydration of flow of feed gas needn't be at H 2S removes step and begins to carry out before.
Fig. 8 has shown the gas processing device 800 that receives extraction air-flow 812.Extraction air-flow 812 comes from the hydrocarbon that occurs in reservoir exploitation district or " oil field " 810 activity of gathering.Should be appreciated that oil field 810 can represent any position that produces 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 at first comprised contactor 820.Contactor 820 limits the chamber 825 that receives from the original hydrocarbon gas in oil field 810.Behind inlet chamber 825 inside, carry out isolating the chemical reaction of hydrogen sulfide and other sulfur component from flow of feed gas 812.
In order to produce this chemical reaction, chamber 820 also receives the oxidized metal of chelating.The instance of this oxidized metal is a chelated iron.Chelated iron is the form of metal-chelating agent solution.Metal-chelator is delivered to chamber 825 through pipeline 842.
Behind inlet chamber 825 inside, the hydrogen sulfide reaction in metal chelate solution and the flow of feed gas 812.Reduction-oxidation reaction takes place.As a result, chelating reducing metal mixture is emitted through tower bottom tube line 822 together with elementary sulfur.Simultaneously, gas is overflowed through overhead 824.Fundamental reaction is S --+ 2Fe +++→ S 0+ 2Fe ++
Gas in the pipeline 824 mainly comprises methane and carbon dioxide.Traces of ethane, nitrogen or other component also can be present in the pipeline 824.Jointly, the gas in the pipeline 824 is represented acid gas.
Illustrative sulfur component is removed system 850 and is also comprised oxidator 830.Oxidator 830 is defined for the chamber 835 of redox metal mixture.Oxidator 830 receives the metal mixture of reduction through pipeline 822.The pressure of the metal mixture in the pipeline 822 is through valve 828 controls.
Oxidator 830 is admission of air also.Through pipeline 834 air is introduced into oxidator 830.Increase the pressure in the pipeline 834 so that the chamber 835 in the oxidator 830 is passed through in the air operation through air blast 838.Behind inlet chamber 835 inside, air contact chelated mineral mixture causes that the metal mixture of reduction is oxidized.Through discharge pipe 836 air is discharged from oxidator 830.
Oxidation reaction produces oxidation chelated mineral mixture.The chelating mixture also contains the sulphur of colloidal form.Chelating mixture with sulphur leaves from oxidator 830 through 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, can adopt other type of separator.The water-based chelating agent mixture separation that centrifuge 840 will have sulphur is two kinds of components.A kind of component is an elementary sulfur.From this process, remove elementary sulfur continuously, as having highly purified solid product.Preferably, owing to have the obstruction of the equipment of sulikol, contact process is limited to lower pressure (300psig or littler).But storage element sulphur, or sell more preferably as commercial product.
Discharge elementary sulfur at pipeline 844.Preferably, sulphur is directed to sulphuring treatment unit (not shown).This has stayed the metal-chelator aqueous solution that does not have elementary sulfur basically.
The metallic catalyst aqueous solution in the removal system 850 is the chelated iron of regeneration.Chelated iron is guided through pipeline 842 to be back to contactor 820 once more.Can provide pump 844 to increase the pressure in the pipeline 842 and to transport chelating agent mixture to contacting container 825.Like this, renewable and reuse chelated iron (or other oxidized metal).
Referring to gas line 824, the acid gas in the gas line 824 is brought to dewatering container 860 once more.Because oxidation-reduction process uses material based on water from flow of feed gas 812, to separate H 2S, subsequently need be before the low temperature sour gas is removed to pipeline 824 in gas dewatering.Because the acid gas from gas line 824 passes through dewatering container 860, has produced current 862.Current 862 can be delivered to water treatment facilities.Alternatively, current 862 can reinject to subsurface formations, like the subsurface formations 630 of Fig. 6.Still alternatively, can handle the current 862 removed to satisfy environmental standard and to be released into local basin (not shown) as the water of having handled then.
Equally, because the acid gas of pipeline 824, produces fully dehydration air-flow 864 through dewatering container 860.Dehydration air-flow 864 comprises methane, and also can comprise trace nitrogen, helium and other inert gas.With regard to native system and method, dehydration air-flow 864 also comprises carbon dioxide.
Dehydration air-flow 864 leaves dewatering container 860 and passes through cooler 626.The temperature of cooler 626 cooled dehydrated air-flows 864 to about-30 ℉ to-40 ℉.Cooler 626 can be for example ethene or propane refrigeration device.Thereby produce cooling light gas stream 678.
Preferably, next light gas stream 678 move through expansion gear 628.Expansion gear 628 can be joule-Tang Pusen (" J-T ") valve for example.The work of 628 quenchers of expansion gear is in order to obtain the further cooling to light gas stream 678.The temperature that expansion gear 628 further reduces light gas stream 678 to for example approximately-70 ℉ to-80 ℉.Preferably, also realize the partial liquefaction at least of gas stream 678.The cooling acid flow is with pipeline 611 indications.
Cooling acid gas in the pipeline 611 is directed to destilling tower.For example, destilling tower can be the CFZ tower 100 of Fig. 1 and 6.Remove the acid gas in the system handles pipeline 611 through sour gas then.Sour gas is removed system can for example remove system 650 according to the sour gas of Fig. 6.
Another method of from flow of feed gas, removing sulfur component is through using the scavenger in the scavenger bed.The use of known scavengers is as from air-flow, removing H in gas treatment industry 2The method of S and mercaptan.Scavenger can be a solid, and they can be liquid forms, and perhaps they can be catalyst solutions.
Scavenger is converted into innoxious compound such as metal sulfide with mercapto compound and other sulfur-containing compound.Can handle compound safely and with the mode (environmentally sound manner) of environmental protection.H in flow of feed gas 2When the low consequently conventional amine processing of S component was infeasible economically, scavenger had special effectiveness.An instance is H 2The S component is less than about 300ppm.
The instance of known liquid-type scavenger is a triazine.Instance is 1,3 more specifically, and the water of 5 three-(2-ethoxy)-six hydrogen-S-triazine becomes preparation.Another instance of liquid-type scavenger is a nitrite solution.
The instance of solid scavenger is iron oxide (FeO, Fe 20 3Or Fe 3O 4) and zinc oxide (ZnO).The solid scavenger is normally non-renewable.After non-renewable scavenger bed loses usefulness, must replacement.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, depend on H 2The initial level of S possibly need subsequent dewatering.
The most common ground is through a kind of application hydrogen sulfide scavenger in three kinds of methods.At first, the batch applications of alveolar fluid clearance agent can be used for the spray tower contactor.Secondly, the batch applications of solid scavenger can be applicable to fixed bed contactor.The 3rd, can adopt the alveolar fluid clearance agent directly to be injected into container continuously.This is prevailing application.
Conventional directly injection H 2S removes and uses pipeline as contactor.In this application, liquid H 2S scavenger such as triazine are injected into air-flow.With H 2S absorbs to removing in the solution.Make H 2The S reaction is to form the accessory substance of from flow of feed gas, removing and abandoning subsequently.H 2An optional method of the direct injection that S removes relates to liquid injection the passing through aperture that under high pressure forces scavenger.Usually, use atomizer so that alveolar fluid clearance agent atomizing is very little drop.For many application, the potential that direct method for implanting has minimum totle drilling cost is because low with respect to its capital cost of batch applications.
Fig. 9 is presented in the embodiment according to the sketch map of from air-flow, removing the gas processing device 900 of sour gas of the present invention.In this is arranged, remove system 950 upper reaches through scavenger at sour gas and from flow of feed gas 912, remove hydrogen sulfide.
Fig. 9 has shown the gas processing device 900 that receives extraction air-flow 912.Extraction air-flow 912 comes from the hydrocarbon that occurs in reservoir exploitation district or " oil field " 910 activity of gathering.Should be appreciated that oil field 910 can represent any position that produces 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 2The S scavenger.Can adopt any of above-mentioned sweep-out method.Illustrative sulfur component is removed system 950 and is used above-mentioned the third method, i.e. 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.Simultaneously, alveolar fluid clearance agent such as triazine are introduced into pipeline 922 through scavenger pipeline 944.Triazine is injected through atomizer 923, and then with static mixer 925 in flow of feed gas 912 mix.From there, the flow of feed gas 912 of contact gets into separation container 920.
Separation container 920 delimit chamber 926.The bottom of liquid inlet chamber 926, simultaneously gaseous component 926 top leaves in the chamber.Liquid is discharged through liquid line 927.Liquid comprises spent scavenger material.Partially liq from pipeline 927 is removed as flowing out the liquid refuse.Waste line 942 will flow out the liquid refuse and guide to preservation groove (not shown) or other refuse storage area.Refuse can leave through truck or through the processing pipeline transportation.If scavenger does not lose usefulness fully, can be back to scavenger pipeline 944 with contact flow of feed gas 912 by guiding once more from the residual fraction of the liquid of pipeline 927.
Sulfur component is removed system 950 and is also comprised scavenger container 930.Scavenger container 930 is preserved the alveolar fluid clearance agent.Like needs, the operator feeds scavenger pipeline 944 with the alveolar fluid clearance agent of scavenger container 930.Provide pump 946 to be used for the alveolar fluid clearance agent is injected into the pressure of pipeline 922 with increase.
Referring to separation container 920, separation container 920 can comprise demister (mist eliminator) 924 once more.Demister 924 helps prevent liquid particles along with gaseous component is overflowed by the top of 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 moves in separation container 920.Demister is known.The Separation Products company that a source of demister is Texas Alfven.Separation Products manufactured trade name is Amistco TMDemister.
Gaseous component leaves separation container 920 through overhead gas pipeline 945.Gaseous component is mainly methane and carbon dioxide.Ethane, nitrogen, helium and the aromatic compound that also can have trace constituent.Gas in the pipeline 945 can be described as acid gas.Acid gas in the gas line 945 is brought to dewatering container 960.
Because the scavenger method uses material based on water from flow of feed gas 912, to separate H 2S need be to the gas dewatering in the pipeline 945 before low-temperature carbon dioxide is removed.Because the acid gas in the gas line 945 through dewatering container 960, is produced current 962.Current 962 can be sent to water treatment facilities.Alternatively, current 962 can be re-injected to subsurface formations, like the subsurface formations 630 of Fig. 6.Still alternatively, can handle the current 962 removed to satisfy environmental standard and to be released into local basin (not shown) as the water of having handled then.
Equally, because the acid gas in the pipeline 945 through dewatering container 960, produces the air-flow 964 of basic dehydration.Dehydration air-flow 964 is through cooler 626.The temperature of cooler 626 cooled dehydrated air-flows 964 to about-30 ℉ to-40 ℉.Cooler 626 can be for example ethene or propane refrigeration device.Thereby produce the light gas stream 678 of cooling.
Preferably, next light gas stream 678 move through expansion gear 628.Expansion gear 628 can be joule-Tang Pusen (" J-T ") valve for example.The work of 628 quenchers of expansion gear is in order to obtain the further cooling to light gas stream 678.The temperature that expansion gear 628 further reduces light gas stream 678 to for example approximately-70 ℉ to-80 ℉.Preferably, also realize the partial liquefaction at least of air-flow 678.The cooling acid flow is with pipeline 611 indications.
Cooling acid gas in the pipeline 611 guides to destilling tower.For example, destilling tower can be the CFZ tower 100 of Fig. 1 and 6.Remove system through sour gas then, handle cooling blast.Sour gas is removed system can for example remove system 650 according to the sour gas of Fig. 6.
This paper proposes is used for removing and has sulfydryl (--another method of organosulfur compound SH) is through being called the method for CrystaSulf method.The CrystaSulf method is by the exploitation of Texas Austin's CrystaTech company.The CrystaSulf method utilizes improved liquid-phase claus reaction method from flow of feed gas, to remove H 2S.
" Claus method " is sometimes by the method that from gas stream containing hydrogen sulphide, reclaims elementary sulfur of natural gas and rendering industry use.In brief, the Claus method of generation elementary sulfur comprises two major sections.First section is hot arc, wherein at about 1,800 ℉ to 2, and combustion parts H under 200 ℉ 2S is SO 2, and the SO that forms 2With residual H 2The S reaction produces elementary sulfur.There is not catalyst at hot arc.Second section is catalytic section, and wherein (like aluminium oxide) produces elementary sulfur under the temperature between 400 ℉ to 650 ℉ on the catalyst that is fit to.The reaction that produces elementary sulfur is balanced reaction; Therefore, separating 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 separates.
Term " CrystaSulf " not only refers to method, and refers to be used for the solvent of this process.CrystaSulf is the non-water physical solvent of dissolved hydrogen sulfide and sulfur dioxide, is elementary sulfur so that they can directly react.CrystaSulf
Figure BDA0000159581960000402
solvent is sometimes referred to as liquid (liquor) or eccysis liquid (scrubbing liquor).In the CrystaSulf method, use non-washing to remove liquid and from air-flow, remove hydrogen sulfide.Eccysis liquid can be the organic solvent such as the phenyl xylyl ethane of elementary sulfur.Normally, nonaqueous solvents can be selected from the substituted naphthalene of alkyl; Diaryl alkane; Comprise phenyl xylyl ethane, like phenyl-ortho-xylene base ethane, phenyltoluene base ethane, phenyl napthyl ethane, phenyl aryl alkane, benzyl ether, diphenyl ether; Partially hydrogenated terphenyl, partially hydrogenated diphenylethane, partially hydrogenated naphthalene; And their mixture.
Usually, CrystaSulf
Figure BDA0000159581960000403
Solvent adopts SO 2As oxidant.This makes claus reaction (2H 2S+SO 2->3S+2H 2O) take place in mutually at solvent.In other words, sulfur dioxide is added into solvent solution to obtain better H 2S removes.
At United States Patent (USP) 6,416, the CrystaSulf method has been described in 729.Should ' 729 patent names be " from comprising or being supplemented with the method (Process for Removing Hydrogen Sulfide from Gas Streams Which Include or are Supplemented with Sulfur Dioxide) of removing hydrogen sulfide the air-flow of sulfur dioxide ".Should ' 729 patents incorporate in full by reference at this.At United States Patent (USP) 6; 818; Other embodiment of CrystaSulf method is disclosed in 194; Its name is called " through with non-water absorbent eccysis, from comprising or be supplemented with the method (Process for Removing Hydrogen Sulfide From Gas Streams Which Include or Are Supplemented with Sulfur Dioxide, by Scrubbing with a Nonaqueous Sorbent) of removal hydrogen sulfide the air-flow of sulfur dioxide ".Should ' 194 patents also incorporate into by reference at this.
Figure 10 shows the sketch map of from air-flow, removing the gas processing device 1000 of sour gas in another embodiment.In this is arranged, remove system 650 upper reaches through the CrystaSulf method at sour gas and from flow of feed gas 1012, remove hydrogen sulfide.The CrystaSulf process is the part that the sulfur component that is used to remove hydrogen sulfide is removed system 1050.
Figure 10 has shown the gas processing device 1000 that receives extraction air-flow 1012.Extraction air-flow 1012 comes from the hydrocarbon that occurs in reservoir exploitation district or " oil field " 1010 activity of gathering.Oil field 1010 and above-mentioned oil field 810 and 910 synonyms.Hydrocarbon produces from the 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 from flow of feed gas 1012, to remove sulfur component according to the CrystaSulf method, flow of feed gas 1012 is directed to absorber 1020.Simultaneously, liquid SO 2Be introduced into absorber 1020 through pipeline 1084.Add liquefaction sulfur dioxide as oxidizing gas.
Liquid SO 2Be kept at first in the reservoir vessel 1080.Like needs, SO 2Pipeline 1082 will be from the liquid SO of reservoir vessel 1080 2Be delivered to pipeline 1084.Provide pump 1076 to be used to increase pressure so that with liquid SO along pipeline 1082 2Move to absorber 1020.
Absorber 1020 delimit chamber 1025.In absorber 1020, the flow of feed gas 1012 and the SO that contains from pipeline 1084 2Liquid flux contact.Liquid sinks to the bottom of chamber 1025, and simultaneously gaseous component 1025 top leaves in the chamber.The liquid that is called absorbent leaves through liquid line 1022.Absorbent generally includes the solution of sulphur and water, together with methane and the remaining hydrogen sulfide and/or the sulfur dioxide of trace constituent.
Through pipeline 1022 guiding liquids to the bottle 1030.Bottle 1030 is used for from solvent flashing water outlet and any hydrocarbon gas of carrying secretly.Sulfur-bearing solution leaves bottle through tower bottom flow 1036.Simultaneously, the hydrocarbon gas and trace water steam leave overhead 1032.
Overhead 1032 is carried through compressor 1034.The pressure that increases overhead 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 the pipeline 1044 guides to the treatment facility (not shown).
The hydrocarbon gas discharges from separation container 1040 through pipeline 1042.The hydrocarbon gas in the pipeline 1042 and flow of feed gas 1012 merge.From there, the hydrocarbon gas gets into absorber 1020 once more.
Referring to bottle 1030, notice that once more bottle discharges sulfur-bearing solution through tower bottom flow 1036.Sulfur-bearing solution moves into cooling circuit 1038.Sulfur-bearing solution with merge from the part clarified solution of pipeline 1058.Clarified solution can comprise for example other physical solvent.
, sulfur-bearing solution increases the pressure in the cooling circuit 1038 when moving through centrifugal pump 1052.From there, cooling sulfur-bearing solution in PTFE heat exchanger 1054.When sulfur-bearing solution when the heat exchanger 1054, it is cooled to below the saturation temperature of sulphur of dissolving.Sulfur-bearing solution is for sulphur the become supersaturation so the crystallization of dissolving.
The sulfur-bearing solution of cooling and crystallization gets into crystallizer 1055.Particularly, be directed into the bottom of crystallizer 1055 from the sulfur-bearing solution of pipeline 1038.Sulphur crystal in the sulfur-bearing solution of the cooling decanting zone 1059 interior with being present in crystallizer 1055 contacts.Crystal rises to the work of the supersaturation sulphur solution inoculation deposition in order to the sulphur of realizing dissolving.This forms the sulphur slurry.
The sulphur slurry leaves crystallizer 1055 through sulphur slurry pipeline 1056.Sulphur in the pipeline 1056 slurry is delivered to filter 1060.Filter 1060 is separated into pure solid-state sulphur and clarified solution with the sulphur slurry.The removal of solid-state sulphur is through pipeline 1062 expressions.Clarified solution discharges through pipeline 1064 as filtrating and recirculation is back to crystallizer 1055.Preferably, provide pump 1066 to be used for moving clarified solution and be back to crystallizer 1055.
Clarified solution rises to the top of crystallizer.The part clarified solution is derived from crystallizer 1055 through pipeline 1058.The clarified solution of pipeline 1058 with merge to form cooling circuit 1038 from the sulphur solution of bottle 1036, as above discuss.Extract the separating part of clarified solution from the top of crystallizer 1055 through pipeline 1072.Extract through heat exchanger 1074 heating pipelines 1072.The liquid of heat and the sulfur dioxide of pipeline 1082 merge.Obtain the liquid 1074 of heat through booster pump 1076, and and then guide to the chamber 1025 of absorber 1020.
Should be appreciated that the CrystaSulf method that combines sulfur component to remove system's 1000 descriptions only is illustrative.Can use those other CrystaSulf methods of describing as in United States Patent (USP) of incorporating into 6,416,729 and United States Patent (USP) 6,818,194.Regardless of method, from absorber 1020, produce overhead gas stream 1045.
Overhead gas stream 1045 mainly contains methane and carbon dioxide.Ethane, nitrogen, helium and the aromatic compounds that also can have trace constituent.Sulfur component has been extracted and has transported through pipeline 1062 and left.Overhead gas stream 1045 can be called as acid gas.Preferably, the acid gas in the air-flow 1045 brings to dewatering container 1060.But,, can before flow of feed gas 1012 gets into sulfur component removal system 1050, dewater because the CrystaSulf method is non-water.
Overhead gas stream 1045 is through cooler 626.Cooler 626 is cooled to about-30 ℉ temperature to-40 ℉ with air-flow 1045.Cooler 626 can be for example ethene or propane refrigeration device.Thereby, produce the light gas stream 678 of cooling.
Preferably, next light gas stream 678 move through expansion gear 628.Expansion gear 628 can be for example joule-Tang Pusen (" J-T ") valve or other device of combining Fig. 6 to describe.The temperature that expansion gear 628 further reduces light gas stream 678 to for example approximately-70 ℉ to-80 ℉.Preferably, also realize the partial liquefaction at least of air-flow 678.Move cooling blast through pipeline 611.
Cooling acid gas in the pipeline 611 is directed to destilling tower.For example, destilling tower can be the CFZ tower 100 of Fig. 1 and 6.Remove system, the cooling acid gas of processing pipeline 611 through sour gas then.The system of removing sour gas can for example according to the sour gas removal system 650 that is used to remove carbon dioxide of Fig. 6.
Be used in the low temperature distillation tower upper reaches and remove the use that two kinds of other methods of appropriate level's hydrogen sulfide at least relate to adsorbent bed.A kind of method adopts alternating temperature absorption, and another kind utilizes transformation absorption.Adsorbent bed is a molecular sieve.In every kind of situation, the said molecular sieve of regenerating.
Molecular sieve usually is used for dehydration, also can be used for removing H 2S and mercaptan.Usually, in single packed bed, combine these operations, this single packed bed has the layer of 4A molecular screen material at the top, be used for dehydration, and has the layer of 13X molecular screen material in the bottom, is used to remove H 2S and mercaptan.Thereby flow of feed gas not only had been dried but also desulfurization.
Figure 11 has presented the sketch map of from air-flow, removing the gas processing device 1100 of sour gas in another embodiment.In this is arranged, remove system 650 upper reaches through temperature swing adsorption system 1150 from sour gas and remove the hydrogen sulfide the flow of feed gas 624.
Gas processing device 1100 is operated according to the gas processing device 600 of Fig. 6 substantially.In this respect, dehydration air-flow 624 is delivered to sulfur component and removes system.From there, the acid gas that mainly comprises methane and carbon dioxide is cooled and is transported to sour gas through pipeline 611 and removes system 650.But, replace using solvent system 605 to remove system as sulfur component together with absorber, use temperature swing adsorption system 1150.Temperature swing adsorption system 1150 provides part separate hydrogen sulfide at least from dehydration air-flow 624.
Temperature swing adsorption system 1150 uses adsorbent beds 1110 with optionally adsorption of hydrogen sulfide and other sulfur component, the light gas that contains methane and carbon dioxide is flowed pass through.Show that at pipeline 1112 light gas stream is released.Light gas stream 1112 is delivered to destilling tower such as Fig. 1 as acid flow tower 100 is with carbon dioxide and methane separation.
Preferably before getting into low temperature distillation tower 100, provide pre-cooled to light gas stream 1112.In illustrative gas processing device 1100, light gas stream 1112 passes through refrigerating plant 626, and then through expansion gear 628.Expansion gear 628 can be joule-Tang Pusen (" J-T ") valve for example.Preferably, realize the partial liquefaction at least of light gas stream 1112 together with cooling.Produced the cooling acid flow, it guides to sour gas through pipeline 611 and removes system 650.
Referring to temperature swing adsorption system 1150, preferably, the adsorbent bed 1110 in temperature swing adsorption system 1150 is molecular sieves of being made by zeolite once more.But, can adopt the bed of other adsorbent bed as making by silica gel.The those of ordinary skill of hydrocarbon gas separation field will be understood, and the composition with the pollutant that is removed is generally depended in the selection of adsorbent bed.In this situation, pollutant mainly is a hydrogen sulfide.
In operation, adsorbent bed 1110 will place in the compression chamber.Adsorbent bed 1110 receives dehydration air-flow 624 and adsorption of hydrogen sulfide and other sulfur component together with a certain amount of carbon dioxide.At the bed basic H that becomes 2After S is saturated, the adsorbent bed 1110 in the adsorption system 1150 will be replaced with Regenerative beds.Owing to use dry this bed of heated air heating, H 2S will discharge from bed 1110.The gas that is fit to comprises the obtainable fuel gas of a part, heated nitrogen or alternate manner of cat head methane stream 112.
Frame 1140 has been described 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 cat head methane stream 112.Cat head methane stream 112 mainly comprises methane, but also can comprise trace nitrogen and helium.Compressible cat head methane stream 112 is with the gas pressure in the rising regeneration room.Show booster 1130.But regeneration is main to be taken place through the temperature that raises, although it strengthens through lower pressure usually.
The cat head methane stream 112 of 10 to 15 percentages can be used to regenerate 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 number of C O 2
For the alternating temperature regeneration cycle, preferred adopt at least three adsorbent beds: first is used for absorption, as showing 1110; In regeneration room 1140, regenerate for second; With the 3rd be reproduced and subsequent use to become abundant and in adsorption system 1150, use when saturated when first 1110.Therefore, for more efficient operation, minimum three beds of parallel use.These beds can for example be filled with silica gel.
As visible among Figure 11, from adsorption system 1110, discharge dense H through pipeline 1114 2The S air-flow.Dense hydrogen sulfide stream 1114 also plays recovery stream.Recovery stream 1114 mainly comprises CH 4And H 2S, but also comprise trace carbon dioxide and some possible heavy hydrocarbons probably.On the one hand, use refrigerating plant 1116 cooling recovery stream 1114.This causes the partial liquefaction at least of recovery stream 1114.Then recovery stream 1114 is introduced separator 1120.Preferably, separator 1120 is gravity separators, and it separates the water in the recovery stream 1114 with light gas.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 dehydration air-flow 624.Simultaneously, the hydrogen sulfide of water, heavy hydrocarbon (being mainly ethane) and dissolving discharges (schematically showing at pipeline 1124) from the bottom of separator 1120.In some were carried out, the recyclegas in the pipeline 1122 possibly need to handle H 2S is to guarantee that it is not through system's recirculation.
Notice that randomly, gas processing device 1100 can not comprise dewatering unit 620.Water will leave the acid flow that solid adsorbent bed 1110 also will not transfer to pipeline 611 with recovery stream 1114.Water will further leave separator 1120 with the hydrogen sulfide of pipeline 1124.Can accomplish separating of water and sulfur-containing compound through using acid water stripper for example or other separator (not shown) then.
In an application, incendivity from the waste gas of regeneration gas heaters 1140 to drive the turbine (not shown).Turbine can drive open loop compressor (like the compressor 176 of Fig. 1) again.Regeneration gas heaters 1140 can further be bonded to sour gas and remove process through obtain used heat and the regeneration gas that uses it to preheat to be used for the heavy hydrocarbon removal process (as at pipeline 1132) from this turbine.Similarly, the heat from cat head compressor 114 can be used for preheating the regeneration gas that is used for the hydrogen sulfide removal process.
Can be observed, regeneration gas contains the H from Solid Bed 1110 desorbs here 2S.That gas can contact with solvent to remove H 2S also reclaims methane and any other hydrocarbon.Like this, can remedy the BTU value of gas.
Notice that transformation absorption also is used in the acid gas removal facility upper reaches and removes hydrogen sulfide and other sulfur component.Transformation absorption or " PSA " are often referred to wherein pollutant are adsorbed on the process on the solid adsorbent bed.After saturated, through reducing its pressure regeneration solid absorbent.Reduce pressure and cause that pollutant is released as lowpressure stream.
Figure 12 provides the sketch map that uses transformation absorption to remove the gas processing device 1200 of hydrogen sulfide.Gas processing device 1200 is operated according to the gas processing device 600 of Fig. 6 substantially.In this respect, cooled dehydrated air-flow 624 and be delivered to sour gas through acid gas pipeline 611 then and 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 part separate hydrogen sulfide at least.
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 molecular sieves of being made by zeolite.But, can adopt the bed of other adsorbent bed as making by silica gel.The selection that the those of ordinary skill of hydrocarbon gas separation field will be understood adsorbent bed once more will be depended on the composition of flow of feed gas 624 usually.
As visible among Figure 12, adsorption system 1250 discharges methane gas through light gas stream 1212.Before getting into low temperature distillation tower 100, carry light gas 1212 through refrigerating plant 626 and then preferably through joule-Tang Pusen valve 628.Simultaneously, discharge dense hydrogen sulfide stream through pipeline 1214 from adsorbent bed 1210.
In operation, the adsorbent bed 1210 in the pressure swing adsorption system 1250 is present in the compression chamber.Adsorbent bed 1210 receives dehydration air-flow 624 and adsorbs H 2S and any residual water and any heavy hydrocarbon.Also adsorbable trace carbon dioxide.Bed 1210 become with hydrogen sulfide and other sulfur component saturated after, adsorbent bed 1210 will be replaced.Owing to reduced the pressure in the compression chamber, H 2S (and heavy hydrocarbon, if the words that have) will from bed, be released.Produce dense hydrogen sulfide stream 1214 then.
As a rule, the pressure in the compression chamber is reduced to environmental pressure and will cause that the most hydrogen sulfide in the dense hydrogen sulfide stream 1214 discharge from adsorbent bed 1210 with other pollutant.But, in some extreme cases, can help pressure swing adsorption system 1250 through using vacuum chamber to apply pressure to the dense hydrogen sulfide stream 1214 that is lower than environment.This is with frame 1220 indications.In the presence of low-pressure more, sulfur component and heavy hydrocarbon will be from constituting the solid matrix desorb of adsorbent bed 1210.
The mixture of water, heavy hydrocarbon and hydrogen sulfide will leave vacuum chamber 1220 through pipeline 1222.Mixture will get into separator 1230.Separator 1230 is preferably the gravity separator that heavy hydrocarbon and water are separated with hydrogen sulfide.Discharge liquid component (schematically showing) at pipeline 1234 from the bottom.At the H that handles dissolving 2Behind the S, any heavy hydrocarbon in the pipeline 1234 can be sent to commercial distribution.Discharge the hydrogen sulfide (schematically showing) of gaseous form at pipeline 1232 from the top of separator 1230.The H of pipeline 1232 2S is sent to the sulfur recovery unit (not shown) or injects subsurface formations as the part of sour gas.
Pressure swing adsorption system 1250 can rely on a plurality of parallel beds.Be used for absorption for first 1210.This is called as the use bed.Second (not shown) regenerated through decompression.The 3rd is reproduced and subsequent use with when the first 1210 complete use in adsorption system 1250 when saturated that becomes.Therefore, for more efficient operation, can walk abreast and use minimum three beds.These beds can be for example with active carbon or molecular sieve filled.
Pressure swing adsorption system 1250 can be a rapid cycle pressure swing adsorption systems.In so-called " Rapid Cycle " method, can lack to several seconds circulation timei.Because Rapid Cycle PSA (" RCPSA ") unit is very little with respect to normal PSA device, so it is with advantageous particularly.Notice that inlet gas possibly need preliminary treatment.Alternatively, but at the top of packed bed the sacrifice layer of materials used with the protection active material.
On the one hand, can use the combination of alternating temperature regeneration and pressure swing regeneration.
Another method of removing heavy hydrocarbon at the sour gas removal system upper reaches that this paper proposes is the method that is called as adsorption dynamics adsorption kinetics separation or AKS.AKS adopts the solid absorbent of new relatively kind, and it depends on some kind and is attracted to the speed on the structuring adsorbent with respect to other kind.The change adsorption method of conventional balanced-control that this mainly gives through the equilibrium adsorption performance of solid absorbent with selectivity wherein forms and contrasts.Under latter event, the competitive Adsorption thermoisopleth of lighter products is disadvantageous in adsorbent micropore or free volume.
In the change adsorption method of dynamics Controlling, selectivity is mainly given through the diffusion of adsorbent and through the transport diffusion coefficient in the micropore.Adsorbent has " dynamics selectivity " for one or more gas components.Use like this paper, term " dynamics selectivity " is defined as for two kinds of variety classeses, and the one-component diffusion coefficient D is (with m 2/ sec meter) ratio.These one-component diffusion coefficients also are called as Si Difen-Maxell transport diffusion coefficient, and it is measured for given pure gas component, given adsorbent.Therefore, for example, component A will equal D with respect to the dynamics selectivity of the concrete adsorbent of B component A/ D BThe one-component diffusion coefficient of material can be confirmed through the well-known test in sorbing material field.
The method for optimizing of measuring the dynamics diffusion coefficient is at " frequency modulating method (Frequency Modulation Methods for Diffusion and Adsorption Measurements in Porous Solids) that diffusion and absorption are measured in the porosu solid " with people such as Reyes; The frequency response technology of describing among the J.Phys.Chem.B.101, pp.614-622 (1997).In the separation of dynamics Controlling, preferred first component (for example component A) (is D with respect to the dynamics selectivity of the selected adsorbent of second component (for example B component) A/ D B) greater than 5, more preferably greater than 20, and even more preferably greater than 50.
Preferred adsorbent is a zeolitic material.The limiting examples that is used to remove the zeolite with suitable aperture of heavy hydrocarbon comprises MFI zeolite, faujasite, MCM-41 zeolite and β zeolite.Preferably, the zeolite Si/Al ratio that is used for removing the inventive method embodiment of heavy hydrocarbon is about 20 to about 1,000, preferably about 200 to about 1,000, to prevent excessively the silting up of adsorbent (fouling).Other technical information about using adsorption dynamics adsorption kinetics to separate hydrocarbon gas component is that United States Patent (USP) discloses 2008/0282884, and its whole disclosures are incorporated at this by reference.
Figure 13 is the sketch map that shows gas processing device 1300 of the present invention in another embodiment.In this is arranged, remove system 650 upper reaches at sour gas and from air-flow, remove hydrogen sulfide through the adsorbent bed 1310 that utilizes absorption power to separate.
Gas processing device 1300 is operated according to the gas processing device 600 of Fig. 6 A substantially.In this respect, dehydration air-flow 624 cools off in preliminary refrigerating plant 625 and is delivered to sour gas through the acid flow in the pipeline 611 then and removes system 650.But, replace sour gas remove system 650 upper reaches 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.
In present adsorption dynamics adsorption kinetics separating application, 2 S component will be adsorbed bed 1310 to be kept.This means H 2S will be in the lower pressure recover.Can use adsorbent bed 1310 with transformation absorption or the absorption of Rapid Cycle transformation.After pressure reduced, under low pressure natural gas liquids stream 1314 discharged from solid adsorbent bed.Natural gas liquids stream 1314 contains the most of sulfur component in the dehydration air-flow 624, and also can contain heavy hydrocarbon and trace carbon dioxide.
For hydrogen sulfide is separated with heavy hydrocarbon with carbon dioxide, need other distillation column.Show distil container 1320.Distil container 1320 can be for example to coil or filled column as the shop of pollutant scavenge system.Discharge hydrogen sulfide and carbon dioxide through overhead 1324.Preferably, pipeline 1324 merges sour gas is injected into reservoir 1349 with sour gas pipeline 646.Acid heavy hydrocarbon and most of hydrone leave distil container 1320 through bottom line 1322.Heavy hydrocarbon can be the form of natural gas liquids, i.e. ethane and possible propane.Handle natural gas liquids to remove H 2S also catches to sell.
The adsorption dynamics adsorption kinetics separation method that should be noted that system 1300 possibly be more useful for recovery hydrogen sulfide and heavy hydrocarbon from the natural gas flow that under big excess pressure, produces.In this case, the acid gas of pipeline 611 has suitable pressure to be processed through low temperature distillation tower 100.The instance of excess pressure can be the pressure greater than 400psig.
Adsorbent bed 1310 discharges light gas stream 1312.Gas in the stream 1312 mainly is made up of methane and carbon dioxide.Preferably supply to be cooled to the light gas in the stream 1312 in entering low temperature distillation tower 100 prerequisites.In illustrative gas processing device 1300, the light gas in the stream 1312 passes through refrigerating plant 626, and then through expansion gear 628.In pipeline 611, produce the cooling acid flow, it is directed to sour gas and removes system 650.
In another commonsense method that is used for removing heavy hydrocarbon, from tower bottom flow 646, extract heavy hydrocarbon at destilling tower 100 " downstream ".In an example, adopt absorption power separation method in low temperature distillation tower downstream.
Figure 14 has presented the sketch map of the gas processing device 1400 that adopts absorption power separation method.This gas processing device 1400 is accordinged to the gas processing device 1300 of Figure 13 substantially.But, substitute in the situation of 650 upper reaches use AKS of sour gas removal system solid adsorbent bed 1310 at this, remove system 100 downstream at sour gas and use AKS solid adsorbent bed 1410.
Visible in Figure 14, from destilling tower 100, removing sour gas is hydrogen sulfide and carbon dioxide, as liquefaction acid gas stream 642 at the bottom of the tower.Randomly, this flow of liquid 642 can be passed through reboiler 643, and the gas that contains trace amounts of methane at reboiler 643 places is guided as air-flow 644 to be back to tower 100 once more.Discharge the residual liquid that mainly contains sour gas through sour gas pipeline 646.
Sour gas from pipeline 646 is transported to AKS solid adsorbent bed 1410.When they through bed 1410 the time, sour gas is still cold and exists with liquid phase.Hydrogen sulfide and any heavy hydrocarbon are removed from sour gas and are discharged through pipeline 1412 as natural gas liquids stream 1412.Simultaneously, sour gas discharges through AKS solid adsorbent bed 1410 and as acid gas stream at the bottom of the tower 1414.
Sour gas at the bottom of the tower in the acid gas stream 1414 still mainly is a liquid phase.Liquefaction sour gas in the pipeline 1414 mainly is CO 2, and can be evaporated.Alternatively, the liquefaction sour gas of pipeline 1414 can be injected into subsurface formations through one or more sour gas injection (AGI) wells like frame 649 indications.In this case, the sour gas in the pipeline 646 is preferably through booster 648.
Should be noted that natural gas liquids stream 1412 contains heavy hydrocarbon and hydrogen sulfide and trace carbon dioxide.Therefore, carry out still-process from natural gas liquids stream 1412, to separate H 2S and CO 2Show distil container 1420.H 2S and trace CO 2Gas discharges from distil container 1420 through overhead 1424.Preferably, pipeline 1424 merges with acid gas stream at the bottom of the tower 1414, to inject sour gas to reservoir 649.Heavy hydrocarbon leaves container 1420 through bottom line 1422 and is hunted down to sell.
Figure 15 A is the sketch map of gas processing device of the present invention 1500 in another embodiment.In this is arranged, remove system 650 downstream through extractive distillation process at sour gas and from air-flow, remove hydrogen sulfide.Extractive distillation process is through frame 1550 expressions.
This illustrative gas processing device 1500 is accordinged to the gas processing device 600 of Fig. 6 substantially.In this respect, dehydration air-flow 624 is cooled and is transported to sour gas through acid gas pipeline 611 then and removes system 650.But, replace removing system 650 upper reaches and use solvent contact system 605 together with contact tower at sour gas, remove system 650 downstream at sour gas and use extractive distillation process.
Visible in Figure 15 A, the cooling acid gas is through pipeline 611 and get into sour gas removal system 650.Cooling acid gas in the pipeline 611 has and the same composition of dehydration flow of feed gas 624.Acid gas in the pipeline 611 comprises methane and hydrogen sulfide and carbon dioxide.Nitrogen, helium and the aromatic compound that also can have ethane and trace constituent.
Acid gas in the pipeline 611 at first gets into post 100.This CFZ tower 100 with Fig. 1 and 6 is identical.As above discuss, CFZ tower 100 is separated into acid gas stream 642 at the bottom of cat head methane stream 112 and the tower with acid gas.In this case, acid gas stream 642 comprises carbon dioxide and hydrogen sulfide at the bottom of the tower.
Randomly, tower bottom flow 642 can send through reboiler 643.From there, the fluid that contains methane is guided as hydrocarbon stream 644 to be back to tower 100 once more.The residual fluid that mainly contains hydrogen sulfide and carbon dioxide discharges through sour gas pipeline 646.Material in the sour gas pipeline 646 is a liquid form, and gets into extractive distillation system 1550.
Figure 15 B is the detailed maps that is used for the gas processing device 1550 of extractive distillation process.It is thus clear that pipeline 646 brings to extractive distillation equipment 1550 with sour gas.In the illustrative layout of Figure 15 B, three extractive distillation posts 1510,1520 and 1530 have been shown.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, the solvent absorbing hydrogen sulphide makes solvent leave post 1510 as solvent column underflow 1514.It also will contain some carbon dioxide and heavy hydrocarbon.Simultaneously, the light hydrocarbon of carbon dioxide and trace leaves post 1510 through overhead streams 1554.The carbon dioxide of stream in 1554 can inject pipeline 1552 with sour gas and combine to be injected into subsurface formations (Figure 15 A 649).
Solvent column underflow 1514 gets into the second extractive distillation post 1520.The second extractive distillation post 1520 is CO 2Remove post.CO 2The temperature of removing in the post 1520 is substantially 0 ℉ to 250 ℉, and it is higher than the temperature in the propane recovery post 1510.At CO 2Remove in the post 1520, solvent and heavy hydrocarbon leave post 1520 as the second solvent column underflow 1524.Simultaneously, carbon dioxide leaves second post 1520 as cat head CO 2Stream 1552.Preferably, cat head CO 2Stream 1552 is used to improve the recovery ratio method and recovers the oil.
Terminal cylinder 1530 shows in Figure 15 B.Terminal cylinder 1530 is that additive reclaims post.Additive reclaims post 1530 and utilizes the distillation principle from solvent, to separate the heavy hydrocarbon component that is called " natural gas liquids ".Temperature in the 3rd post 1530 is substantially 80 ℉ to 350 ℉, and it is higher than the temperature in second post 1530.Natural gas liquids leaves post 1530 and is brought to through pipeline 1532 and is used to remove any residual H 2S and CO 2Processing unit.For example, this processing unit can be that wherein amine is used to remove H 2S/CO 2Liquid-liquid extractor.
Solvent leaves additive as tower base solvent stream 1534 and reclaims post 1530.The additive of tower base solvent stream 1534 expression regeneration.Most of tower base solvent streams 1534 are introduced into first post 1510 that is used for extractive distillation process again.Randomly, flow automatically 1534 excessive solvent can flow 1532 with natural gas liquids and combines to handle through pipeline 1536.
Once more referring to Figure 15 A, preferably, the CO in carbon dioxide in the pipeline 1554 and the pipeline 1552 2In conjunction with and through booster 648 and inject (AGI) wells through one or more sour gas then and be injected into subsurface formations like frame 649 expression.
It is thus clear that many methods can be used for combining sour gas removal method to remove sulfur component.Normally, the method for selection depends on the situation of original natural gas or pending gas.For example, if H 2S concentration is less than about 0.1%, in conjunction with molecular sieve (mole sieve) method possibly be best, in any case because need dehydration.Molecular sieve has the number of C of removal O 2Additional benefits, this can be beneficial to " impure (dirty) " and start.
For in the inlet gas about 0.1% to 10%H 2The situation of S, physical solvent such as Selexol TMIt possibly be best choice.Solvent be dry be desirable because it can be used for inlet gas is dried to some levels.Handle for CFZ, gas can need further to dewater through (littler) mol sieve unit.Dense H from the Selexol unit 2S stream can be handled in sulfur recovery unit (SRU), maybe can be compressed and combines to be used for the down-hole disposal with the CFZ tower bottom flow.
Should be appreciated that to combine any sour gas removal method, just do not utilize the method for " control freezing zone " tower, be used to remove the said method of hydrogen sulfide.Can adopt other low temperature distillation posts.Further, can use other cryogenic distillation method such as whole fractionation.Whole fractionating column is similar to the CFZ tower 100 of Fig. 1, but does not have middle freezing zone.Whole fractionating column generally operating down than CFZ tower 100 higher pressure, more than 700psig, thereby is avoided CO 2Solid forms.But cat head methane stream 112 can contain the CO of significant quantity 2In arbitrary situation, when dehydration air-flow 624 contains the C greater than about 3% 2Or more during heavy hydrocarbon, utilize separation process to remove hydrogen sulfide and expect.
Although benefit and advantage to realize that preceding text propose are fully prepared in invention as herein described significantly, will understand, the present invention can improve, change and change under the situation that does not break away from its spirit.Provide the sour gas that uses the control freezing zone to remove the improvement of the operation of process.These improvement provide and in product gas, have removed H 2S is to very low-level design.

Claims (45)

1. from acid flow, remove the system of sour gas, it comprises:
The sour gas that receives said acid flow is removed system, and the utilization of wherein said sour gas removal system is separated into the overhead gas stream that mainly contains methane with said acid flow and the low temperature distillation tower of acid gas stream at the bottom of the liquefaction tower that mainly contains carbon dioxide; And
Said sour gas is removed the sulfur component at the system upper reaches and is removed system, and wherein said sulfur component removal system receives flow of feed gas and substantially said flow of feed gas is separated into hydrogen sulfide stream and said acid flow.
2. the described system of claim 1, wherein said flow of feed gas contains the sulfur component between about 4ppm and the 100ppm.
3. the described system of claim 2, wherein said low temperature sour gas is removed system and further is included in and gets into the heat exchanger that cools off said acid flow before the said low temperature distillation tower.
4. the described system of claim 3, wherein:
Said low temperature distillation tower comprises distillation zone, bottom and intermediate controlled freezing zone; Said intermediate controlled freezing zone receives the cooling liquid spray mainly contain methane, and said tower receives said acid flow and then said acid flow is separated into acid gas stream at the bottom of cat head methane stream and the said tower; And
The refrigeration plant in said low temperature distillation tower downstream is used to cool off the said cat head methane stream of said cat head methane stream and returning part to said low temperature distillation tower as said chilling spray.
5. the described system of claim 2, wherein said sour gas removal system is whole fractionating system.
6. the described system of claim 2, wherein said sulfur component removal system comprises chemical solvent system.
7. the described system of claim 6, wherein said chemical solvent comprises methyl diethanolamine (MDEA), from Flexsorb
Figure FDA0000159581950000011
family's choice of Solvent property amine or their combination.
8. the described system of claim 6, wherein said chemical solvent system utilize a plurality of and the stream contactor.
9. the described system of claim 8, wherein said chemical solvent system and flow contactor and comprise:
First and flow contactor; It is configured to receive (i) the said flow of feed gas and (ii) second liquid flux, and said first and flow contactor and also be configured to discharge first's desulfurization air-flow of (iii) mainly containing methane and (iv) first's supporting gas Treatment Solution;
Second and flow contactor, it is configured to receive (i) said first desulfurization air-flow and (ii) the 3rd liquid flux, and is configured to discharge (iii) second portion desulfurization air-flow and (iv) second portion supporting gas Treatment Solution; With
Final and flow contactor, it is configured to receive (i) the previous partial desulfurization air-flow and the (ii) liquid flux of regeneration, and is configured to discharge the final desulfurization air-flow that (iii) mainly contains methane and the (iv) final slight gas treatment solution of load;
Wherein:
Said hydrogen sulfide stream comprises said first supporting gas Treatment Solution and said second portion supporting gas Treatment Solution at least in part; And
The liquid flux of said regeneration comprises the solvent streams of regeneration at least in part, and wherein said hydrogen sulfide is removed from said at least first supporting gas Treatment Solution and said second portion supporting gas Treatment Solution basically.
10. the described chemical solvent system of claim 9, it further comprises:
The liquid flux regenerator, it disposes and receives said at least first supporting gas Treatment Solution, and produces the liquid flux of said regeneration.
11. the described gas processing device of claim 9, wherein:
The liquid flux of said liquid flux and said regeneration comprises hindered amine, tertiary amine or their combination.
12. the described system of claim 8, wherein said chemical solvent system and flow contactor and comprise:
First and flow contactor, second and flow contactor and final and flow contactor, these also flow in the contactor each and are configured (i) receiving said flow of feed gas and liquid flux, and (ii) discharge the gas treatment solution of desulfurization air-flow and independent load;
Said first and flow contactor, said second and flow contactor and said final and flow contactor and be configured to and in series carry as each desulfurization air-flow of the air-flow of desulfurization gradually; And
Said final and flow contactor, said second and flow contactor and said first and flow contactor and be arranged in series to carry as each gas treatment solution of the gas treatment solution of enrichment more gradually.
13. the described method of claim 12, wherein:
Said first and flow contactor and receive (i) the said initial air-flow and (ii) second liquid flux, and discharge (iii) first's desulfurization air-flow and (iv) first's supporting gas Treatment Solution;
Said second and flow contactor and receive (i) from said first and flow the said first desulfurization air-flow of contactor and (ii) the 3rd liquid flux, and discharge (iii) second portion desulfurization air-flow and (iv) second portion supporting gas Treatment Solution; And
Said final and flow contactor and receive (i) the previous partial desulfurization air-flow and the (ii) liquid flux of regeneration, and discharge (iii) the gas treatment solution of final desulfurization air-flow and (iv) final slight load.
14. the described system of claim 2, wherein said sulfur component removal system comprises the physical solvent system that utilizes physical solvent.
15. the described system of claim 14, wherein said physical solvent comprises methyl alcohol, tetramethylene sulfone, the Selexol of N-methyl pyrrolidone, propylene carbonate, malonic methyl ester nitrile, cooling TMOr their combination.
16. the described system of claim 14, wherein said physical solvent system comprises:
Receive said flow of feed gas and said flow of feed gas is separated into the absorber of said acid flow and said hydrogen sulfide stream, said hydrogen sulfide stream comprises hydrogen sulfide and liquid physical solvent;
Handle said hydrogen sulfide stream so that at least two separators that hydrogen sulfide is separated with physical solvent; And
Regenerate said physical solvent and return the regenerator of the said physical solvent of part at least to said absorber.
17. the described system of claim 2, wherein:
Said sulfur component removal system comprises at least one solid adsorbent bed that is used for significantly absorbing sulfur component, and said sulfur component is released as said hydrogen sulfide stream when said at least one solid adsorbent bed of regeneration; And
Said at least one solid adsorbent bed makes methane and CO basically 2Through, as said acid flow.
18. the described system of claim 17, wherein said solid adsorbent bed (i) is by the zeolitic material manufacturing, or (ii) comprises at least a molecular sieve.
19. the described system of claim 18, wherein said sulfur component remove system and further comprise the separator that the carbon dioxide in the said hydrogen sulfide stream is separated with sulfur component.
20. the described system of claim 17, wherein said regeneration is the part of pressure-swing absorption process.
21. the described system of claim 20, wherein said at least one solid adsorbent bed comprises at least three adsorbent beds, wherein:
In said at least three adsorbent beds first is used for absorbing hydrogen sulphide;
Regenerate for second in said at least three adsorbent beds; And
In said at least three adsorbent beds the 3rd keeps subsequent use to replace in said at least three adsorbent beds first.
22. the described system of claim 21; Wherein said sulfur component is removed system and is further comprised vacuum; It is used for negative relative pressure is applied to first of said at least three adsorbent beds, to help first desorb hydrogen sulfide from said at least three adsorbent beds before said hydrogen sulfide stream gets into said separator.
23. the described system of claim 17, wherein said regeneration is the part of alternating temperature adsorption process.
24. the described system of claim 23, wherein said at least one solid adsorbent bed comprises at least three adsorbent beds, wherein:
In said at least three adsorbent beds first is used for absorbing hydrogen sulphide;
Regenerate for second in said at least three adsorbent beds; And
In said at least three adsorbent beds the 3rd keeps subsequent use to replace in said at least three adsorbent beds first.
25. the described system of claim 24, wherein:
Said sulfur component is removed system and is further comprised regeneration gas heaters; It is used for (i) and receives regeneration gas; (ii) heat said regeneration gas and (iii) make hydrogen sulfide from the said second adsorbent bed desorb through being applied to said second adsorbent bed from the heat of the regeneration gas that is heated;
Said regeneration gas heaters discharges air-flow to said first solid adsorbent bed, being said hydrogen sulfide stream and said acid flow with said flow separation; And
Said sulfur component is removed system and is further comprised the separator of from said hydrogen sulfide stream, isolating any methane.
26. the described system of claim 25, wherein said sulfur component remove system and further comprise cooler, it receives said hydrogen sulfide stream and before said hydrogen sulfide fluid flows into said separator, cools off said hydrogen sulfide fluid stream.
27. the described system of claim 2, wherein:
Said sulfur component removal system comprises the solid adsorbent bed of at least one remarkable absorbing hydrogen sulphide, and said hydrogen sulfide is released as said hydrogen sulfide stream when said at least one solid adsorbent bed of regeneration; And
Said at least one solid adsorbent bed makes methane and carbon dioxide pass through basically, as said acid flow.
28. the described system of claim 27, wherein said at least one solid adsorbent bed is that absorption power separates bed.
29. the described system of claim 2, wherein said sulfur component removal system comprises oxidation-reduction system.
30. the described system of claim 29, wherein said oxidation-reduction system comprises:
Receive the contactor of said flow of feed gas and chelating oxidized metal, said chelating oxidized metal is mixed with the aqueous solution at the bottom of causing reduction-oxidation reaction and discharging the tower that (i) comprise chelating reducing metal and elementary sulfur and is (ii) comprised the overhead gas stream of methane and carbon dioxide with said flow of feed gas;
Receive the aqueous solution and air at the bottom of the said tower and be provided for the oxidator of the chamber of oxidation reaction, said oxidator discharges the water-based chelated mineral mixture with elementary sulfur;
Receive said water-based chelated mineral mixture also with said separator with water-based chelated mineral mixture separation of elementary sulfur for regeneration metal chelate catalyst solution and elementary sulfur with elementary sulfur; And
Guide the said regeneration metal chelate catalyst of part solution at least to be back to the pipeline of said contactor.
31. the described system of claim 2, wherein said sulfur component removal system comprises the scavenger system.
32. the described system of claim 31, wherein said scavenger system comprises:
The pipeline that mixes with said flow of feed gas of alveolar fluid clearance agent wherein;
Said flow of feed gas is separated into the separation container of said acid flow and spent scavenger stream, and said spent scavenger stream comprises hydrogen sulfide and said alveolar fluid clearance agent.
33. the described system of claim 2, wherein said overhead gas stream not only comprises methane, and comprises helium, nitrogen or their combination.
34. the described system of claim 2, wherein said sulfur component removal system comprises the system that carries out the CrystaSulf method.
35. the described system of claim 34, wherein said sulfur component remove system and further comprise:
Receive (i) said acid flow and (ii) as the absorber of the oxidizing gas of eccysis liquid; Said oxidizing gas mixes to cause chemical reaction with said flow of feed gas, makes said absorber (i) discharge said acid flow and (ii) discharges the absorbent that contains water, hydrogen sulfide and said oxidizing gas;
With said liquid-absorbant be separated into (i) mainly contain the vapor stream of top of the tower of the hydrocarbon gas and any steam of carrying secretly and (ii) sulphur solution the bottle;
From the said hydrocarbon gas, divide dried up and carry the said hydrocarbon gas to be back to the separation container of said flow of feed gas;
Receive the crystallizer of said sulphur solution; Said crystallizer is inoculated the deposition of said sulphur solution with the sulphur of realization dissolving with the sulphur crystal in the decanting zone; Said crystallizer (i) discharges the sulphur slurry from said crystallizer than lower part; (ii) from the top tapping of said crystallizer as said oxidizing gas, the said liquid of part is directed being back to said absorber; And
Said sulphur slurry is separated into the pure solid-state sulphur and the filter of clarified solution, and said clarified solution is directed returning said crystallizer.
36. the described system of claim 2, it further comprises:
Dehydration equipment, it received said flow of feed gas before said flow of feed gas is removed system through said sulfur component, and said flow of feed gas is separated into the dehydration flow of feed gas and significantly contains the stream of aqueous fluids; And
The said flow of feed gas that wherein said sulfur component removal system receives is said dehydration flow of feed gas.
37. from acid flow, remove the system of sour gas, it comprises:
The sour gas that receives said acid flow is removed system; Said acid flow comprises the sulfur component less than about 10%, and the utilization of wherein said sour gas removal system is separated into said acid flow in the low temperature distillation tower of overhead gas stream that mainly contains methane and the liquid column bottoms acid gas stream that mainly contains carbon dioxide and sulfur component; And
Said sour gas is removed the sulfur component of system downstream and is removed system, and wherein said sulfur component removal system receives at the bottom of the said tower acid gas stream and substantially acid gas stream at the bottom of the said tower is separated into CO 2 fluid stream and hydrogen sulfide stream.
38. the described system of claim 37, wherein said sour gas is removed system and is further comprised the heat exchanger that is used for before getting into said destilling tower, cooling off said acid flow.
39. the described system of claim 38, wherein said low temperature distillation tower comprises:
Distillation zone, bottom and intermediate controlled freezing zone, said intermediate controlled freezing zone receive the cooling liquid spray mainly contain methane, and said tower receives said acid flow and then said acid flow is separated into the acid gas stream that liquefies at the bottom of cat head methane stream and the tower; And
The refrigeration plant in said low temperature distillation tower downstream, its part that is used to cool off said cat head methane stream and return said cat head methane stream to said low temperature distillation tower refluxes as liquid.
40. the described system of claim 37, wherein said sulfur component removal system comprises:
Remarkable at least one solid adsorbent bed of absorbing hydrogen sulphide the acid gas stream at the bottom of the said tower, said hydrogen sulfide is released as said hydrogen sulfide stream when said at least one solid adsorbent bed of regeneration; And
Said at least one solid adsorbent bed makes the sour gas that comprises carbon dioxide pass through basically, as said CO 2 fluid stream.
41. the described system of claim 40, wherein said at least one solid adsorbent bed comprises that at least one absorption power separates bed.
42. the described system of claim 37, wherein said sulfur component removal system comprises the extractive distillation system with at least two extractive distillation posts.
43. the described system of claim 42, wherein said extractive distillation system comprises:
As the first extractive distillation post of propane recovery post, said propane recovery post mixes solvent to absorb sour gas with said acid gas stream, make said solvent leave said post as the solvent column underflow, discharges said carbon dioxide stream simultaneously separately;
As CO 2Remove the second extractive distillation post of post, said CO 2Remove post and make solvent and heavy hydrocarbon leave said sour gas removal post, discharge CO simultaneously separately as the second solvent column underflow 2And
Reclaim the 3rd extractive distillation post of post as additive; Said additive reclaims post utilization distillation principle and from solvent, separates the heavy hydrocarbon component that is called " natural gas liquids "; So that tower base solvent stream discharges as regenerated additive, natural gas liquids leaves capital separately simultaneously.
44. the described system of claim 37, wherein said acid flow comprises and is less than about 1% sulfur component.
45. the described system of claim 37, wherein said acid flow comprises the sulfur component between about 4ppm and the 100ppm.
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