Patent application title: OFFSHORE GAS SEPARATION PROCESS
Michael Siskin (Westfield, NJ, US)
Robert A. Fedich (Long Valley, NJ, US)
Michel A. Daage (Hellertown, PA, US)
Michel A. Daage (Hellertown, PA, US)
Thomas F. Parkerton (Cypress, TX, US)
Richard A. Davi (Milford, NJ, US)
IPC8 Class: AC10L310FI
Class name: Carbon dioxide or hydrogen sulfide component utilizing organic reactant amine
Publication date: 2013-06-06
Patent application number: 20130142717
A process for the selective absorption of normally gaseous acid
components from hydrocarbon gas mixtures containing both the acidic
components and gaseous non-acidic components which is carried out in a
gas separation unit located at an offshore marine production
installation. The sorbent used in the process comprises a severely
sterically hindered amino ether. The process is capable of selectively
removing H2S from gas mixtures which also contain CO2 in
addition to the hydrocarbon components.
1. A marine offshore petroleum fluid production installation including a
cyclic amine absorption natural gas purification unit for separating
acidic gases from produced petroleum gas, the unit comprising an
absorption tower and a regeneration tower through which an aqueous amine
absorbent solution is circulated to absorb acidic gases from the gas in
the absorption tower and to desorb acidic gases in the regeneration tower
to produce a stream of purified gas and at least one stream of acidic gas
removed from the gas, the aqueous amine absorbent solution comprises an
aqueous solution of a severely sterically hindered amino ether of the
formula: R1--NH--[CnH2n-O-]x-OY where R1 is a secondary or
tertiary alkyl group of 3 to 8 carbon atoms, Y is H or alkyl of 1 to 6
carbon atoms, n is a positive integer from 3 to 8 and x is a positive
integer from 3 to 6.
2. A marine offshore petroleum fluid production installation according to claim 1 in which R1 is a branched secondary or tertiary alkyl group of 3 to 9 carbon atoms.
3. A marine offshore petroleum fluid production installation according to claim 2 in which R1 is tertiary butyl.
4. A marine offshore petroleum fluid production installation according to claim 3 in which n is 2.
5. A marine offshore petroleum fluid production installation according to claim 1 in which x is 3.
6. A marine offshore petroleum fluid production installation according to claim 1 in which Y is H
7. A marine offshore petroleum fluid production installation according to claim 6 in which the amino ether is tert-butylamino ethoxyethoxyethanol.
8. A marine offshore petroleum fluid production installation according to claim 1 in which Y is methyl.
9. A marine offshore petroleum fluid production installation according to claim 1 in which the amino ether is tert-butylamino methoxy-ethoxyethoxyethanol.
10. A marine offshore petroleum fluid production installation according to claim 1 in which the absorbent solution also comprises a diamino ether of the formula: R1--NH--[CnH2n--O--]x--NHR2 where R1, n and x are as defined in claim 1 and R2, which may the same or different to R1, is a secondary or tertiary alkyl group of 3 to 8 carbon atoms.
11. A marine offshore petroleum fluid production installation according to claim 1 in which the absorbent solution also comprises bis-(t-butylamino ethoxy)ethane.
12. A marine offshore petroleum fluid production installation according to claim 11 in which the absorbent solution comprises tert-butylamino methoxy-ethoxyethoxyethanol and bis-(t-butylamino ethoxy)ethane.
13. A process for the selective absorption of normally gaseous acidic components from hydrocarbon gas mixtures containing both the acidic component and gaseous non-acidic components, which process is carried out in a gas separation unit located at an offshore marine petroleum fluid production installation in which an aqueous amine absorbent solution is circulated in a cyclic amine absorption natural gas purification unit to absorb acidic gases from the hydrocarbon gas in an absorption tower and to desorb acidic gases in a regeneration tower to produce a stream of purified hydrocarbon gas and at least one stream of acidic gas removed from the hydrocarbon gas, the aqueous amine absorbent solution being an aqueous solution of a severely sterically hindered amino ether of the formula: R1--NH--[CnH2n--O--]x--OY where R1, Y, n and x are as defined in claim 1.
14. A process according to claim 13 in which H2S is selectively removed from a produced natural gas stream which contains H2S and CO.sub.2.
15. A process according to claim 13 in which the amino ether comprises tert-butylamino-ethoxyethoxy ethanol.
16. A process according to claim 13 in which the absorbent solution also comprises a diamino ether of the formula: R1--NH--[CnH2n--O--]x--NHR2 where R1, Y, n and x are as defined in claim 1 and R2 is as defined in claim 10.
17. A process according to claim 16 in which the absorbent solution also comprises bis-(t-butylaminoethoxy)ethane.
18. A process according to claim 17 in which the absorbent solution comprises tert-butylamino methoxy-ethoxyethoxyethanol and bis-(t-butylaminoethoxy)ethane.
19. A process for purifying a stream of natural gas produced at a marine offshore petroleum fluid production installation including a cyclic amine absorption natural gas purification unit for separating acidic gases from produced natural gas, the unit comprising an absorption tower and a regeneration tower through which an aqueous amine absorbent solution is circulated to absorb acidic gases from the natural gas in the absorption tower and to desorb acidic gases in the regeneration tower to produce a stream of purified gas and at least one stream of acidic gas removed from the natural gas, the aqueous amine absorbent solution being an aqueous solution of a hindered.
20. A process according to claim 19 which selectively absorbs H2S from the natural gas.
21. A process according to claim 19 in which the amino ether comprises tert-butylamino-ethoxyethoxy ethanol.
22. A process according to claim 19 in which the absorbent solution also comprises a diamino ether of the formula: R1--NH--[CnH2n--O--]x--NHR2 where R1, Y, n and x are as defined in claim 1 and R2 is as defined in claim 1.
23. A process according to claim 22 in which R1 is tertiary butyl, n is 2 and x is 3.
24. A process according to claim 22 in which the absorbent solution also comprises bis-(t-butylaminoethoxy)ethane.
25. A process according to claim 22 in which the absorbent solution comprises tert-butylamino methoxy-ethoxyethoxyethanol and bis-(t-butylaminoethoxy)ethane.
FIELD OF THE INVENTION
 This invention relates to a process carried out on an offshore petroleum production platform for removing acid gases from gas produced at the platform. It also relates to the gas treatment unit for carrying out the process.
BACKGROUND OF THE INVENTION
 As reserves in onshore natural gas and petroleum fields have decreased over time, production of these resources has moved progressively offshore and recently into ever deeper waters. Interest in natural gas production has increased as the utility of this energy source in transport, electrical power generation and other applications have increased in recent years with recognition of the importance of reducing atmospheric carbon emissions. The natural gas produced with petroleum liquids and the gas from a gas field frequently contains carbon dioxide and sulfur in the form of hydrogen sulfide, as well as other acid gases such as, CS2, HCN, COS and sulfur derivatives of light hydrocarbons (mercaptans etc). Hydrogen sulfide (H2S) is desirably separated to meet pipeline specifications before the gas is sent ashore by underwater pipeline in view of its corrosive action on pipeline steels. Similarly, it is also desirable to remove the hydrogen sulfide from gas which is stored or processed at a production facility which is not linked to the shore by a pipeline. When H2S is dissolved in water, it forms a weak acid which promotes pipeline corrosion The most common types of corrosion where H2S is present consist of pitting, blistering, embrittlement, fatigue, and cracking. The severity of the corrosion due to H2S is determined by factors such as oxygen and carbon dioxide (CO2) levels, temperature, gas velocity, pH levels less than 6.5 (acidic), especially in he presence of salt water (conductive electrolyte), internal/external stresses, concentration (parts per million or partial pressure levels). The combination of CO2 and H2S is more corrosive than H2S alone, and can be considered very corrosive when combined with even minute quantities of oxygen and for this reason, removal of both CO2 and H2S is considered desirable.
 The removal of acid gases from the produced fluids on offshore platforms and production rigs raises significant problems. The main constraints for application on an offshore platform are space and weight limitations. Installing a complex system with numerous equipment and extensive utilities to support its operation is against the trend in the offshore industry to pursue compact facilities and to reduce manning levels for safety and logistic reasons and operating costs. A number of different technologies are available for consideration including, for example, chemical absorption (amine), physical absorption, cryogenic distillation (Ryan Holmes process), and membrane system separation. Of these, amine separation is a highly developed technology with a number of competing processes in hand using various amine sorbents such as monoethanolamine (MEA), diethanolamine (DEA), methyldiethanolamine (MDEA), diisopropylamine (DTPA), diglycolamine (DGA), 2-amino-2-methyl-1-propanol (AMP) and piperazine (PZ). Of these, MEA, DEA, and MDEA are the ones most commonly used. The amine purification process usually contacts the gas mixture in the form of an aqueous solution of the amine in an absorber tower with the aqueous amine solution contacting the acidic fluid countercurrently. The liquid amine stream is then regenerated by desorption of the sorbed gases in a separate tower with the regenerated amine and the desorbed gases leaving the tower as separate streams. The various gas purification processes which are available are described, for example, in Gas Purification, Fifth Ed., Kohl and Neilsen, Gulf Publishing Company, 1997, ISBN-13: 978-0-88415-220-0.
 The treatment of acid gas mixtures containing CO2 and H2S with amine solutions typically results in the simultaneous removal of substantial amounts of both the CO2 and H2S. It is often desirable, however, to treat acid gas mixtures containing both CO2 and H2S so as to remove the H2S selectively from the mixture, thereby minimizing removal of the CO2. Selective removal of H2S results in a relatively high H2S/CO2 ratio in the separated acid gas which simplifies the conversion of H2S to elemental sulfur, e.g., using the Claus process. Although primary and secondary amines such as MEA, DEA, DPA, and DGA absorb both H2S and CO2 gas, they have not proven especially satisfactory for preferential absorption of H2S. In aqueous solution, the amines undergo reaction with CO2 to form carbamates. The tertiary amine, MDEA, has a high degree of selectivity toward H2S absorption over CO2 but the commercial usefulness of MDEA is limited because of its restricted capacity.
 An improvement in the basic amine process involves the use of sterically hindered amines. U.S. Pat. No. 4,112,052 describes the use of hindered amines for nearly complete removal of acid gases such as CO2 and H2S. U.S. Pat. Nos. 4,405,581; 4,405,583; 4,405,585 and 4,471,138 disclose the use of severely sterically hindered amine compounds for the selective removal of H2S in the presence of CO2. Compared to aqueous MDEA, severely sterically hindered amines lead to much higher selectivity at high H2S loadings. Amines described in these patents include BTEE (bis(tertiary-butylamino)-ethoxy-ethane synthesized from tertiary-butylamine and bis-(2-chloroethoxy)-ethane as well as EEETB (ethoxyethoxyethanol-tertiary-butylamine) synthesized from tertiary-butylamine and chloroethoxyethoxyethanol). U.S. Pat. No. 4,894,178 indicates that a mixture of BTEE and EEETB is particularly effective for the selective separation of H2S from CO2. U.S. 2010/0037775 describes the preparation of alkoxy-substituted etheramines as selective sorbents for separating H2S from CO2 US 2009/0308248 describes a different class of absorbents which are selective for H2S removal in the presence of CO2, the hindered amino alkyl sulfonate, sulfate and phosphonate salts, with the sulfonate and phosphonates being the preferred species.
 Regardless of the improved selectivities and sorption capacities offered by those new materials, they have not achieved general acceptance for use in offshore units, the reason being that as regulations regarding toxicity and biodegradability of chemicals that could potentially be spilled into the ocean have become more severe, the potential number of acceptable absorbents has become correspondingly more limited. Acid gas clean-up on off-shore platforms has therefore come to require absorbents to be selected for with lower toxicity and higher biodegradability.
SUMMARY OF THE INVENTION
 We have now identified a class of absorbents which have high selectivity for the removal of H2S in the presence of CO2 with very acceptable environmental properties permitting their use in offshore installations such as natural gas production platforms. According to the present invention, therefore, we provide a process for the selective absorption of normally gaseous acid components from gas mixtures containing both the acidic component and gaseous non-acidic components, which process is carried out in a gas separation unit located at an offshore marine installation. The preferred asorbents used in the process comprise severely sterically hindered amino ethers, including ether alcohols, bis-(amino) ethers and alkoxy amino ethers; mixtures of the amino ether compounds may be used. The process is capable of selectively removing H2S from gas mixtures which also contain CO2 and so makes it useful for treating natural gas from fields containing both these acidic components.
 The invention also provides a gas separation unit containing a liquid absorbent comprising hindered amino ethers and ether alcohols. Offshore petroleum fluids production installations having a gas separation unit with one of these sorbents are also provided. The separation unit includes a cyclic amine absorption natural gas purification unit for separating acidic gases from produced petroleum gas; this unit has an absorption tower and a regeneration tower through which an aqueous amine absorbent solution is circulated to absorb acidic gases from the gas in the absorption tower and to desorb acidic gases in the regeneration tower. The purified petroleum gas and at least one stream of acidic gas removed from the gas are recovered as separate streams from the regenerator.
 The single FIGURE of the accompanying drawings is a graph showing the biodegradability of several candidate compounds as reported below.
General Processing Features
 The acid gas sorbents used in the present gas separation process are normally used in the form of aqueous solutions which can be circulated in the normal type of continuous cyclic amine gas purification unit mentioned briefly above, comprising essentially an absorber tower in which the aqueous amine solution is contacted in countercurrent flow with the incoming gas mixture. The liquid amine stream is then passed to a regenerator in which the sorbed gases are desorbed by a change in conditions, typically a reduction of pressure or an increase in temperature in a separate tower although stripping with another gas stream may also be utilized; the regenerated sorbent solution and the desorbed gases leave the regenerator tower as separate streams. The present amine sorbents can be used in the same manner as conventional amine sorbents and consequently, similar operating practices in the units containing these sorbents can be followed.
 The processed gas mixtures include H2S, and may optionally include other acidic gases such as CO2, SO2, COS, HCN, as well as non-acidic gases such as N2, CH4, H2, CO, H2O, C2H4, NH3, and the like. High selectivity for H2S absorption is favored for the present purposes although less selective absorption is not excluded when required by the feed gas or purification needs. If processing conditions are adjusted non-selective removal of the acid gas components from the non-acidic components may be achieved with subsequent separation of the acidic gases one from another, e.g., separation of H2S from CO2, allowing the CO2 to be re-injected for reservoir pressure maintenance.
 The preferred absorbents used in the separation units are the severely sterically hindered amino ethers, ether alcohols and alkoxy amino ethers, with especial preference given to the amino ether derivatives of triethylene glycol.
 The hindered amine ethers are used in the form of aqueous solutions, typically from about 0.1 to 5M concentration in order to secure adequate loading; variations both within this range and outside it may be made according to individual processing requirements, e.g., concentration of gas species in total gas flow, size of unit, etc. In most cases, the rich solution will have an amine concentration of 0.05 to 2.5 M. Conditions in the separation unit will be typical of those used in conventional amine gas purification processes, for example, in temperature swing operation, sorption temperatures are typically in the range of 30-50° C., more usually 40-50° C. and desorption temperatures typically at 60 to 140° C., e.g., 100-125° C. In pressure swing operation the sorption and desorption pressures are usually set by the pressure of the incoming feed stream and perhaps also by any requirement for the product stream.
 A typical procedure for the selective H2S removal phase of the process comprises selectively absorbing H2S in countercurrent contact of the gaseous mixture is described in US 2009/00308248 to which reference is made for this description.
 The gas purification or separation unit is situated in a marine, offshore location, typically on an offshore gas or crude oil production platform. In the case of a platform producing from an oilfield, the gas will be the natural hydrocarbon gases which are co-produced with the crude oil and which are separated from the oil on the platform to stabilize the liquid before transport either by pipeline or by offloading onto a transfer vessel. Production platforms may be fixed to the ocean floor as with the familiar and conventional rigid (concrete or steel) leg platforms or the concrete gravity base structures such as the Condeep platforms used in locations usually no more than 200 m in depth although some Condeep structures have been installed in about 350 m of water. Fixed platforms of this type have usually provided adequate space for processing equipment. In deeper water, for example, over 500 m depth, fixed platforms are not economically feasible and floating production, storage and offloading structures tethered to the seabed in a manner that eliminates most vertical movement of the structure, such as tension leg platforms, SPAR or Deep Draft Caisson Vessels (DDCVs), are used at greater depths up to about 2,000 m with one currently placed in over 2400 m (Perdido SPAR in the Gulf of Mexico in 2,438 meters of water). The gas processing unit and related equipment will be installed on the structure of whatever kind in a manner conformable to space and stability requirements. The produced gases may be handled according to the location with close offshore platforms discharging the purified natural gas into the pipeline to shore and, when pipelining to shore is not an option as in the deepwater locations, to the related storage facilities either on the same platform or on another nearby storage facility. CO2 is frequently re-injected into the formation to improve recovery of the oil or gas and for this purpose, the CO2 will be sent to the re-injection compressor equipment. Separated H2 may be handled in the same way or, if possible, treated in a Claus plant and the product sulfur stored for later disposal. On far offshore installations not linked to shore by pipeline, gas liquefaction facilities can be provided to store the hydrocarbon gases as well as separated gases pending transfer to a vessel for transport ashore.
 One class of H2S selective absorbents which are predicted to exhibit favorable environmental characteristics, particularly aquatic toxicity, are the hindered amine alkylsulfonate and alkylphosphonate salts which are described in US 2009/0308248, to which reference is made for a description of these salts as well as of their synthesis and use in selective gas separation processes. Briefly, the salts are generally represented by the following formulae:
in which R1, R2, R3 and R4 are the same or different and selected from H, C1-C9 substituted or unsubstituted straight or C3-C9 substituted or unsubstituted branched chain alkyl, C3-C9 cycloalkyl, C6-C9 aryl, alkylaryl, arylalkyl, C2-C9 straight or branched hydroxyalkyl, cycloalkyl and mixtures thereof provided that both R1 and R2 are not hydrogen and, when n is 2 or more, R3 and R4 on adjacent carbon or on carbons separated by one or more carbons, can be a cycloalkyl or aryl ring and, when the substituents are substituted, they are heteroatom containing substituents, preferably an --NR5R6 group wherein R5 and R6 are the same or different and are selected from H, C1-C9 straight or C3-C9 branched chain alkyl, C3-C9 cycloalkyl, C6-C9 aryl, alkylaryl, arylalkyl, C2-C9 straight or branched chain hydroxyalkyl, cycloalkyl, provided that R5 and R6 are not both H, and further, when R1 is H, and n is 2 or more, R2 and R3 or R4 on the carbon at least one carbon removed from the aminic nitrogen can form a ring; n is an integer of 1 or more, preferably 1 to 4, more preferably 2 to 4; metal cation is one or more monovalent, divalent or trivalent metal cation(s) sufficient to satisfy the valence requirements of the anion(s), for example, magnesium, barium, sodium, lithium, potassium or calcium with preference for sodium and potassium. Salts formed from divalent cations can be half- or full-salts.
 R1 and R2(R1 and R2 are not both hydrogen) are preferably selected from H, C4-C6 alkyl, more preferably C4-C6 branched chain alkyl, most preferably tertiary-butyl. R3 and R4 are normally H or C2-C3 alkyl. The value of n is preferably from 1 to 4, most preferably 2 or 3.
 For optimal sorption of the acidic component(s) of the gas mixture, it is necessary to use the salts, preferably the alkali metal salts in order to maintain a reserve of alkalinity in the sorbent solution: the free acids are relatively less effective.
 The sulfonate and phosphonate salts may be synthesized by the methods described in US 2009/0308248 to which reference is made for a description of such methods.
 The preferred absorbent materials for offshore use are the severely sterically hindered amino ethers and amino alcohols of polyalkyleneglycols, especially diethylene glycol and, more preferably triethylene glycol. These have been shown to be selective for absorption of H2S in the presence of CO2 and other acidic gases in mixtures with non-acidic gases. The hindered amino derivatives of triethylene glycol have been found to be particularly favorable from the environmental point of view. These absorbents have been found to exhibit high selectivity for H2S absorption in the presence of acidic gases such a CO2 and from non-acidic gases.
 The preferred amino ethers for offshore application are defined by the formula:
where R1 is a secondary or tertiary alkyl group of 3 to 8 carbon atoms, preferably a tertiary group of 4 to 8 carbon atoms, Y is H or alkyl of 1 to 6 carbon atoms, n is a positive integer from 3 to 8 and x is a positive integer from 3 to 6. The preferred R1 group is tertiary butyl and the most preferred amino ethers are those derived from triethylene glycol (n is 2, x is 3). When Y is H, the amino ether is an amino ether alcohol such as tert-butylamino ethoxyethoxyethanol, derived from triethylene glycol; when Y is alkyl, preferably methyl, the amino ether is an alkoxy amino ether, with preference for tert-butylamino methoxy-ethoxyethoxyethanol. The monoamino ethers may be used in blends with diamino ethers in which the terminal OH group of the ether alcohol or the terminal alkoxy group of the alkoxy amino ether is replaced by a further hindered amino group as expressed in the formula:
where R1, n and x are as defined above and R2, which may the same or different to R1, is a secondary or tertiary alkyl group of 3 to 8 carbon atoms. A preferred diamino ether of this type is bis-(t-butylamino ethoxy)ethane which may conveniently be used as a mixture of tert-butylamino methoxy-ethoxyethoxyethanol and bis-(t-butylamino ethoxy)ethane.
 Preferred examples of these amino ethers are disclosed in U.S. Pat. Nos. 4,405,583; 4,405,585, 4,471,138, 4,894,178 and U.S. Patent Publication 2010/0037775, to which reference is made for a full description of these materials, their synthesis and their use in selective acidic gas separation processes. Their disclosures are summarized below for convenience.
 U.S. Pat. No. 4,405,583: The hindered diamino ethers disclosed in this patent are defined by the formula:
where R1 and R8 are each C1 to C8 alkyl and C2 to C8 hydroxyalkyl groups, R2, R3, R4, R5, R6, and Rare each hydrogen, C1-C4 alkyl and hydroxyalkyl groups, with certain provisos to define the adequately hindered molecule and m, n, and p are integers from 2 to 4 and o is zero or an integer from 1 to 10. A typical diamino ether of this type is 1,2-bis(tert-butylaminoethoxy)ethane, a diamino derivative of triethylene glycol.
 U.S. Pat. No. 4,405,585: The hindered amino ether alcohols disclosed in this patent are defined by the formula:
where R1 is C1-C8 primary alkyl and primary C2-C8 hydroxyalkyl, C3-C8 branched chain alkyl and branched chain hydroxyalkyl and C3-C8 cycloalkyl and hydroxycycloalkyl, R2, R3, R4 and R5 are each hydrogen, C1-C4alkyl and C1-C4 hydroxyalkyl radicals, with the proviso that when R1 is a primary alkyl or hydroxyalkyl radical, both R2 and R3 bonded to the carbon atom directly bonded to the nitrogen atom are alkyl or hydroxyalkyl radicals and that when the carbon atom of R1 directly bonded to the nitrogen atom is secondary at least one of R2 or R3 bonded to the carbon atom directly bonded to the nitrogen atom is an alkyl or hydroxyalkyl radical, x and y are each positive integers from 2 to 4 and z is an integer from 1 to 4. Exemplary compounds of this type include the amino ether alcohol tert-butylaminoethoxyethanol, a derivative of diethylene glycol.
 U.S. Pat. No. 4,471,138: This patent discloses the desirability of using a combination of a diamino ether with an aminoether alcohol. The two compounds are represented by the respective formulae:
where x is an integer ranging from 2 to 6. This mixture can be prepared in the novel one-step synthesis, by the catalytic tertiary butylamination of a polyalkenyl ether glycol, HO--(CH2CH2O)x--CH2CH2--OH, or halo alkoxyalkanol. For example, a mixture of bis-(tert-butylaminoethoxy)ethane (BTEE) and ethoxyethoxyethanol-tert-butylamine (EEETB) can be obtained by the catalytic tertiary-butylamination of triethylene glycol. The severely hindered amine mixture, e.g., BTEE/EEETB, in aqueous solution can be used for the selective removal of H2S in the presence of CO2 and for the removal of H2S from gaseous streams in which H2S is the only acidic component, as is often the case in refineries.
 U.S. Pat. No. 4,894,178: A specific combination of diamino ether and aminoalcohol represented by the respective formulae:
with x being an integer ranging from 2 to 6 and the weight ratio of the first amine to the second amine ranging from 0.43:1 to 2.3:1. This mixture can be prepared in the one-step synthesis, by the catalytic tertiary-butylamination of the corresponding polyalkenyl ether glycol, for example, by the catalytic tertiary-butylamination of triethylene glycol. This mixture is one of the preferred absorbents for use in offshore gas processing.
 US 2010/0037775: The reaction of a polyalkenyl ether glycol with a hindered amine such as tert-butylamine is improved by the use of an alkoxy-capped glycol. In the case of alkoxy DEG, the capped glycol now precludes the formation of an unwanted cyclic by-product, tert-butyl morpholine (TBM). A preferred capped glycol is methoxy-triethylene glycol although the ethoxy-, propoxy- and butoxy homologs may also be used. The reaction between monomethoxy triethylene glycol and tert-butylamine is shown to produce MEEETB almost exclusively, in ˜95% yield, eliminating the need for extensive distillation to remove the product.
 The amino ether compounds may be used in conjunction with other related materials such as an amine salt as described in U.S. Pat. No. 4,618,481. The severely sterically hindered amino compound can be a secondary amino ether alcohol or a disecondary amino ether. The amine salt can be the reaction product of the severely sterically hindered amino compound, a tertiary amino compound such as a tertiary alkanolamine or a triethanolamine, with a strong acid, or a thermally decomposable salt of a strong acid, i.e., ammonium salt or a component capable of forming a strong acid.
 Similarly, U.S. Pat. No. 4,892,674 discloses a process for the selective removal of H2S from gaseous streams using an absorbent composition comprising a non-hindered amine and an additive of a severely-hindered amine salt and/or a severely-hindered aminoacid. The amine salt is the reaction product of an alkaline severely hindered amino compound and a strong acid or a thermally decomposable salt of a strong acid, i.e., ammonium salt.
Selectivity of Candidate Compounds
 Three characteristics which are important in determining the effectiveness of the amino compounds herein for H2S removal are "selectivity", "loading" and "capacity". "Selectivity" is defined as the mole ratio fraction of the H2S to the CO2 in the liquid (sorbent solution) phase to the mole ratio fraction of the H2S to the CO2 in the gaseous phase. The higher this fraction, the greater the selectivity of the absorbent solution for the H2S in the gas mixture. "Loading" is the concentration of the H2S and CO2 gases physically dissolved and chemically combined in the absorbent solution expressed in moles of gas per moles of the amine. The amino compounds used in the present invention typically have a "selectivity" of not substantially less than 10 at a "loading" of 0.1 moles, preferably, a "selectivity" of not substantially less than 10 at a loading of 0.2 or more moles of H2S and CO2 per moles of the amino compound. "Capacity" is defined as the moles of H2S loaded in the absorbent solution at the end of the absorption step minus the moles of H2S loaded in the absorbent solution at the end of the desorption step. High capacity enables one to reduce the amount of amine solution to be circulated and use less heat or steam during regeneration.
Selectivity=(H2S/CO2) in solution/(H2S/CO2) in feed gas Loading=Moles H2S/Moles absorbent compound Capacity=Moles H2S absorbed/Moles H2S after desorption Moles H2S absorbed
 The selectivity of the preferred amino glycol derivatives is demonstrated by comparison of the following absorbents:
EETB Ethoxyethanol-tert-butylamine (tert-butylamino-ethoxy-ethanol)
 TEGTB Triethylene glycol-t-butylamine (t-butylaminoethoxyethoxyethanol)
 Bis-TEGTB Bis-(t-butylamino ethoxy)ethane (bis-(t-butylamino)triethylene glycol)
 1. Absorption tests were carried out at 35° C. on 0.15 M aqueous solutions of absorbent using a gas mixture of nitrogen:carbon dioxide:hydrogen sulfide of 89:10:1 for 2 hours.
 2. Desorption experiments were run at 85° C. in flowing nitrogen for 2 hours at the same flow rate as the test gas mixture.
 The results are shown in Table 1 below.
TABLE-US-00001 TABLE 1 SUMMARY OF ABSORPTION TESTING RESULTS Molecular Loading Capacity Selectivity- Compound Weight Selectivity (%) (%) Reabsorption EETB (U.S. Pat. No. 4,405,585) 161.24 15.4 16.3 60 13.3 Bis-SE (U.S. Pat. No. 4,405,583) 216.36 16.7 28.2 80 25.2 MEETB 175 56.01 21.57 67.4 59.6 EEETB 189.30 75.4 13.1 89.3 86.7 BEETB 217.35 90.2 16.8 92.5 197.6 MEEETB 219.32 64.4 24.2 98.4 69.7 TEGTB (32.2%): 205.26/ 128.2 45.4 82.6 231.2 [Bis-TEGTB](67.4%) 260.42 (U.S. Pat. No. 4,894,178) TBA-NH--(CH2)2--HN-TBA 172.31 26.2 9.8 46 20.2 Selectivity = (H2S/CO2) in solution / (H2S/CO2) in feed gas Loading = Moles of H2S / Moles of Compound Capacity = Moles of H 2 S absorbed by solution - Moles of H 2 S after desorption from solution Moles of H 2 S absorbed by solution ##EQU00001##
 As can be seen, the methoxy-, ethoxy- and butoxy-substituted diethylene and triethylene glycol-t-butyl amines have higher degrees of selectivity as compared to the EETB and its diamino derivative (Bis-SE, bis-(t-butylaminoethyl)ether) and have at least equivalent and in most cases superior capacity and superior selectivity after regeneration than the EETB and the corresponding diamino bis-SE.
Assessment of Health and Environmental Aspects of Candidate Compounds
 To assess the toxicity potential and environmental fate properties of various selective absorbents, quantitative structure activity relationships (QSARs) were applied together with experimental confirmation of aquatic toxicity.
 The chemical structures of candidate absorbents were run through a series of computer models for comparative purposes. Physical chemical properties (i.e., vapor pressure, water solubility, and octanol/water partition coefficient) were estimated using two models, EPISuite1 and SPARC2. Biodegradation potential was determined using BIOWin, a subroutine of EPISuite. 1 EPI (Estimation Programs Interface) Suite® is a Windows-based suite of physical/chemical property and environmental fate estimation programs developed by the EPA's Office of Pollution Prevention Toxics and Syracuse Research Corporation (SRC).2 Scalable Processor Architecture, the RISC instruction set architecture of Sun Microsystems
 The four candidates in the evaluation were:
 Candidate A EETB
 Candidate B MEEETB
 Candidate C TEGTB
 Candidate D Bis-TEGTB
 Table 2 below compares physical chemical properties (VP, WS, Log Kow) of the candidate substances. The octanol/water partition coefficient (or Log Kow) of all candidate substances indicates these substances would not be expected to pose a bioaccumulation concern.
TABLE-US-00002 TABLE 2 Property Predictions of Absorbents Vapor Water Compound Pressure (Pa) Solubility, mg/l Log Kow A EETB 0.77 miscible -0.06 B MEETB 1.22 miscible 0.37 C TEGTB 0.014 miscible -0.33 D Bis-TEGTB 0.05 miscible 1.49
 BIOWin3 model predictions for candidate absorbents indicate that primary biodegradation (loss of parent compound) will occur over the range of days to weeks, whereas, ultimate biodegradation (mineralization to carbon dioxide) will occur over the range of weeks to months. 3 BioWin dynamic wastewater treatment process modeling and simulation package of EnviroSim Associates Ltd.
 The biodegradation of the four candidates was tested by Manometric Respirometry following OECD TG 301F [at 20° C.] with the results in Table 3 below and in the accompanying FIGURE.
TABLE-US-00003 TABLE 3 Biodegradability DAY A B D Mix C, D* 0 0 0 0 0 1 0.05 0.00 0.00 0.81 2 0.00 0.20 0.61 1.56 3 0.00 0.30 0.61 1.56 4 0.00 0.60 0.70 1.52 5 0.00 1.02 0.62 1.55 6 0.00 1.54 0.54 1.75 7 0.06 2.09 0.37 2.35 8 1.68 3.00 0.07 3.01 9 3.34 3.81 0.00 3.17 10 0.47 1.89 0.00 3.79 11 0.56 3.82 0.69 6.09 12 0.76 4.04 0.63 7.51 13 0.91 4.70 0.00 8.67 14 1.04 5.70 0.77 10.49 15 1.16 6.03 0.85 11.70 16 1.33 6.56 1.12 12.91 17 1.51 7.14 1.34 13.31 18 1.56 7.65 1.77 13.54 19 1.58 9.52 1.68 13.60 20 1.71 7.55 1.71 13.60 21 1.89 7.55 1.67 13.60 22 2.00 7.55 1.67 14.77 23 1.95 7.55 1.67 14.77 24 2.00 7.55 1.67 14.77 25 2.06 7.55 1.67 14.99 26 2.06 7.55 1.67 16.51 27 2.06 7.55 1.67 17.17 28 2.06 7.55 1.67 17.34 Mix C, D: Approx. 33% C, 65-67% D
 The continued upward trend in the biodegradation of the mixture of C and D indicates that degradative elimination from the environment can be expected with increasing time.
 Aquatic toxicity predictions for fish, invertebrates (Daphnia) and algae were made using ECOSAR, also a subroutine of EPISuite that estimates aquatic toxicity and verified experimentally. The commercial TOPKAT® 4model was used to estimate mammalian toxicity endpoints. 4 Accelrys Discovery Studio Predictive Toxicology tool, Discovery Studio TOPKAT.
 The acute aquatic toxicity predictions in Table 4 indicate absorbents A, B, E and F exhibit toxicity to at least one aquatic organism in the 10-100 mg/l range. Fish appear to be consistently less sensitive than daphnids or algae.
TABLE-US-00004 TABLE 4 Aquatic Toxicity Predictions of Absorbents Fish 96-hour Daphnia 48-hour Algae 96-hour Code Compound LC50 (mg/l) LC50 (mg/l) EC50 (mg/l) A EETB 924 (225) 52.3 (31.6) 48.5 B MEEETB 667 39.9 42.9 C TEGTB 1,752 95.7 80.8 D Bis-TEGTB 152 10.5 16.6 Note: values in brackets ( ) indicate experimental results.
 Aquatic toxicity was tested experimentally using the OECD TG 202--Daphnia sp. Acute Immobilisation Test The results are given below in Table 5.
TABLE-US-00005 TABLE 5 Aquatic Toxicity Daphnia Daphnia Predicted, Experimental, 48 hours, 48 hours, EC50 (mg/l) EC50 (mg/l) Classification A 52.3 10 < EC50 < 100 Harmful to aquatic organisms B 39.9 EC50 > 100 No classification D 10.5 10 < EC50 < 100 Harmful to aquatic organisms Mix C/D 31.7 10 < EC50 < 100 Harmful to aquatic organisms
 The classification "Harmful to aquatic organisms" signifies that the compounds in question may be used in the offshore environment subject to mitigation, for example, secondary treatment or dilution. None were deemed toxic, barring their use. Based on biodegradability and aquatic toxicity predictions none of the candidate substances are expected to require a negative environmental label (e.g., the European dead fish/dead tree symbol) although absorbent D appeared on the basis of the predictions to be least preferred from an environmental perspective.
 The TOPKAT® predictions for mammalian toxicity endpoints given in Table 6 indicate absorbents A, and C have a low potential for acute toxicity in rats, while absorbents B and D show predicted acute toxicity in the range of 1000 to 2000 mg/kg, which would put them in the harmful category. Chronic toxicity in rats is reported as the Lowest Observed Adverse Effect Level (LOAEL), which is the lowest dose level, in weight of chemical to body weight units, which is predicted to cause an adverse effect. The Ocular Irritancy module computes the probability of a chemical structure being an ocular irritant in the Draize test. All candidates are expected to cause severe eye irritation. The Developmental Toxicity Potential module of the TOPKAT package predicts that candidate A derived from diethylene glycol is likely to be less favorable than the triethylene glycol derivatives.
 Carcinogenic potential is predicted using the NTP Rodent Carcinogenicity Module in TOPKAT and comprises four statistically significant quantitative structure-toxicity relationship models. These models are derived from 366 uniform rodent carcinogenicity studies conducted by the National Cancer Institute. Positive results listed in Table 4 below indicate the potential for the candidate to be carcinogenic or not carcinogenic in either rats or mice. Results scored as indeterminate indicate insufficient evidence to score either as positive or negative. The model also predicts that none of the candidate absorbents are expected to be skin sensitizers, nor are they expected to be mutagens.
TABLE-US-00006 TABLE 4 Mammalian Toxicity Predictions of Absorbents Tox Endpoint A B C D Rat Oral LD50 (mg/kg) 2500 1900 3400 1000 Chronic LOAEL (mg/kg) 68.9 46.3 97 24.8 Skin Sensitization No No No No Eye Irritation Severe Severe Severe Severe Develop Tox Potential Yes No No No Ames Mutagenicity Negative Negative Negative Negative Carcinogenic Potential Male Rat Indeterm. Positive Indeterm. Positive Female Rat Negative Positive Negative Negative Male Mouse Negative Negative Negative Negative Female Mouse Negative Positive Negative Negative
Patent applications by Michael Siskin, Westfield, NJ US
Patent applications by Michel A. Daage, Hellertown, PA US
Patent applications in class Amine
Patent applications in all subclasses Amine