DETAILED ACTION
Notice of Pre-AIA or AIA Status
The present application, filed on or after March 16, 2013, is being examined under the first inventor to file provisions of the AIA .
Claim Objections
Claim 1 is objected to because of the following informalities: In line 5 the term “hydrocarbon gas steam” should be altered to say - - hydrocarbon gas stream- -. Appropriate correction is required.
Applicant is advised that should claim 1 be found allowable, claim 6 will be objected to under 37 CFR 1.75 as being a substantial duplicate thereof. When two claims in an application are duplicates or else are so close in content that they both cover the same thing, despite a slight difference in wording, it is proper after allowing one claim to object to the other as being a substantial duplicate of the allowed claim. See MPEP § 608.01(m).
Claim Rejections - 35 USC § 102
The following is a quotation of the appropriate paragraphs of 35 U.S.C. 102 that form the basis for the rejections under this section made in this Office action:
A person shall be entitled to a patent unless –
(a)(1) the claimed invention was patented, described in a printed publication, or in public use, on sale, or otherwise available to the public before the effective filing date of the claimed invention.
Claim(s) 1, 3, 6 and 8 is/are rejected under 35 U.S.C. 102(a)(1) as being anticipated by Rhinesmith et al. US 20110000133.
Regarding claims 1 and 6, Rhinesmith teaches a method of generating hydrogen from a hydrocarbon feed stream (Abstract). The reference teaches a preheater 9 for preheating hydrocarbon and pre-reformed hydrocarbon going into a reformer 19 (Para [0111]). The hydrocarbon undergoes steam reforming with heat to result in syngas (“CnHm(v) +nH2O+heat→nCO(v)+(m/2+n)H2” See Para [0110]-[0111]). The reforming temperature is disclosed as 1115°F (Para [0111]). This reads on the claimed limitation of heating the pretreated hydrocarbon gas stream in the reformer to produce synthesis gas since the hydrocarbon of the reference is already pretreated in the pre-reformer 18. Flue gas is also produced in the reformer (See Para [0112]). The hot flue gas exiting the burner of the reformer is sent to heat exchanger 10 which utilizes the heat from the flue gas to preheat the hydrocarbon before it enters the reformer 19 (See Fig. 3 and Para [0114]). This is considered to read on the claimed limitation of recovering waste heat to increase the thermal efficiency of the process. The thermal efficiency is increased because the process used excess heat from an internal source to heat another stream in a different part of the process. The syngas exiting the reformer is sent to a high temperature shift where carbon monoxide is converted to carbon dioxide and hydrogen by the water gas shift reaction (See Para [0115]-[0116] “CO(v)+H2O(v)→CO2(v)+H2(v)+heat”). The shifted syngas is compressed and hydrogen is separated using separator 39 (Para [0139]). Carbon dioxide is separated using stripper 46 (Para [0145]).
Regarding claims 3 and 8, the Rhinesmith reference teaches a desulfurization heater and desulfurization beds to remove sulfur (Para [0108]). The reference teaches a heating the stream passing through the desulfurization heater on the way to the desulfurization bed (Para [0109]).
Claim(s) 1, 3, 6 and 8 is/are rejected under 35 U.S.C. 102(a)(1) as being anticipated by Drnevich et al. US 20100158776.
Regarding claims 1 and 6, Drnevich teaches a process for producing low carbon intensity hydrogen (para [0009]-[0012], [0039]; figure 1; The present invention provides a method of reducing carbon dioxide emissions in a refinery by treating a refinery off gas stream. The steps of the method include steam methane reforming to produce hydrogen and carbon dioxide. Carbon dioxide is then separated to produce a carbon dioxide containing gas stream and a hydrogen containing gas stream. The hydrogen containing gas would have about 2% mole carbon dioxide.), comprising the steps of: pretreating a hydrocarbon gas stream (para [0022], [0024]; figure 1; With reference to figure 1, a steam methane reforming installation 1 is illustrated in which a hydrocarbon containing stream to be reformed by steam methane reforming originates as in incoming refinery off gas stream 10. Refinery off gas stream 10 is compressed in a compressor 12 to produce a compressed refinery off gas stream 14. Here, compressing is considered as pretreating.); feeding the pretreated hydrocarbon gas stream into a reformer (para [0025], [0028], [0031]-[0033]; figure 1; The resultant treated, compressed refinery off gas stream 18 is then preheated; and then introduced into a catalytic reactor 26, which produces the reacted stream 36. Further, reacted stream 36 is introduced into another sulfur removal bed 40 to form a treated reacted stream 42 that is then combined with a superheated steam stream 44 to produce a reactant stream 46 that serves as a feed to a steam methane reformer 48, that includes reactor tubes 58. Reactor tubes 58 are fed by the reactant stream 46 after reactant stream 46 has been heated.); heating the pretreated hydrocarbon gas steam in the reformer to produce a synthesis gas stream and a flue gas stream (para [0033], [0035]; figure 1; Reactor tubes 58 are fed by the reactant stream 46 after reactant stream 46 has been heated within convective section 52 of steam methane reformer 50. In this regard, a flue gas stream 59 is produced by the combustion occurring within radiant section 50. Further, as known in the art, the reaction of the steam and the hydrocarbons within catalyst-filled reaction tubes 58 produce a reformed stream 90 that contains steam, hydrogen, carbon monoxide and carbon dioxide and a small amount of methane. Here, the reformed stream 90 is considered as the synthesis gas.); feeding the flue gas stream to a waste heat recovery section (para [0032]-[0034]; figure 1; Steam methane reformer 48 has a radiant section 50 and a convective section 52. In this regard, a flue gas stream 59 is produced by the combustion occurring within radiant section 50 that is then used to heat reactant stream 46 within a heat exchanger 60 located within convective section 52. Furthermore, flue gas stream 59 then passes to selective catalytic reduction unit 78 for removal of nitrogen oxides. The treated flue gas then passes through combustion air heater 80 to produce a heated combustion air stream 82 from an air feed stream 84. As seen in figure 1, the air heater is located in the convective section 52. Here, the convective section 52 is considered as the waste heat recovery section.);recovering waste heat so as to increase the thermal efficiency of the process (para [0033]-[0034]; figure 1; In this regard, a flue gas stream 59 is produced by the combustion occurring within radiant section 50 that is then used to heat reactant stream 46 within a heat exchanger 60 located within convective section 52. Furthermore, flue gas stream 59 then passes to selective catalytic reduction unit 78 for removal of nitrogen oxides. The treated flue gas then passes through combustion air heater 80 to produce a heated combustion air stream 82 from an air feed stream 84. The flue gas then is discharged as a stack gas 86 from flue stack 88. Heated combustion air stream 82 supports combustion of the fuel that is used in firing burners 54 and 56. Thus, here using the flue gas 59 to heat reactant stream 46, and to produce a heated combustion air stream 82, is considered as means of increasing the thermal efficiency of the process.):feeding the synthesis gas stream to a shift gas reactor (para [0037]; figure 1: Reformed stream 90 (synthesis gas) is then cooled in a process steam heater 92, that can also be used to raise steam for steam drum 66, to a temperature of about 600F and is then introduced into a high temperature shift conversion unit 94.); converting carbon monoxide from the synthesis gas stream in the shift gas reactor to produce hydrogen and carbon dioxide (para [0037]; figure 1; In high temperature shift conversion unit 94, reformed stream 90 is subjected to known water-gas shift reactions in which steam is reacted with carbon monoxide to produce a shifted stream 96 that contains additional hydrogen and carbon dioxide over the reformed stream 90.); separating the carbon dioxide from the synthesis gas stream (para [0038], [0039]; figure 1; The shifted stream 96 is then cooled to about ambient temperature in a cooler 102 by indirect heat exchange with air or water to produce an ambient temperature shifted stream 104. Carbon dioxide is then removed from the ambient temperature shifted stream 104 in an amine absorption unit 106 to produce a carbon dioxide containing gas stream 108 of about 99 mole % purity and a hydrogen containing gas stream 110.); and separating the hydrogen (para [0039]: figure 1; Hydrogen containing gas stream 110 is then passed through a dryer 112 that can be a temperature swing adsorption unit. The removal of moisture produces a dry hydrogen containing gas stream 114.).
Regarding claims 3 and 8, Drnevich teaches a process further comprising the step of: feeding a heated stream to a desulfurizer vessel to remove sulfur (para [0025], [0027]; figure 1; The resultant treated, compressed refinery off gas stream 18 is then preheated within a feed heater 20 to a temperature of no greater than about 900F to avoid cracking of higher order hydrocarbons that are contained within such stream. The resulting heated refinery off gas stream 24 is then introduced into a catalytic reactor 26 together with oxygen stream 28 and steam stream 30 as necessary. In the catalytic hydrogenation mode of operation, saturated rated hydrocarbons will be produced from olefins present in the feed and also sulfur compounds, such as carbonyl sulfide, mercaptans, thiophenes and other organic sulfur species will be reduced to hydrogen sulfide for further treatment.).
Claim Rejections - 35 USC § 103
The following is a quotation of 35 U.S.C. 103 which forms the basis for all obviousness rejections set forth in this Office action:
A patent for a claimed invention may not be obtained, notwithstanding that the claimed invention is not identically disclosed as set forth in section 102, if the differences between the claimed invention and the prior art are such that the claimed invention as a whole would have been obvious before the effective filing date of the claimed invention to a person having ordinary skill in the art to which the claimed invention pertains. Patentability shall not be negated by the manner in which the invention was made.
Claim(s) 11 and 13-15 is/are rejected under 35 U.S.C. 103 as being unpatentable over Rhinesmith et al. US 20110000133, in view of Chinn et al. US 20120167766.
Regarding claims 11, 13 and 14, Rhinesmith teaches a method of generating hydrogen from a hydrocarbon feed stream (Abstract). The reference teaches a preheater 9 for preheating hydrocarbon and pre-reformed hydrocarbon going into a reformer 19 (Para [0111]). The hydrocarbon undergoes steam reforming with heat to result in syngas (“CnHm(v) +nH2O+heat→nCO(v)+(m/2+n)H2” See Para [0110]-[0111]). The reforming temperature is disclosed as 1115°F (Para [0111]). This reads on the claimed limitation of heating the pretreated hydrocarbon gas stream in the reformer to produce synthesis gas since the hydrocarbon of the reference is already pretreated in the pre-reformer 18. Flue gas is also produced in the reformer (See Para [0112]). The hot flue gas exiting the burner of the reformer is sent to heat exchanger 10 which utilizes the heat from the flue gas to preheat the hydrocarbon before it enters the reformer 19 (See Fig. 3 and Para [0114]). This is considered to read on the claimed limitation of recovering waste heat to increase the thermal efficiency of the process. The thermal efficiency is increased because the process used excess heat from an internal source to heat another stream in a different part of the process. The syngas exiting the reformer is sent to a high temperature shift where carbon monoxide is converted to carbon dioxide and hydrogen by the water gas shift reaction (See Para [0115]-[0116] “CO(v)+H2O(v)→CO2(v)+H2(v)+heat”).
The difference between the invention of Rhinesmith and that of claim 11 is that claim 11 requires that carbon dioxide is separated from the flue gas.
Chinn et al. teaches that flue gas from a reformer or specifically a steam methane reformer contains CO2 which is captured using an ionic absorbent (Abstract and Para [0026]). The reference provides an embodiment where amine based solvents are used as the ionic absorbent due to the ionic selectivity towards CO2 (Para [0030]). The reference teaches that the ionic absorbent (amine solvent) captures Co2 from a flue gas stream A and is regenerated in regenerator H (Para [0068]-[0070]). The regenerator H produces a CO2 depleted ionic absorbent sorbent S which is sent to heat exchangers Q and K then recirculated for use in the CO2 absorber unit D (Para [0070] and [0075]). See Fig. 5. This reads on using a regenerated amine as claimed.
Before the effective filing date of the claimed invention it would have been obvious for a person of ordinary level of skill in the art to use the amine wash of Chinn to remove the carbon dioxide in the flue gas from the burner of the reformer of Rhinesmith. One would be motivated to do so in effort to sequester harmful CO2 (See Chinn Para [0004]).
Regarding claim 15, the Chinn et al. reference teaches using a blower B to pressurize the flue gas to an appropriate pressure for the absorber unit D (See Fig. 5 and Para [0065]).
Claim(s) 11 and 13-15 is/are rejected under 35 U.S.C. 103 as being unpatentable over Drnevich et al. US 20100158776, in view of Chinn et al. US 20120167766.
Regarding claims 11, 13 and 14, Drnevich teaches a process for producing low carbon intensity hydrogen (para [0009]-[0012], [0039]; figure 1; The present invention provides a method of reducing carbon dioxide emissions in a refinery by treating a refinery off gas stream. The steps of the method include steam methane reforming to produce hydrogen and carbon dioxide. Carbon dioxide is then separated to produce a carbon dioxide containing gas stream and a hydrogen containing gas stream. The hydrogen containing gas would have about 2% mole carbon dioxide.), comprising the steps of: pretreating a hydrocarbon gas stream (para [0022], [0024]; figure 1; With reference to figure 1, a steam methane reforming installation 1 is illustrated in which a hydrocarbon containing stream to be reformed by steam methane reforming originates as in incoming refinery off gas stream 10. Refinery off gas stream 10 is compressed in a compressor 12 to produce a compressed refinery off gas stream 14. Here, compressing is considered as pretreating.); feeding the pretreated hydrocarbon gas stream into a reformer (para [0025], [0028], [0031]-[0033]; figure 1; The resultant treated, compressed refinery off gas stream 18 is then preheated; and then introduced into a catalytic reactor 26, which produces the reacted stream 36. Further, reacted stream 36 is introduced into another sulfur removal bed 40 to form a treated reacted stream 42 that is then combined with a superheated steam stream 44 to produce a reactant stream 46 that serves as a feed to a steam methane reformer 48, that includes reactor tubes 58. Reactor tubes 58 are fed by the reactant stream 46 after reactant stream 46 has been heated.); heating the pretreated hydrocarbon gas steam in the reformer to produce a synthesis gas stream and a flue gas stream (para [0033], [0035]; figure 1; Reactor tubes 58 are fed by the reactant stream 46 after reactant stream 46 has been heated within convective section 52 of steam methane reformer 50. In this regard, a flue gas stream 59 is produced by the combustion occurring within radiant section 50. Further, as known in the art, the reaction of the steam and the hydrocarbons within catalyst-filled reaction tubes 58 produce a reformed stream 90 that contains steam, hydrogen, carbon monoxide and carbon dioxide and a small amount of methane. Here, the reformed stream 90 is considered as the synthesis gas.); feeding the flue gas stream to a waste heat recovery section (para [0032]-[0034]; figure 1; Steam methane reformer 48 has a radiant section 50 and a convective section 52. In this regard, a flue gas stream 59 is produced by the combustion occurring within radiant section 50 that is then used to heat reactant stream 46 within a heat exchanger 60 located within convective section 52. Furthermore, flue gas stream 59 then passes to selective catalytic reduction unit 78 for removal of nitrogen oxides. The treated flue gas then passes through combustion air heater 80 to produce a heated combustion air stream 82 from an air feed stream 84. As seen in figure 1, the air heater is located in the convective section 52. Here, the convective section 52 is considered as the waste heat recovery section.);recovering waste heat so as to increase the thermal efficiency of the process (para [0033]-[0034]; figure 1; In this regard, a flue gas stream 59 is produced by the combustion occurring within radiant section 50 that is then used to heat reactant stream 46 within a heat exchanger 60 located within convective section 52. Furthermore, flue gas stream 59 then passes to selective catalytic reduction unit 78 for removal of nitrogen oxides. The treated flue gas then passes through combustion air heater 80 to produce a heated combustion air stream 82 from an air feed stream 84. The flue gas then is discharged as a stack gas 86 from flue stack 88. Heated combustion air stream 82 supports combustion of the fuel that is used in firing burners 54 and 56. Thus, here using the flue gas 59 to heat reactant stream 46, and to produce a heated combustion air stream 82, is considered as means of increasing the thermal efficiency of the process.):feeding the synthesis gas stream to a shift gas reactor (para [0037]; figure 1: Reformed stream 90 (synthesis gas) is then cooled in a process steam heater 92, that can also be used to raise steam for steam drum 66, to a temperature of about 600F and is then introduced into a high temperature shift conversion unit 94.); converting carbon monoxide from the synthesis gas stream in the shift gas reactor to produce hydrogen and carbon dioxide (para [0037]; figure 1; In high temperature shift conversion unit 94, reformed stream 90 is subjected to known water-gas shift reactions in which steam is reacted with carbon monoxide to produce a shifted stream 96 that contains additional hydrogen and carbon dioxide over the reformed stream 90.); separating the carbon dioxide from the synthesis gas stream (para [0038], [0039]; figure 1; The shifted stream 96 is then cooled to about ambient temperature in a cooler 102 by indirect heat exchange with air or water to produce an ambient temperature shifted stream 104. Carbon dioxide is then removed from the ambient temperature shifted stream 104 in an amine absorption unit 106 to produce a carbon dioxide containing gas stream 108 of about 99 mole % purity and a hydrogen containing gas stream 110.); and separating the hydrogen (para [0039]: figure 1; Hydrogen containing gas stream 110 is then passed through a dryer 112 that can be a temperature swing adsorption unit. The removal of moisture produces a dry hydrogen containing gas stream 114.).
The difference between the invention of Drnevich and that of claim 11 is that claim 11 requires that carbon dioxide is separated from the flue gas.
Chinn et al. teaches that flue gas from a reformer or specifically a steam methane reformer contains CO2 which is captured using an ionic absorbent (Abstract and Para [0026]). The reference provides an embodiment where amine based solvents are used as the ionic absorbent due to the ionic selectivity towards CO2 (Para [0030]). The reference teaches that the ionic absorbent (amine solvent) captures CO2 from a flue gas stream A and is regenerated in regenerator H (Para [0068]-[0070]). The regenerator H produces a CO2 depleted ionic absorbent sorbent S which is sent to heat exchangers Q and K then recirculated for use in the CO2 absorber unit D (Para [0070] and [0075]). See Fig. 5. This reads on using a regenerated amine as claimed.
Before the effective filing date of the claimed invention it would have been obvious for a person of ordinary level of skill in the art to use the amine wash of Chinn to remove the carbon dioxide in the flue gas from the burner of the reformer of Drnevich. One would be motivated to do so in effort to sequester harmful CO2 (See Chinn Para [0004]).
Regarding claim 15, the Chinn et al. reference teaches using a blower B to pressurize the flue gas to an appropriate pressure for the absorber unit D (See Fig. 5 and Para [0065]).
Claim(s) 2 and 7 is/are rejected under 35 U.S.C. 103 as being unpatentable over Drnevich et al. US 20100158776, in view of Schoenfeld US 2300634.
Regarding claims 2 and 7, Drnevich teaches a process wherein the waste heat recovery section includes a plurality of heat transfer elements (para [0033]; figure 1; Reactor tubes 58 are fed by the reactant stream 46 after reactant stream 46 has been heated within convective section 52 of steam methane reformer 50. In this regard, a flue gas stream 59 is produced by the combustion occurring within radiant section 50 that is then used to heat reactant stream 46 within a heat exchanger 60 located within convective section 52 (waste heat recovery section). Further heat exchangers 61, 62 and 64 are also provided within convective section 52 (waste heat recovery section) to raise steam and then to superheat the steam. Thus, here, heat exchangers 60, 61, 62 and 64 in the convective section 52 (waste heat recovery section) is considered as the heat transfer elements.), comprising: a boiler feed water preheater (para [0033]; figure 1; Heat exchangers 61, 62 and 64 are also provided within convective section 52 (waste heat recovery section) to raise steam and then to superheat the steam. The steam is raised within a steam drum 66 by passing a boiler feedwater stream 68 into heat exchangers 61 and 62 to produce a steam containing stream 70 that is fed back into steam drum 66. Steam drum 66 is fed with heated boiler feedwater in a manner that will be discussed and that, in any case, is conventional. The resultant steam is fed as a steam stream 72 into steam superheater 64 to produce superheated steam stream 74 that is divided into superheated steam stream 44 and an export steam stream 76. Thus, as the boiler feedwater stream 68 is heated by heat exchangers 61 and 62; and then superheated with heat exchangers 64; then this indicates that the heating of the boiler feedwater stream 68 by heat exchangers 61 and 62 in convective section 52 (waste heat recovery section) is preheating.);a mixed feed preheater (para [0031], [0033], [0032]; figure 1; Treated reacted stream 42 is combined with a superheated steam stream 44 to produce a reactant stream 46 that serves as a feed to a steam methane reformer 48. Here, the combination of the treated reacted stream 42 and superheated steam stream 44, i.e., reactant stream 46, is considered as the mixed feed. Moreover, reactor tubes 58 are fed by the reactant stream 46 after reactant stream 46 has been heated within convective section 52 (waste heat recovery section) of steam methane reformer 50. Further, burners 54 and 56 fire into radiant section 50 to heat reactor tubes 58. Thus, this indicates that heating of the reactant stream 46 (mixed feed) by heat exchanger 60 in convective section 52 (waste heat recovery section) is preheating.); and one steam element (para [0033]; figure 1; Heat exchangers 61, 62 and 64 are also provided within convective section 52 (waste heat recovery section) to raise steam and then to superheat the steam. Steam drum 66 is fed with heated boiler feedwater in a manner that will be discussed and that, in any case, is conventional. The resultant steam is fed as a steam stream 72 into steam superheater 64 to produce superheated steam stream 74. Here, steam superheater 64 is considered as the steam element.).
A difference between the invention of Drnevich and that of claims 2 and 7 is that the claims require the waste heat recovery section have heat transfer coils that have a natural gas feed preheater. The reference does not exactly teach that the heat transfer elements in the waste heat recovery section include a natural gas feed preheater. However, Drnevich teaches that the heat transfer elements include a natural gas feed preheater (para [0022], [0024][0025]; Figure 1; Natural gas could be mixed with the refinery off gas stream 10 and then same could be processed as described hereinbelow. Next, refinery off gas stream 10 (which is mixed with natural gas here) is compressed in a compressor 12 to produce a compressed refinery off gas stream 14. Thereafter, the compressed refinery off gas stream is then introduced into a guard bed 16. The resultant treated, compressed refinery off gas stream 18 is then preheated within a feed heater 20.).
Before the effective filing date of the claimed invention it would have been obvious to one ordinary skilled in the art to utilize the waste heat recovery for preheating the natural gas-containing refinery off gas stream 10; such that the heat transfer elements in the waste heat recovery section include a natural gas feed preheater; in order to utilize the flue gas stream that is produced by the combustion occurring within radiant section 50 of the convective section 52 (waste heat recovery section), to heat stream(s) within heat exchanger(s) (para [0033]; figure 1); such as preheating the compressed refinery off gas stream 18 that contains natural gas (para [0025]); because flue gas can produce a heated combustion air stream from an air feed stream, which can in turn support combustion and/or heating (para [0033]-[0034]). Thus, in order to allow the flue gas to heat-exchange with processes, such as the natural gas feed preheater (para [0033], [0034], [0025]); for energy considerations.
A further difference is that Drnevich does not teach that the heat transfer elements and the steam element(s) are heat transfer coils and steam coil(s).
Schoenfeld on the other hand, teaches the heat transfer elements and the steam element(s) are heat transfer coils and steam coil(s) (Pg 1, col 1, In 1-4; Pg 1, col 2, In 37-46; figures 1 and 5-9; This invention relates to improvements in tubular heat exchange elements adapted for use in forced circulation boilers and particularly in waste heat forced circulation boilers. In the embodiment shown in figure 1, the sets of coils in the boiler are divided into two groups, designated 10 and 11. Group II which is nearest to the hot entering gases and in which a major portion of the tubes are filled with steam, is constructed of sets of coils as shown in figures 5 to 9.)
Before the effective filing date of the claimed invention it would have been obvious to one ordinary skilled in the art to utilize coils as heat transfer elements, as taught by Schoenfeld; with the process for producing low carbon intensity hydrogen, as taught by Drnevich; because in waste heat boilers such as those used to extract heat from exhaust gases of gas engines, it is desirable lo have the tubes arranged compactly so as to occupy a small space. A flat tube coil is a useful form of heat exchange element for constructing such a boiler (Schoenfeld; Pg 1, col 1, In 5-10). Further, because the coils in one set are of different lengths than the coils in another set and so arranged that each of the assembled sets has substantially the same overall diameter and tube length, the same tube size and tube spacing in all groups, whereby the resistance to fluid flow through each of the coils is substantially the same (Schoenfeld; Pg 1, col 1, In 42-50). For instance, the two tube coils 24 and 25 forming a set in group 10 have substantially the same total tube length as the three tube coils 30, 31 and 32 forming a set in group 11, one tube coil 24 or 25 being one and one-half times as long as the length of one tube coil 30, 31 or 32. Since the velocity of fluid flow through the tubes of group 11 is greater than that through the tubes of group 10, the resulting greater resistances per unit length of the latter are offset by their shorter length of tubes and a closer uniformity of pressure drop for the groups is obtained (Schoenfeld; Pg 2, col 1, In 29-40; figures 1-9).
Claim(s) 4 and 9 is/are rejected under 35 U.S.C. 103 as being unpatentable over Drnevich et al. US 20100158776, in view of Baksh et al. US 20120174776.
Regarding claims 4 and 8, Drnevich does not teach a process further comprising the step of: separating hydrogen from the synthesis gas stream by pressure swing adsorption.
Baksh, on the other hand, teaches a process further comprising the step of: separating hydrogen from the synthesis gas stream by pressure swing adsorption (para [0001]; The present invention relates to a six bed pressure swing adsorption (PSA) system utilizing new and advanced cycles to obtain enhanced hydrogen recovery from a hydrogen containing feed gas (i.e., synthesis gas).).
Before the effective filing date of the claimed invention it would have been obvious to one ordinary skilled in the art to utilize pressure swing adsorption for separation of hydrogen, as taught by Baksh; with the process for producing low carbon intensity hydrogen, as taught by Drnevich; because the invention discloses high efficiency PSA processes/cycles employed in a six bed PSA system to attain 20-50 million standard cubic feet per day of hydrogen production. The cycles achieve enhanced recovery of hydrogen from a hydrogen containing gas. Further, because the invention provides novel and advanced PSA cycles for six bed PSA systems which can be operated in turndown mode, and provide high hydrogen recovery (Baksh; para [0021]-[0022]).
Claim(s) 5 and 10 is/are rejected under 35 U.S.C. 103 as being unpatentable over Drnevich et al. US 20100158776, in view of Giroudiere et al. US 20090044701
Regarding claims 5 and 10, Drnevich does not teach a process further comprising the step of: separating hydrogen from the synthesis gas stream by membrane separation.
Giroudiere, on the other hand, teaches a process further comprising the step of: separating hydrogen from the synthesis gas stream by membrane separation (para [0036]-[0037]; The process according to this invention can be defined as a hydrogen purification process contained in a synthesis gas. The process according to the invention relies on at least three membrane separation units.).
Before the effective filing date of the claimed invention it would have been obvious to one ordinary skilled in the art to utilize membranes for separation of hydrogen, as taught by Giroudiere; with the process for producing low carbon intensity hydrogen, as taught by Drnevich; because this process allows non-stationary operations (Giroudiere; abstract). Moreover, because this process makes it possible to obtain the purified hydrogen with at least 99% purity with a recovery level that can reach 86% (Giroudiere; para [0055]).
Claim(s) 4 and 9 is/are rejected under 35 U.S.C. 103 as being unpatentable over Rhinesmith et al. US 20110000133, in view of Baksh et al. US 20120174776.
Regarding claims 4 and 8, Rhinesmith does not teach a process further comprising the step of: separating hydrogen from the synthesis gas stream by pressure swing adsorption.
Baksh, on the other hand, teaches a process further comprising the step of: separating hydrogen from the synthesis gas stream by pressure swing adsorption (para [0001]; The present invention relates to a six bed pressure swing adsorption (PSA) system utilizing new and advanced cycles to obtain enhanced hydrogen recovery from a hydrogen containing feed gas (i.e., synthesis gas).).
Before the effective filing date of the claimed invention it would have been obvious to one ordinary skilled in the art to utilize pressure swing adsorption for separation of hydrogen, as taught by Baksh; with the process of Rhinesmith; because the invention discloses high efficiency PSA processes/cycles employed in a six bed PSA system to attain 20-50 million standard cubic feet per day of hydrogen production. The cycles achieve enhanced recovery of hydrogen from a hydrogen containing gas. Further, because the invention provides novel and advanced PSA cycles for six bed PSA systems which can be operated in turndown mode, and provide high hydrogen recovery (Baksh; para [0021]-[0022]).
Claim(s) 5 and 10 is/are rejected under 35 U.S.C. 103 as being unpatentable over Rhinesmith et al. US 20110000133, in view of Giroudiere et al. US 20090044701
Regarding claims 5 and 10, Rhinesmith does not teach a process further comprising the step of: separating hydrogen from the synthesis gas stream by membrane separation.
Giroudiere, on the other hand, teaches a process further comprising the step of: separating hydrogen from the synthesis gas stream by membrane separation (para [0036]-[0037]; The process according to this invention can be defined as a hydrogen purification process contained in a synthesis gas. The process according to the invention relies on at least three membrane separation units.).
Before the effective filing date of the claimed invention it would have been obvious to one ordinary skilled in the art to utilize membranes for separation of hydrogen, as taught by Giroudiere; with the process of Rhinesmith because this process allows non-stationary operations (Giroudiere; abstract). Moreover, because this process makes it possible to obtain the purified hydrogen with at least 99% purity with a recovery level that can reach 86% (Giroudiere; para [0055]).
Claim(s) 12 is/are rejected under 35 U.S.C. 103 as being unpatentable over Drnevich et al. US 20100158776, in view of Chinn et al. US 20120167766 as applied to claims 11 and 13-15 above, and further in view of Schoenfeld US 2300634.
Regarding claim 12, Drnevich teaches a process wherein the waste heat recovery section includes a plurality of heat transfer elements (para [0033]; figure 1; Reactor tubes 58 are fed by the reactant stream 46 after reactant stream 46 has been heated within convective section 52 of steam methane reformer 50. In this regard, a flue gas stream 59 is produced by the combustion occurring within radiant section 50 that is then used to heat reactant stream 46 within a heat exchanger 60 located within convective section 52 (waste heat recovery section). Further heat exchangers 61, 62 and 64 are also provided within convective section 52 (waste heat recovery section) to raise steam and then to superheat the steam. Thus, here, heat exchangers 60, 61, 62 and 64 in the convective section 52 (waste heat recovery section) is considered as the heat transfer elements.), comprising: a boiler feed water preheater (para [0033]; figure 1; Heat exchangers 61, 62 and 64 are also provided within convective section 52 (waste heat recovery section) to raise steam and then to superheat the steam. The steam is raised within a steam drum 66 by passing a boiler feedwater stream 68 into heat exchangers 61 and 62 to produce a steam containing stream 70 that is fed back into steam drum 66. Steam drum 66 is fed with heated boiler feedwater in a manner that will be discussed and that, in any case, is conventional. The resultant steam is fed as a steam stream 72 into steam superheater 64 to produce superheated steam stream 74 that is divided into superheated steam stream 44 and an export steam stream 76. Thus, as the boiler feedwater stream 68 is heated by heat exchangers 61 and 62; and then superheated with heat exchangers 64; then this indicates that the heating of the boiler feedwater stream 68 by heat exchangers 61 and 62 in convective section 52 (waste heat recovery section) is preheating.);a mixed feed preheater (para [0031], [0033], [0032]; figure 1; Treated reacted stream 42 is combined with a superheated steam stream 44 to produce a reactant stream 46 that serves as a feed to a steam methane reformer 48. Here, the combination of the treated reacted stream 42 and superheated steam stream 44, i.e., reactant stream 46, is considered as the mixed feed. Moreover, reactor tubes 58 are fed by the reactant stream 46 after reactant stream 46 has been heated within convective section 52 (waste heat recovery section) of steam methane reformer 50. Further, burners 54 and 56 fire into radiant section 50 to heat reactor tubes 58. Thus, this indicates that heating of the reactant stream 46 (mixed feed) by heat exchanger 60 in convective section 52 (waste heat recovery section) is preheating.); and one steam element (para [0033]; figure 1; Heat exchangers 61, 62 and 64 are also provided within convective section 52 (waste heat recovery section) to raise steam and then to superheat the steam. Steam drum 66 is fed with heated boiler feedwater in a manner that will be discussed and that, in any case, is conventional. The resultant steam is fed as a steam stream 72 into steam superheater 64 to produce superheated steam stream 74. Here, steam superheater 64 is considered as the steam element.).
A difference between the invention of Drnevich and that of claims 2 and 7 is that the claims require the waste heat recovery section have heat transfer coils that have a natural gas feed preheater. The reference does not exactly teach that the heat transfer elements in the waste heat recovery section include a natural gas feed preheater. However, Drnevich teaches that the heat transfer elements include a natural gas feed preheater (para [0022], [0024][0025]; Figure 1; Natural gas could be mixed with the refinery off gas stream 10 and then same could be processed as described hereinbelow. Next, refinery off gas stream 10 (which is mixed with natural gas here) is compressed in a compressor 12 to produce a compressed refinery off gas stream 14. Thereafter, the compressed refinery off gas stream is then introduced into a guard bed 16. The resultant treated, compressed refinery off gas stream 18 is then preheated within a feed heater 20.).
Before the effective filing date of the claimed invention it would have been obvious to one ordinary skilled in the art to utilize the waste heat recovery for preheating the natural gas-containing refinery off gas stream 10; such that the heat transfer elements in the waste heat recovery section include a natural gas feed preheater; in order to utilize the flue gas stream that is produced by the combustion occurring within radiant section 50 of the convective section 52 (waste heat recovery section), to heat stream(s) within heat exchanger(s) (para [0033]; figure 1); such as preheating the compressed refinery off gas stream 18 that contains natural gas (para [0025]); because flue gas can produce a heated combustion air stream from an air feed stream, which can in turn support combustion and/or heating (para [0033]-[0034]). Thus, in order to allow the flue gas to heat-exchange with processes, such as the natural gas feed preheater (para [0033], [0034], [0025]); for energy considerations.
A further difference is that Drnevich does not teach that the heat transfer elements and the steam element(s) are heat transfer coils and steam coil(s).
Schoenfeld on the other hand, teaches the heat transfer elements and the steam element(s) are heat transfer coils and steam coil(s) (Pg 1, col 1, In 1-4; Pg 1, col 2, In 37-46; figures 1 and 5-9; This invention relates to improvements in tubular heat exchange elements adapted for use in forced circulation boilers and particularly in waste heat forced circulation boilers. In the embodiment shown in figure 1, the sets of coils in the boiler are divided into two groups, designated 10 and 11. Group II which is nearest to the hot entering gases and in which a major portion of the tubes are filled with steam, is constructed of sets of coils as shown in figures 5 to 9.)
Before the effective filing date of the claimed invention it would have been obvious to one ordinary skilled in the art to utilize coils as heat transfer elements, as taught by Schoenfeld; with the process for producing low carbon intensity hydrogen, as taught by Drnevich; because in waste heat boilers such as those used to extract heat from exhaust gases of gas engines, it is desirable lo have the tubes arranged compactly so as to occupy a small space. A flat tube coil is a useful form of heat exchange element for constructing such a boiler (Schoenfeld; Pg 1, col 1, In 5-10). Further, because the coils in one set are of different lengths than the coils in another set and so arranged that each of the assembled sets has substantially the same overall diameter and tube length, the same tube size and tube spacing in all groups, whereby the resistance to fluid flow through each of the coils is substantially the same (Schoenfeld; Pg 1, col 1, In 42-50). For instance, the two tube coils 24 and 25 forming a set in group 10 have substantially the same total tube length as the three tube coils 30, 31 and 32 forming a set in group 11, one tube coil 24 or 25 being one and one-half times as long as the length of one tube coil 30, 31 or 32. Since the velocity of fluid flow through the tubes of group 11 is greater than that through the tubes of group 10, the resulting greater resistances per unit length of the latter are offset by their shorter length of tubes and a closer uniformity of pressure drop for the groups is obtained (Schoenfeld; Pg 2, col 1, In 29-40; figures 1-9).
Relevant Art
Bairamijamal US 20150376801 relates to high pressure CO2 capture from a CO2 gas stream by subcritical condensation, separation of liquid CO2, pressure elevation of obtained liquid CO2, super-heating of CO2 and generating power with the CO2 (Abstract).
Vakil et al. US 20100037521 teaches a hydrogen plant enhanced for carbon dioxide recovery. The reference teaches that hydrogen is produced utilizing a steam reformer and enhanced in a shift step (Para [0018]). The hydrogen is recovered in a PSA (Para [0020]). The reference further teaches that reformer flue gas is cooled in a waste heat recovery unit to generate steam and to preheat reformer feed streams (Para [0033]).
Conclusion
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/SYED T IQBAL/ Examiner, Art Unit 1736
/ANTHONY J ZIMMER/ Supervisory Patent Examiner, Art Unit 1736