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 Rejections - 35 USC § 103
In the event the determination of the status of the application as subject to AIA 35 U.S.C. 102 and 103 (or as subject to pre-AIA 35 U.S.C. 102 and 103) is incorrect, any correction of the statutory basis (i.e., changing from AIA to pre-AIA ) for the rejection will not be considered a new ground of rejection if the prior art relied upon, and the rationale supporting the rejection, would be the same under either status.
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.
The factual inquiries for establishing a background for determining obviousness under 35 U.S.C. 103 are summarized as follows:
1. Determining the scope and contents of the prior art.
2. Ascertaining the differences between the prior art and the claims at issue.
3. Resolving the level of ordinary skill in the pertinent art.
4. Considering objective evidence present in the application indicating obviousness or nonobviousness.
Claims 1-4, 8-14 and 18-20 are rejected under 35 U.S.C. 103 as being unpatentable over Gaskin US 2017/0176099.
Regarding claims 1-3, Gaskin teaches a method of using external natural gas liquid (NGL) to remove heavies from a natural gas feed stream, the method comprising:
evaluating a composition of a natural gas feed stream to determine at least a heavies quantity by analyzing a cooling curve of the feed gas to determine the freeze point of the mixture ([0023]);
combining the amount of external NGL (propane or butane solvent [0053]) with the natural gas feed stream in a first chiller 4 to generate a mixture having the heavies quantity dissolved therein ([0024]); and
cooling the mixture in the first chiller to a temperature sufficient to separate the mixture into a liquid stream and a gas stream, the liquid stream comprising the external NGL and dissolved quantity of heavies ([0053]-[0055]).
Gaskin does not explicitly teach calculating an amount of external NGL required to dissolve the heavies quantity of the natural gas feed stream.
However, it would have been obvious to determine the heavies content from the feed composition and use that content to calculate the amount of propane and butane to add. Gaskin does teach that the amount of solvent needed depends on the feed composition and the amount of freezing components. The injection rate of the solvent may therefore be predicted using stream composition ([0023]-[0024]). Thus, one having ordinary skill in the art would have made this calculation to supply enough solvent to keep the heavies in the liquid and avoid freezing as Gaskin intends ([0023], [0024], [0037], [0038]).
Regarding claim 4, Gaskin teaches separating the mixture bottoms in a separator to generate the liquid stream and the gas stream; diverting the liquid stream to a first stripping column (demethanizer 60); and transferring the gas stream to a second chiller as heat exchanger 18 ([0047]-[0051]).
Regarding claims 8, 9, and 10, the natural gas feed stream further includes methane and nitrogen, is a rich natural gas and includes a lean natural gas [0047], [0052]).
Regarding claims 11 and 12, the external NGL comprises at least one of C4 or C5 hydrocarbon, including a C2-C6 alkane ([0023] and [0026]).
Regarding claim 13, Gaskin teaches a system for using external natural gas liquid (NGL) to remove heavies from a natural gas feed stream, the system comprising:
means for evaluating a composition of a natural gas feed stream to determine at least a heavies quantity by analyzing a cooling curve of the feed gas to determine the freeze point of the mixture ([0023]);
combining the amount of external NGL (propane or butane solvent [0053]) with the natural gas feed stream in a first chiller 4 to generate a mixture having the heavies quantity dissolved therein ([0024]); and
cooling the mixture in the first chiller to a temperature sufficient to separate the mixture into a liquid stream and a gas stream, the liquid stream comprising the external NGL and dissolved quantity of heavies ([0053]-[0055]).
Gaskin does not explicitly teach calculating an amount of external NGL required to dissolve the heavies quantity of the natural gas feed stream.
However, it would have been obvious to determine the heavies content from the feed composition and use that content to calculate the amount of propane and butane to add. Gaskin does teach that the amount of solvent needed depends on the feed composition and the amount of freezing components. The injection rate of the solvent may therefore be predicted using stream composition ([0023]-[0024]). Thus, one having ordinary skill in the art would have made this calculation to supply enough solvent to keep the heavies in the liquid and avoid freezing as Gaskin intends ([0023], [0024], [0037], [0038]).
Regarding claim 14, Gaskin teaches demethanizer 60 (first stripping column) that receives liquid from the separator 8. Heat exchanger 18 (second chiller) receives the further cooling gas from separator 8 ([0047]).
Regarding claims 18, 19, and 20, the natural gas feed stream further includes methane and nitrogen, is a rich natural gas and includes a lean natural gas [0047], [0052]).
Claims 5, 6, 7, 15, 16, and 17 are rejected under 35 U.S.C. 103 as being unpatentable over Gaskin US 2017/0176099 in view of Swenson US Patent 3,393,527.
Regarding claim 5, Gaskin teaches:
cooling the gas from the first separator 8 in the second heat exchanger 18;
separating the cooled gas in second separator 22 into an overhead gas stream 24 and a liquid bottoms stream 26;
directing the liquid bottoms stream 26 along with the liquid from the first separator 8 to demethanizer 60; wherein
demethanizer 60 separates methane from the liquids and produces a methane-containing overhead stream 62 ([0047]-[0051]).
Gaskin does not direct the overhead gas stream 24 from the second separator 22 to the demethanizer 60. Swenson teaches sending separated liquid to a fractionator 24 and sending the remaining gas to that same fractionator 24, where heavier hydrocarbons collect in the liquid and methane is removed overhead (column 5 lines 5-25, Figure 1).
Thus, it would have been obvious to one having ordinary skill in the art to direct Gavin’s overhead gas stream 24 to demethanizer 60, as taught by Swenson, to separate any remaining heavier hydrocarbons and recover methane overhead.
Regarding claim 6, Swenson further directs gas from an expander 26 into the fractionator 24 (column 5 lines 40-55, column 6 lines 10-14). Thus, in the modified Gaskin process, the gas would be cooled in Gaskin’s expander before entering the demethanizer 60 (Figure 1).
Regarding claim 7, Gaskin teaches sending the overhead gas from demethanizer 60 through a condenser 46 and an accumulator 78, where a liquid portion is separated from the gas, and further using columns to recover propane and butane for recycle to the feed before inlet heat exchanger 4 ([0051] and [0055]-[0058]).
Gaskin does not explicitly teach sending the demethanizer overhead gas to a second stripping column. However, it would have been obvious to one having ordinary skill in the art to further separate the demethanizer overhead gas in a stripping column to recover any remaining NGL, rather than lose it in the methane stream, and recycle the recovered NGL to the feed to prevent freezing of the feed.
Regarding claim 15, Gaskin teaches the system further comprises:
the first separator 8 that produces a cooled gas which is sent in the second heat exchanger 18;
a second separator 22 configured to produce an overhead gas stream 24 and a liquid bottoms stream 26;
means for directing the liquid bottoms stream 26 along with the liquid from the first separator 8 to demethanizer 60; wherein
demethanizer 60 is configured to separate methane from the liquids and produces a methane-containing overhead stream 62 ([0047]-[0051]).
Gaskin does not direct the overhead gas stream 24 from the second separator 22 to the demethanizer 60. Swenson teaches sending separated liquid to a fractionator 24 and sending the remaining gas to that same fractionator 24, where heavier hydrocarbons collect in the liquid and methane is removed overhead (column 5 lines 5-25, Figure 1).
Thus, it would have been obvious to one having ordinary skill in the art to direct Gavin’s overhead gas stream 24 to demethanizer 60, as taught by Swenson, to separate any remaining heavier hydrocarbons and recover methane overhead.
Regarding claim 16, Swenson further provides means for directs gas from an expander 26 into the fractionator 24 (column 5 lines 40-55, column 6 lines 10-14). Thus, in the modified Gaskin process, the gas would be cooled in Gaskin’s expander before entering the demethanizer 60 (Figure 1).
Regarding claim 17, Gaskin teaches means for sending the overhead gas from demethanizer 60 through a condenser 46 and an accumulator 78, where a liquid portion is separated from the gas, and using additional columns and further using columns to recover propane and butane for recycle to the feed before inlet heat exchanger 4 ([0051] and [0055]-[0058]).
Gaskin does not explicitly teach means for sending the demethanizer overhead gas to a second stripping column. However, it would have been obvious to one having ordinary skill in the art to configure a second stripping column to further separate the demethanizer overhead gas and recover any remaining NGL from the methane stream, rather than lose it in the methane stream, and recycle the recovered NGL to the feed to prevent freezing of the feed.
Conclusion
Any inquiry concerning this communication or earlier communications from the examiner should be directed to SHARON PREGLER whose telephone number is (571)270-5051. The examiner can normally be reached Monday - Friday 9am - 5pm.
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/SHARON PREGLER/ Primary Examiner, Art Unit 1772
