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 .
Summary
This is the initial Office action based on application 18659139 filed 5/9/24.
Claims 1-20 are pending and have been fully considered.
Information Disclosure Statement
IDS filed on 10/15/24 have been considered by the examiner and copies of the Form PTO/SB/08 are attached to the office action.
Drawings
The Drawings filed on 5/9/24 are acknowledged and accepted by the examiner.
Specification
The Specification has not been checked to the extent necessary to determine the presence of all possible minor errors. Applicant's cooperation is requested in correcting any errors of which applicant may become aware in the specification. MPEP § 608.01
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 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 of this title, 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 1-20 are rejected under 35 U.S.C. 103 as being unpatentable over KOSEOGU (US PG PUB 20210246383) and as evidence by AL-SHAFEI ET AL. (US PG PUB 20220017829) in their entirety. Hereby referred to as KOSEOGU and AL-SHAFEI.
Regarding claims 1-20:
KOSEOGU teaches in para [0002] relate to deep hydrogenation of middle distillates for conversion into feedstocks suitable for steam cracking to produce light olefins, and an integrated process and system for converting crude oil to petrochemicals integrating deep hydrogenation of middle distillates.
KOSEOGU teaches in para [0009] a vacuum gas oil fraction is separated from the atmospheric residue fraction in a vacuum distillation zone. In a distillate hydrotreating (“DHT”) zone, such as a diesel hydrotreater, at least a portion of the middle distillates are processed to produce a naphtha fraction and a hydrotreated middle distillate fraction. The vacuum gas oil fraction (and optionally all or a portion of an atmospheric gas oil fraction, or all or a portion of a heavy atmospheric gas oil fraction) is processed in a gas oil hydroprocessing zone to produce naphtha, middle distillates, and hydrotreated gas oil and/or unconverted oil. In certain embodiments, the middle distillates from gas oil hydroprocessing are passed to deep hydrogenation. In further embodiments the middle distillates from gas oil hydroprocessing are subjected to hydrotreating prior to deep hydrogenation.
KOSEOGU teaches in para [0101] the total feed to the atmospheric distillation zone 1110 is primarily the feed 1102, although it shall be appreciated that wild naphtha, LPGs and off-gas streams from the diesel hydrotreating zone 1150 and in certain embodiments from the gas oil hydroprocessing step and/or the vacuum residue hydrocracking zone 1180 can be routed to the atmospheric distillation zone 1110 where they are fractionated before being passed to the steam cracking complex. A desalting unit (not shown) is typically included upstream of the distillation zone 1110. A substantial amount of the water required for desalting can be obtained from a sour water stripper within the integrated process and system.
KOSEOGU teaches in para [0083] all or a portion of the wild naphtha 1152 is routed to the steam cracking zone 1220; any portion that is not passed to the steam cracking zone 1220 can be upgraded if necessary and routed to the gasoline pool.
KOSEOGU teaches in para [0011] all or a portion of the deeply hydrogenated middle distillate fraction is used as feed to the stream cracking zone, to produce light olefins, pyrolysis gasoline and pyrolysis oil.
KOSEOGU teaches in para [0079] A feed 1102 is separated into fractions in a crude complex 1105, typically including an atmospheric distillation zone (“ADU”) 1110, a saturated gas plant 1130 and a vacuum distillation zone (“VDU”) 1140. The feed 1102 can be crude oil, or in certain embodiment the feed can be crude oil that has been subjected to hydrotreating (hydrotreated crude oil), solvent deasphalting (deasphalted oil) or coking, such as delayed coking (coker liquid and gas products). The atmospheric distillation unit and vacuum distillation unit are used in well-known arrangements. The feed 1102, in certain embodiments having LPG and light naphtha removed, is separated into fractions in the atmospheric distillation zone 1110. In embodiments in which LPG and light naphtha are removed, those products can be sent to the same steam cracking complex 1215, a separate steam cracking complex, or used for other purposes. Light products, for instance, light hydrocarbons with fewer than six carbons, are passed to the steam cracking zone 1220. In particular, C2-C4 hydrocarbons 1136 including ethane, propane and butanes are separated from the light ends and LPG 1112 from the atmospheric distillation zone 1110 via the saturated gas plant 1130. Optionally, other light products are routed to the saturated gas plant 1130, shown in dashed lines as stream 1134, such as light gases from refinery units within the integrated system, and in certain embodiments light gases from outside of the battery limits. The separated C2-C4 hydrocarbons 1136 are routed to the steam cracking complex 1215. Sweet off-gases 1132 from the saturated gas plant 1130 and off-gases 1234 from the steam cracking complex 1215 (via an olefins recovery train 1230) are removed and recovered as is typically known, for instance to contribute to a fuel gas (“FG”) system, or in certain embodiments recycled to the steam cracker.
KOSEOGU teaches in the abstract -the deep hydrogenation zone operates under conditions effective to reduce aromatic content in a diesel range feedstream from a range of about 10-40 wt % or greater, to a hydrogenated distillate range intermediate product having an aromatic content of less than about 5-0.5 wt %.
KOSEOGU teaches in para [0124] Effective hydrocracking catalyst generally contain about 5-40 wt % based on the weight of the catalyst, of one or more active metal component of metals or metal compounds (oxides or sulfides) selected from the Periodic Table of the Elements IUPAC Groups 6, 7, 8, 9 and 10. In certain embodiments, the active metal component is one or more of Mo, W, Co or Ni. The active metal component is typically deposited or otherwise incorporated on a support, such as amorphous alumina, amorphous silica alumina, zeolites, or combinations thereof. In certain embodiments, alone or in combination with the above metals, Pt group metals such as Pt and/or Pd, may be present as a hydrogenation component, generally in an amount of about 0.1-2 wt % based on the weight of the catalyst.
KOSEOGU teaches in para [0111] a hydrogen partial pressure (barg) in the range of from about 30-80 (converted to 3000 kPa to 8000 kPa)
KOSEOGU teaches in para [0160] a reactor temperature (° C.) in the range of from about 300-450, 300-440, 300-420, 330-450, 330-440 or 330-420
KOSEOGU teaches in para [0113] a liquid hourly space velocity (h.sup.−1), on a fresh feed basis relative to the hydrotreating catalysts, in the range of from about 0.1-10.0, 0.1-6.0, 0.1-5.0, 0.1-4.0, 0.1-2.0, 0.5-10.0, 0.5-5.0, 0.5-2.0, 0.8-10.0, 0.8-6.0, 0.8-5.0, 0.8-4.0, 0.8-2.0, 1.0-10.0, 1.0-6.0, 1.0-5.0, 1.0-4.0 or 1.0-2.0.
KOSEOGU teaches in para [0071] In certain embodiments, a vacuum residue treatment zone and/or an atmospheric residue treatment zone can include a solvent deasphalting zone to process all or a portion of vacuum residue (straight run vacuum residue or vacuum residue that has been subjected to treatment to remove sulfur, nitrogen and/or other heteroatoms), or all or a portion of atmospheric residue (straight run atmospheric residue or atmospheric residue that has been subjected to treatment to remove sulfur, nitrogen and/or other heteroatoms). The deasphalted oil phase and the asphalt phase can be used as conventionally known. In certain embodiments of the processes herein, all or a portion of the deasphalted oil is used as a source of additional middle distillate feed for the DHG zone. For example, all or a portion of the deasphalted oil can be subjected to treatment to remove sulfur, nitrogen and/or other heteroatoms prior to deep hydrogenation; the additional treatment of deasphalted oil can comprise a dedicated treatment unit or step, or one or more of the units or steps within the integrated process and system such as a vacuum residue treatment zone (if included), the GOHP zone (if included) or the DHT zone. In embodiments in which deasphalted oil is passed to the DHT zone, severity of the conditions in those zones may be increased to accommodate the higher concentrations of sulfur, nitrogen and/or other heteroatoms.
KOSEOGU teaches in para [0276] FIG. 2A schematically depicts an embodiment of a process and system 2100 for conversion of crude oil to petrochemicals and fuel products, integrating deep hydrogenation of middle distillates to increase the steam cracking feedstock.
KOSEOGU teaches in para [0277] As described above in conjunction with the system 1100, the system 2100 generally includes a crude complex 2105, typically including an atmospheric distillation zone (“ADU”) 2110, a saturated gas plant 2130 and a vacuum distillation zone (“VDU”) 2140. The distillate products from the atmospheric distillation zone 2110 include straight run naphtha 2114, one or more middle distillate streams including light middle distillates 2116, medium range middle distillates 2122, and heavier distillates 2124. Atmospheric residue 2126 is further separated in the vacuum distillation zone 2140 to obtain vacuum gas oil 2144 and vacuum residue 2142.
KOSEOGU teaches in para [0278] A steam cracking zone 2220 is integrated and receives at least a portion of the middle distillates produced within the system that are subjected to deep hydrogenation. The steam cracking zone can include a single unit or multiple units, each processing feedstocks having different boiling point characteristics. For instance, the steam cracking zone can have one or more units operating as described herein with respect to the steam cracking zone 1220 and/or one or more units operating with respect to the gas oil steam cracking zone described herein. In certain embodiments the steam cracking zone 2220 receives plural naphtha streams including the straight run naphtha 2114 and other naphtha fractions produced within the system, shown as the combined stream 2222 in dashed lines in FIGS. 2A and 2B, and also as described herein with respect to the system 1100. In certain embodiments, one or more of the individual naphtha sources that make up the combined stream 2222 are passed to the steam cracking zone 2220, while others are diverted for other purposes such as gasoline blending components after treatment (if necessary).
KOSEOGU teaches in para [0281] The vacuum gas oil 2144, and in certain embodiments all or a portion of atmospheric gas oil 2124, is treated in a gas oil hydroprocessing zone 2160/2170 operating as a hydrocracking zone 2160 or as a hydrotreating zone 2170. In embodiments in which gas oils are hydrocracked, the hydrocracking zone 2160 produces a naphtha fraction 2162 as part of the feed to the steam cracking zone 2220, a middle distillate range fraction 2164′ which can be used as a feed for hydrogenation, and an unconverted oil fraction 2166. All or a portion of the unconverted oil 2166, for instance a diverted flow of a full range of the unconverted oil, or a light portion of the unconverted oil, can be passed to the DHG zone 2200. In embodiments in which gas oils are hydrotreated, the hydrotreating zone 2170 produces a hydrotreated naphtha fraction 2172 as part of the feed to the steam cracking zone 2220, and hydrotreated gas oil 2176. All or a portion of the hydrotreated gas oil 2176, for a diverted flow of a full range of the hydrotreated gas oil, or a light portion of the hydrotreated gas oil, can be passed to the DHG zone 2200. In certain embodiments, a middle distillate range fraction 2164′ is also recovered from the hydrotreating zone 2170 effluents. All or a portion of the middle distillate fraction 2164′ can be passed to the DHG zone 2200. In certain embodiments, an additional hydrotreating reaction zone can be included between the gas oil hydroprocessing zone 2160/2170 and the DHG zone 2200, depending on the sulfur and nitrogen content of the middle distillate fraction 2164′, and whether this stream is processed in the DHG zone 2200 alone or in combination with other middle distillate streams that have lower sulfur and nitrogen content. In these embodiments, the catalyst used and operating conditions for hydrotreating can be similar to those of the diesel hydrotreating zone 2150. In certain embodiments an in-line hydrotreater can be used after the gas oil hydroprocessing zone 2160/2170 as is known in the art, whereby the temperature and pressure variations between the gas oil hydroprocessing zone and the hydrotreater are minimized as the effluents are passed in-line to one or more hydrotreating catalyst beds. In certain embodiments all or a portion of the middle distillate fraction 2164′ can be recovered as a diesel fuel blending component that can be compliant with Euro V diesel standards as described above in conjunction with FIG. 1, and wherein one or more other sources of middle distillate feed are used for deep hydrogenation.
KOSEOGU teaches in para [0299] In the embodiment of FIG. 2B, a system similar to that of FIG. 2A is schematically depicted, further integrating a naphtha hydrogenation zone 2204 for hydrogenation of naphtha to produce a hydrogenated naphtha stream 2206 as additional stream cracker feed.
KOSEOGU teaches in para [0300] In FIG. 2B, the combined naphtha stream 2222 is processed in a naphtha hydrogenation zone 2204. In other embodiments (not shown), the wild naphtha 2152 only is processed in the naphtha hydrogenation zone 2204.
KOSEOGU teaches a system and process of deep hydrogenation of middle distillates for conversion into feedstocks suitable for steam cracking to produce light olefins, and an integrated process and system for converting crude oil to petrochemicals integrating deep hydrogenation of middle distillates; however KOSEOGU does not explicitly subterranean formation in the system, but it is within the scope of KOSEOGU as evident by AL-SHAFEI teaching that subterranean formation can be used for systems and processes for direct converting distillate fractions of crude oil to olefins – para [0072] Referring now to FIG. 3, the system 100 may further include introducing a gas condensate 31 to the steam catalytic cracking system 20 in addition to the distillate feed 110. Some refineries may have limited topping capacity for producing distillate fractions. In these refineries, gas condensates may be combined with the distillate fractions 14, 15, 16, 17, 18, to produce the distillate feed 110. The system 100 may include a gas condensate feed unit 30 that may feed the gas condensate 31 to the steam catalytic cracking system 20. The gas condensate feed unit 30 may be an intermediate storage vessel containing gas condensate 31, a gas plant operating to separate gas condensate 31 from raw natural gas produced from a subterranean formation, or other system capable of feeding a gas condensate 31 to the steam catalytic cracking system 20. The gas condensate 31 may be passed directly from the condensate feed unit 30 to the steam catalytic cracking system 20 or may be combined with the distillate feed 110 upstream of the steam catalytic cracking system 20.
Therefore, it would have been obvious to one of ordinary skill in the art at the time the invention was made to use the subterranean formation of AL-SHAFEI in the system and process of KOSEOGU since it is known in the art to the skilled oil formulator.
From the teachings of the all the references, it is apparent that one of ordinary skill in the art would have had a reasonable expectation of success in producing the claimed invention. Therefore, the invention as a whole was prima facie obvious to one of ordinary skill in the art before the effective filing date, as evidenced by the references, especially in the absence of evidence to the contrary.
Also, a claim containing a “recitation with respect to the manner in which a claimed apparatus is intended to be employed does not differentiate the claimed apparatus from a prior art apparatus” if the prior art apparatus teaches all the structural limitations of the claim. Ex parte Masham, 2 USPQ2d 1647 (Bd. Pat. App. & Inter. 1987)
In addition, “Expressions relating the apparatus to contents thereof during an intended operation are of no significance in determining patentability of the apparatus claim.” Ex parte Thibault, 164 USPQ 666, 667 (Bd. App. 1969). Furthermore, “[i]nclusion of material or article worked upon by a structure being claimed does not impart patentability to the claims.” In re Young, 75 F.2d 996, 25 USPQ 69 (CCPA 1935) (as restated in In re Otto, 312 F.2d 937, 136 USPQ 458, 459 (CCPA 1963)). In In re Young, a claim to a machine for making concrete beams included a limitation to the concrete reinforced members made by the machine as well as the structural elements of the machine itself. The court held that the inclusion of the article formed within the body of the claim did not, without more, make the claim patentable
Additionally, the claimed changes in the sequence of performing steps is considered to be prima facie obvious because the time at which a particular step is performed is simply a matter of operator preference, especially since the same result is obtained regardless of when the step occurs. See Ex parte RUBIN, 128 USPQ 440 (Bd. App. 1959). See also In re Burhans, 154 F.2d 690, 69 USPQ 330 (CCPA 1946) (selection of any order of performing process steps is prima facie obvious in the absence of new or unexpected results).
Nevertheless, an intended result of a process being claimed does not impart patentability to the claims when the general conditions of a claim are disclosed in the prior art. Furthermore, it has been held that obviousness is not rebutted by merely recognizing additional advantages or latent properties present in the prior art process and composition. Further, the fact that applicant has recognized another advantage which would flow naturally from following the suggestion of the prior art cannot be the basis for patentability when the differences would otherwise be obvious. Ex parte Obiaya, 227 USPQ 58, 60 (Bd.Pat. App. & Inter. 1985).
Therefore, it would have been obvious to the person having ordinary skill in the art to have selected appropriate conditions, as guided by the prior art, in order to obtain the desired products. It is not seen where such selections would result in any new or unexpected results. Please see MPEP 2144.05, II: noting obviousness within prior art conditions or through routine experimentation.
If it is the applicant's position that this would not be the case, evidence would need to be provided to support the applicant's position.
Again, AL-SHAFEI is considered a teaching reference, not a modifying reference. See MPEP 2112.
Conclusion
Any inquiry concerning this communication or earlier communications from the examiner should be directed to CHANTEL GRAHAM whose telephone number is (571)270-5563. The examiner can normally be reached on M-TH 9:00 am - 7:00 pm.
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/CHANTEL L GRAHAM/
Examiner, Art Unit 1771
/ELLEN M MCAVOY/Primary Examiner, Art Unit 1771