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
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) 1 ,6-8,11,15-17,19,20 is/are rejected under 35 U.S.C. 103 as being unpatentable over Ogundare et al. 20250129679 in view of Newton 20230037547 and Pringle et al. 5207272 ,Creighton 20180209235 and Neuroth et al. 6192983.
Referring to claim 1, Ogundare discloses (see fig. 6) a gas-lift system for a well having production tubing configured to convey production fluids to a surface location, the gas-lift system comprising: a surface pressure barrier system comprising: a gas pump (650) configured to pump a gas into an annulus of the well, and a surface actuation system (see control lines going to pump) coupled to and configured to actuate the gas pump; a sub-surface pressure barrier system comprising: a downhole gas injection valve (see paragraph 0091, 644) configured to actuate to allow or prevent the gas from entering the production tubing to mix with the production fluids to lower a density of the production fluids, and a sub-surface actuation system ( see paragraph 0092, telemetry system that send signals to valve 644) coupled to and configured to actuate the downhole gas injection valve; a plurality of surface sensors comprising a pressure sensor, gas inlet flowmeter (see paragraph 0093) , production fluid outlet flowmeter (measures volume of fluid comping out of the production tubing per unit time) coupled to the surface pressure barrier system; a plurality of sub-surface sensors coupled to the sub-surface pressure barrier system including a pressure sensor uphole from a production packer in the annulus ( see paragraph 0093, sensor to measure pressure in the annulus 642 which is uphole from packer ); and an automated gas-lift manager coupled to the surface pressure barrier system, the sub-surface pressure barrier system, the plurality of surface sensors, and the plurality of sub-surface sensors, wherein the automated gas-lift manager ( 670) is configured to monitor and control the surface pressure barrier system and the sub-surface pressure barrier system based on data received from the plurality of surface sensors and the plurality of sub-surface sensors. Ogundare discloses a surface gas injection valve (664), manual gate valve (623) Ogundare does disclose that other sensors can be included to measure any other suitable operational parameters or well conditions and can be included at any appropriate location (see paragraph 0093 and 0096). Ogundare does not disclose a surface annular safety valve located within a wellhead of the well and configured to close to prevent the production fluids from migrating through an annulus of the wellhead and a sub-surface safety valve configured to close the production tubing to prevent the production fluids from flowing to the wellhead, valve position sensors, surface temperature sensor, atmospheric gas concentration sensor at the surface location, a temperature sensor uphole from the production packer, a pressure sensor downhole for the production packer, a temperature sensor downhole from the production packer, a downhole production tubing flowmeter, or the monitoring comprising detecting an incident, that in absence of preventive action would result in environmental or safety issues, based on data received from at least one sensor of the plurality of surface sensors and the plurality of sub-surface sensors. Newton teaches an electric surface annular safety valve (116) located within a wellhead of the well and configured to close to prevent the production fluids from migrating through an annulus of the wellhead and surface sensors that measure temperature (see paragraph 0045). Pringle teaches an electrically actuated sub-surface safety valve (34) configured to close the production tubing to prevent the production fluids from flowing to the wellhead and using position sensors to measure valve positions ( see col. 2, lines 8-11, transducer ). Neuroth teaches a well system with sensors (150a-150n and 152a-152n) including a production flow meter and pressure sensor above a packer and temperature and pressure sensors below a packer (col. 5, lines 43-68 and see fig. 1, some sensors 152n are above and below packer 126). Creighton teaches an atmospheric gas concentration sensor located at a surface location and using sensors to monitor for gas leaks to ensure gas levels are at a predetermined safe limit (see paragraph 0175) and detecting a safety condition based on data received from a sensor (see Abstract). Therefore, it would be obvious to one of ordinary skill in the art before the effective filing date to modify the system disclosed by Ogundare to have surface annular safety valve located within a wellhead of the well to control annulus contents during shutdown conditions, a sub-surface safety valve configured to close the production tubing to prevent the production fluids from flowing to the wellhead, valve position sensors for the surface annular safety valve, a surface gas injection valve, proximate manual gate valve and downhole gas injection valve and subsurface safety valve in order to know whether the valves are open or closed, surface temperature sensor, atmospheric gas concentration sensor at the surface location, a temperature sensor uphole from the production packer, a pressure sensor downhole for the production packer, a temperature sensor downhole from the production packer, a downhole production tubing flowmeter, or the monitoring comprising detecting an incident, that in absence of preventive action would result in environmental or safety issues, based on data received from at least one sensor of the plurality of surface sensors and the plurality of sub-surface sensors in view of the teachings of Newton ,Pringle, Creighton and Neuroth with a reasonable expectation of success by using valve position sensors in order to know whether valves are open or closed, having the sensors to properly operate the wells efficiently and to monitor the well to prevent well fluids from entering the gas line and to prevent fluid from coming out the production line during an incident and to ensure gas levels are at predetermined safe limits.
Referring to claim 6-7, Ogundare does not specifically disclose the automated gas-lift manager is configured to send a command to the gas-lift system to shut down operations based on detection of the incident. Creighton teaches sensing a condition at adjacent or within a well and performing a safety procedure in response to the sensed condition to improve the safety of the well (see Abstract) which can for example help to prevent a leakage of a fluid (see paragraph 0008). Pringle teaches shutting a safety valve to prevent unwanted fluid flow in the event of a disaster or problem (see col. 5, lines 43-46). Newton teaches closes an annular safety valve in to prevent leakage in the event of a problem (see paragraph 0020). Therefore, it would be obvious to one of ordinary skill in the art to further modify the system disclosed by Ogundare to send a command to the gas-lift system to shut down operations based on detection of the incident such as shutting a sub-surface safety valve or annular safety valve in view of the teachings of Creighton, Pringle and Newton with a reasonable expectation of success in order to prevent fluid from coming out the production line during an incident.
Referring to claim 8, Creighton teaches a controller is configured to detect leakage based on data received from the atmospheric gas concentration sensor (see paragraph 0175).
Referring to claim 11, Ogundare discloses a method for a gas-lift system for a well having production tubing configured to convey production fluids to a surface location, the method comprising: pumping a gas from the surface location into an annulus of the well using a gas pump (650); opening a downhole gas injection valve (644) to allow the gas to enter the production tubing from the annulus of the well; mixing the gas with the production fluids to lower a density of the production fluids and allow the production fluids to flow to the surface location using the production tubing ( paragraph 0091); monitoring the gas-lift system using a plurality of surface sensors coupled to a surface pressure barrier system and a plurality of sub-surface sensors coupled to the sub-surface pressure barrier system the plurality of surface sensors comprising a pressure sensor, gas inlet flowmeter (see paragraph 0093) , production fluid outlet flowmeter (measures volume of fluid comping out of the production tubing per unit time) and the plurality of sub-surface sensors coupled to the sub-surface pressure barrier system including a pressure sensor uphole from a production packer in the annulus ( see paragraph 0093, sensor to measure pressure in the annulus 642 which is uphole from packer ), wherein data is sent from the plurality of surface sensors and the plurality of sub-surface sensors to an automated gas-lift manager ( see paragraph 0093-0094). Ogundare discloses a surface gas injection valve (664), manual gate valve (623) Ogundare does disclose that other sensors can be included to measure any other suitable operational parameters or well conditions and can be included at any appropriate location (see paragraph 0093 and 0096). Ogundare does not disclose a surface annular safety valve located within a wellhead of the well and configured to close to prevent the production fluids from migrating through an annulus of the wellhead and a sub-surface safety valve configured to close the production tubing to prevent the production fluids from flowing to the wellhead, valve position sensors, surface temperature sensor, atmospheric gas concentration sensor at the surface location, a temperature sensor uphole from the production packer, a pressure sensor downhole for the production packer, a temperature sensor downhole from the production packer, a downhole production tubing flowmeter, or detecting, using the automated gas-lift manager, an incident that in absence of preventive action would result in environmental or safety issues in the gas-lift system using the data from the plurality of surface sensors and the plurality of sub-surface sensors ; and sending a command signal from the automated gas-lift manager to a surface actuation system in the surface pressure barrier system or to a sub-surface actuation system in the sub-surface pressure barrier system to perform one or more functionalities based on the detection of the incident, the functionalities comprising: turning off the gas pump, using the surface actuation system, to prevent the gas from being pumped into the well. Newton teaches an electric surface annular safety valve (116) located within a wellhead of the well and configured to close to prevent the production fluids from migrating through an annulus of the wellhead and surface sensors that measure temperature (see paragraph 0045). Pringle teaches an electrically actuated sub-surface safety valve (34) configured to close the production tubing to prevent the production fluids from flowing to the wellhead and using position sensors to measure valve positions ( see col. 2, lines 8-11, transducer ). Neuroth teaches a well system with sensors (150a-150n and 152a-152n) including a production flow meter and pressure sensor above a packer and temperature and pressure sensors below a packer (col. 5, lines 43-68 and see fig. 1, some sensors 152n are above and below packer 126). Creighton teaches an atmospheric gas concentration sensor located at a surface location using sensors to monitor for gas leaks to ensure gas levels are at a predetermined safe limit (see paragraph 0175) and shutting out flow from well ( see paragraph 0178). Therefore, it would be obvious to one of ordinary skill in the art before the effective filing date to modify the method disclosed by Ogundare to have surface annular safety valve located within a wellhead of the well to control annulus contents during shutdown conditions, a sub-surface safety valve configured to close the production tubing to prevent the production fluids from flowing to the wellhead, valve position sensors for the surface annular safety valve, a surface gas injection valve, proximate manual gate valve and downhole gas injection valve and subsurface safety valve in order to know whether the valves are open or closed, surface temperature sensor, atmospheric gas concentration sensor at the surface location, a temperature sensor uphole from the production packer, a pressure sensor downhole for the production packer, a temperature sensor downhole from the production packer, a downhole production tubing flowmeter and to detect the gas leak and to prevent flow from flowing from well if concentration of gas is too high by closing subsurface valve Newton ,Pringle, Creighton and Neuroth with a reasonable expectation of success by using valve position sensors in order to know whether valves are open or closed, having the sensors to properly operate the wells efficiently to detect the gas leak and to prevent flow from flowing from well if concentration of gas is too high by closing subsurface valve in order to prevent a safety issue.
Referring to claims 15-17, Ogundare does not disclose a detecting a spike in temperature or pressure using data from sensors. Creighton teaches detecting an incident by detecting a spike in pressure a pressure o\ sensor (see paragraph 0194) at the wellhead and controlling the pressure at the wellhead based on the sensed condition ( see paragraph 0079). Newton teaches closing an annular safety valve to contain pressure at a wellhead (see paragraph 0020). Therefore, it would be obvious to one of ordinary skill int eh art before the effective filing date to modify the method disclosed by Ogundare to detect a spike in pressure using a sensor, diagnose incident location and determine with functionality to perform based on the diagnosis of the incident in view of the teachings of Creighton and Newton with a reasonable expectation of success in order to prevent fluid from escaping the annulus.
Referring to claim 19, Creighton teaches detected leakage based increase of gas detected the atmospheric gas concentration sensor (see paragraph 0175) and shutting out flow from well ( see paragraph 0178).
Referring to claim 20, Ogundare does not specifically disclose the automated gas-lift manager is configured to send a command to the gas-lift system to shut down operations based on detection of the incident. Creighton teaches uses sensors to monitor for gas leaks to ensure gas levels are at a predetermined safe limit (see paragraph 0175) and shutting out flow from well ( see paragraph 0178). Therefore, it would be obvious to one of ordinary skill in the art to modify the system disclosed by Ogundare to detect the gas leak and to prevent flow from flowing from well if concentration of gas is too high by closing subsurface valve in view of the teachings of Creighton with a reasonable expectation of success in order to prevent a safety issue.
Allowable Subject Matter
Claims 3 and 13 are objected to as being dependent upon a rejected base claim, but would be allowable if rewritten in independent form including all of the limitations of the base claim and any intervening claims.
The following is a statement of reasons for the indication of allowable subject matter: The closest prior art to Ogundare does not teach or suggest the automated gas-lift manager is configured to monitor and control the gas-lift system by detecting a position of the surface annular safety valve using data from the valve position sensor coupled to the surface annular safety valve, a position of the downhole gas injection valve using data from the downhole gas injection valve position sensor, and a position of the sub-surface safety valve using data from the subsurface safety valve position sensor in combination with the other limitations of the claim nor would it be obvious to modify Ogundare to include this limitation without hindsight.
Response to Arguments
Applicant’s arguments, claim(s) 1,6-8,11,15-17,19-20 under Ogundare et al. 20250129679 in view of Newton 20230037547, Pringle et al. 5207272 , and Al Daif et al. 20230063604 and under Ogundare et al. 20250129679 in view of Newton 20230037547 ,Pringle et al. 5207272 , and Creighton 20180209235 have been fully considered and are persuasive. Therefore, the rejection has been withdrawn. However, upon further consideration, a new ground(s) of rejection is made in view of Ogundare et al. 20250129679 in view of Newton 20230037547 and Pringle et al. 5207272 ,Creighton 20180209235 and Neuroth et al. 6192983.
Conclusion
Applicant's amendment necessitated the new ground(s) of rejection presented in this Office action. Accordingly, THIS ACTION IS MADE FINAL. See MPEP § 706.07(a). Applicant is reminded of the extension of time policy as set forth in 37 CFR 1.136(a).
A shortened statutory period for reply to this final action is set to expire THREE MONTHS from the mailing date of this action. In the event a first reply is filed within TWO MONTHS of the mailing date of this final action and the advisory action is not mailed until after the end of the THREE-MONTH shortened statutory period, then the shortened statutory period will expire on the date the advisory action is mailed, and any nonprovisional extension fee (37 CFR 1.17(a)) pursuant to 37 CFR 1.136(a) will be calculated from the mailing date of the advisory action. In no event, however, will the statutory period for reply expire later than SIX MONTHS from the mailing date of this final action.
Any inquiry concerning this communication or earlier communications from the examiner should be directed to GIOVANNA WRIGHT whose telephone number is (571)272-7027. The examiner can normally be reached M-F 8 am- 5 pm.
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/Giovanna Wright/ Primary Examiner, Art Unit 3672
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