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 § 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 and 11 are rejected under 35 U.S.C. 102(a)(1) as being anticipated by Mohsen et al (US PGPub 20030217956, cited in the IDS).
Regarding Claim 1, Mohsen et al teaches an apparatus (illustrated in Figure 1) comprising:
a wellhead assembly (10) mounted on a well at a wellsite (see [0030] and [0066]-[0068]); a production line (148) to receive and transport a gas-containing well effluent (see [0068] and Figure 4); and a zero-flaring well testing assembly (referred to as multiphase measuring system 160) coupled to receive the gas-containing well effluent from the wellhead assembly (see [0007], [0034] and [0068]), wherein the zero-flaring well testing assembly includes a multiphase pump (146) (see [0066]-[0068]), and the zero-flaring well testing assembly is coupled to the production line so as to provide at least a gas-containing portion of the gas-containing well effluent received from the wellhead assembly by the zero-flaring well testing assembly to the production line (see claims 1, 3 and 5 and [0066]-[0068]).
Regarding Claim 11, Mohsen et al teaches that the apparatus does not include a gas flaring device at the wellsite to flare gas from the gas-containing well effluent (see [0007] and [0066]).
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.
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.
Claim(s) 2-8 and 12-14 and 18-21 are rejected under 35 U.S.C. 103 as being unpatentable over Mohsen et al as applied to claim 1 above, and further in view of Slater et al (US PGPub 2018/0202432, as cited in the IDS).
Regarding Claims 2-3, Mohsen et al a well testing assembly (multiphase measuring system 160) disposed upstream of the multiphase phase, and further discloses separating water from hydrocarbon phases and discharging the water phase (see [0005], [0030], [0068] and Figure 4).
However, Mohsen does not disclose using the zero-flaring well testing assembly to add liquid (specifically, water) to the gas-containing well effluent received from the wellhead.
However, in the analogous art of subsea/downhole pumps pumping multiphase fluid, Slater et al teaches adding liquid (such as water) via an inlet/connection line 7 to a fluid conditioning unit 3 upstream of the pump intake (see [0058]). Furthermore, Slater et al teaches that output flow 8 from the pump 5 is fed through check-valve 9 to prevent a backflow and into LCU 10, and that the outlet from LCU 10 is arranged so that all the gas goes to the outlet stream together with some of the liquid. Therefore, liquid is retained and recycled in order to achieve a GVF of less than 60% for the pump in order to avoid excessive heating and wear, when the pump is an ESP. Such liquid is mixed with the incoming gas-liquid flow and will reduce the gas-to-liquid fraction going to the pump (see [0058]-[0060]). It would have been obvious to one of ordinary skill in the art to have the zero-flaring well testing assembly add liquid (water) to the gas-containing well effluent (in the wellhead) for the benefit of reducing the gas-to-liquid fraction going to the pump and achieve a GVF of less than 60% to avoid excessive heating and wear.
Regarding Claim 4, the combination of Mohsen et al and Slater et al teaches that the zero-flaring well testing assembly includes a separator (i.e. 20 in Figure 1 and 120 in Figure 4) (see [0030] and [0068] of Mohsen et al).
Regarding 5, Mohsen et al teaches a well testing assembly (multiphase measuring system 160) disposed upstream of the multiphase phase, and further discloses separating water from hydrocarbon phases and discharging the water phase (see [0005], [0030], [0068] and Figure 4). Furthermore, Mohsen et al teaches a separator (20 or 120) disposed downstream of the multiphase pump (46 or 146) (see Figures 1 and 4).
However, Mohsen et al does not explicitly disclose that liquid is added at a location upstream of the multiphase pump includes water separated from the gas-containing well effluent via the separator at a location downstream of the multiphase pump.
However, in the analogous art of subsea/downhole pumps pumping multiphase fluid, Slater et al teaches adding liquid (such as water) via an inlet/connection line 7 to a fluid conditioning unit 3 upstream of the pump intake (see [0058]). Furthermore, Slater et al teaches that output flow 8 from the pump 5 is fed through check-valve 9 to prevent a backflow and into LCU 10, and that the outlet from LCU 10 is arranged so that all the gas goes to the outlet stream together with some of the liquid. Therefore, liquid is retained and recycled in order to achieve a GVF of less than 60% for the pump in order to avoid excessive heating and wear, when the pump is an ESP. Such liquid is mixed with the incoming gas-liquid flow and will reduce the gas-to-liquid fraction going to the pump (see [0058]-[0060]). Furthermore, Slater et al teaches additional measures that can be used in order to alter the gas fraction going to the pump 5 includes using the additional line (26, FIG. 2) going from the FCU 3 to the topside separator 25. If the gas fraction in the FCU 3 is too high, line 26 can be used to drain gas into the topsides separator 25. Line 26 can alternatively be used to inject liquid from topsides to the FCU 3 and thereby reduce the gas fraction being fed to the pump 5 (see [0062]).
It would have been obvious to one of ordinary skill in the art to have the zero-flaring well testing assembly add liquid (water) to the gas-containing well effluent (in the wellhead) via the separator for the benefit of reducing the gas-to-liquid fraction going to the pump and achieve a GVF of less than 60% to avoid excessive heating and wear.
Regarding Claim 6, Mohsen et al does not disclose that the zero-flow well testing assembly further includes a multiphase flowmeter.
However, in the analogous art of subsea/downhole pumps pumping multiphase fluid, Slater et al teaches subsea multiphase flow meters and level sensors in pipes and equipment upstream to the pump are typical examples of instrumentation needed to control a subsea pump (see [0007]). It would have been obvious to one of ordinary skill in the art to incorporate a multiphase flowmeter in the well testing assembly (as taught by Slater et al) for the benefit of effectively controlling varying gas volume fraction (“GVF”) of a multiphase flow to be pumped.
Regarding Claims 7-8, Mohsen et al does not disclose a controller configured to control flow of the liquid added, at the location upstream of the multiphase pump, to the gas- containing well effluent received from the wellhead assembly based on a characteristic of the gas-containing well effluent measured by the multiphase flowmeter, and wherein the controller is configured to, in response to detection via the multiphase flowmeter that a gas volume fraction of the gas-containing well effluent is above a threshold level, cause flow of the liquid added, at the location upstream of the multiphase pump, to the gas-containing well effluent to lower the gas volume fraction of the gas-containing well effluent to no more than the threshold level.
However, in the analogous art of subsea/downhole pumps pumping multiphase fluid, Slater et al teaches a controller configured to reduce a speed of the subsea or downhole pump when a measured pump current decreases, and increases the speed of the subsea or downhole pump when the measured pump current increases (see abstract and [0054]). Furthermore, Slater et al teaches that “a controller acting to reduce the pump speed when the measured pump current decreases and to increase the pump speed when the measured pump current increases” means that the pump speed change is sufficient to reverse an increasing GVF in the inlet flow and reverse a decreasing GVF in the inlet flow, achieving a regulation at or around a favorable GVF of the inlet flow (see [0045]). In addition, Slater et al teaches that the controller can thereby alter the gas-to-liquid ratio going to the pump in a favorable way to increase pump efficiency. If arranged differently or as an alternative, a topside located valve and pump can be activated by the same controller to feed additional liquid to the conditioning unit to obtain better operational pumping conditions (see [0038]). It would have been obvious to one of ordinary skill in the art to modify the apparatus of Mohsen et al by incorporating a controller (as taught by Slater et al) for the benefit of enabling the controller to act to reduce the pump speed when the measured pump current decreases and to increase the pump speed when the measured pump current increases, which means that the pump speed change is sufficient to reverse an increasing GVF in the inlet flow and reverse a decreasing GVF in the inlet flow, achieving a regulation at or around a favorable GVF of the inlet flow (see [0045]).
Regarding Claim 12, Mohsen et al teaches an apparatus
comprising a multiphase measuring system (160) configured to receive a multiphase fluid from a well head (10) and measure multiphase flow rates, a multiphase pump (146), and a separator (120) separating water, oil and gas from the multiphase fluid and providing the oil and gas to a production flow line (148), thereby avoiding flaring of the gas phase (see [0003], [0007], [0030], [0066]-[0068], claims 1, 3, 5, and figures 1, 4).
However, Mohsen et al does not teach that the zero-flaring well testing assembly is configured to lower a gas volume fraction of the gas-containing well effluent upstream of the multiphase pump by adding the separated water to the gas-containing well effluent at a location of the zero-flaring well testing assembly upstream of the multiphase pump
However, in the analogous art of subsea/downhole pumps pumping multiphase fluid, Slater et al teaches adding liquid (such as water) via an inlet/connection line 7 to a fluid conditioning unit 3 upstream of the pump intake (see [0058]). Furthermore, Slater et al teaches that output flow 8 from the pump 5 is fed through check-valve 9 to prevent a backflow and into LCU 10, and that the outlet from LCU 10 is arranged so that all the gas goes to the outlet stream together with some of the liquid. Therefore, liquid is retained and recycled in order to achieve a GVF of less than 60% for the pump in order to avoid excessive heating and wear, when the pump is an ESP. Such liquid is mixed with the incoming gas-liquid flow and will reduce the gas-to-liquid fraction going to the pump (see [0058]-[0060]). Furthermore, Slater et al teaches additional measures that can be used in order to alter the gas fraction going to the pump 5 includes using the additional line (26, FIG. 2) going from the FCU 3 to the topside separator 25. If the gas fraction in the FCU 3 is too high, line 26 can be used to drain gas into the topsides separator 25. Line 26 can alternatively be used to inject liquid from topsides to the FCU 3 and thereby reduce the gas fraction being fed to the pump 5 (see [0062]). Furthermore, Slater et al teaches a controller configured to reduce a speed of the subsea or downhole pump when a measured pump current decreases, and increases the speed of the subsea or downhole pump when the measured pump current increases (see abstract and [0054]). It would have been obvious to one of ordinary skill in the art to have the zero-flaring well testing assembly add liquid (water) to the gas-containing well effluent (in the wellhead) via the separator for the benefit of reducing the gas-to-liquid fraction going to the pump and achieve a GVF of less than 60% to avoid excessive heating and wear.
Regarding Claim 13, the combination of Mohsen et al and Slater et al teaches that the flowmeter is a multiphase flowmeter upstream of the multiphase pump (see [0007] and [0009] of Slater et al).
Regarding Claim 14, the combination of Mohsen et al and Slater et al teaches that the characteristic of the gas- containing well effluent to be measured is the gas volume fraction of the gas-containing well effluent received in the zero-flaring well testing assembly (see [0007], [0020] and [0044] of Slater et al).
Regarding Claim 18, Mohsen et al teaches a method
comprising: coupling an apparatus in fluid communication between a well head (10) and a production flow line (148), the apparatus comprising a multiphase measuring system (160), a multiphase pump (146), and a separator (120); receiving a multiphase fluid from the well head (10); measuring multiphase flow rates via the multiphase
measuring system (160) (i.e. the zero-flaring well test assembly); and separating oil and gas from the multiphase fluid and providing the oil and gas to a production flow line (148), thereby avoiding flaring of the gas phase (see [0003], [0007], [0030], [0066]-[0068], claims 1, 3, 5, and figures 1, 4).
However, Mohsen et al does not teach adding liquid to the gas-containing well effluent at a location upstream of the multiphase pump to lower a gas volume fraction of the gas-containing well effluent upstream of the multiphase pump.
However, in the analogous art of subsea/downhole pumps pumping multiphase fluid, Slater et al teaches adding liquid (such as water) via an inlet/connection line 7 to a fluid conditioning unit 3 upstream of the pump intake (see [0058]). Furthermore, Slater et al teaches that output flow 8 from the pump 5 is fed through check-valve 9 to prevent a backflow and into LCU 10, and that the outlet from LCU 10 is arranged so that all the gas goes to the outlet stream together with some of the liquid. Therefore, liquid is retained and recycled in order to achieve a GVF of less than 60% for the pump in order to avoid excessive heating and wear, when the pump is an ESP. Such liquid is mixed with the incoming gas-liquid flow and will reduce the gas-to-liquid fraction going to the pump (see [0058]-[0060]). Furthermore, Slater et al teaches additional measures that can be used in order to alter the gas fraction going to the pump 5 includes using the additional line (26, FIG. 2) going from the FCU 3 to the topside separator 25. If the gas fraction in the FCU 3 is too high, line 26 can be used to drain gas into the topsides separator 25. Line 26 can alternatively be used to inject liquid from topsides to the FCU 3 and thereby reduce the gas fraction being fed to the pump 5 (see [0062]). Furthermore, Slater et al teaches a controller configured to reduce a speed of the subsea or downhole pump when a measured pump current decreases, and increases the speed of the subsea or downhole pump when the measured pump current increases (see abstract and [0054]). It would have been obvious to one of ordinary skill in the art to have the zero-flaring well testing assembly add liquid (water) to the gas-containing well effluent (in the wellhead) via the separator for the benefit of reducing the gas-to-liquid fraction going to the pump and achieve a GVF of less than 60% to avoid excessive heating and wear.
Regarding Claim 19, the combination of Mohsen et al and Slater et al teaches adding the liquid to the gas-containing well effluent at the location upstream of the multiphase pump includes separating the liquid from the gas-containing well effluent with the separator at a location downstream of the multiphase pump and routing the separated liquid to the gas-containing well effluent at the location upstream of the multiphase pump (see [0058]- [0062], claims 15, 18, and figure 2 of Slater et al).
Regarding Claim 20 , the combination of Mohsen et al and Slater et al teaches routing the gas-containing portion of the gas-containing well effluent to a production facility via the output line (see [0029] and [0068] of Mohsen et al).
Regarding Claim 21, the combination of Mohsen et al and Slater et al teaches injecting the gas-containing portion of the gas-containing well effluent into a well via the output line (see [0009], [0030] and [0066] of Mohsen et al).
Claim(s) 9-10 are rejected under 35 U.S.C. 103 as being unpatentable over Mohsen et al as applied to claim 1 above, and further in view of Hopper et al (US PGPub 2005/0145388).
Regarding Claims 9-10, Mohsen et al does not teach that the zero-flaring well testing assembly includes an additional multiphase pump, and wherein the multiphase pump and the additional multiphase pump are connected in series.
However, in the analogous art of subsea process aseemblies, Hopper et al teaches a process module which has the capability to re-pressurise each phase separately to suit the delivery point. Pump modules for a phase can be assembled in series to achieve high pressures, or in parallel if there are two different delivery points for an individual phase. This allows the gas and/or water to be re-injected into local injection wells at their optimum injection pressure instead of into a higher pressure common field injection line. Furthermore, the ability to individually select the pressure also allows the use of either pressurized gas to gas lift the producing well or to use pressure oil or water as the drive liquid to operate the turbine of a hydraulic submersible pump in the producing well (see [0058]). It would have been obvious to one of ordinary skill in the art to modify the apparatus of Mohsen et al by incorporating additional multiphase pumps connected in series (as taught by Hopper et al) for the benefit of achieving high pressures and enabling one to individually select the pressure.
Claim 15 is rejected under 35 U.S.C. 103 as being unpatentable over Mohsen et al and Slater et al as applied to claim 12 above, and further in view of Zaragoza Labes et al (US PGPub 2018/0274351).
Regarding Claim 15, the combination of Mohsen et al and Slater et al does not disclose that the flowmeter, the multiphase pump, and the separator are mounted together on a shared platform.
However, in the analogous art of subsea separation and pumping systems, Zaragoza Labes et al teaches integrated compact station of subsea separation and pumping systems of fluids, which is suitable for use in any subsea system, that is for the separation of fluids and/or solids. The compact integrated station includes a first separation module and a second pumping module of reinjection water, and a harp as a gas-liquid gravitational separator. Additionally, the compact integrated station includes a robotic arm installed on a cover involving said first separation module and a liquid-liquid gravitational tubular separator module. The integrated compact station may be applied to any subsea system of separation of fluids connected to the well of oil and gas production, or alternatively, installed directly connected to the production manifold (see abstract). Furthermore, Zaragoza Labes et al teaches that the integrated compact station of subsea separation and pumping systems of fluids of the present invention has concept of modular arrangement for located intervention in equipment and integration of components for compacting and reducing sizing and weight of the modules, thus composing an improved subsea system of three-phase separation of fluids and pumping (see [0024]). It would have been obvious to one of ordinary skill in the art to position the flowmeter, the multiphase pump, and the separator are mounted together on a shared (integrated) platform (as taught by Zaragoza Labes et al) for the benefit of providing a more compact apparatus, thus providing an improved subsea system of three-phase separation of fluids and pumping.
Claim(s) 16-17 are rejected under 35 U.S.C. 103 as being unpatentable over Mohsen et al and Slater et al as applied to claim 12 above, and further in view of Moneyhun et al (US PGPub 2021/0002989).
Regarding Claim 16, the combination of Mohsen et al and Slater et al does not disclose that the zero-flaring well testing assembly is a mobile well testing assembly installed on a trailer.
However, in the analogous art of gas conditioning systems, Moneyhun et al teaches a conditioning system 10, which can comprise a mobile skid 14 that can be transportable, and thus delivered to, and retrieved from, a wellsite. The skid 14 can be received on a truck or trailer for transportation, or can have wheels itself for being towed. The mobility of the skid can facilitate placement at the wellsite with respect to existing production and well equipment. In another aspect, the skid 14 can be enclosed to protect contents from weather and well site elements (see [0027]). It would have been obvious to one of ordinary skill in the art to modify the previous combination by having the zero-flaring well testing assembly be mobile and installed on a trailer (as taught by Moneyhun et al) for the benefit of facilitating placement at the wellsite with respect to existing production and well equipment since the assembly is easily transportable.
Regarding Claim 17, the combination of Mohsen et al and Slater et al does not disclose that the zero-flaring well testing assembly includes a slug catcher.
However, in the analogous art of gas conditioning systems, Moneyhun et al a conditioning system 10 and skid 14, which may have an inlet 18 and wherein a slug catcher or condensate collection trap can be positioned before the compressor 22. In one aspect, the slug catcher or condensate collection trap can be carried by the skid 14 (see [0028]). It would have been obvious to one of ordinary skill in the art to incorporate a slug catcher into the well testing assembly (as taught by Moneyhun et al) for the benefit of providing condensate collection.
While, claim 21 is rejected by the combination of Mohsen et al and Slater et al above in the alternative…
Claim 21 is rejected under 35 U.S.C. 103 as being unpatentable over Mohsen et al and Slater et al as applied to claim 18 above, and further in view of Johnsen et al (US PGPub 2021/0079777).
Regarding Claim 21 , Mohsen et al and Slater et al does not explicitly disclose injecting the gas-containing portion of the gas-containing well effluent into a well via the output line.
However, in the analogous art of systems and methods for hydrocarbon processing, Johnsen et al teaches that gas separated from the hydrocarbon-containing fluid is conditioned at the UPP™ 9 so that it may be used for gas injection back into the subsea oil reservoir. After conditioning, the gas passes through a conduit in riser 8, via riser base 7 and flow lines 5 to injectors 3, where it is re-injected into the reservoir. The re-injection of gas is a known process that supports the pressure of the well as fluid is produced and can also cause the pressure to rise in the well, causing more gas molecules to dissolve in the oil, thereby lowering its viscosity and increasing the well's output (see [0056]). In addition, Johnsen et al teaches a first stage suction scrubber 37 has a single outlet conduit 46 leading to first stage gas injection compressor 38. The outlet conduit 47 from this leads via a second interstage gas cooler 39 to a second stage suction scrubber 40 and a second stage gas injection compressor 41 which feeds gas inlet riser conduit 20, which leads to the gas injectors 3 at the sea bed (see [0068]). It would have been obvious to one of ordinary skill in the art to reinject the gas-containing portion into the well via an output line (as taught by Johnsen et al) for the benefit of effectively supporting pressure within the well as fluid is produced, thus viscosity is lowered and the well’s output is increased.
Conclusion
The prior art made of record and not relied upon is considered pertinent to applicant's disclosure: Gordon et al (US PGPub 2015/0184511) discloses a well testing device for conducting well test operations on an oil, gas, or water well including a production flowline. A conduit guides fluids from the production flowline to the well test device and then back to the flowline. The well test device may include, in various combinations, one or more of a flow measurement device, a sampling device, a sampling chamber to collect sampled fluids from the production flowline, a particle separator, a particle detector, a pressure sensor, a temperature sensor, a controller or data storage module, a choke, and other components (see abstract).
Any inquiry concerning this communication or earlier communications from the examiner should be directed to JENNIFER WECKER whose telephone number is (571)270-1109. The examiner can normally be reached 9:30AM - 6 PM EST M-F.
Examiner interviews are available via telephone, in-person, and video conferencing using a USPTO supplied web-based collaboration tool. To schedule an interview, applicant is encouraged to use the USPTO Automated Interview Request (AIR) at http://www.uspto.gov/interviewpractice.
If attempts to reach the examiner by telephone are unsuccessful, the examiner’s supervisor, Lyle Alexander can be reached at 571-272-1254. The fax phone number for the organization where this application or proceeding is assigned is 571-273-8300.
Information regarding the status of published or unpublished applications may be obtained from Patent Center. Unpublished application information in Patent Center is available to registered users. To file and manage patent submissions in Patent Center, visit: https://patentcenter.uspto.gov. Visit https://www.uspto.gov/patents/apply/patent-center for more information about Patent Center and https://www.uspto.gov/patents/docx for information about filing in DOCX format. For additional questions, contact the Electronic Business Center (EBC) at 866-217-9197 (toll-free). If you would like assistance from a USPTO Customer Service Representative, call 800-786-9199 (IN USA OR CANADA) or 571-272-1000.
/JENNIFER WECKER/ Primary Examiner, Art Unit 1797
Prosecution Insights