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
Claims 1-15 are objected to because of the following informalities:
Claims 1, 7, 9, 13, and 14 state the terms “flowrate” and “flow rate” interchangeably. Consistent terminology must be used throughout the claims.
Claim 7 recites the term “VLP” in line 3. The term should be positively set forth by defining the acronym at first use, and then the acronym may be used thereafter in the claims depending therefrom. The term in claim 7, line 3 should be replaced with - -vertical lift performance (VLP)- -.
Appropriate correction is required.
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) 1-15 is/are rejected under 35 U.S.C. 103 as being unpatentable over BERGE ET AL (US 2008/0319726) alone, or in the alternative in view of WO’216 (WO 2004/049216) and LI ET AL (US 10012055), each cited by applicant.
With respect to claim 1, BERGE ET AL disclose a process of determining a future injection performance of a well (see fig.2 and page 8 line 3; BERGE ET AL applies to injection as well as production), a fluid being intended to be injected from a surface network (see surface network in fig.1) via the well into a geological formation defining a reservoir ( at a reservoir pressure intended to increase over time, the fluid being injected at a wellhead (see page 1 line 18) at a wellhead flowing pressure and a wellhead flowing temperature at which the fluid is in liquid or dense phase, the fluid flowing at a flowrate from the
wellhead to a bottom hole where the fluid is at a bottom hole flowing pressure, a bottom hole flowing temperature and a bottom hole flowing enthalpy, and the fluid flowing at the flow rate from the bottom hole into the reservoir (all of the above are implicit features of an injection system), the injection performance providing a relationship between the flowrate and the bottom hole flowing pressure (see fig.2 of BERGE ET AL showing a relationship between THP and flowrate and page 6 line 10-14 where the BHP is used instead of THP), the process comprising the following steps: a) obtaining a first set of data providing the bottom hole flowing pressure as functions of the WHFP, and of the flowrate (see page 6 line 8-10 and fig.2),
b) obtaining a surface network simulator (surface network model) adapted for
performing a nodal analysis of the surface network (see page 1 line 23-24) and
the well, and obtaining a reservoir simulator (see reservoir simulator in fig.3)
adapted for modeling flows in the reservoir,
c) providing the reservoir simulator with a current working point of the well comprising the wellhead flowing pressure, and the flowrate for a current time step,
d) running the reservoir simulator over the current time step, and obtaining
updated pressure conditions in the reservoir (see page 2 line 7-14),
e) using the updated pressure conditions in the reservoir the wellhead flowing
pressure, calculating a second set of data, the second set of data providing the bottom hole flowing pressure as a function of the flowrate for a next time step,
f) providing the surface network simulator with the second set of data, and
g) using the second set of data and at least part of the first set of data, obtaining
the bottom hole flowing pressure for the next time step and, using the surface
network simulator, obtaining an updated working point of the well comprising the
wellhead flowing pressure, and the flowrate for the next time step, wherein steps c) to g) are iterated over a plurality of time steps, the process further comprising obtaining the injection performance from the second set of data obtained at one of the time steps. (see page 8 line 3 - page 9 line 2 as well as page 2 line 7 - 24 and page 6 "the
coupling scheme").
However, BERGE ET AL fails to explicitly teach that the mathematical algorithm uses also the bottom hole flowing temperature (BHFT) and the bottom hole flowing enthalpy (BHFH) as well as the wellhead flowing temperature (WHFT) as variables as claimed. The differential features represent a mathematical method that does not produce a technical effect serving a technical purpose. It is noted that although a future injection performance of a well is mentioned in the claim, the direct link with the control of the well using the results of the assessment is not defined in the independent claim and is therefore unclear and left to interpretation. The required technical link is present in claim 13. Even if this was included into independent claim 1, it is not considered an
inventive choice for the skilled person in the art. BERGE ET AL is already considering the
reservoir temperature for the assessment. The BHFT, and WHFT would
therefore seem to be obvious choices for the skilled person to consider
according to the needs and the computer capabilities and time available for the simulation.
With respect to claims 2-6, including the fluid at least partially liquid, wellhead/reservoir temperatures and/or pressures, fluid pressures, and vol% of CO2, these are features of a fluid which is intended to be injected and which would depend of the conditions of the reservoir and the choice of the skilled person about what type of fluid injection he wants to simulate. The features are typical features for an injection fluid, particularly if this fluid is carbon dioxide.
With respect to claims 7,8, including data comprising a VLP table including pressures/temperatures, and enthalpy table, using a VLP curve is a known
feature for injecting a fluid in a reservoir. See also WO’216 par. 93. See also LI ET AL for enthalpy data in the reservoir. Therefore, it would be considered obvious to one of ordinary skill in the art before the effective filing date of the present application to have provided the tables as necessary in order to inject fluids into a reservoir.
With respect to claims 9-11, including techniques/calculations of parameters and using reservoir simulator, the features are steps of a mathematical treatment which don't
solve any technical problem and are just data processing and cannot justify any
inventive skill and they do not solve a specific technical problem.
With respect to claim 12, including a plurality of wells and surface network, (see BERGE ET AL page 6, line 8).
With respect to claims 13,15: including obtaining a target flowrate, determine a needed pressure, and injecting fluid at the needed pressure, see BERGE ET AL page 12 line 3-10.
With respect to claim 14, wherein the target flowrate is provided by the surface network simulator, see BERGE ET AL page 7 line 7-8.
Conclusion
The prior art made of record and not relied upon is considered pertinent to applicant's disclosure. US 2022/0214474 teaches a method where production engineers rely on pressure and temperature measurements of the wells and physics-based models of the reservoirs/wells (e.g., reservoir simulators, well flow simulators, nodal analysis, etc.) to judge the performance of individual wells, identify sub-par production zones and take corrective actions (e.g. artificial lift, fluid injection, etc.).
Any inquiry concerning this communication or earlier communications from the examiner should be directed to ZAKIYA W BATES whose telephone number is (571)272-7039. The examiner can normally be reached M-F 8:30am - 5pm.
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/ZAKIYA W BATES/Primary Examiner, Art Unit 3674 1/7/2026