The present application, filed on or after March 16, 2013, is being examined under the first inventor to file provisions of the AIA .
The following is a quotation of 35 U.S.C. 112(f):
(f) Element in Claim for a Combination. – An element in a claim for a combination may be expressed as a means or step for performing a specified function without the recital of structure, material, or acts in support thereof, and such claim shall be construed to cover the corresponding structure, material, or acts described in the specification and equivalents thereof.
The claims in this application are given their broadest reasonable interpretation using the plain meaning of the claim language in light of the specification as it would be understood by one of ordinary skill in the art. The broadest reasonable interpretation of a claim element (also commonly referred to as a claim limitation) is limited by the description in the specification when 35 U.S.C. 112(f) is invoked.
As explained in MPEP § 2181, subsection I, claim limitations that meet the following three-prong test will be interpreted under 35 U.S.C. 112(f):
(A) the claim limitation uses the term “means” or “step” or a term used as a substitute for “means” that is a generic placeholder (also called a nonce term or a non-structural term having no specific structural meaning) for performing the claimed function;
(B) the term “means” or “step” or the generic placeholder is modified by functional language, typically, but not always linked by the transition word “for” (e.g., “means for”) or another linking word or phrase, such as “configured to” or “so that”; and
(C) the term “means” or “step” or the generic placeholder is not modified by sufficient structure, material, or acts for performing the claimed function.
Use of the word “means” (or “step”) in a claim with functional language creates a rebuttable presumption that the claim limitation is to be treated in accordance with 35 U.S.C. 112(f). The presumption that the claim limitation is interpreted under 35 U.S.C. 112(f) is rebutted when the claim limitation recites sufficient structure, material, or acts to entirely perform the recited function.
Absence of the word “means” (or “step”) in a claim creates a rebuttable presumption that the claim limitation is not to be treated in accordance with 35 U.S.C. 112(f). The presumption that the claim limitation is not interpreted under 35 U.S.C. 112(f) is rebutted when the claim limitation recites function without reciting sufficient structure, material or acts to entirely perform the recited function.
Claim limitations in this application that use the word “means” (or “step”) are being interpreted under 35 U.S.C. 112(f), except as otherwise indicated in an Office action. Conversely, claim limitations in this application that do not use the word “means” (or “step”) are not being interpreted under 35 U.S.C. 112(f) except as otherwise indicated in an Office action.
This application includes one or more claim limitations that do not use the word “means,” but are nonetheless being interpreted under 35 U.S.C. 112(f) because the claim limitations use a generic placeholder that is coupled with functional language without reciting sufficient structure to perform the recited function and the generic placeholder is not preceded by a structural modifier. Such claim limitation(s) is/are: "a pressure pump configured to apply a confining pressure to the inner chamber"; a carbon dioxide pump configured to inject carbon dioxide into the inner chamber via the fluid inlet"; and "a treatment injection pump configured to inject a treatment chemical into the fluid inlet" in claim 1.
Because this/these claim limitations are being interpreted under 35 U.S.C. 112(f), they are being interpreted to cover the corresponding structure described in the specification as performing the claimed function, and equivalents thereof.
If applicant does not intend to have this/these limitations interpreted under 35 U.S.C. 112(f), applicant may: (1) amend the claim limitation(s) to avoid them being interpreted under 35 U.S.C. 112(f) (e.g., by reciting sufficient structure to perform the claimed function); or (2) present a sufficient showing that the claim limitations recite sufficient structure to perform the claimed function so as to avoid it/them being interpreted under 35 U.S.C. 112(f).
Claims 4-5 are rejected under 35 U.S.C. 112(b) as being indefinite for failing to particularly point out and distinctly claim the subject matter which the inventor or a joint inventor regards as the invention. Claims 4-5 are dependent from a cancelled claim. For examination purposes claim 4 will be treated as if dependent from claim 1 because of the incorporation of the limitation of claim 3 into claim 1.
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.
Claims 1 and 6-7 are rejected under 35 U.S.C. 102(a)(1) as being clearly anticipated by Perrin (Energy Procedia 2009, herein after called Perrin ‘09 or Transport in Porous Media 2010, herein after called Perrin ‘10), Krevor (Water Resources Research 2010, hereinafter called Krevor ’10 or International Journal of Greenhouse Gases 2015, hereinafter called Krevor ’15) Akbarabadi (Advances in Water Resources 2015) or Niu (Water Resources Research 2015).
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.
This application currently names joint inventors. In considering patentability of the claims the examiner presumes that the subject matter of the various claims was commonly owned as of the effective filing date of the claimed invention(s) absent any evidence to the contrary. Applicant is advised of the obligation under 37 CFR 1.56 to point out the inventor and effective filing dates of each claim that was not commonly owned as of the effective filing date of the later invention in order for the examiner to consider the applicability of 35 U.S.C. 102(b)(2)(C) for any potential 35 U.S.C. 102(a)(2) prior art against the later invention.
Claims 1 and 4-7 are rejected under 35 U.S.C. 103 as being unpatentable over Perrin (Energy Procedia 2009, herein after called Perrin ‘09 or Transport in Porous Media 2010, herein after called Perrin ‘10), Krevor (Water Resources Research 2012, hereinafter called Krevor ’12 or International Journal of Greenhouse Gases 2015, hereinafter called Krevor ’15) Akbarabadi (Advances in Water Resources 2015) or Niu (Water Resources Research 2015) in view of Wang (US 2023/0212943).
In the paper, with respect to claim 1, Perrin '09 teaches apparatus for determining a carbon sequestration characteristic of a geological material, the apparatus comprising: a sample holder comprising a fluid inlet, an inner chamber, and a fluid outlet, wherein the sample holder is configured to hold a sample representative of the geological material within the inner chamber and to permit a flow of fluid from the fluid inlet through the sample and thence out the fluid outlet (see the core holder in figure 1 and its associated description in section 2.1); a pressure pump configured to apply a confining pressure to the inner chamber (see the confining pressure pump D in figure 1 and it description in section 2.1); a first pressure gauge and a second pressure gauge configured to measure a fluid pressure at the fluid inlet and a fluid pressure at the fluid outlet, respectively (see the pressure transducers on both sides of the core holder in figure 1 and the pressure drop measurement in section 2.1); a carbon dioxide pump configured to inject carbon dioxide into the inner chamber via the fluid inlet (see pumps A1 and A2 of figure 1 and their associated description in section 2.1); a separator for separating a volume of carbon dioxide from fluid flowing from the fluid outlet (see the separator of figure 1 with its associated description in section 2.1); and a return line configured to return at least a portion of the volume of carbon dioxide separated by the separator to the fluid inlet see the line going from the separator to the CO2 pumps in figure 1 along with the description of the return of CO2 from the separator to the CO2 pump system in section 2.1). With respect to claims 6-7, figure 1 shows a structure capable of injecting a mixture comprising (a) carbon dioxide returned by the return line and (b) carbon dioxide from a carbon dioxide tank (the carbon dioxide pump is connected to both the separator and a carbon dioxide tank in figure 1 in a manner that the carbon dioxide from the carbon dioxide tank has not been in contact with the sample before the injecting). The first paragraph of the introduction section on page 3515 of Perrin ‘09 teaches that carbon dioxide capture and storage can play an important role on reducing greenhouse gas emissions from stationary sources of emissions. The capacity for storing CO2 resides in saline aquifers, which are both broadly distributed and have a tremendous amount of pore volume. Experimental studies of both drainage and imbibition displacements are needed to improve our fundamental understanding of multi-phase flow and trapping in saline aquifers and effectively take advantage of their large storage capacity.
With respect to claims 1 and 4-5, Perrin ‘09 does not teach structure for or use of a treatment injection pump configured to inject a treatment chemical into the fluid inlet.
In the paper, with respect to claim 1, Perrin '10 teaches apparatus for determining a carbon sequestration characteristic of a geological material, the apparatus comprising: a sample holder comprising a fluid inlet, an inner chamber, and a fluid outlet, wherein the sample holder is configured to hold a sample representative of the geological material within the inner chamber and to permit a flow of fluid from the fluid inlet through the sample and thence out the fluid outlet (see the core holder in figure 1 and its associated description in section 2.1); a pressure pump configured to apply a confining pressure to the inner chamber (see the confining pressure pump D in figure 1 and it description in section 2.1); a first pressure gauge and a second pressure gauge configured to measure a fluid pressure at the fluid inlet and a fluid pressure at the fluid outlet, respectively (see the pressure transducers on both sides of the core holder in figure 1 and the pressure drop measurement in section 2.2); a carbon dioxide pump configured to inject carbon dioxide into the inner chamber via the fluid inlet (see pumps A1 and A2 of figure 1 and their associated description in section 2.1); a separator for separating a volume of carbon dioxide from fluid flowing from the fluid outlet (see the separator of figure 1 with its associated description in section 2.1); and a return line configured to return at least a portion of the volume of carbon dioxide separated by the separator to the fluid inlet (see the line going from the separator to the CO2 pumps in figure 1 along with the description of the return of CO2 from the separator to the CO2 pump system in section 2.1). With respect to claims 6-7, figure 1 shows a structure capable of injecting a mixture comprising (a) carbon dioxide returned by the return line and (b) carbon dioxide from a carbon dioxide tank (the carbon dioxide pump is connected to both the separator and a carbon dioxide tank in figure 1 in a manner that the carbon dioxide from the carbon dioxide tank has not been in contact with the sample before the injecting). In the paragraph bridging pages 93-94 Perrin “10 teaches that among the different main types of potential storage formations (saline aquifers, depleted oil reservoirs, unminable coal seams), saline aquifers have by far the largest estimated storage capacity and are more broadly distributed worldwide. In order to improve the understanding of multi-phase flow and trapping in CO2-brine systems and take advantage of this capacity, more experimental data, numerical simulations, and theoretical studies are needed. While the literature describing multi-phase flow of oil and water, and CO2 and oil is abundant, very few laboratory experiments have been performed on CO2/brine systems and, thus, very few data are available.
With respect to claims 1 and 4-5, Perrin ’10 does not teach structure for or use of a treatment injection pump configured to inject a treatment chemical into the fluid inlet.
In the paper, with respect to claim 1, Krevor '12 teaches that the apparatus is a modified version of the Perrin ’09 apparatus for determining a carbon sequestration characteristic of a geological material, the apparatus comprising: a sample holder comprising a fluid inlet, an inner chamber, and a fluid outlet, wherein the sample holder is configured to hold a sample representative of the geological material within the inner chamber and to permit a flow of fluid from the fluid inlet through the sample and thence out the fluid outlet (see the core holder in figure 7 and its associated description in section 2.5); a pressure pump configured to apply a confining pressure to the inner chamber (see the confining pressure pump D in figure 7 and it description in section 2.5); a first pressure gauge and a second pressure gauge configured to measure a fluid pressure at the fluid inlet and a fluid pressure at the fluid outlet, respectively (see the pressure transducers on both sides of the core holder in figure 7 and the pressure drop measurement in section 2.5); a carbon dioxide pump configured to inject carbon dioxide into the inner chamber via the fluid inlet (see pumps A1 and A2 of figure 7 and their associated description in section 2.5); a separator for separating a volume of carbon dioxide from fluid flowing from the fluid outlet (see the separator of figure 7 with its associated description in section 2.5); and a return line configured to return at least a portion of the volume of carbon dioxide separated by the separator to the fluid inlet (see the line going from the separator to the CO2 pumps in figure 7 along with the description of the return of CO2 from the separator to the CO2 pump system in section 2.5). With respect to claims 6-7, figure 7 shows a structure capable of injecting a mixture comprising (a) carbon dioxide returned by the return line and (b) carbon dioxide from a carbon dioxide tank (the carbon dioxide pump is connected to both the separator and a carbon dioxide tank in figure 7 in a manner that the carbon dioxide from the carbon dioxide tank has not been in contact with the sample before the injecting).
With respect to claims 1 and 4-5, Krevor ’12 does not teach structure for or use of a treatment injection pump configured to inject a treatment chemical into the fluid inlet.
In the paper, with respect to claim 1, Krevor '15 teaches an apparatus for determining a carbon sequestration characteristic of a geological material, the apparatus comprising: a sample holder comprising a fluid inlet, an inner chamber, and a fluid outlet, wherein the sample holder is configured to hold a sample representative of the geological material within the inner chamber and to permit a flow of fluid from the fluid inlet through the sample and thence out the fluid outlet (see the core holder in figure 9); a pressure pump configured to apply a confining pressure to the inner chamber (see the confining pressure pump in figure 9); a first pressure gauge and a second pressure gauge configured to measure a fluid pressure at the fluid inlet and a fluid pressure at the fluid outlet, respectively (see the pressure transducers on both sides of the core holder in figure 9); a carbon dioxide pump configured to inject carbon dioxide into the inner chamber via the fluid inlet (see the CO2 pumps of figure 9); a separator for separating a volume of carbon dioxide from fluid flowing from the fluid outlet (see the two-phase separator of figure 9); and a return line configured to return at least a portion of the volume of carbon dioxide separated by the separator to the fluid inlet (see the line going from the separator to the CO2 pumps in figure 9). With respect to claims 6-7, figure 9 shows a structure capable of injecting a mixture comprising (a) carbon dioxide returned by the return line and (b) carbon dioxide from a carbon dioxide tank (the carbon dioxide pump is connected to both the separator and a carbon dioxide tank in figure 9 in a manner that the carbon dioxide from the carbon dioxide tank has not been in contact with the sample before the injecting). In the final paragraph of section 5.2 on page 235, Krevor ’15 teaches that carbon dioxide injection into depleted oil and gas fields represents a low-cost opportunity for CO2 storage for many reasons including revenue from enhanced oil recovery and the ability to take advantage of existing reservoir characterization and site infrastructure. Understanding migration and trapping for CO2 in these systems should be a high priority for research. the second to last paragraph on page 235 teaches that key outstanding uncertainties that will likely have further impact on reservoir characterization and management include the characterization of the impact of reservoir rock heterogeneity on capillary trapping, and the character of capillary trapping in depleted oil reservoirs with altered wettability.
With respect to claims 1 and 4-5, Krevor ’15 does not teach structure for or use of a treatment injection pump configured to inject a treatment chemical into the fluid inlet.
In the paper, with respect to claim 1, Akbarabadi teaches apparatus for determining a carbon sequestration characteristic of a geological material, the apparatus comprising: a sample holder comprising a fluid inlet, an inner chamber, and a fluid outlet, wherein the sample holder is configured to hold a sample representative of the geological material within the inner chamber and to permit a flow of fluid from the fluid inlet through the sample and thence out the fluid outlet (see the core holder in figure 2 and its associated description in section 2.2); a pressure pump configured to apply a confining pressure to the inner chamber (see the overburden pressure pump in figure 2 and it description in section 2.2); a first pressure gauge and a second pressure gauge configured to measure a fluid pressure at the fluid inlet and a fluid pressure at the fluid outlet, respectively (see the pressure array connected to both sides of the core holder in figure 2 and the pressure measurement in section 2.2); a carbon dioxide pump configured to inject carbon dioxide into the inner chamber via the fluid inlet (see the CO2 pumps of figure 2 and their associated description in section 2.2); a separator for separating a volume of carbon dioxide from fluid flowing from the fluid outlet (see the three-phase separator of figure 2 with its associated description in section 2.2); and a return line configured to return at least a portion of the volume of carbon dioxide separated by the separator to the fluid inlet (see the line going from the separator to the CO2 pumps in figure 2 along with the description of the retracting and injecting of CO2 from the separator to the CO2 pump system in section 2.2). With respect to claims 6-7, figure 2 shows a structure capable of injecting a mixture comprising (a) carbon dioxide returned by the return line and (b) carbon dioxide from a carbon dioxide tank (the carbon dioxide pump is connected to both the separator and a carbon dioxide tank in figure 1 in a manner that the carbon dioxide from the carbon dioxide tank has not been in contact with the sample before the injecting). The last full paragraph on page 44 of the Akbarabadi paper teaches that geologic mitigation (sequestration) occurs through CO2 injection into three different types of formations: (1) unmineable coal seams, (2) mature hydrocarbon reservoirs, and (3) deep saline aquifers, among which the latter is known to have the highest total storage capacity and comprises about 90% of the global CO2 storage space.
With respect to claims 1 and 4-5, Akbarabadi does not teach structure for or use of a treatment injection pump configured to inject a treatment chemical into the fluid inlet.
In the paper, with respect to claim 1, Niu '15 teaches an apparatus for determining a carbon sequestration characteristic of a geological material, the apparatus comprising: a sample holder comprising a fluid inlet, an inner chamber, and a fluid outlet, wherein the sample holder is configured to hold a sample representative of the geological material within the inner chamber and to permit a flow of fluid from the fluid inlet through the sample and thence out the fluid outlet (see the experimental core holder in figure 8 and its description in section 4.1); a pressure pump configured to apply a confining pressure to the inner chamber (see the overburden pump D in figure 8 along with its description in section 4.1); a first pressure gauge and a second pressure gauge configured to measure a fluid pressure at the fluid inlet and a fluid pressure at the fluid outlet, respectively (see the absolute pressure transducers on both sides of the core holder in figure 8 along with the pressure drop measurement description in section 4.1); a carbon dioxide pump configured to inject carbon dioxide into the inner chamber via the fluid inlet (see the CO2 pumps A of figure 8 along with their description in section 4.1); a separator for separating a volume of carbon dioxide from fluid flowing from the fluid outlet (see the two-phase separator of figure 8 along with its description in section 4.1); and a return line configured to return at least a portion of the volume of carbon dioxide separated by the separator to the fluid inlet (see the line going from the separator to the CO2 pumps in figure 8). With respect to claims 6-7, figure 8 shows a structure capable of injecting a mixture comprising (a) carbon dioxide returned by the return line and (b) carbon dioxide from a carbon dioxide tank (the carbon dioxide pump is connected to both the separator and a carbon dioxide tank in figure 8 in a manner that the carbon dioxide from the carbon dioxide tank has not been in contact with the sample before the injecting). The last full paragraph on page 2009 of the Niu paper teaches that residual trapping has been investigated extensively for petroleum engineering applications for two primary reasons. Intuitively, residual trapping has a primary control on the ultimate oil recovery in conventional production processes. Where water is being used to drive oil from a reservoir, for example, a product of the sweep, the total fraction of the reservoir contacted by the injected water, and the complement of the residually trapped oil saturation determines the ultimate recovery. This is the analog to the role of residual trapping in capacity estimation for CO2 storage. The product of the spatial extent of the CO2 plume and residually trapped saturation will determine the extent to which residual trapping contributes to the total storage capacity of a reservoir.
With respect to claims 1 and 4-5, Niu does not teach structure for or use of a treatment injection pump configured to inject a treatment chemical into the fluid inlet.
With respect to the use of a treatment chemical in core flooding apparatus as required by claims 1 and 4-5, Wang teaches systems and method to at least partially restoring carbonate core samples. The systems and methods include extracting a carbonate core sample from a subterranean formation. The extracted carbonate core sample is inserted into a core flooding test machine. A first brine permeability of the extracted carbonate core sample is measured. A fluid is pumped through the extracted carbonate core sample to flood the carbonate core sample. The fluid includes at least one of a high-molecular weight polymer solution and a gel particle solution. The systems and methods include at least partially restoring the porosity and the brine permeability of the flooded carbonate core sample by pumping an oxidizing solution through the carbonate core sample and heating the carbonate core sample to a temperature of at least 60 °C after pumping the oxidizing solution through the carbonate core sample. Paragraph [0008] teaches that the systems and methods use a process of pumping an oxidizing solution through the core sample and heating the core sample. In some examples, the systems and methods are also used to clean oils and salts from the core sample. In general, the systems and methods are used to clean oil, salts, surfactants, polymers, and/or gel particles from a core sample and restore at least 85% permeability of core samples to their respective pre-tested states. Paragraph [0050] describes figure 2B as a schematic view of residual hydrocarbon 154 within the carbonate rock 200. The choice of a particular displacing fluid 152 affects the wettability and oil recovery of the reservoir 150. In figure 2B, residual hydrocarbon 154 becomes trapped within the pores of the porous rock 200. Trapped hydrocarbon 154 is undesirable. In some examples, the residual hydrocarbon 154 does not substantially move towards the production well 102 when displacing fluid 152 is continuously pumped into the reservoir 150 using the injection well 104. Selecting the displacing fluid 152 is an important aspect of reducing trapped residual hydrocarbon 154 of the reservoir 150. Figure 4 in particular shows a schematic of a core sample restoration system. Paragraph [0053] teaches that the core sample restoration system 230 is configured to both perform a core-flooding experiment and to clean and restore core samples after the core-flooding experiment has been performed. Paragraphs [0054]-[0057] teach that the core sample restoration system 230 includes a computer 228 operable to control various aspects of the core sample restoration system 230, a furnace 232 operable to heat objects inside the furnace 232 to temperatures up to 700 °C, a core sample holder 234 with two end caps 236A, 236B mounted inside the furnace 232, a plurality of pumps 231A-231C, valves 240A-240C, and containers 238A-238C. A user places a core sample (for example, the core sample 210) inside the core sample restoration system 230 by attaching the core sample 210 to the core sample holder 234 and the two end caps 236A, 236B. The user then closes the doors to the furnace 232 to both thermally insulate the core sample 210 from the ambient surroundings of the laboratory and form a pressure seal around the core sample 210 so the core sample 210 can be pressurized. While three pumps, valves and containers are shown in figure 4, some core sample restoration systems include more than three (for example, 5, 6, or 10) and some core sample restoration systems include less than three (for example, 1 or 2). Paragraph [0058] teaches that the first pump 231A is operable to pump a first fluid (fluid “A”) to and through the core sample 210. In some examples, the first fluid is or includes water (for example, fresh water, distilled water, connate water, seawater, Qatar seawater, or brine). Paragraph [0059] teaches that the second pump 231B is operable to pump a second fluid (fluid “B”) to and through the core sample 210. In some examples, the second fluid is an oxidizing solution (for example, a NaClO, HClO, K2S2O8, NaBrO, KClO3, or KMnO4 all are water soluble). Paragraph [0060] teaches that the third pump 231C is operable to pump a third fluid (fluid “C”) to and through the core sample 210. In some examples, the third fluid is a non-oxidizing solution that includes KCl. Paragraph [0062] teaches that the core sample restoration system 230 includes a hydraulic system 246 operable to pressurize the core sample 210 up to at least 5000 psi. A pressure transducer 248 measures a pressure of the core sample 210. In some examples, the computer 228 determines porosity based on data of the pressure transducer 248 representing the measured pressure of the core sample 210 restoration process. Paragraph [0065] teaches that in some examples, during a core-flooding experiment, the first fluid is water for rinsing the core sample 210, the second fluid is a micro-gel particle solution for chemical injection through the core sample 210, and the third fluid is polymer solution also for chemical injection through the core sample 210. In some examples, during a core restoration process, the first fluid includes water (for example, connate water, brine, seawater, or Qatar seawater) for rinsing the core sample 210, the second fluid is an oxidizing solution for cleaning the remaining polymer and gels from the core sample 210, and the third fluid is a non-oxidizing solution that includes KCl for rinsing the core sample 210.
With respect to claims 1 and 4-5, it would have been obvious to one of ordinary skill in the art at the time the application was filed to incorporate one or more additional pumps with containers for addition of treatment chemicals such as the chemical oxidizer of Wang to the Perrin ‘09, Perrin ’10, Krevor ’10, Krevor ’15, Akbarabadi or Niu core flooding systems because of the use of depleted oil reservoirs for carbons sequestration as taught by one or more of Perrin ‘09, Perrin ’10, Krevor ’10, Krevor ’15, Akbarabadi or Niu or the use of carbon dioxide with enhanced oil recovery processes which may also be taught as leading to stored carbon dioxide by one or more of Perrin ‘09, Perrin ’10, Krevor ’10, Krevor ’15, Akbarabadi or Niu and ability of the oxidizers to remove polymers used in enhanced oil recovery that are blocking the pores of the core being tested or clean oils from a core as taught by Wang would have been recognized as beneficial when testing for sequestration associated with enhanced oil recovery or depleted oil reservoirs where the presence of trapped oil in a core sample would have been expected as taught by at least Niu.
Claim 2 is rejected under 35 U.S.C. 103 as being unpatentable over Perrin ‘09, Perrin ’10, Krevor ’10, Krevor ’15, Akbarabadi or Niu in view of Wang as applied to claim 1 above and further in view of Shi (International Journal of Greenhouse Gas Control 2011) or Trivedi (Journal of Canadian Petroleum Technology 2010). With respect to claim 2, Perrin ‘09, Perrin ’10, Krevor ’10, Krevor ’15, Akbarabadi or Niu do not teach a gas flow meter to measure a flow rate of the gas flowing from the fluid outlet to the separator.
In the paper Shi presents a numerical simulation study of a full CO2 core flooding and imbibition cycle performed on a heterogeneous Tako sandstone core. During the test, supercritical CO2 (at 10MPa and 40 ◦C) and CO2-saturated brine was injected into one end of the horizontal core and a X-ray CT scanner was employed to monitor and record changes in the fluid saturations, which enabled 3D mapping of the saturation profiles throughout the core during the course of core flooding test. The CO2 flooding test demonstrated that (1) sub-core porosity heterogeneity had a marked impact on the CO2 migration pattern within the Tako sandstone core at low injection rates (∼0.1cm3/min); (2) the influence of the porosity heterogeneity on the mean CO2 saturation profiles along the core became gradually diminished as the injection rate was increased in steps to 3 cm3/min. The numerical simulation results have shown that the immiscible displacement processes in the heterogeneous Tako core could not be adequately described by using a single capillary pressure curve in a 1D model of the core. This was found to be the case even when a 3D model (5×5×24) was used, where the porosity/permeability heterogeneity across the cross-sections, as well as along the core, was taken into account. Furthermore, the apparent correlation between the CO2 saturation and the porosity (mean) profiles during the CO2 flooding could largely be accounted for by employing a Leverett J-function type scaling factor, which reflects the influence of porosity/permeability heterogeneity on the capillary pressure. Figure 1 presents a schematic of the core flood system with X-ray CT scan. Relative to the instant claims, figure 1 shows a first pressure gauge and a second pressure gauge configured to measure a fluid pressure at the fluid inlet and a fluid pressure at the fluid outlet, respectively and a gas flow meter to measure a flow rate of the gas flowing from the fluid outlet.
In the paper Trivedi teaches a CO2 flooding test performed with an apparatus shown in figure 1 and described in the “Diffusion Cell (Core Holder)” and “Injection-Production Setup” sections on page 23 of the paper. Relevant to the instant claims are the description of the core holder with its inlet, outlet and ability to supply an overburden pressure to a core sample as described in the “Diffusion Cell (Core Holder)” section and the pumps for supplying CO2, the separator is used for oil and gas separation, coming through the backpressure regulator and the volume/mass flowmeter attached to the top of the separator to measure the rate of CO2 produced that are described in the “Injection-Production Setup” section. Also of relevance is the teaching that the flow rate, volume remaining and pump pressure signals output from the pump controller, digital scale value and weight of oil production data with time, CO2 mass flow, volume flow, temperature and pressure data were acquired through an automatic data acquisition system.
With respect to claim 2, it would have been obvious to one of ordinary skill in the art at the time the application was filed to incorporate a fluid pressure as taught by Shi or Travedi into the Perrin ‘09, Perrin ’10, Krevor ’10, Krevor ’15, Akbarabadi or Niu devices because of the similarity in the things being measured by the different devices and at least the desire to measure CO2 flow by Shi and Travedi.
Claim 8 is rejected under pre-AIA 35 U.S.C. 103(a) as being unpatentable over Perrin ‘09, Perrin ’10, Krevor ’10, Krevor ’15, Akbarabadi or Niu in view of Wang as applied to claim 1 above, and further in view of Ott (Review of Scientific Instruments 2012). With respect to claim 8, Perrin ‘09, Perrin ’10, Krevor ’10, Krevor ’15, Akbarabadi or Niu do not teach a gas chromatograph-mass spectrometer configured to determine a composition of a fluid mixture flowing from the fluid outlet.
In the paper Ott teaches an experimental setup to investigate physical and chemical processes caused by the flow of reactive and volatile fluids such as supercritical CO2 and/or H2S in geological formations. Potential applications are geological sequestration of CO2 in the frame of carbon capture and storage and acid-gas injection for sulfur disposal and/or enhanced oil recovery. The paper outlines the design criteria and the realization of reactive transport experiments on the laboratory scale. Figure 10 shows a process engineering flow scheme (PEFS) of the experimental setup. The last full paragraph on page 7 of the paper teaches that chemical interaction also changes the composition of the involved fluids manifested in the composition of the produced fluids compared to the initial and injected fluids. They combined the classical design of a core-flood experiment with in-line fluid analysis and sampling options as shown in Figures 9 and 10; the produced fluids undergo a two-step phase separation to separate, e.g., an aqueous phase from a CO2/H2S phase. The separation is followed by in-line chemical gas analysis by gas chromatography and sampling options for both phases for continuative ex situ analysis. Figure 10 shows the gas chromatograph mass spectrometer as part of the fluid analysis and sampling section of the experimental section. The first full paragraph on page 12 of the paper teaches that the analytical section is shown in the lower part of Figure 10. The available options are listed in Table I and are: (1) fluid density and mass flow in the acid-gas feed line and in the production line measured by Coriolis mass flow meters, (2) two-step gas/liquid phase separation, (3) online chemical gas analysis of the separated gas streams using gas chromatography (GC) and mass spectroscopy (MS), (4) gas sampling by gas bags and sampling by precipitation of gas constituents for ex situ isotopic composition determination, (5) automated sampling of liquid phases for subsequent ex situ analysis.
With respect to claim 8, it would have been obvious to one of ordinary skill in the art at the time the application was filed to add an analysis section including a gas chromatograph mass spectrometer as taught by Ott to the core flood systems of Perrin ‘09, Perrin ’10, Krevor ’10, Krevor ’15, Akbarabadi or Niu because of the analysis potential to follow reactions and/or determine compositions to either control the apparatus or monitor processes occurring within the core as taught by Ott.
Claims 9-21 are allowed.
The following is a statement of reasons for the indication of allowable subject matter: The art of record fails to teach or fairly suggest the combination of steps found in claim 9. The references that are anticipatory of claim 1 in general use external apparatus for measuring the carbon dioxide saturation of the cores. The cited Jin paper (Journal of Hydrology 2022) teaches that the pressure differential can be used to follow capillary and viscous forces in CO2 core flooding experiments but fails to show that the measurements can be used to determine a carbon dioxide sequestration characteristic. Thus the art of record fails to teach or fairly suggest this aspect of claim 9 in combination with the other steps although the apparatus are capable of measuring the inlet and outlet pressures and/or the pressure differential.
Applicant's arguments filed May 8, 2026 have been fully considered but they are not persuasive. In response to the amendments, the anticipation rejections have been converted to obviousness rejections and a new rejection under 35 U.S.C. 112(b) has been applied against certain claims. Additionally, examiner has determined that interpreting the claims under 35 U.S.C. 112(f) is appropriate. Based on this the arguments are moot with respect to the previous anticipation rejections and the new rejection under 35 U.S.C. 112(b).
With respect to the arguments directed toward the reference combinations previously applied against claim 3 and currently applied against claim 1, examiner first notes that the particular limitation that applicant has argued as not being obvious is “a treatment injection pump configured to inject a treatment chemical into the fluid inlet”. This limitation does not require that the treatment chemical be any particular chemical or that the treatment chemical even be used in combination with the carbon dioxide pump configured to inject carbon dioxide into the inner chamber via the fluid inlet. In other words, the limitation simply requires the presence of a pump and associated structure capable of injecting a treatment chemical into the fluid inlet. While not applied, the previously cited Baldygin paper could have shown the obviousness of this limitation based on the teaching that there is a need to modify the traditional core flooding apparatus by increasing the number of fluids that can be injected into a core in a core flooding process. Thus this limitation of claim 1 is an obvious modification of the Perrin ‘09, Perrin ’10, Krevor ’10, Krevor ’15, Akbarabadi or Niu teachings.
Moreover, even if one looks at the limitation of claim 4, Wang clearly teaches that an oxidizer is used to treat cores to clean residual oil from them. If as disclosed by Niu, the amount of trapped oil affects the amount of carbon dioxide that can be stored/sequestered in a particular formation, looking a treatments known to clean/remove that oil would be an obvious modification to test whether the amount of sequestered carbon dioxide can be increased. Thus contrary to the arguments of applicant, Wang contains teachings that, when combined with the teachings of Perrin ‘09, Perrin ’10, Krevor ’10, Krevor ’15, Akbarabadi or Niu, point to the obviousness of the chemical treatment comprising an oxidizer. Thus the arguments are not persuasive relative to claims 1 or 4-5. Since claims 1 and 4-5 are obvious in view of the applied combinations, the argument that claims 2 and 6-8 are allowable based on the allowability of claim 1 is also not persuasive.
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.
The prior art made of record and not relied upon is considered pertinent to applicant's disclosure. The additionally cited references are related to core flooding structures and methods.
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/ARLEN SODERQUIST/ Primary Examiner, Art Unit 1797
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