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 .
Detailed Action
Claims 1-6 are pending.
Drawings
The drawings filed on 10/21/2022 are accepted.
Oath/Declaration
4. For the record, the Examiner acknowledges that the Oath/Declaration submitted on 05/15/2024 has been received.
Information Disclosure Statement
5. The information disclosure statements (IDS) submitted on 01/10/2023 has been considered. The submission is in compliance with the provisions of 37 CFR 1.97. Accordingly, an initialed and dated copy of Applicant's IDS form SB08 filed 01/10/2023 is attached to the instant Office action.
Examiner Notes
6. Examiner cites particular columns, paragraphs, figures and line numbers in the references as applied to the claims below for the convenience of the applicant. Although the specified citations are representative of the teachings in the art and are applied to the specific limitations within the individual claim, other passages and figures may apply as well. It is respectfully requested that, in preparing responses, the applicant fully consider the references in their entirety as potentially teaching all or part of the claimed invention, as well as the context of the passage as taught by the prior art or disclosed by the examiner. The entire reference is considered to provide disclosure relating to the claimed invention. The claims & only the claims form the metes & bounds of the invention. Office personnel are to give the claims their broadest reasonable interpretation in light of the supporting disclosure. Unclaimed limitations appearing in the specification are not read into the claim. Prior art was referenced using terminology familiar to one of ordinary skill in the art. Such an approach is broad in concept and can be either explicit or implicit in meaning. Examiner's Notes are provided with the cited references to assist the applicant to better understand how the examiner interprets the applied prior art. Such comments are entirely consistent with the intent & spirit of compact prosecution.
Claim Rejections - 35 USC § 112
The following is a quotation of 35 U.S.C. 112(b):
(b) CONCLUSION.—The specification shall conclude with one or more claims particularly pointing out and distinctly claiming the subject matter which the inventor or a joint inventor regards as the invention.
The following is a quotation of 35 U.S.C. 112 (pre-AIA ), second paragraph:
The specification shall conclude with one or more claims particularly pointing out and distinctly claiming the subject matter which the applicant regards as his invention.
7. Claims 1-6 are rejected under 35 U.S.C. 112(b) or 35 U.S.C. 112 (pre-AIA ), second paragraph, as being indefinite for failing to particularly point out and distinctly claim the subject matter which the inventor or a joint inventor, or for pre-AIA the applicant regards as the invention.
Claim 1 recites the limitation “A COMBINED METHOD FOR ESTIMATING THE LOSS OF INJECTIVITY IN CARBONATE RESERVOIRS, considering reactive effects and the presence of suspended solids, characterized in that it comprises the following steps: a) Experimental method: a.1) Saturate the rock samples (plugs) with a non- reactive water - NRW;
a.2) Gradually increase the pressure and confine the system to a pressure equal to the confinement pressure to which they were submitted in the routine tests of basic petrophysics;
a.3) After the system is pressurized, carry out a flow with the non-reactive water to check the initial water permeability and pH, under conditions of room temperature and injection flow rate of 0.8 to 2.0 ml/min;
a.4) Next, inject about 900 mL of desulfated seawater (DSW) + acid + solids, where the fluid addition flow rate is 0.8 ml/min; a.5) Carry out a filtration in a 0.45 pm mixed cellulose ester membrane at the point where the plug is located to determine the effective value of the suspended solids content;
a.6) Collect samples at the system outlet, after the fluid has come into contact with the rock, to monitor changes in chemical composition; a.7) Determine the concentration of sodium, calcium, magnesium and potassium by the atomic emission spectrometry technique (ICP-OES), and of chloride, analyzed by titration; and also measure the pH of the solution at the test outlet under ambient conditions;
b) Simulation method: b.1) Determine the parameter pL of the Perkins and Gonzalez modeling with data from the experimental test; b.2) Carry out the adjustment of the open area to the flow of the Perkins and Gonzalez modeling according to the pL determined in item b.1 (comparison with the reactive and non-reactive test in the presence of suspended solids) or with the history adjustment the injectivity index of item b.1;
b.3) Carry out the Perkins and Gonzalez simulation to predict the injectivity index over time, also using well parameters and operating data, in addition to the area value adjusted in item b.2.”
All the bolded/highlighted claim elements above have insufficient antecedent basis for this limitation in the claim 1, makes the scope of the claim indeterminate. The claim elements in claim 1: “A COMBINED METHOD FOR ESTIMATING THE LOSS OF INJECTIVITY IN CARBONATE RESERVOIRS, considering reactive effects and the presence of suspended solids, characterized in that it comprises”, it is not clear to understand what the term “it” means or is it indicating the “loss of injectivity in carbonate reservoirs”? The claim elements in step a.2): “the pressure and confine the system to a pressure equal to the confinement pressure to which they were submitted in the routine tests”, it is not clear to understand which system is confined and which confinement pressure is submitted to which routine test. The term “they” created a big question, what does it mean (is it “a pressure equal to the confinement pressure”). The claim elements in step b.2) Carry out the adjustment of the open area to the flow of the Perkins and Gonzalez modeling … with the history adjustment the injectivity index”, it is not clear to understand which adjustment is referred to the “Perkins and Gonzalez modeling” and the “history adjustment the injectivity index”.
The dependent claims 2-6 do not resolve the indefinite issue in the independent claim 1, and thus are also rejected under 112(b) by virtue of their dependence on the rejected independent claim 1. Therefore, specific clarifications and appropriate corrections are required.
Claim Rejections - 35 USC § 103
In the event the determination of the status of the application as subject to AIA 35 U.S.C. 102 and 103 (or as subject to pre-AIA 35 U.S.C. 102 and 103) is incorrect, any correction of the statutory basis (i.e., changing from AIA to pre-AIA ) for the rejection will not be considered a new ground of rejection if the prior art relied upon, and the rationale supporting the rejection, would be the same under either status.
The following is a quotation of 35 U.S.C. 103 which forms the basis for all obviousness rejections set forth in this Office action:
A patent for a claimed invention may not be obtained, notwithstanding that the claimed invention is not identically disclosed as set forth in section 102, 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 set forth in Graham, v. John Deere Co., 383 U.S.1.148 USPQ 459 (1966), that are applied 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 non-obviousness.
8. Claims 1,2,4 and 5 are rejected under 35 U.S.C. 103 as being unpatentable over a dissertation “Particle Retention in Porous Media: Applications to Water Injectivity Decline” by Kjell Erik Wennberg (hereinafter Wennberg, dissertation published on 1998) and in view of NPL “The Effect of Thermoelastic Stresses on Injection Well Fracturing” by Perkins et al. (hereinafter Perkins, IDS provided dated 1/10/2023) and further in view of a thesis “In-situ preconcentration of trace metals in natural waters and brines with analysis by flow injection atomic spectrometry” by Robert A. Nickson (hereinafter Nickson, thesis submitted on 1998).
Regarding Claim 1, Wennberg teaches a COMBINED METHOD FOR ESTIMATING THE LOSS OF INJECTIVITY IN CARBONATE RESERVOIRS, considering reactive effects and the presence of suspended solids, (Wennberg disclosed in page 5 section 2.1.1: “When such a suspension of liquid and particles is flooded through a porous medium, various mechanisms may cause a particle to stick to the pore surface at some location within the porous medium. This process is called particle deposition, particle retention or colloid retention. … These particles include clay minerals, quartz, amorphous silica, feldspar, mica, carbonates and barite. … This, due to the small size and platy structure, results in relatively large surface area compared to many other minerals. They tend to react readily and rapidly with fluids introduced to the reservoir.” In page 10 section 2.2.4: “To maintain the reservoir pressure, water is often injected into the water zone below the oil or gas bearing layers, while for sweep improvements, water needs to be injected directly into the petroleum bearing formations. Depending on in-situ stresses and well patterns, fracturing may or may not be desirable in an injection well, … Injected water thus contain both particles, oil drops, oily particles, bacteria and several dissolved chemicals, each having its own potential to reduce near-well permeability.” In page 90 section 6.1.4: “All the wells examined above showed declines in injectivity even when 5 mm filters were in place. The decline in injectivity clearly accelerates when the 5 mm filters are replaced by the 10 mm filters. … The results obtained from all 5 injection wells show that the injection of relatively clean sea water with particle sizes in the range of 1 to 5 micron and particle concentration in the range of 0.5 to 2 ppm results in significant declines in injectivity for all of the injectors studied.” Further, in page 117-118 section 1: “The deposition of small suspended particles in porous media has wide applications in solid-liquid separation, … In addition to chemical engineering where fines deposition constitutes a desirable effect, the oil industry is faced with the same type of processes in oil reservoirs. … In most cases, the dominant cause of deposition leading to formation damage is the entrainment of clay particles in the micron range, which are then deposited near the well. … For example, there are the already-mentioned clay particle entrainment and clogging appearing in reservoir rocks. Chemical reactions may occur when injected fluids react with the reservoir rock to produce precipitates which again lead to clogging.”).
Wennberg teaches characterized in that it comprises the following steps: a) Experimental method: a.1) Saturate the rock samples (plugs) with a non- reactive water - NRW; (Wennberg disclosed in page 101 section 6.2.2: “Before flooding the sea water through the core plugs, the water was sterilized with hypochlorite and filtered through membrane filters with absolute filter ratings of 1, 2, 5, 10 or 20 pm. Particle contents in the water was analyzed after the different filters were applied.” In page 90 section 6.1.4: “The results obtained from all 5 injection wells show that the injection of relatively clean sea water with particle sizes in the range of 1 to 5 micron and particle concentration in the range of 0.5 to 2 ppm results in significant declines in injectivity for all of the injectors studied.” Further, in page 117-118 section 1: “In most cases, the dominant cause of deposition leading to formation damage is the entrainment of clay particles in the micron range, which are then deposited near the well. … For example, there are the already-mentioned clay particle entrainment and clogging appearing in reservoir rocks. Chemical reactions may occur when injected fluids react with the reservoir rock to produce precipitates which again lead to clogging.”).
Wennberg teaches a.2) Gradually increase the pressure and confine the system to a pressure equal to the confinement pressure to which they were submitted in the routine tests of basic petrophysics; (For purposes of applying prior art and to facilitate compact prosecution, Examiner would construe the claim element “the system” as the system of estimating injectivity loss.
Wennberg disclosed in page 10 section 2.2.4: “Sea water injection has been for many years, and still remains, the most efficient and economic Improved Oil Recovery method used by the petroleum industry. Water is injected both for pressure maintenance and to improve sweep efficiency. To maintain the reservoir pressure, water is often injected into the water zone below the oil or gas bearing layers, while for sweep improvements, water needs to be injected directly into the petroleum bearing formations.” In page 83-84 section 6.1.1: “The goal of this water injection project was to maintain reservoir pressure in the target sand. … Five injectors were drilled and completed below the oil - water contact in the target sand. Each well has a permeability height (kh) product in excess of 53,000 md ft. (Table 6.1). Based on reservoir properties and expected injection water quality it was determined that injection rates of 50,000 barrels of water per day could be sustained in radial flow. … Because the waterflood injection rate target needed to maintain reservoir pressure was essentially the same as the facility injection capacity, …”).
Wennberg teaches a.3) After the system is pressurized, carry out a flow with the non-reactive water to check the initial water permeability and pH, under conditions of room temperature and injection flow rate of 0.8 to 2.0 ml/min; (Examiner would construe the term claim term “pH” as “a chemical measurement of the hydrogen ion concentration in a liquid, which indicates how acidic or basic (alkaline) that substance is" (according to conventional meaning in the art).
Wennberg disclosed in page 90 section 6.1.4: “All the wells examined above showed declines in injectivity even when 5 mm filters were in place. … Since a very large number of pore volumes flow through the near wellbore region the accumulation of trapped colloids builds up rapidly causing the permeability in the very near wellbore region (few inches) to decline appreciably. The effectiveness of acid treatments in improving injectivity clearly shows that the colloid induced damage is shallow … Results from the WID simulator showing the permeability as a function of distance from the wellbore are shown in Figure 6.19 for Well A09. … The penetration of the particles is seen to be only a few inches. This is consistent with the observations that acid treatments are very effective in restoring injectivity i.e. the permeability impairment is near the wellbore. The results obtained from all 5 injection wells show that the injection of relatively clean sea water with particle sizes in the range of 1 to 5 micron and particle concentration in the range of 0.5 to 2 ppm results in significant declines in injectivity for all of the injectors studied. … Contrary to our expectations when we initiated the project, relatively short half-lives, on the order of 30-90 days, were obtained when injecting relatively clean water into unfractured wells.”
Further in page 36-39 section 3.3.2: “For large particles, when straining or size exclusion is the dominant mechanism, γu will be zero, at least within the viscous flow regime. In most other cases, γu ε [0,2]. In some cases, γu = 1, ... When the grain size is increased to 4 mm, γu increases to 1. Ives (1967) found that Iwasaki’s (1937) experimental results on filtration of drinking water through sand filters gave γu = 1. … Gruesbeck and Collins (1982) flowed 8pm CaC03 particles through an unconsolidated sand pack with grains between 0.8 and 2 mm and found γu to be 1. Yoshimura (1980) injected polydis- persed kaolin suspensions into both Soma sand and glass beads. His experiments showed that γu is close to 1 in most cases.” The disclosure above “γu ε [0,2]; experiments showed that γu is close to 1 in most cases” correspond to claim limitation “injection flow rate of 0.8 to 2.0 ml/min”).
Wennberg teaches a.4) Next, inject about 900 mL of desulfated seawater (DSW) + acid + solids, where the fluid addition flow rate is 0.8 ml/min; (Under BRI and for purposes of applying prior art and to facilitate compact prosecution, Examiner would construe the claim term “desulfated seawater” as clean sea water, i.e., water without added any chemical element.
Wennberg disclosed in page 90 section 6.1.4 (2nd and 3rd para): “Results from the WID simulator showing the permeability as a function of distance from the wellbore are shown in Figure 6.19 for Well A09. Similar results are obtained for other wells. The penetration of the particles is seen to be only a few inches. This is consistent with the observations that acid treatments are very effective in restoring injectivity i.e. the permeability impairment is near the wellbore. The results obtained from all 5 injection wells show that the injection of relatively clean sea water with particle sizes in the range of 1 to 5 micron and particle concentration in the range of 0.5 to 2 ppm results in significant declines in injectivity for all of the injectors studied.” Further in page 105 Figure 6.23 shown “Filtration tests on 6 core plugs with a 2pm filter applied, the chlorine was shut off early, and the “Injected pore volumes” (or volume of fluid) shown 500 to 1000, where the permeability ratio is shown as 0.8. Therefore, this figure shown that about 900 mL of desulfated or clean water has been used to get the permeability or fluid flow rate as 0.8).
Wennberg teaches a.5) Carry out a filtration in a 0.45 μm mixed cellulose ester membrane at the point where the plug is located to determine the effective value of the suspended solids content; (Wennberg disclosed in page 85-86 section 6.1.2 (1st para): “Significant work has been done to characterize the solids content of the injection water. As shown in Figure 6.1, solids content measured at a variety of points in the facility … Particle composition was evaluated for the filtered water from various points in the injection facility through preweighed membrane filters (0.45 μm), rinsing the samples with deionized water and digesting the solids in 1:1 HN03: HBF4”. In page 101 section 6.2.2: “Before flooding the sea water through the core plugs, the water was sterilized with hypochlorite and filtered through membrane filters with absolute filter ratings of 1, 2, 5, 10 or 20 pm. Particle contents in the water was analyzed after the different filters were applied. One would of course expect the finest filters to allow only a few fine particles to pass while the coarsest filters would allow most of the particulate materials to pass.”).
Wennberg teaches a.6) Collect samples at the system outlet, after the fluid has come into contact with the rock, to monitor changes in chemical composition; (Wennberg disclosed in page 85-86 section 6.1.2 (1st para): “Significant work has been done to characterize the solids content of the injection water. As shown in Figure 6.1, solids content measured at a variety of points in the facility … Particle composition was evaluated for the filtered water from various points in the injection facility through preweighed membrane filters (0.45 μm), rinsing the samples with deionized water and digesting the solids in 1:1 HN03: HBF4. The main metal component of all samples was sodium, followed by sili con, iron, calcium, and magnesium (Figure 6.3).” In page 117-118 section 1: “For example, there are the already-mentioned clay particle entrainment and clogging appearing in reservoir rocks. Chemical reactions may occur when injected fluids react with the reservoir rock to produce precipitates which again lead to clogging. … There may also be attractive forces induced between the suspended particles causing these to flocculate. When the reservoir fluid undergoes a demixing transition caused by a temperature or pressure change near the well, immovable droplets may form which cause clogging … We should also mention here the degradation of electrical conductance of metals through the process of electromigration. This degradation is caused by drift and resettling of the metal ions induced by collisions with the electrons. Thus, this is also a migration and deposition process.”
In page 47 and 48 Figure 3.4 and 3.5 it has been shown “the suspended concentration is constant while the specific deposit increases until the critical porosity is reached at the inlet surface” and “the suspended concentration decreases with time while the specific deposit increases until the critical porosity is reached at the inlet surface”. This disclosure teaches the claim limitation “Collect samples at the system outlet”).
Wennberg teaches determine the parameter pL with data from the experimental test; (Examiner would construe “the parameter pL” as “injectivity index” according to Specification of current Application page 6 and 7. Wennberg disclosed in page 51 section 4.1: “The expression inflow performance relation (IPR) customarily is used to define the relation between surface oil rate and wellbore flowing pressure for a production well. Most widely used is the straight-line IPR which states that the rate is directly proportional to the pressure drawdown. … Similarly, the injectivity index for an injection well can be defined as I = q / Pwf - PR.” In page 62-63 section 4.6.2. (last para): “In Figure 4.8, we show how a low-permeability zone affects the total well injectivity for a fracture of 50m half-length in a formation with drainage radius 500m. If the damaged zone extends 10 cm into the formation, the permeability ratio (kd/k) must be well below 0.01 before the reduction in injectivity becomes significant. … As a comparison, a kd/k ratio of 0.01 that extends 10 cm into an openhole formation causes the injectivity of that well to decrease to 0.1 relative to an undamaged well.”).
Wennberg teaches carry out the adjustment of the open area to the flow according to the pL determined in item b.1 (comparison with the reactive and non-reactive test in the presence of suspended solids) or with the history adjustment the injectivity index of item b.1; (Examiner notes that the claim language includes two optional embodiments, a first embodiment “carry out the adjustment of the open area to the flow …” "or" a second embodiment “with the history adjustment the injectivity index”. Since "and/or" is interpreted as at least one of, only one of the two embodiments need to be taught by the reference.
Wennberg disclosed in page 88-89 section 6.1.3: “Well A-10 showed slightly higher initial injection rates of about 4,000 barrels of water per day. … During the first period of injection, an injector half-life of 64 days was obtained (Figure 6.7). An acid treatment consisting of 10% HCl was conducted which resulted in a significant increase in injectivity in the well. The injectivity was found to increase above the initial injectivity of the well suggesting that in addition to any plugging particulates from the injection water some of the completion damage had also been removed. … The injectivity immediately began to decline again as seen in Figure 6.7. … The injectivity decline profile seen is similar to that observed during Stage 1 of injection. An HCl treatment was again performed when the injectivity had dropped to below 2000 BWPD. A marked improvement in injectivity was observed with the well taking over 5000 BWPD after the acid treatment. … At this stage of injection, the injector filters were changed from 5 micron cartridge filters to 10 micron cartridge filters. This resulted in a much more rapid decline in injectivity than observed earlier. … A mud-acid treatment was performed on the well that resulted in a dramatic improvement in injectivity. The well was now taking 10,800 BWPD and had a sustained injectivity significantly above the previously attained injectivities. Clearly the use of mud acid removed the injected solids and fines that were reducing the permeability in the near wellbore region resulting in extremely high skins.”
The disclosure above “An HCl treatment was again performed when the injectivity had dropped to below 2000 BWPD. A marked improvement in injectivity was observed with the well taking over 5000 BWPD after the acid treatment; A mud-acid treatment was performed on the well that resulted in a dramatic improvement in injectivity” correspond to claim limitation “carry out the adjustment of the open area to the flow according to the pL determined or with the history adjustment the injectivity index”).
Wennberg teaches Carry out the simulation to predict the injectivity index over time, also using well parameters and operating data, in addition to the area value adjusted in item b.2. (Wennberg disclosed in page 62-63 section 4.6.2. (last para): “In Figure 4.8, we show how a low-permeability zone affects the total well injectivity for a fracture of 50m half-length in a formation with drainage radius 500m. If the damaged zone extends 10 cm into the formation, the permeability ratio (kd/k) must be well below 0.01 before the reduction in injectivity becomes significant. … As a comparison, a kd/k ratio of 0.01 that extends 10 cm into an openhole formation causes the injectivity of that well to decrease to 0.1 relative to an undamaged well.”
In page 73-74 section 5.2.1: “The author of this thesis … developed a PC- based simulator for prediction of Well Injectivity Decline (WID 3.1). … A great deal of work was carried out to improve the models and equations on which the injectivity predictions are based. … Some of the notable features of the model (WID) used to simulate the injectivity decline are: … The simulator can be used to predict injectivity decline in vertical and horizontal wells with openhole, perforated and gravel packed completions. For vertical wells, fractures and layering can also be handled.” In page 86 section 6.1.2 (last para): “According to a conventional particle trap ping model, injectivity decline should have been minimal and slow. We should have been able to maintain target injectivities for the anticipated life of the flood. To improve our understanding of the observed injectivity decline and to better predict the performance of injectors in the future, an injectivity decline simulator (WID) was used to simulate the results.”).
However, Wennberg doesn’t explicitly teach the limitation “Simulation method: b.1) Determine the parameter pL of the Perkins and Gonzalez modeling with data from the experimental test; b.2) Carry out the adjustment of the open area to the flow of the Perkins and Gonzalez modeling according to the pL determined in item b.1; b.3) Carry out the Perkins and Gonzalez simulation to predict the injectivity index over time,
Perkins teaches b) Simulation method: b.1) Determine the parameter pL of the Perkins and Gonzalez modeling with data from the experimental test; (Perkins disclosed in page 78 under ‘Abstract’: “When a cool fluid such as water is injected into a hot reservoir, a growing region of cooled rock is established around the injection well. The rock matrix within the cooled region contracts, and a thermoelastic stress field is induced around the well. … This paper considers thermoelastic stresses that would result from cooled regions of fixed thickness and of elliptical cross section. The stresses for an infinitely thick reservoir have been deduced from information available in public literature. A numerical method has been developed to calculate thermoelastic stresses induced within elliptically shaped regions of finite thickness.” This disclosure corresponds to claim element “Perkins and Gonzalez modeling”.
Further in page 81 heading ‘Opening of Secondary Fractures’: “Fig. 4 shows expected fractures for three injection conditions. For Case 1, the injection rate exceeds slightly the ability of the unfractured formation to accept the fluid. A short fracture ex tends from the wellbore; the surrounding region of cooled rock, although slightly elliptical, is nearly circular in shape. … In Case 2, the injection rate is much larger (or some fracture-face damage has occurred); thus, the fracture extends a greater distance from the well. The cooled region becomes more elongated in shape. As the cool region elongates, the thermoelastic reduction in stress parallel to the fracture exceeds the thermoelastic stress reduction perpendicular to the fracture.” The disclosure above “injection rate” in case 1 and case 2 (Fig. 4) corresponds to claim limitation “Determine the parameter pL with data from the experimental test using Perkins and Gonzalez modeling”).
Perkins teaches b.2) Carry out the adjustment of the open area to the flow of the Perkins and Gonzalez modeling according to the pL determined in item b.1; b.3) Carry out the Perkins and Gonzalez simulation to predict the injectivity index over time, (Perkins disclosed in page 81 ‘Opening of Secondary Fractures’: “Fig. 4 shows expected fractures for three injection conditions. For Case 1, the injection rate exceeds slightly the ability of the unfractured formation to accept the fluid. A short fracture extends from the wellbore; the surrounding region of cooled rock, although slightly elliptical, is nearly circular in shape. … In Case 2, the injection rate is much larger (or some fracture-face damage has occurred); thus, the fracture extends a greater distance from the well. The cooled region becomes more elongated in shape. As the cool region elongates, the thermoelastic reduction in stress parallel to the fracture exceeds the thermoelastic stress reduction perpendicular to the fracture. … Consider the case where continued injection would cause the fracture to extend further. A flatter shape of cooled region would cause the stresses parallel to the fracture to become less than those across the fracture; that is, fractures or joints perpendicular to the two-winged fracture would open preferentially. This is illustrated conceptually in Case 3 of Fig. 4. For this case, the shape of the jointed region would presumably adjust itself continually to maintain open fractures in both directions as the size of the cooled region expanded.”
The disclosures above “Consider the case where continued injection would cause the fracture to extend further; in Case 3 of Fig. 4, the shape of the jointed region would presumably adjust itself continually to maintain open fractures in both directions as the size of the cooled region expanded” correspond to claim limitation “Carry out the adjustment of the open area to the flow of the Perkins and Gonzalez modeling according to the pL (injectivity index) determined. Further the disclosure above “injection rate” in case 1 and case 2 (Fig. 4) corresponds to claim element “injectivity index”, therefore it is understood that the Perkins and Gonzalez simulation is carried out to predict the injectivity rate/index).
Wennberg and Perkins are analogous because they are related in monitoring/determining injectivity loss in reservoir in the presence of suspended solids. Before the effective filing date of the claimed invention, it would have been obvious to one of ordinary skill in the art, having the teachings of Wennberg and Perkins before him or her, to modify performing simulation to predict the injectivity index in Wennberg’s teaching, to include performing Perkins and Gonzalez simulation to predict the injectivity index in Perkins’s teaching. The suggestion/motivation for doing so would have been obvious by Perkins because “In this paper, thermoelastic stresses for cooled regions of fixed thickness and of elliptical cross section are determined, and a theory of hydraulic fracturing of injection wells is developed. Examples using typical elastic and thermal proper ties of rocks show that the injection of cool water can reduce earth stresses around injection wells substantial ly, causing them to fracture at pressures considerably lower than would be expected in the absence of the thermoelastic effect. (Perkins disclosed in page 78 heading ‘Introduction’ (right col.) and in page 84 heading ‘conclusion’ (left col.) respectively).
Nickson teaches a.7) Determine the concentration of sodium, calcium, magnesium and potassium by the atomic emission spectrometry technique (ICP-OES), and of chloride, analyzed by titration; (Nickson disclosed in page 62-63 section 1.4: “Atomic spectrometric techniques are methods of choice to apply to the analysis of these elements in natural waters, particularly when coupled to on-line preconcentration techniques, because of reduced analysis times and reduced operating costs per analysis. The primary aim of this research was to develop an on-line matrix elimination and preconcentration method which could be coupled to both ICP-MS and ICP-AES detection for the analysis of trace elements in natural waters and industrial discharges such as concentrated brines.” In page 8 Table 1.1 shown the concentration of sodium, calcium, magnesium and potassium as 10.76, 0.4119, 1.297 and 0.399, respectively. Further, in page Table 3.2 shown the “Concentrations of elements in oil field waters” for sodium, calcium, magnesium and potassium”.
In page 2 section 1.1: “Salinity is a function of the weight of total dissolved solids present in a sample of sea water and can be calculated using the equation below after the chlorinity, (CI (%o)), defined as the "mass in grams of chlorine equivalent to the mass of halogens contained in one kilogram of sea water", is determined by titration.”).
and also Nickson teaches measure the pH of the solution at the test outlet under ambient conditions; (Nickson disclosed in page 78-79 section 2.3.2.: “A univariate investigation of a number of variables in the FI procedure was carried out, with flame AAS and flame AES detection in order to determine the optimum conditions for the retention of zinc and the elimination of the matrix (as sodium). The variables examined were the effect of ammonium acetate concentration (0 - 1.0 M) on analyte retention and sodium retention, buffer pH (4.5 < pH > 6.5), nitric acid concentration (0.5-3.0 M) and sea water concentration (0-100% v/v)”. In page 79 section 2.3.3.: “As has been noted (section 2.3.2) the pH range 5-6 is optimal for the retention of transition metals on Metpac CC-1. Using a buffer concentration of 0.2 M ammonium acetate, buffer solutions were prepared with pH in the range 4.5-6.5 by the addition of suitable volumes of dilute (1 % v/v) nitric acid. Artificial sea water was acidified to pH 2 with nitric acid, prior to preconcentration (1.0 ml) which is the standard method for storing sea water samples, … The pH range for quantitative retention of the analyte is 5.2-6.0. Outside this range, retention efficiency is reduced and errors are increased. At a buffer pH of 5.0, there is a drastic reduction in the performance of the system.”).
Wennberg, Perkins and Nickson are analogous because they are related in monitoring/determining injectivity loss in reservoir in the presence of suspended solids. Before the effective filing date of the claimed invention, it would have been obvious to one of ordinary skill in the art, having the teachings of Wennberg, Perkins and Nickson before him or her, to modify determining the concentration of sodium, calcium, magnesium as particle composition evaluated for the filtered water in Wennberg’s teaching, to include determining the concentration of sodium, calcium, magnesium by the atomic emission spectrometry technique in Nickson’s teaching. The suggestion/motivation for doing so would have been obvious by Nickson because “This thesis describes the development of analytical methodologies involving on-line sample preconcentration and matrix removal for the determination of trace elements in natural waters and brines using ICP-MS and ICP AES detection for the determination of a suite of trace elements including cadmium, cobalt, copper, lead manganese, nickel, selenium and zinc. Careful selection of analytical lines for ICP-AES detection makes possible the quantification of transition elements in natural waters using an aqueous calibration rather than a time consuming standard addition process. This in-situ method has potential applications for sample preparation in the field, e.g. on a production rig. This has obvious benefits for the oil companies, notably, safety of operation is improved because concentrated acids for sample preservation do not have to be flown out to the rigs, and there is little or no analytical training required of the sampling personnel in order to obtain reliable preconcentration with a minimum of potential contamination.” (Nickson disclosed in page iii under ‘Abstract’ and 208 under bullet point (4) respectively).
Regarding Claim 2, Wennberg, Perkins and Nickson teach THE METHOD according to claim 1, Wennberg teaches characterized in that, in step a.2, the pressure is raised to 1000 psi (6.895 MPa), in steps of 500 psi (3.447 MPa). (Wennberg disclosed in page 92 Fig. 6.5 shows “Pressure and rate data for well A09” where the pressure is raised to 1000 psi).
Regarding Claim 4, Wennberg, Perkins and Nickson teach THE METHOD according to claim 1, however Wennberg and Perkins do not explicitly teach the limitation “the strong acid of step a.4 is nitric acid in the amount necessary to reach a pH of 3.0 (concentration of nitric acid in water equal to 0.001 mol/L).”
Nickson teaches characterized in that the strong acid of step a.4 is nitric acid in the amount necessary to reach a pH of 3.0 (concentration of nitric acid in water equal to 0.001 mol/L). (Nickson disclosed in page 78-79 section 2.3.2.: “A univariate investigation of a number of variables in the FI procedure was carried out, with flame AAS and flame AES detection in order to determine the optimum conditions for the retention of zinc and the elimination of the matrix (as sodium). The variables examined were the effect of ammonium acetate concentration (0 - 1.0 M) on analyte retention and sodium retention, buffer pH (4.5 < pH > 6.5), nitric acid concentration (0.5-3.0 M) and sea water concentration (0-100% v/v).” The disclosure “pH (4.5 < pH > 6.5) showing pH is less than 4.5 eventually teaches pH value is considered as 3.0 with nitric acid concentration in FI procedure).
Wennberg, Perkins and Nickson are analogous because they are related in monitoring/determining injectivity loss in reservoir in the presence of suspended solids. Before the effective filing date of the claimed invention, it would have been obvious to one of ordinary skill in the art, having the teachings of Wennberg, Perkins and Nickson before him or her, to modify determining the concentration of sodium, calcium, magnesium as particle composition evaluated for the filtered water in Wennberg’s teaching, to include determining the concentration of sodium, calcium, magnesium by the atomic emission spectrometry technique in Nickson’s teaching. The suggestion/motivation for doing so would have been obvious by Nickson because “This thesis describes the development of analytical methodologies involving on-line sample preconcentration and matrix removal for the determination of trace elements in natural waters and brines using ICP-MS and ICP AES detection for the determination of a suite of trace elements including cadmium, cobalt, copper, lead manganese, nickel, selenium and zinc. Careful selection of analytical lines for ICP-AES detection makes possible the quantification of transition elements in natural waters using an aqueous calibration rather than a time consuming standard addition process. This in-situ method has potential applications for sample preparation in the field, e.g. on a production rig. This has obvious benefits for the oil companies, notably, safety of operation is improved because concentrated acids for sample preservation do not have to be flown out to the rigs, and there is little or no analytical training required of the sampling personnel in order to obtain reliable preconcentration with a minimum of potential contamination.” (Nickson disclosed in page iii under ‘Abstract’ and 208 under bullet point (4) respectively).
Regarding Claim 5, Wennberg, Perkins and Nickson teach THE METHOD according to claim 1, Wennberg teaches characterized in that the concentration of solids added to desulfated seawater (DSW) in step a.4 is from 2 to 20 mg/L. (Wennberg disclosed in page 43 section 3.4: “the filtration coefficient is a dynamic property that changes with the specific deposit, σ. λ can increase or decrease with σ, but is commonly observed to increase during the initial stages of filtration, … the surface forces between the deposited particles and suspended particles are strongly repulsive, λ is likely to decrease with time as the collectors are progressively coated with deposited particles.” In page 46 Figure 3.3 shown variation of the filtration coefficient (λ) with specific deposit (σ) for various values of b. The value of b = +10 at x-axis, where the concentration of solids at y-axis can be seen as 2. Further it has been discussed in page 49 last para that Fointainebleau sandstone cores with permeability from 0.4-1 μm2, suspension concentrations ranged from 4-20 mg/l).
Claim 3 is rejected under 35 U.S.C. 103 as being unpatentable over Wennberg, Perkins and Nickson and in view of “NPL paper “Long-Term Comparative Evaluation of HCl/Formic Acid System Used to Stimulate Carbonate Formations at Severe Conditions in Saudi Arabia” by H.A. Nasr-El-Din et al. (hereinafter Nasr-El-Din, paper published on 2006).
Regarding Claim 3, Wennberg, Perkins and Nickson teach THE METHOD according to claim 1, however Wennberg, Perkins and Nickson do not explicitly teach the limitation “the organic acid of step a.4 is formic acid with sodium formiate, with a concentration of 0.06 mol/L and 0.34 mol/L, respectively, to achieve a pH of 4.2”.
Nasr-El-Din teaches characterized in that the organic acid of step a.4 is formic acid with sodium formiate, with a concentration of 0.06 mol/L and 0.34 mol/L, respectively, to achieve a pH of 4.2. (Nasr-El-Din disclosed in page 1 under ‘Abstract’: “This paper describes the selection, optimization and long term comparative evaluation of the gelled and in-situ cross linked HCl/formic acid systems used this type of wells. … The paper also shows for the first time a comparative long term well response to the acid stimulation of the two acid systems used in the area, showing the better performance of the in-situ crosslinked HCl/formic system over the gelled HCl/formic system.” In page 1 heading ‘Introduction’ (right col.): “The southern part of this reservoir has very low hydrogen sulfide content, less than 100 ppm, and more than 2 mol% CO2.” This disclosure corresponds to claim element organic acid with a concentration of at least 0.06 mol/L.
Further, in page 2 heading ‘Rheological Tests’ (right col.): “The fluid was prepared in the lab using a Waring® blender. Two fluids were tested. … The fluid composition for the in-situ crosslinked HCl/formic acid blend is given in Table 2. … For the spent acid tests in Figs. 1 and 2, the fluid was prepared by starting with the live test acid (28 wt% HCl or 20 wt% HCl/10 wt% formic acid with additives) and then spending the acid to pH value of 4-5 with reagent grade calcium carbonate.” This disclosure “formic acid with additives, the acid to pH value of 4-5” correspond to claim limitation “formic acid with sodium formiate to achieve a pH of 4.2”).
Wennberg, Perkins, Nickson and Nasr-El-Din are analogous because they are related in monitoring/determining injectivity loss in reservoir in the presence of suspended solids. Before the effective filing date of the claimed invention, it would have been obvious to one of ordinary skill in the art, having the teachings of Wennberg, Perkins, Nickson and Nasr-El-Din before him or her, to modify implementing acid treatment in injectivity decline plots for the water injection wells in Wennberg’s teaching, to include applying acid stimulation using formic acid to achieve pH value 4.2 in Nasr-El-Din’s teaching. The suggestion/motivation for doing so would have been obvious by Nasr-El-Din because “In all the cases the wells responded very well to the acid stimulation and the completion integrity was not compromised in a short or long term. The paper also shows for the first time a comparative long term well response to the acid stimulation of the two acid systems used in the area, showing the better performance of the in-situ crosslinked HCl/formic system over the gelled HCl/formic system. This acid system is also based on HCl/formic and contains a synthetic polymer, a cross-linker, and a breaker, and other acid additives. This acid cross-links over a narrow pH range (2-4) where its viscosity increases by several order of magnitude. (Nasr-El-Din disclosed in page 1 and 2 heading ‘Abstract’ and ‘Introduction’).
Claim 6 is rejected under 35 U.S.C. 103 as being unpatentable over Wennberg, Perkins and Nickson and in view of a dissertation “Carbonaceous Nanosized Surfactant Carriers and Oil-Induced Viscoelastic Fluid for Potential EOR Applications” by C Chen (dissertation published on 2018).
Regarding Claim 6, Wennberg, Perkins and Nickson teach THE METHOD according to claim 5, however Wennberg, Perkins and Nickson do not explicitly teach the limitation “the solids are a pulverized sandstone with a size between 45 and 75 μm”.
Chen teaches characterized in that the solids are a pulverized sandstone with a size between 45 and 75 μm. (Chen disclosed in page 18 section iii): “For the sand pack tests, Ottawa sand and crushed Berea sandstone were used. … Ottawa sand size distribution is between 75 μm and 300 μm … Crushed Berea was provided by Stim-Lab (Duncan, OK) with particle size ranging between 75 μm and 250 μm.”).
Wennberg, Perkins, Nickson and Chen are analogous art because they are related in monitoring/determining injectivity loss in reservoir. Before the effective filing date of the claimed invention, it would have been obvious to one of ordinary skill in the art, having the teachings of Wennberg, Perkins, Nickson and Chen, before him or her, to modify determining the evolution of near wellbore permeability and water injectivity in the presence of suspended solids in Wennberg’s teaching, to include solids as pulverized sandstone in Chen’s teaching. The suggestion/motivation for doing so would have been obvious by Chen because “This work deals with a detailed investigation on the physicochemical characterization of alpha olefin sulfonate (AOS). Due to its unique molecular structure, AOS is an effective emulsifier and outstanding detergent, which has high compatibility with hard water (superior than SDBS and SDS) as well as good wetting, foaming, and thermal stability properties. All these features combined with low adsorption on sandstone enabling AOS to be an excellent candidate as foam booster in enhanced oil recovery. (Chen disclosed in page 78 last para).
Conclusion
9. The prior arts made of record and not relied upon is considered pertinent to applicant's disclosure. A thesis “Injectivity Decline in Ultra-Filtered Water Flooding of High Permeability Sandstone Reservoirs” By Ali Murtaza investigated experimentally injectivity decline by ultra-filtered water injection. To mimic ultra-filtered water, spherical silica nanoparticles of 120 nm diameter were used as dispersed particles in the injected water. First, stability study of nanoparticle colloid was carried out by varying nanoparticle concentration, brine compositions and pH. Hydrodynamic size and zeta potential measurements showed that there exists a salinity and pH range in which nanoparticle colloid remain within the expected size range. Experimental results showed about 50 to 70 percent less injectivity decline compared to micron size suspended particles. Furthermore, results showed that external filter cake does not form by nanoparticle flow through porous media if the injection fluid’s pH and salinity are kept within a defined range obtained from stability study. Only deep bed filtration takes place where three main retention mechanisms dominate i.e. surface deposition, plugging and entrainment. Finally, a numerical model is presented in this study that describes deep bed filtration taking into account observed retention mechanisms. Model results are found to be in good agreement with experimental results.
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/NUPUR DEBNATH/Examiner, Art Unit 2186
/RENEE D CHAVEZ/Supervisory Patent Examiner, Art Unit 2186
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