Using nuclear magnetic resonance for operating hydrogen storage in partially depleted shale gas reservoirs

Abstract

A method of determining a ratio of hydrogen to methane produced from a partially depleted shale gas reservoir comprising an organic nanopore system, an inorganic pore system, and a micro-fracture system, and housing stored hydrogen, comprises: obtaining a core sample from the reservoir, and subjecting the core sample to 1H Nuclear Magnetic Resonance (NMR) testing to obtain respective T2 and T1-T2 relaxation times for methane and for hydrogen in each one of the organic nanopore system, the inorganic pore system, and the fracture system.

Description

[0001] USING NUCLEAR MAGNETIC RESONANCE FOR OPERATING HYDROGEN STORAGE IN PARTIALLY DEPLETED SHALE GAS RESERVOIRS

[0002] FIELD OF THE INVENTION

[0003] The present invention relates to the use of nuclear magnetic resonance (NMR) to quantify the concentrations of hydrogen and methane in various pore systems during reservoir operation of hydrogen storage in a partially depleted shale gas reservoir.

[0004] BACKGROUND

[0005] As the transition towards renewable energy sources intensifies, hydrogen emerges as a promising energy carrier. The use of partially depleted shale gas reservoirs as storage units for hydrogen has become increasingly popular. Consequently, a precise and efficient technique is needed to determine the ratio of extracted hydrogen to residual methane during production, as well as gas flow rate and hydrogen recovery efficiency for both safety and optimal energy yield.

[0006] The teachings of US Patent No. 11,680,466, published on June 20, 2023, are incorporated herein by reference in their entirety.

[0007] SUMMARY OF THE INVENTION

[0008] A method is disclosed, according to embodiments, for operating a partially depleted shale gas reservoir. The method comprises: (a) preparing a core sample acquired from the gas reservoir, the preparing comprising (i) receiving the core sample in a core-sample holder, (ii) introducing, into the core-sample holder, a methane-containing gas so as to pressurize the core sample to a first pressure, and (iii) introducing, into the core-sample holder, a hydrogen-containing gas so as to pressurize the core sample to a second pressure, the second pressure being higher than the first pressure. The method further comprises: (b) obtaining nuclear magnetic resonance (NMR) measurements of the core sample at the second pressure, the NMR measurements including Ti and T2 relaxation times; and (c) determining, based on the obtained NMR measurements, a projected ratio of hydrogen to methane in a gas recoverable from the gas reservoir at a target time when the gas reservoir is characterized as having had a methane-containing gas recovered therefrom until a downhole pressure reached a residual-methane pressure substantially equal to the first pressure, and subsequently having had a hydrogen-containing gas injected thereinto until the downhole pressure reached a total target pressure substantially equal to the second pressure; and

[0009] In some embodiments, it can be that (i) the method additionally comprises, before the determining: obtaining a gas chromatographic (GC) analysis of methane and hydrogen gas molecules effluent from the core sample, and (ii) the determining is additionally based on the obtained GC analysis.

[0010] In some embodiments, the method can additionally comprise: based on the determining, performing at least one gas-reservoir operation selected from: (i) further recovering methane-containing gas from the gas reservoir until the downwell pressure reaches the residual-methane pressure, (ii) injecting a hydrogen-containing gas into the gas reservoir at least until the downhole pressure reaches the total target pressure, and (iii) recovering a gas comprising methane and hydrogen molecules from the gas reservoir, the hydrogen molecules accounting for a majority of a molar weight of the recovered gas. In some embodiments, the performing can include performing both the injecting of the hydrogen-containing gas and the further recovering of the gas comprising methane and hydrogen molecules. In some embodiments, the performing can additionally include, before the injecting, the further recovering of the methane- containing gas. In some embodiments, the further recovered methane-containing gas can be substantially without hydrogen.

[0011] In some embodiments, the determining can include determining a pore distribution of the core sample, and the determined pore distribution can include a fraction of meso-pores and macro-pores occupied by the hydrogen molecules, and a fraction of micro pores and kerogen pores occupied by the methane molecules.

[0012] In some embodiments, the determining can include projecting a hydrogenpermeability projection of the gas reservoir at the target time. In some embodiments, the determining of the hydrogen-permeability projection can include applying a modified Carman-Kozeny permeability mode to the determined pore distribution of the core sample.

[0013] A method is disclosed, according to embodiments, for determining a ratio of hydrogen to methane produced from a partially depleted shale gas reservoir housing stored hydrogen. The reservoir comprises an organic nanopore system, an inorganic pore system, and a micro-fracture system. The method comprises: (a) obtaining a core sample from the reservoir; and (b) subjecting the core sample to 1H Nuclear Magnetic Resonance (NMR) testing to obtain respective T2 and T1-T2 relaxation times for methane and for hydrogen in each one of the organic nanopore system, the inorganic pore system, and the fracture system.

[0014] In some embodiments, the method can additionally comprise: determining a hydrogen-to-methane ratio based on the respective T2 and T1-T2 relaxation times.

[0015] In some embodiments, the method can additionally comprise: (i) subjecting one or more gas samples obtained from the shale gas reservoir to NMR testing and / or (ii) comparing results of the NMR testing on the gas samples with results of the NMR testing of the core sample.

[0016] In some embodiments, the ratio of hydrogen to methane can be calculated using the formula:

[0017] In some embodiments, the method can additionally comprise: defining or changing a hydrogen extraction strategy based on the determined hydrogen-to- methane ratio.

[0018] In some embodiments, the method can additionally comprise: predicting safety and efficiency of hydrogen extraction from the shale gas reservoir based on methane co-production levels determined from NMR testing of one or more core samples.

[0019] In some embodiments, the method can additionally comprise: assessing hydrogen-storage efficiency in the shale gas reservoir based on a result of quantifying residual methane after extraction of hydrogen from the shale gas reservoir. In some embodiments, the testing can be carried out using a system comprising an NMR instrument operating at a Larmor frequency of at least 20 Mhz. In some embodiments, the system can be configured to operate at interecho times of under 10 microseconds. In some embodiments, the system can comprise a first set of NMR instrument components configured to operate at interecho times between 50 and 100 microseconds, and a second set of NMR instrument components configured to operate at interecho times under 10 microseconds. In some embodiments, can be carried out using a system comprising an NMR instrument adapted to discriminate between hydrogen and methane based on their distinct T2 relaxation times in different pore systems. In some embodiments, the system can be configured to access or operate data analysis software that automatically calculates a hydrogen-to-methane ratio based on NMR measurements. In some embodiments, the system can be configured to access or include a database containing T2 relaxation times of various gases in different pore systems. In some embodiments, the testing can be carried out using a system comprising an NMR instrument configured to use two different pulse sequences, the two pulse sequences including a first pulse sequence for measuring T2 relaxation times and a second pulse sequence for T1-T2 relaxation times.

[0020] In some embodiments, the method can additionally comprise: subjecting gas produced by the shale gas reservoir to periodic NMR analysis to monitor a hydrogen- to-methane ratio.

[0021] In some embodiments, the method can additionally comprise: obtaining a GC analysis of methane and hydrogen gas molecules effluent from the one or more core samples.

[0022] In some embodiments, the method can additionally comprise: changing a hydrogen storage strategy in a shale gas reservoir based on the determined hydrogen- to-methane ratio.

[0023] In some embodiments, the method can additionally comprise: determining a hydrogen gas density inside at least one of the microfracture system and the inorganic pore system using respective P2 and P3 peaks of the obtained T2 relaxation times. BRIEF DESCRIPTION OF THE DRAWINGS

[0024] The invention will now be described further, by way of example, with reference to the accompanying drawings, in which the dimensions of components and features shown in the figures are chosen for convenience and clarity of presentation and not necessarily to scale. In the drawings:

[0025] Fig. 1 shows a schematic block diagram of a system for performing1H NMR testing a core sample from a gas shale reservoir to obtain relaxation measurements for methane and hydrogen gas on, according to embodiments of the present invention.

[0026] Fig. 2A schematically illustrates an organic nanopore with adsorbed and free methane molecules, according to embodiments of the present invention.

[0027] Fig. 2B shows the nanopore of Fig. 2A after partial depletion of methane and resaturation with hydrogen gas, according to embodiments of the present invention.

[0028] Fig. 2C schematically illustrates a mesopore or macropore with surface relaxation of the gas molecules, according to embodiments of the present invention.

[0029] Fig. 3 shows an idealized graph of an exemplary1H NMR T2 relaxation spectrum of the core sample when fully saturated with methane, according to embodiments of the present invention.

[0030] Fig. 4 shows an idealized graph of an exemplary1H NMR T2 relaxation spectrum of the core sample when partially depleted of methane, according to embodiments of the present invention.

[0031] Fig. 5 shows an idealized graph of an exemplary1H NMR T2 relaxation spectrum of the core sample when partially depleted of methane and repressurized with hydrogen, according to embodiments of the present invention.

[0032] Fig. 6 shows an idealized graph of an exemplary1H NMR T1-T2 relaxation spectrum of the core sample when partially depleted of methane and repressurized with hydrogen, according to embodiments of the present invention.

[0033] Fig. 7 shows a schematic graph of an increase in H2 / CH4 ratio as a function of the number of H2 pressurization-depressurization cycles, according to embodiments of the present invention. Figs. 8A-C show flowcharts of methods and method steps for operating a partially depleted shale gas reservoir, according to embodiments of the present invention.

[0034] Figs. 9 A- J show flowcharts of methods and method steps for determining a ratio of hydrogen to methane produced from a partially depleted shale gas reservoir housing stored hydrogen, according to embodiments of the present invention.

[0035] DETAILED DESCRIPTION OF THE ILLUSTRATED EMBODIMENTS

[0036] The invention is herein described, by way of example only, with reference to the accompanying drawings. With specific reference now to the drawings in detail, it is stressed that the particulars shown are by way of example and for purposes of illustrative discussion of the preferred embodiments of the present invention only, and are presented in the cause of providing what is believed to be the most useful and readily understood description of the principles and conceptual aspects of the invention. In this regard, no attempt is made to show structural details of the invention in more detail than is necessary for a fundamental understanding of the invention, the description taken with the drawings making apparent to those skilled in the art how the several forms of the invention may be embodied in practice.

[0037] Embodiments of the present invention relate to methods and systems for utilizing nuclear magnetic resonance (NMR) in attaining physical information about a partially depleted shale gas reservoir used for hydrogen gas storage or under consideration for future storage of hydrogen gas. In particular, the NMR testing can include1H nuclear magnetic resonance testing, and any reference to ‘NMR’ testing in this disclosure and in the claims appended thereto refers to1H nuclear magnetic resonance testing unless otherwise specified. In the embodiments, the NMR testing is performed on core samples obtained from, e.g., extracted from, the partially depleted shale gas reservoir. The term ‘partially-depleted’ indicates that the shale gas reservoir is being exploited or has been exploited for gas production (equivalently: gas extraction); the descriptor ‘partially’ is not limiting but merely reflects, inter alia, common practice wherein some natural gas, e.g., methane gas, remains in the reservoir even at end of commercial life of the reservoir. The physical information attained through the NMR testing can include Ti and T1-T2 relaxation times of hydrogen molecules and of methane molecules. Unless otherwise specified, ‘hydrogen’ and ‘H2’ are synonymous throughout this disclosure, as are ‘methane’ and ‘CH4’. In embodiments, the relaxation times can be used to ascertain the ratio of hydrogen to methane produced from a partially depleted shale gas reservoir used for hydrogen storage. Using the distinctive T2 and T1-T2 relaxation times of hydrogen and methane gases in specific pore systems, this method provides data on the composition, flow rate, and recovery efficiency of produced gases from each pore system under different reservoir conditions. Using this data, a numerical simulation program can be developed for optimizing production strategies. The foregoing improvements offer an innovative approach for effective and safe reservoir operation of hydrogen stored in partially depleted shale gas reservoirs by using the capabilities of NMR to measure the composition, flow rate, and recovery efficiency of the produced gases under different reservoir conditions.

[0038] While H2 and CH4 molecules are mentioned in all of the examples hereinbelow, CD4 can be used in place of CH4 in the embodiments. CD4 is invisible toJH NMR and thus there is no overlap between the deuterated methane and the hydrogen. The use of CD4 can be done with an identical core sample to the one where CH4 is utilized. Similarly, HD may be used instead of H2 in the embodiments. HD has a longer relaxation time than H2 but shorter than CH4.

[0039] In a first example of performing a method according to some embodiments, core samples are extracted from a partially depleted gas shale reservoir designated for hydrogen storage. The core samples are subjected to1H NMR relaxation measurements to ascertain the T2 and T1-T2 relaxation times for both methane and hydrogen in three different pore systems: organic nanopores, inorganic mesopores and macropores, and microfractures.

[0040] According to the first example, the following results are obtained from the NMR testing:

[0041] For methane residual in the organic nanopore system: T2 of approximately 50 microseconds and T1-T2 of approximately 100 microseconds.

[0042] For methane residual in the inorganic pore system: T2 of 1 to 20 milliseconds and T1-T2 of approximately 7 milliseconds For methane present in the fracture system: T2 of approximately 1 second and T1-T2 of 1 to 5 seconds.

[0043] For hydrogen stored within the organic nanopore system: T2 of approximately 200 microseconds and T1-T2 of approximately 30 microseconds.

[0044] For hydrogen stored within the inorganic pore system: T2 of 1 to 20 milliseconds and T1-T2 of approximately 20 milliseconds.

[0045] For hydrogen present in the microfracture system: T2 of approximately 25 milliseconds and T1-T2 of 1-5 milliseconds.

[0046] The T2 and T1-T2JH NMR relaxation spectra are used to determine the hydrogen to methane ratio in each pore system and thus the JfeCFU ratio in the produced gas, the hydrogen and methane flow rates and total hydrogen and methane production and recovery efficiency. The H2:CH4 ratio is calculated as hydrogen signal / HI(H2) / methane signal / HI(CH4) in each of the three pore systems, namely organic nanopores, inorganic mesopores, and microfractures. HI is the hydrogen index, which depends on pressure and temperature under reservoir conditions. Typical values are HImethane - 0.2 - 0.4 and H hydrogen - 0.08 - 0.16. The low HI for hydrogen can make using a 20 MHz1H NMR relaxometer desirable for improved signal-to-noise ratio.

[0047] The gas composition and flow rate, along with total hydrogen and methane production, are correlated with the NMR measurements using a mass flow meter, a hydrogen concentration meter, and a gas chromatograph.

[0048] The derived H2:CH4 ratios for the three different pore systems are used, according to the first example, to assess the efficiency of hydrogen extraction and to determine the level of methane co-production using a numerical simulation program that matches the gas flow from each pore system. The numerical simulation program includes a molecular simulation that matches the observed NMR data during production from the organic nanopores and their coupling to the mesopores and microfractures. This numerical simulation program assists in optimizing production strategies and ensuring safety during production. According to embodiments, the physical information derived from the NMR testing and subsequent steps enables reservoir managers to fine-tune their extraction methods, ensuring maximum hydrogen yield with minimal methane co-production, addition, the requirements may be met to stay below the maximum percentage of hydrogen transported in existing gas pipelines, and the sizing of the surface facilities for separation of methane from hydrogen may be optimized. Further, by promptly determining the hydrogen-to-methane ratio, potential hazards due to flammability and explosive limits can be addressed, ensuring safe hydrogen production. In

[0049] Referring now to the figures, Fig. 1 shows, in a schematic block diagram, a non-limiting example of a system comprising an NMR apparatus, also called an NMR relaxometer, and associated equipment according to embodiments.

[0050] AJH NMR relaxometer configured to measure relaxation times of H2 and CH4 in the core sample is selected to operate at about 20 MHz Larmor frequency. In some embodiments, the frequency can be as low as 12 MHz, 20 MHz, or as high as 40 MHz. The higher Larmor frequencies, e.g., from 20 MHz and up, provide a higher signal-to-noise ratio, which can be of benefit in distinguishing a low signal intensity from hydrogen gas. Also, the higher Larmor frequencies enable shorter RF pulse interecho times, so that more of the NMR signal in the nanopores is detected. The higher Larmor frequencies also enhance the T1-T2 ratio, improving discrimination between fluid types. However, the higher magnetic field strengths increase the internal magnetic field gradients which can shorten T2. Thus, in embodiments, an optimal value of the1H Larmor frequency is about 20 MHz. Suitable NMR relaxometers are commercially available from Oxford Instruments, UK, Bruker Instruments, Billerica, MA, USA, or Zealax, Inc., The Woodlands, TX.

[0051] In embodiments, the cylindrical core samples are drilled parallel to the natural fractures in the shale gas reservoir and can be about 1” -1.5” diameter by 1 inch long. The core sample is mounted inside the pressure vessel and sleeved with shrink-fit Teflon and / or Viton to separate the confining fluid from the core. Fluorinert is a typical confining fluid which does not contain protons. The confining fluid is pressurized by a pump (not shown). The pressure vessel may be constructed of titanium with an interior RF coil, or of zirconia ceramic or epoxy fiberglass, with an exterior RF coil. The temperature-stabilized magnets are located outside the pressure vessel.

[0052] The relatively large-size core samples described above can cause the RF interecho time to be limited to a minimum time of about 60 microseconds. Some of the signal from the organic nanopores relaxes faster than this and is therefore not detected. To capture this fast-relaxing signal, a smaller core sample size of approximately 10 mm may be used in a smaller diameter pressure cell that does not include overburden pressure. Such a 20 MHz1H NMR relaxometer is available from Zealax, Inc.. (The Woodlands,, TX) and a zirconia ceramic pressure cell available from Daedalus Innovations (Aston, PA). This second system has an interecho time under 10 microseconds, e.g., 7 microseconds, and can use a solid echo pulse sequence capable of detecting all the signal from the adsorbed fluids in the organic nanopores, albeit with a lower signal-to-noise ratio and an absence of overburden stress. However, the adsorbed fluids in the nanopores do not change with overburden stress. Thus, a combination of both NMR systems can measure all the adsorbed fluids and accurately determine the fluids in mesopores and microfractures.

[0053] Fig. 1 also shows gas cylinders containing methane and hydrogen. In other examples, the methane and / or hydrogen gases can also be delivered via separate ISCO pumps and accumulators. Boyle’s-law measurement of total pore volume can be made using helium gas and a reference pressure cell, as is known in the art.

[0054] The gas flow from the sample cell is measured using a digital mass flow meter and hydrogen concentration meter, and periodically sampled by the gas chromatograph and mass spectrometer for H2 / CH4 ratio to convert mass flow to flow of the individual gases. Cumulative gas effluent volume is measured by a gas volume collection system.

[0055] A data acquisition system records the NMR data, digital flow meter, gas chromatograph, gas volume collection, pressure and temperature transducers, and pressure control valves (PCVs). The data acquisition system may be a PC or a SCADA system.

[0056] Reference is now made to Figs. 2A, 2B and 2C. Organic -rich gas shales typically contain pore systems, where gases such as methane and hydrogen may be stored, that are commonly classified as three different types of pore systems. Organic nanopores, illustrated schematically in Figs. 2 A and 2B, are typically 2 to 5 nm in diameter, and are formed as the kerogen undergoes maturation due to time and temperature and expels liquid and then gaseous hydrocarbons. Methane is adsorbed on the walls of the kerogen nanopore and occupies the interior of the nanopore, as shown in Fig. 2A. Fig. 2B shows the same nanopore after partial depletion of methane, and hydrogen molecules re-saturating the interior of the nanopore. Inorganic mesopores, illustrated schematically in Fig. 2C, are typically 2 to 50 nm in diameter, and initially store most of the methane in the shale gas reservoir. The methane is not adsorbed on the inorganic minerals, and the flow from these pores depends on pressure gradient corrected for gas slippage. Microfractures are typically 10 to 100 microns in diameter and are formed during the expulsion of the liquids and gases from the rock matrix during the maturation of the organic matter. The microfractures have the highest flow rate and are the first to be depleted, followed by the inorganic mesopores, and finally the organic nanopores.

[0057] In porous media such as gas shales, the NMR relaxation is caused by the bulk relaxation of the fluid shortened by surface relaxation and adsorption on the kerogen surfaces of organic nanopores.

[0058] In the following discussion: is the measured longitudinal (or spin-lattice) relaxation time of the pore fluid as measured by an inversion recovery or saturation recovery pulse sequence, is the relaxation time of the pore fluid as it would be measured in a container so large that container effects would be negligible, and Tlsurface 'sthe relaxation time of the pore fluid resulting from surface relaxation. The relationship among these three values is expressed as:

[0059] T2is the transverse (or spin-spin) relaxation time of the pore fluid as measured by a CPMG (Carr-Purcell-Meiboom-Gill) pulse sequence, T2bUik isthe T2relaxation time of the pore fluid as it would be measured in a container so large that container effects would be negligible, and T2Surfaceis the T2 relaxation time of the pore fluid resulting from surface relaxation. The relationship of these three values is expressed as:

[0060] As disclosed hereinbelow, there is a difference between the NMR relaxation of methane and hydrogen gases.

[0061] For methane, Tlbuik methane= 2.5 X 104

[0062] T'lbulk, methane =Tlbulk, methane where pgis the gas density in g / cm3, TKis the temperature in °K, and Tlbulk methaneand T2bulk methanehave units of seconds.

[0063] For hydrogen, TbuikjiydrOgen = 0.125 X 10 (Pg,amagats')an(i sthe gas density in amagats and Tlbulk fiydrogenand T2bulk hydrogenhave units of seconds.

[0064] Figs. 3 and 4 show exemplary schematic plots of signal amplitude vs. T2 relaxation times for CH4 molecules, with the x-axis (T2 relaxation times) emulating a logarithmic scale. The plot of Fig. 3 shows three peaks Pl, P2 and P3, corresponding to the three pore systems - organic micropores, inorganic mesopores and macropores, and microfractures respectively - in a core sample saturated with methane at 200 amagat. Fig. 4 shows a similar plot for the core sample after partial depletion of the methane. Fig. 5 shows another similar plot for the core sample, after repressurization with hydrogen to 200 amagat.

[0065] Methane and hydrogen gases have different magnitudes of Ti relaxation and different temperature dependencies. Unlike methane, Tlbuikhydrogen isindependent of temperature between 100°K and 400°K. This enables determination of the hydrogen gas density inside the microfractures and mesopores from the T2 of the P2 and P3 peaks.

[0066] The Ti relaxation of fluids confined in tight spaces such as nanopores is increased at higher Larmor frequencies, e.g., at least 20MHz, as described above. This increase in Ti improves the ability to separate fluid types in confined pore spaces from fluids in free pore spaces. The T1 / T2 ratio increases significantly for fluids in tightly confined pore spaces and may be as high as 100 or higher for methane gas in organic nanopores. Fig. 6 shows the plot of Fig. 5, emulating the partly depleted reservoir having hydrogen stored therewithin, together with a Ti vs. T2 plot and examples of T1 / T2 ratios.

[0067] The kinetic diameter of hydrogen gas molecules is 289 picometers while the kinetic diameter of methane gas molecules is 380 picometers. Thus, the mean free path for H2 at 200 atm and 50°C is 8.71 x 10"7mm and the mean free path for CH4 at 200 atm and 50°C is 6.62 x 10"7mm. Therefore, hydrogen gas confined in the mesopores (of the inorganic pore system) will have a higher T1 / T2 ratio than methane confined in the mesopores, as evidenced in Fig. 6 at the P2 peak.

[0068] Similarly, the examples in Fig. 6 indicate that the hydrogen gas in organic nanopores (Pl peaks) will have a different T1 / T2 ratio than methane confined in the organic nanopores, and methane adsorbed on the kerogen surfaces. However, methane is adsorbed on the kerogen surfaces preferentially to hydrogen, so the T2 of methane in the organic nanopores will be shorter than hydrogen in the center of the organic nanopores. Additionally, hydrogen has about 3 times the diffusivity of methane, so hydrogen is more mobile in the organic nanopores and may have a lower T1 / T2 ratio than methane in the organic nanopores.

[0069] The surface relaxivity p is a measure of the capability of a surface to cause the protons to relax. The surface relaxivity can be different for Ti and T2 relaxation mechanisms. The Ti relaxivity may be increased significantly relative to T2 for fluids in tightly confined spaces or for molecules adsorbed on surface. The T2 surface relaxivity for methane and hydrogen may be about equal but may be unequal on some surfaces, p2,methane~0.0167 cm / s and p2,hydrogen~0.0167 cm / s. The range of surface relaxivity can be 0.03-0.003 cm / s in mesopores and macropores depending on the surface minerology, wettability and ferromagnetic impurities.

[0070] Referring now to Fig. 8A, a method is disclosed for operating a partially depleted shale gas reservoir. As illustrated by the flow chart in Fig. 8A, the method comprises at least the 3 method steps SOI, S02 and S03.

[0071] Step SOI includes preparing a core sample acquired from the partially depleted shale gas reservoir. This can include procuring one or more representative core samples. A non-limiting example of an appropriate core sample size is a cylinder with a diameter of 1-1.5 inches and a height (length) of 1 inch. According to the method, the preparing comprises receiving the core sample in a core-sample holder.

[0072] It can be desirable to optionally measure BET absorption isotherms, Rockeval for TOC and organic maturity, total porosity, and permeability, e.g., using a Coreval 30 by Vinci Technologies, on the samples and endpieces. It can also be desirable to obtain SEM and BSE SEM images to visualize the pore systems and estimate average pore sizes. It can also be desirable to remove residual water from the core by drying it, e.g., at 120°C until weight is stable, and measure NMR on the dry core to verify absence of water signal in the T2 relaxation spectrum. This can be used as a baseline to subtract from later measurements.

[0073] Step SOI further includes introducing, into the core-sample holder, a methane- containing gas to pressurize the core sample to a first pressure. In a non-limiting example, the first pressure is equivalent to the reservoir pressure after partial depletion of the methane. In some embodiments, the core sample is pressurized directly to the first pressure.

[0074] In some embodiments, the core is first pressurized to the equivalent of the initial reservoir pressure, i.e., the pressure before initial production of methane. In such embodiments, the core is pressurized by applying overburden pressure using a pump with Fluorinert and applying pore pressure with methane to match reservoir conditions of pore pressure, overburden stress, and reservoir temperature. Pressurization can be done in small differential pressure steps to keep the fractures open. It can be desirable to measure T2 and T1-T2 NMR relaxation for methane, e.g., at 20 MHz, at the equivalent of initial reservoir pressure, obtaining amplitudes under the peaks for Pl, P2, and P3 and dividing by HI to obtain PU1 (the amplitude equivalent for water at HI=I ). SEM and BSE SEM images can be compared to estimate inorganic pore sizes and to measure surface relaxivity to methane. The1H NMR T2 and T1-T2 relaxation spectra can be segmented to determine Pl (the amplitude of the signal from organic nanopores), P2 (the amplitude from inorganic mesopores), and P3 (the amplitude from microfractures) for methane at initial reservoir pressure and temperature conditions. Some of the methane signal from the organic nanopores may relax at T2 times shorter than the 60 microsecond interecho spacing. It can further be desirable to reduce pressure of the methane to a depleted level, i.e., to the first pressure, allowing the core to desorb. The methane mass flow rate and cumulative flow during the desorption stage can be measured. In addition, T2 NMR relaxation during depletion can be measured, and changes in Pl, P2, and P3 can be correlated with the methane flow rate.

[0075] In another embodiment, the dry core may be first saturated with hydrogen gas to determine Pl, P2 and P3 peaks for pure hydrogen. The core may then be completely desorbed of hydrogen to continue carrying out the method.

[0076] Step SOI also includes introducing, into the core-sample holder, a hydrogencontaining gas so as to pressurize the core sample to a second pressure higher than the first pressure. This is preferably done after allowing the core sample to equilibrate at the first pressure. In some embodiments, the second pressure is equivalent to the initial reservoir pressure, and the temperature of the core pressure vessel is set to emulate the corresponding reservoir temperature.

[0077] Before carrying out Step S02 it can be desirable to measure the volume of hydrogen injected into the core and to allow the hydrogen to equilibrate in the three pore systems.

[0078] Step S02 includes obtaining NMR measurements of the core sample at the second pressure, including T2 andTi-T2 relaxation times.

[0079] In embodiments, Pl, P2 and P3 peaks are computed for hydrogen gas and methane gas, and further divided by HI, e.g., by segmenting the T2 and T1-T2 relaxation spectra into regions for hydrogen and methane. Where the hydrogen and methane spectra potentially overlap, such as in the T2 inorganic mesopores (as shown in Fig. 5), the hydrogen component can be computed from the T1-T2 plot or from an increase in signal in the overlap part of the T2 relaxation spectrum because the methane signal stays constant. SEM and BSE SEM images can be compared to estimate inorganic pore size and to measure surface relaxivity to hydrogen.

[0080] Step S03 includes determining, based on the NMR measurements obtained in Step S02, a projected ratio of hydrogen to methane in a gas recoverable from the gas reservoir at a target time when the gas reservoir is characterized as having had a methane-containing gas recovered therefrom until a downhole pressure reached a residual-methane pressure substantially equal to the first pressure, and subsequently having had a hydrogen-containing gas injected thereinto until the downhole pressure reached a total target pressure substantially equal to the second pressure.

[0081] In some embodiments, the determining includes determining a pore distribution of the core sample, and the determined pore distribution includes a fraction of meso-pores and macro-pores occupied by the hydrogen molecules, and a fraction of micro pores and kerogen pores (organic nanopores) occupied by the methane molecules. In some embodiments, the determining includes projecting a hydrogen-permeability projection of the gas reservoir at the target time. In some embodiments, the determining of the hydrogen-permeability projection includes applying a modified Carman-Kozeny permeability mode to the determined pore distribution of the core sample.

[0082] In embodiments, the H2:CH4 ratio is computed for each of the distinct pore systems evidenced by the Pl, P2 and P3 peaks. Initial production of gas recovered from the gas reservoir at the target time will be from the microfracture system, and thus the produced gases will have the H2:CH4 ratio measured for the P3 pore system. Later production will come from the P2 pore system and have the H2:CH4 ratio of the P2 pore system (mesopores and macropores). Finally, Knudsen diffusion will occur from the Pl pore system (organic nanopores). Referring again to Fig. 2B, hydrogen has about 3 times the diffusivity as methane, so the hydrogen in the center of the organic nanopore will be recovered before the adsorbed methane on the kerogen surface.

[0083] In some embodiments, as illustrated in Fig. 8B, the method additionally includes Step S04. As shown in Fig. 8B, Step S04 includes obtaining a gas chromatographic (GC) analysis of methane and hydrogen gas molecules effluent from the core sample before completing Step S03. In such embodiments, the determining of Step S03 is additionally based on the GC analysis.

[0084] In embodiments, hydrogen gas is depleted from the core sample by lowering the pore pressure to a predetermined level. Mass flow rate and hydrogen concentration versus time during hydrogen depletion can be measured. The H2:CH4 ratio may be sampled periodically by gas chromatography or by mass spectroscopy. Changes in Pl, P2 and P3 peaks are correlated with the mass flow rate and with H2:CH4 ratios. The gas composition and flow rate, and total hydrogen and total methane production, can be correlated with the NMR measurements using the mass flow meter, hydrogen concentration meter and / or gas chromatograph.

[0085] In some embodiments, Step SOI, starting with the introducing of the hydrogen gas into the core-sample holder, Step S02, and Step S03 are repeated, and the computed H2 / CH4 ratio increasing with each ensuing cycle, as illustrated in Fig. 7.

[0086] In some embodiments, as illustrated in Fig. 8C, the method additionally includes Step S05. As shown in Fig. 8C, Step S05 includes performing at least one gas-reservoir operation selected from the following: (a) further recovering methane- containing gas from the gas reservoir until the downwell pressure reaches the residual-methane pressure, (b) injecting a hydrogen-containing gas into the gas reservoir at least until the downhole pressure reaches the total target pressure, and (c) recovering a gas comprising methane and hydrogen molecules from the gas reservoir, the hydrogen molecules accounting for a majority of a molar weight of the recovered gas. In some embodiments, the further recovered methane-containing gas is recovered substantially without hydrogen.

[0087] In some embodiments, the performing of Step S05 includes performing both the injecting of the hydrogen-containing gas and the further recovering of the gas comprising methane and hydrogen molecules. In some embodiments, the performing of Step S05 additionally includes, before the injecting, the further recovering of the methane-containing gas.

[0088] Referring now to Fig. 9A, a method is disclosed for determining a ratio of hydrogen to methane produced from a partially depleted shale gas reservoir housing stored hydrogen and for using said ratio in the operation of said reservoir. According to the method, the reservoir comprises an organic nanopore system, an inorganic pore system, and a micro-fracture system. As illustrated by the flow chart in Fig. 9A, the method comprises at least the 2 method steps Sil and S12.

[0089] Step Sil includes obtaining a core sample from the reservoir. This can include procuring one or more representative core samples. A non-limiting example of an appropriate core sample size is a cylinder with a diameter of 1-1.5 inches and a height (length) of 1 inch. In embodiments, the preparing comprises receiving the core sample in a core-sample holder. Step S12 includes subjecting the core sample to Nuclear Magnetic Resonance (NMR) testing to obtain respective T2 and T1-T2 relaxation times for methane and for hydrogen in each one of the organic nanopore system, the inorganic pore system, and the microfracture system. In some embodiments, the testing is carried out using a system comprising an NMR instrument operating at a Larmor frequency of at least 20 Mhz. In some embodiments, the system is configured to operate at interecho times of under 10 microseconds. In some embodiments, the system comprises a first set of NMR instrument components configured to operate at interecho times between 50 and 100 microseconds, and a second set of NMR instrument components configured to operate at interecho times under 10 microseconds.

[0090] In some embodiments, the testing of Step S12 is carried out using a system comprising an NMR instrument adapted to discriminate between hydrogen and methane based on their distinct T2 relaxation times in different pore systems.

[0091] In some embodiments, the testing of Step S12 is carried out using a system comprising an NMR instrument configured to use two different pulse sequences, the two pulse sequences including a first pulse sequence for measuring T2 relaxation times and a second pulse sequence for T1-T2 relaxation times.

[0092] In some embodiments, the system used for the testing of Step S12 is configured to access or operate data analysis software that automatically calculates a hydrogen-to-methane ratio based on NMR measurements. The software can include a numerical simulation program that includes different flow regimes that match the observed NMR data during diffusion from the organic nanopores and their coupling to the mesopores with Klinkenberg-corrected Darcy flow and Darcy flow in the fractures. The derived H2:CH4 ratios for the three different pore systems can be used to assess the efficiency of hydrogen extraction and / or to determine the level of methane co-production, using the numerical simulation program to match the gas flow from each pore system. The numerical simulation program can be used to assist in optimizing production strategies and ensuring safety during production. In some embodiments, the system is configured to access or include a database containing T relaxation times of various gases in different pore systems. In some embodiments, as illustrated in Fig. 9B, the method additionally comprises Step S13. As shown in Fig. 9B, Step S13 includes determining a hydrogen- to-methane ratio based on the respective T2 and T1-T2 relaxation times. In some embodiments, the ratio of hydrogen to methane is calculated using the formula:

[0093] In some embodiments, as illustrated in Fig. 9C, the method additionally comprises Steps S14 and S15.

[0094] As shown in Fig. 9C, Step S14 includes subjecting one or more gas samples obtained from the shale gas reservoir to NMR testing, and Step S15 includes comparing results of the NMR testing on the gas samples with results of the NMR testing of the core sample.

[0095] In some embodiments, as illustrated in Fig. 9D, the method additionally comprises Step S16.

[0096] As shown in Fig. 9D, Step S16 includes defining or changing a hydrogen extraction strategy based on the determined hydrogen-to-methane ratio.

[0097] In some embodiments, as illustrated in Fig. 9E, the method additionally comprises Step S17.

[0098] As shown in Fig. 9E, Step S17 includes predicting safety and efficiency of hydrogen extraction from the shale gas reservoir based on methane co-production levels determined from NMR testing of one or more core samples.

[0099] In some embodiments, as illustrated in Fig. 9F, the method additionally comprises Step S18.

[0100] As shown in Fig. 9F, Step S18 includes assessing hydrogen-storage efficiency in the shale gas reservoir based on a result of quantifying residual methane after extraction of hydrogen from the shale gas reservoir.

[0101] In some embodiments, as illustrated in Fig. 9G, the method additionally comprises Step S19.

[0102] As shown in Fig. 9G, Step S19 includes subjecting gas produced by the shale gas reservoir to periodic NMR analysis to monitor a hydrogen-to-methane ratio. In some embodiments, as illustrated in Fig. 9H, the method additionally comprises Step S20.

[0103] As shown in Fig. 9H, Step S20 includes obtaining a GC analysis of methane and hydrogen gas molecules effluent from one or more core samples.

[0104] In some embodiments, as illustrated in Fig. 91, the method additionally comprises Step S21.

[0105] As shown in Fig. 91, Step S21 includes changing a hydrogen storage strategy in a shale gas reservoir based on the determined hydrogen-to-methane ratio.

[0106] In some embodiments, as illustrated in Fig. 9J, the method additionally comprises Step S22.

[0107] As shown in Fig. 9J, Step S22 includes determining a hydrogen gas density inside at least one of the microfracture system and the inorganic pore system using respective P2 and P3 peaks of the obtained T2 relaxation times.

[0108] The present invention has been described using detailed descriptions of embodiments thereof that are provided by way of example and are not intended to limit the scope of the invention. The described embodiments comprise different features, not all of which are required in all embodiments of the invention. Some embodiments of the present invention utilize only some of the features or possible combinations of the features. Variations of embodiments of the present invention that are described and embodiments of the present invention comprising different combinations of features noted in the described embodiments will occur to persons skilled in the art to which the invention pertains. Any of the disclosed methods, method steps, and optional activities related to the method steps can be combined in any way.

[0109] In the description and claims of the present disclosure, each of the verbs, "comprise", "include" and "have", and conjugates thereof, are used to indicate that the object or objects of the verb are not necessarily a complete listing of members, components, elements or parts of the subject or subjects of the verb. As used herein, the singular form "a", "an" and "the" include plural references unless the context clearly dictates otherwise. For example, the term "a marking" or "at least one marking" may include a plurality of markings.

Claims

CLAIMS1. A method of operating a partially depleted shale gas reservoir, the method comprising: a. preparing a core sample acquired from the gas reservoir, the preparing comprising (i) receiving the core sample in a core-sample holder, (ii) introducing, into the core-sample holder, a methane-containing gas so as to pressurize the core sample to a first pressure, and (iii) introducing, into the core-sample holder, a hydrogen-containing gas so as to pressurize the core sample to a second pressure, the second pressure being higher than the first pressure; b. obtaining nuclear magnetic resonance (NMR) measurements of the core sample at the second pressure, the NMR measurements including Ti and T2 relaxation times; and c. determining, based on the obtained NMR measurements, a projected ratio of hydrogen to methane in a gas recoverable from the gas reservoir at a target time when the gas reservoir is characterized as having had a methane-containing gas recovered therefrom until a downhole pressure reached a residual-methane pressure substantially equal to the first pressure, and subsequently having had a hydrogencontaining gas injected thereinto until the downhole pressure reached a total target pressure substantially equal to the second pressure.

2. The method of claim 1, wherein (i) the method additionally comprises, before the determining: obtaining a gas chromatographic (GC) analysis of methane and hydrogen gas molecules effluent from the core sample, and (ii) the determining is additionally based on the obtained GC analysis.

3. The method of claim 1, additionally comprising: based on the determining, performing at least one gas-reservoir operation selected from:i. further recovering methane-containing gas from the gas reservoir until the downhole pressure reaches the residual- methane pressure, ii. injecting a hydrogen-containing gas into the gas reservoir at least until the downhole pressure reaches the total target pressure, and iii. recovering a gas comprising methane and hydrogen molecules from the gas reservoir, the hydrogen molecules accounting for a majority of a molar weight of the recovered gas.

4. The method of claim 2, wherein the performing includes performing both the injecting of the hydrogen-containing gas and the further recovering of the gas comprising methane and hydrogen molecules.

5. The method of claim 2, wherein the performing additionally includes, before the injecting, the further recovering of the methane-containing gas.

6. The method of claim 1, wherein the determining includes determining a pore distribution of the core sample, the determined pore distribution including a fraction of organic nanopores, inorganic mesopores and macropores, and microfractures occupied by the hydrogen molecules, and a fraction of organic nanopores, inorganic mesopores and macropores, and microfractures occupied by the methane molecules.

7. The method of claim 1, wherein the determining includes projecting a hydrogen-permeability projection of the gas reservoir at the target time.

8. The method of claim 5, wherein the determining of the hydrogen-permeability projection includes applying a modified Carman-Kozeny permeability mode to the determined pore distribution of the core sample.

9. The method of claim 2, wherein the further recovered methane-containing gas is substantially without hydrogen.

10. A method of determining a ratio of hydrogen to methane produced from a partially depleted shale gas reservoir housing stored hydrogen, the reservoircomprising an organic nanopore system, an inorganic pore system, and a microfracture system, the method comprising: a. obtaining a core sample from the reservoir; and b. subjecting the core sample toNuclear Magnetic Resonance (NMR) testing to obtain respective T2 and T1-T2 relaxation times for methane and for hydrogen in each one of the organic nanopore system, the inorganic pore system, and the microfracture system.

11. The method of claim 10, additionally comprising: determining a hydrogen-to- methane ratio based on the respective T2 and T1-T2 relaxation times.

12. The method of claim 1, additionally comprising: (i) subjecting one or more gas samples obtained from the shale gas reservoir to NMR testing and (ii) comparing results of the NMR testing on the gas samples with results of the NMR testing of the core sample.

13. The method of claim 11, where the ratio of hydrogen to methane is calculated using the formula:

14. The method of claim 11, additionally comprising: defining or changing a hydrogen extraction strategy based on the determined hydrogen-to-methane ratio.

15. The method of claim 10, additionally comprising: predicting safety and efficiency of hydrogen extraction from the shale gas reservoir based on methane co-production levels determined from NMR testing of one or more core samples.

16. The method of claim 10, additionally comprising: assessing hydrogen-storage efficiency in the shale gas reservoir based on a result of quantifying residual methane after extraction of hydrogen from the shale gas reservoir.

17. The method of claim 10, wherein the testing is carried out using a system comprising an NMR instrument operating at a Larmor frequency of at least 20 MHz.

18. The method of claim 17, wherein the system is configured to operate at interecho times of under 10 microseconds.

19. The method of claim 17, wherein the system comprises a first set of NMR instrument components configured to operate at interecho times between 50 and 100 microseconds, and a second set of NMR instrument components configured to operate at interecho times under 10 microseconds.

20. The method of claim 10, wherein the testing is carried out using a system comprising an NMR instrument adapted to discriminate between hydrogen and methane based on their distinct T2 relaxation times in different pore systems.

21. The method of claim 20, wherein the system is configured to access or operate data analysis software that automatically calculates a hydrogen-to-methane ratio based on NMR measurements.

22. The method of claim 20, wherein the system is configured to access or include a database containing T2 relaxation times of various gases in different pore systems.

23. The method of claim 10, wherein the testing is carried out using a system comprising an NMR instrument configured to use two different pulse sequences, the two pulse sequences including a first pulse sequence for measuring T2 relaxation times and a second pulse sequence for T1-T2 relaxation times.

24. The method of claim 10, additionally comprising: subjecting gas produced by the shale gas reservoir to periodic NMR analysis to monitor a hydrogen-to- methane ratio.

25. The method of claim 10, wherein the method additionally comprises: obtaining a GC analysis of methane and hydrogen gas molecules effluent from the one or more core samples.

26. The method of claim 11, additionally comprising: changing a hydrogen storage strategy in a shale gas reservoir based on the determined hydrogen-to- methane ratio.

7. The method of claim 10, additionally comprising: determining a hydrogen gas density inside at least one of the microfracture system and the inorganic meso and macro pore systems using respective P2 and P3 peaks of the obtained T2 relaxation times.

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