Patent Application
20240319066
The application claims priority to Chinese patent application No. 2023102817552, filed on Mar. 21, 2023, the entire contents of which are incorporated herein by reference.
The present invention relates to the technical field of oil and gas field development, hydrogen energy and energy storage, in particular to a method for evaluating the underground hydrogen storage (UHS) capacity in porous media of depleted gas reservoirs using CO2 as cushion gas.
The hydrogen energy is a renewable, high-energy and high-efficiency energy carrier, which is convenient for storage and conversion. China's solar power and wind power industry is large in scale, but these two types of power utilization are low, and the waste electricity cannot be utilized, so the hydrogen energy becomes a favorable energy conversion carrier. The hydrogen energy is widely used in steel, chemical and petrochemical industries, replacing fossil energy such as coal and oil. It is expected that the demand for hydrogen energy in the industrial field will exceed 35 million tons in 2050, and the demand is huge. Along with the implementation of the “carbon neutrality, carbon emissions peak” policy, the hydrogen energy will play an important role as a clean energy source.
The hydrogen energy storage is mainly divided into the physical hydrogen storage and the chemical hydrogen storage. The physical hydrogen storage mainly includes high-pressure gaseous hydrogen storage, low-temperature liquid hydrogen storage, activated carbon adsorption hydrogen storage, carbon fiber and carbon nanotube hydrogen storage, and underground hydrogen storage. The chemical hydrogen storage mainly includes metal hydride hydrogen storage, liquid organic hydrogen carrier hydrogen storage, inorganic hydrogen storage, and liquid ammonia hydrogen storage. The UHS is an effective way of large-capacity and long-term energy storage. Similar to underground gas storage, natural gas is often stored in depleted oil and gas reservoirs, aquifers, salt caverns and some abandoned pit caverns. There are higher requirements for underground storage of hydrogen, and the focus of the UHS research is to store hydrogen in depleted gas reservoirs and salt caverns. The UHS in depleted gas reservoir has the advantages of large volume, high geological awareness, good sealing and wide geographical distribution; the depleted gas reservoir usually contains a certain volume of residual gas, which can be used as cushion gas: meanwhile, the underground and surface original facilities can be partially utilized to reduce the investment cost of the UHS construction.
The development of UHS technology is an effective way to overcome the volatility and intermittency of renewable energy. The hydrogen storage capacity is a key factor for design engineers to consider and is an important indicator of the performance of the UHS. It is important to account for the volume of hydrogen stored in the UHS in real time and to determine the working gas volume at different pressures. Depleted gas reservoirs are the most common and economical form of building the UHS. Replacing valuable primary cushion gas with cheap CO2 not only reduces the loss of hydrogen but also achieves the purpose of carbon storage. The construction of UHS with CO2 as cushion gas not only achieves carbon emission reduction, but also improves the utilization of low-carbon energy. Compared with the primary cushion gas and N2, CO2 has stronger compressibility, which can improve the CO2 storage capacity of depleted gas reservoirs and enhance the hydrogen recovery efficiency in the process of hydrogen extraction. However, the existing UHS capacity evaluation method cannot accurately evaluate the hydrogen storage capacity in porous media of depleted gas reservoirs using CO2 as cushion gas. When CO2 is used as the cushion gas of the UHS of the depleted gas reservoir, it needs to consider the equilibrium relationship of H2—CO2—CH4 multi-component so that the hydrogen storage capacity of this reservoir can be evaluated more accurately.
In response to the above problems, the present invention aims to provide a method for evaluating the underground hydrogen storage (UHS) capacity in porous media of depleted gas reservoirs using CO2 as cushion gas.
The technical solution of the present invention is as follows:
A method for evaluating the UHS capacity in porous media of depleted gas reservoirs using CO2 as cushion gas, comprising the following steps:
Preferably, in S1, the physical parameters include original geological reserves, water saturation, water body size, temperature of the depleted gas reservoir, pressure of the depleted gas reservoir, formation water intrusion under depleted formation conditions, accumulated water production, gas component, formation water mineralization.
Preferably, in S2, the cap-rock breakthrough pressure is calculated by the following equation:
where, χ is the cap safety factor; when χ=0, the shear failure occurs; σi is the maximum effective principal stress, MPa; σ3 is the minimum effective principal stress, MPa; c is the cohesion force, MPa; ϕ is the internal friction angle, °: τin is the maximum shear stress at a certain stress state, MPa; τm* is the critical shear stress when the shear failure occurs, MPa.
Preferably, in S2, the fault-slip pressure is calculated by the following equation:
where, ST is the fault slip trend index; when ST<0.6, the fault is mechanically stable; when ST≥0.6, the fault is at risk of slip; the larger the ST, the higher the risk of slip; τ and τ, are the fault shear stress and the shear stress along the fault plane under a certain stress state respectively, MPa; σ and σn are the positive stress perpendicular to the fault plane and the effective positive stress respectively, MPa; σH and σh are the maximum principal stress and the minimum principal stress respectively, MPa; α is the dip angle of the fault plane, °.
Preferably, in S2, the highest operating pressure of the UHS is determined. The cap-rock breakthrough pressure and the fault-slip pressure are compared, and the smaller one is the highest operating pressure of the UHS.
Preferably, in S3, the H2—CO2—CH4 multi-component material balance equation is:
where, psc, p and pdep are the standard condition pressure, formation pressure, pressure of the depleted gas reservoir, respectively. MPa; VCO2_inj, VCO2 and VCO2_dis are the volume of injected CO2, the volume of CO2 in the formation, and the volume of dissolved CO2, respectively, m3; Zsc, ZCO2, ZH_dep, ZH and ZH2 are the gas deviation factor under standard conditions, CO2 deviation factor, natural gas deviation factor under depleted formation conditions, natural gas deviation factor under formation conditions, and H2 deviation factor, respectively, R is the ideal gas constant, 0.00831451 J·mol−1·k−1; Tsc, T and Tdep are the standard condition temperature, formation temperature, and temperature of the depleted gas reservoir, respectively, K; VH_dep, Vdep_dis, VH and VH_dis are the volume of natural gas in the depleted gas reservoir formation, the volume of natural gas dissolved in the depleted gas reservoir formation, the volume of natural gas in the gas reservoir formation, and the volume of natural gas dissolved in the formation, respectively, m3; VH2_inj, VH2 and VH2_dis are the volume of injected H2, the volume of H2 in the formation pore, and the volume of dissolved H2 in the formation, respectively, m3.
Preferably, in S4, the proportion of different gas components in the reservoir pore space is calculated. The proportion of CO2 in the reservoir pore space is calculated by substituting the following equation into the H2—CO2—CH4 multi-component material balance equation:
Where, a is the proportion of CO2 occupying the gas-bearing pore space of the formation excluding the water intrusion volume; V and Vi are the gas-bearing pore space in the formation under different pressure conditions and the gas-bearing pore space in the formation under initial conditions, respectively, m3; ceff is the effective compression coefficient of the formation, MPa−1; pi is the initial formation pressure, MPa; Vw_p is the water production volume, m3; Bw and Bwi are the formation water volume coefficient and the initial formation water volume coefficient, respectively; We is the water intrusion volume, m3; Gi is the gas reservoir reserve, m; Bi is natural gas volume coefficient under initial formation conditions; Zi is the initial formation natural gas deviation factor: Ti is the initial formation temperature, K; Sw is the water saturation; M is the water body multiplier; RCO2 is the CO2 solubility in formation water, m3/m3.
Preferably, in S4, the proportion of different gas components in the reservoir pore space is calculated, the proportion of CH4 in the reservoir pore space is calculated by substituting the following equation into the H2—CO—CH4 multi-component material balance equation:
Where, b is the proportion of natural gas occupying the gas-bearing pore space excluding the water intrusion volume: Vdep is the gas-bearing pore space in the formation under depleted formation conditions, m3; Bw_dep is the formation water volume coefficient in the depleted formation condition; We_dep is the water intrusion volume in the depleted formation condition, m3; RH and RH_dep are the solubility of natural gas under formation conditions and the solubility of natural gas under depleted formation conditions.
Preferably, in S4, the proportion of different gas components in the reservoir pore space is calculated, the proportion of H2 in the reservoir pore space is calculated by substituting the following equation into the H2—CO2—CH4 multi-component material balance equation:
Where, RH2 is the solubility of H2 under formation conditions, m3/m3;
The calculated VH2_inj value is the UHS capacity of the target depleted gas reservoir.
Preferably, the high pressure and high temperature device comprises an injection device, a core device, a back-pressure device I, a back-pressure device II, and a vacuum extraction device.
The injection device comprises a gas cylinder, a compressor, a gas intermediate vessel and a pressure pump I connected in sequence. The gas intermediate vessel is further connected to the input end of the core device. The gas cylinder comprises an H2 gas cylinder, a CO2 gas cylinder and a CH4 gas cylinder arranged in parallel, and the gas intermediate vessel comprises an H: intermediate vessel, a CO2 intermediate vessel and a CH4 intermediate vessel.
The core device comprises a core holder arranged in an oven, a confining pressure pump and a formation water intermediate vessel. The back-pressure device I comprises a pressure pump II and a back-pressure valve I. The core holder is provided with a pressure gauge I and a pressure gauge II respectively at the left and right ends. The confining pressure pump is connected to the core holder. The output end of the core holder is connected to the formation water intermediate vessel, and the other end of the formation water intermediate vessel is connected to the pressure pump II. The pressure pump II is connected to the output end of the core holder via the back-pressure valve I.
The back-pressure device II comprises a pressure pump III and a back-pressure valve II, and the other end of the back-pressure valve II is connected to the input end of the core holder;
The vacuum extraction device comprises an evacuator and a pressure gauge III. The evacuator is connected to the input end of the core holder, and the pressure gauge III is provided on the connected line.
A valve is provided between sub-components, and a one-way valve for flowing from the gas cylinder to the gas intermediate vessel is further provided between the H2 gas cylinder and the H2 intermediate vessel, between the CO2 gas cylinder and the CO2 intermediate vessel, and between the CH4 gas cylinder and the CH4 intermediate vessel.
The present invention has the following beneficial effects:
The method of evaluating hydrogen storage capacity described in the present invention takes into account the effect of CO2 as cushion gas on the UHS capacity in porous media of depleted gas reservoirs, which can evaluate the UHS capacity more accurately and provide technical support for the design and operation of the UHS.
In order to explain the embodiments of the present invention or the technical solutions in the prior art more clearly, the following will make a brief introduction to the drawings needed in the description of the embodiments or the prior art. Obviously, the drawings in the following description are merely some embodiments of the present invention. For those of ordinary skill in the art, other drawings can be obtained based on the structures shown in these drawings without any creative effort.
The present invention is further described with reference to the drawings and embodiments. It should be noted that the embodiments in this application and the technical features in the embodiments can be combined with each other without conflict. It is to be noted that, unless otherwise specified, all technical and scientific terms herein have the same meaning as commonly understood by those of ordinary skill in the art to which this application belongs. “Include” or “comprise” and other similar words used in the present disclosure mean that the components or objects before the word cover the components or objects listed after the word and its equivalents, but do not exclude other components or objects.
As shown in
In a specific embodiment, the physical parameters include original geological reserves, water saturation, water body size, temperature of depleted gas reservoir, pressure of depleted gas reservoir, formation water intrusion under depleted formation conditions, accumulated water production, gas component, formation water mineralization.
In a specific embodiment, the cap-rock breakthrough pressure is calculated by the following equation:
where, χ is the cap safety factor; when χ=0, the shear failure occurs; σ1 is the maximum effective principal stress (the difference between the maximum principal stress σH and the formation pressure), MPa; σ3 is the minimum effective principal stress (the difference between the minimum principal stress σh and the formation pressure), MPa; c is the cohesion force, MPa; ϕ is the internal friction angle, °: τm is the maximum shear stress at a certain stress state, MPa; τm* is the critical shear stress when the shear failure occurs, MPa.
The fault-slip pressure is calculated by the following equation:
where, ST is the fault slip trend index; when ST<0.6, the fault is mechanically stable; when ST≥0.6, the fault is at risk of slip; the larger the ST, the higher the risk of slip: τ and τs are the fault shear stress and the shear stress along the fault plane under a certain stress state respectively, MPa; σ and σa are the positive stress perpendicular to the fault plane and the effective positive stress respectively, MPa; σH and σh are the maximum principal stress and the minimum principal stress respectively, MPa; α is the dip angle of the fault plane, °.
It should be noted that the formula for calculating the cap-rock breakthrough pressure and fault-slip pressure in the above embodiment is only the preferred calculation method of the present invention, which can obtain a more accurate the highest pressure of the formation. Other calculation methods for considering this corresponding parameter can also be applied to the present invention. For example, the cap-rock breakthrough pressure can be determined using shear dilatancy safety factor, tensile damage limit pressure, uniaxial tensile strength, etc. And the fault-slip pressure can be determined using fault activation enabling limit pressure, fault-slip limit pressure, and fault closure factor.
S3: developing the H2—CO2—CH4 multi-component material balance equation in underground porous media by considering the dissolution of three components of hydrogen, carbon dioxide and methane in formation water, and using the molar weight material balance method.
In a specific embodiment, the H2—CO2—CH4 multi-component material balance equation is:
where, psc, p and pdep are the standard condition pressure, formation pressure, and pressure of the depleted gas reservoir, respectively, MPa; VCO2_inj, VCO2 and VCO2_dis are the volume of injected CO2, the volume of CO2 in the formation, and the volume of dissolved CO2, respectively, m3; Zsc, ZCO2, ZH_dep, ZH and ZH2 are the gas deviation factor under standard conditions. CO2 deviation factor, natural gas deviation factor under depleted formation conditions, natural gas deviation factor under formation conditions, and H2 deviation factor, respectively; R is the ideal gas constant, 0.00831451 J·mol−1·k−; Tsc, T and Tdep are the standard condition temperature, formation temperature, and temperature of the depleted gas reservoir, respectively, K; VH_dep, Vdep_dis, VH and VH_dis are the volume of natural gas in the depleted gas reservoir formation, the volume of natural gas dissolved in the depleted gas reservoir formation, the volume of natural gas in the gas reservoir formation, and the volume of natural gas dissolved in the formation, respectively, m3; VH2_inj, VH2 and VH2_dis are the volume of injected H2, the volume of H2 in the formation pore, and the volume of dissolved H2 in the formation, respectively, m3.
S4: substituting the parameters obtained from S1 and S2 into the H2—CO2—CH4 multi-component material balance equation to calculate the proportion of different gas components in the pore space to finally determine the UHS capacity of the target depleted gas reservoir.
In a specific embodiment, when the proportion of different gas components in the reservoir pore space is calculated, the proportion of CO2 in the reservoir pore space is calculated by substituting the following equation into the H2—CO2—CH4 multi-component material balance equation:
where, a is the proportion of CO2 occupying the gas-bearing pore space of the formation excluding the water intrusion volume; V and Vi are the gas-bearing pore space in the formation under different pressure conditions and the gas-bearing pore space in the formation under initial conditions, respectively, m3; ceff is the effective compression coefficient of the formation, MPa−1; pi is the initial formation pressure, MPa; Vw_p, is the water production volume, m3; Bw and Bwi are the formation water volume coefficient and the initial formation water volume coefficient, respectively; We is the water intrusion volume, m3; Gi is the gas reservoir reserve, m3; Bi is natural gas volume coefficient under initial formation conditions; Zi is the initial formation natural gas deviation factor; Ti is the initial formation temperature, K; Sw is the water saturation; M is the water body multiplier; RCO2 is the CO2 solubility in formation water, m3/m3.
In a specific embodiment, the proportion of different gas components in the reservoir pore space is calculated, the proportion of CH4 in the reservoir pore space is calculated by substituting the following equation into the H2—CO2—CH4 multi-component material balance equation:
Where, b is the proportion of natural gas occupying the gas-bearing pore space excluding the water intrusion volume: Vdep is the gas-bearing pore space in the formation under depleted formation conditions, m3; Bw_dep is the formation water volume coefficient in the depleted formation condition; We_dep is the water intrusion volume in the depleted formation condition, in; RH, and RH_dep are the solubility of natural gas under formation conditions and the solubility of natural gas under depleted formation conditions.
In a specific embodiment, when the proportion of different gas components in the reservoir pore space is calculated, the proportion of H2 in the reservoir pore space is calculated by substituting the following equation into the H2—CO2—CH4 multi-component material balance equation:
Where, RH2 is the solubility of H2 under formation conditions, m3/m3:
The calculated VH2_inj value is the UHS capacity of the target depleted gas reservoir.
In a specific embodiment, the method for evaluating the UHS capacity in porous media of depleted gas reservoirs using CO2 as cushion gas also comprises simulating hydrogen injection into a hydrogen storage by using a high-pressure and high-temperature device. And it is be used to verify the accuracy of H2—CO2—CH4 multi-component material balance equation.
In a specific embodiment, as shown in
The injection device comprises a gas cylinder, a compressor (18, a gas intermediate vessel and a pressure pump I (4) connected in sequence. The gas intermediate vessel is further connected to the input end of the core device. The gas cylinder comprises an H2 gas cylinder (1), a CO2 gas cylinder (2) and a CH4 gas cylinder (3) arranged in parallel. And the gas intermediate vessel comprises an H2 intermediate vessel (12), a CO2 intermediate vessel (13) and a CH4 intermediate vessel (14);
The core device comprises a core holder (33) arranged in an oven (29), a confining pressure pump (32) and a formation water intermediate vessel (41). The core holder (33) is used for holding the core (34). The back-pressure device I comprises a pressure pump II (43) and a back-pressure valve I (38). The core holder (33) is provided with a pressure gauge I (31) and a pressure gauge II (36) respectively at the left and right ends. The confining pressure pump (32) is connected to the core holder (33). The output end of the core holder (33) is connected to the formation water intermediate vessel (41), and the other end of the formation water intermediate vessel (41) is connected to the pressure pump II (43). The pressure pump II (43) is connected to the output end of the core holder (33) via the back-pressure valve I (38);
The buck-pressure device II comprises a pressure pump II (46) and a back-pressure valve II (45), and the other end of the back-pressure valve II (45) is connected to the input end of the core holder (33);
The vacuum extraction device comprises an evacuator (24) and a pressure gauge III (25). The evacuator (24) is connected to the input end of the core holder (33), and the pressure gauge III (25) is provided on the connected line;
A valve is provided between sub-components, and a one-way valve I (19). A one-way valve II (20) and a one-way valve III (23) for flowing from the gas cylinder to the gas intermediate vessel is further provided between the H2 gas cylinder (1) and the H2 intermediate vessel (12), between the CO2 gas cylinder (2) and the CO2 intermediate vessel (13), and between the CH4 gas cylinder (3) and the CH4 intermediate vessel (14).
In a specific embodiment, the pressure pump I (4) is connected to the gas intermediate vessel by a four-way valve I (5), and the valves between the four-way valve I (5) and the H2 intermediate vessel (12). CO2 intermediate vessel (13) and CH4 intermediate vessel (14) are labeled as valve I (6), valve II (7), and valve III (8), respectively. The valves between the H2 gas cylinder (1), CO2 gas cylinder (2) and CH4 gas cylinder (3) and the compressor (18) are labeled as valve IV (9), valve V (10), valve VI (11), respectively. The valves between the one-way valve I (19), one-way valve II (20), one-way valve II (23) and the H2 intermediate vessel (12). CO2 intermediate vessel (13) and CH4 intermediate vessel (14) are labeled as valve VII (15), valve VII (16), valve IX (17), respectively. The gas intermediate vessel and the core holder are connected by the four-way valve II (21) and the four-way valve III (27) respectively, and the other two lines of the four-way valve III (27) are connected to the evacuation device and the back-pressure device II respectively. The valve between the four-way valve II (21) and the four-way valve III (27) is labeled as valve X (22). The valve between the evacuator (24) and the four-way valve III (27) is labeled as valve XI (26). The valve between the back-pressure valve II (45) and the four-way valve III (27) is labeled as valve XII (28) The four-way valve III (27) is connected to the core holder (33) by a three-way valve (30), and the other end of the three-way valve (30) is connected to the pressure gauge I (31) The core holder (33) is connected to the formation water intermediate vessel 41) and the back-pressure valve I (38) by a four-way valve IV (35). The valve between the back-pressure valve I (38) and the four-way valve IV (35) is labeled as valve XIII (37), and the valve on the line connecting the back-pressure valve I (38) to air is labeled as valve XIV (39). The valves provided at the ends of the formation water intermediate vessel (41) are labeled as valve XV (40) and valve XVI (42) and the valve on the line connecting the back-pressure valve II (45) to air is labeled as valve XVII (44).
The specific use of the high-pressure and high-temperature device of the above embodiment to simulate the UHS injection comprises the following steps:
In this embodiment, the production parameters of the cores are shown in Table 2:
The experiment results are shown in
In a specific embodiment, a method for evaluating the UHS capacity in porous media of depleted gas reservoirs using CO2 as cushion gas is used to evaluate the capacity of a target UHS. The basic parameters of the target UHS are shown in Table 3:
As shown in
In summary, the present invention can accurately evaluate the capacity of the UHS using CO2 as cushion gas. Compared with the prior art, the present invention has significant improvements.
The above are only the preferred embodiments, which are not intended to limit the present invention in any form. Although the present invention has been disclosed as above with preferred embodiments, it is not intended to limit the present invention. Those skilled in the art, within the scope of the technical solution of the present invention, can use the disclosed technical content to make a few changes or modify the equivalent embodiment with equivalent changes. Within the scope of the technical solution of the present invention, any simple modification, equivalent change and modification made to the above embodiments according to the technical essence of the present invention are still regarded as a part of the technical solution of the present invention.
| Number | Date | Country | Kind |
|---|---|---|---|
| 2023102817552 | Mar 2023 | CN | national |
