Hydrogen production, storage and recovery

{
  "publication_number": "US12366138B2",
  "country": "US",
  "kind": "B2",
  "title": "Hydrogen production, storage and recovery",
  "abstract": "A method for operating a kerogen-rich unconventional gas reservoir characterized by there being multiple hydraulically-fractured wells drilled thereinto comprises: recovering a methane-containing gas from a first hydraulically-fractured well drilled into the gas reservoir, steam-methane reforming the recovered methane-containing gas to yield a hydrogen gas and an inorganic carbon-containing gas, injecting at least a portion of the hydrogen gas into a second hydraulically-fractured well drilled into the gas reservoir, and injecting at least a portion of the inorganic carbon-containing gas into a third hydraulically-fractured well drilled into the gas reservoir.",
  "claims": [
    "1. A method of storing hydrogen gas in a kerogen-rich geological formation, the method comprising: a. injecting a fracturing fluid through a horizontal wellbore into the geological formation to cause fracturing within the geological formation; b. recovering a methane-containing gas through the wellbore, the recovering characterized by a maximum flow rate FLOW MAX; c. monitoring a current flow rate FLOW CURRENT of the recovered methane-containing gas over time; d. determining a flow-rate trigger criterion FLOW TRIGGER at or below which hydrogen injected into the geological formation is subsequently recoverable in a hydrogen-containing gas having an H 2 molar fraction of at least 85%; e. responsively to and contingent upon the monitored FLOW CURRENT being equal to or below FLOW TRIGGER, ceasing the recovering of the methane-containing gas and injecting a hydrogen gas through the wellbore into the geological formation at a pressure higher than a current shut-in gas pressure at the wellbore; and f. subsequent to the injecting, recovering, through the wellbore, the hydrogen-containing gas having the H 2 molar fraction of at least 85%.",
    "2. The method of claim 1, wherein FLOW TRIGGER is equal to at least 10% of FLOW MAX and not more than 20% of FLOW MAX.",
    "3. The method of claim 1, wherein FLOW TRIGGER is determined based at least in part on a kerogen concentration in the geological formation.",
    "4. The method of claim 1, wherein FLOW TRIGGER is determined based at least in part on a fluid flow regime of the geological formation.",
    "5. The method of claim 1, wherein the injecting of the hydrogen gas is at a pressure that is less than a calculated hydrogen fracture extension pressure H2FRAC EXT within the geological formation.",
    "6. The method of claim 1, wherein the monitoring of the current flow rate FLOW CURRENT includes determining the flow regime in the geological formation.",
    "7. The method of claim 1, wherein (i) the determining includes determining the flow-rate trigger criterion FLOW TRIGGER at or below which hydrogen injected into the geological formation is subsequently recoverable in a hydrogen-containing gas having an H 2 molar fraction of at least 90%, and (ii) the recovered hydrogen-containing gas has an H 2 molar fraction of at least 90%.",
    "8. The method of claim 1, wherein the kerogen concentration of the kerogen-rich geological formation is at least 2% by volume.",
    "9. A method of storing and subsequently recovering a hydrogen gas, the method comprising: a. injecting the hydrogen gas through a horizontal wellbore into a hydraulically-fractured, kerogen-rich, and partially-depleted reservoir of a methane-containing gas, at a pressure higher than a current shut-in gas pressure at the wellbore, the partial depletion of the reservoir being by a methane-containing-gas recovery process characterized by a maximum flow rate of FLOW MAX, b. determining a flow-rate trigger criterion FLOW TRIGGER below which hydrogen injected into the reservoir is subsequently recoverable in a hydrogen-containing gas having an H 2 molar fraction of at least 85%; and c. recovering a portion of the hydrogen gas through the wellbore, the recovered portion of the hydrogen gas having an H 2 molar fraction of at least 85%, wherein FLOW TRIGGER is equal to at least 10% of FLOW MAX and not more than 20% of FLOW MAX.",
    "10. The method of claim 9, additionally comprising a step, performed before the injecting of the hydrogen gas, of selecting the reservoir based on a kerogen concentration in the reservoir.",
    "11. The method of claim 9, additionally comprising a step, performed before the injecting of the hydrogen gas, of selecting the reservoir based on a fluid flow regime of the reservoir.",
    "12. The method of claim 9, wherein (i) the determining includes determining the flow-rate trigger criterion FLOW TRIGGER at or below which hydrogen injected into the reservoir is subsequently recoverable in a hydrogen-containing gas having an H 2 molar fraction of at least 90%, and (ii) the recovered hydrogen-containing gas has an H 2 molar fraction of at least 90%.",
    "13. The method of claim 9, wherein the kerogen concentration in the reservoir is at least 2% by volume.",
    "14. A system configured for storing and subsequently recovering a hydrogen-containing gas by performing the method of claim 9, the system comprising: a. pumping arrangements for injecting hydrogen-containing gas, disposed in fluid communication with the hydraulically-fractured, kerogen-rich and partially-depleted reservoir of a methane-containing gas and operative to inject the hydrogen gas through a horizontal wellbore into the reservoir at a pressure higher than a shut-in gas pressure at the wellbore; and b. gas-recovery equipment disposed in fluid communication with the reservoir and operative to recover the portion of the hydrogen-containing gas through the wellbore.",
    "15. The system of claim 14, wherein the fluid flow regime of the reservoir is substantially characterized by diffusional processes.",
    "16. The system of claim 14, wherein the fluid flow regime of the reservoir is substantially Knudsen diffusion.",
    "17. The system of claim 14, additionally comprising equipment for monitored by a delta (C13) isotope ratio in the recovered methane to determine a fluid flow regime in the reservoir."
  ],
  "description_excerpt": "The present invention relates to methods and systems for production, storage and recovery of a hydrogen-containing gas in a geological formation comprising a partially-depleted unconventional gas reservoir, and particularly to methods and systems for recovering the hydrogen gas at a high level of purity.\n\nAchieving a diversified low-carbon emissions energy economy has been limited by economic and technological limitations. Economic limitations include the cost of renewable energy projects compared to the value of the energy production, as well as competition from low-cost fossil fuels. Technological limitations are related to the energy production efficiency, storage of enormous amounts of excess energy, and ability to connect energy sources to users.\n\nFor example, renewable energy sources like solar and wind have intermittency challenges in which excess energy is produced with insufficient storage capacity. Thus, capital costs are increased because the solar and wind farms are built for peak power loads which are often twice or three times the mean (levelized) power loads. One of the ways to make renewable energy sources more economical is to provide large scale, inexpensive, geographically diversified, and energy efficient storage solutions. Currently, complex, expensive storage facilities are used to store excess energy (e.g. pumped hydroelectric storage, batteries, thermal storage), and the conversion efficiency is low.\n\nThe enormous scale of hydrogen storage that is required to support a green economy is so large that it necessitates some form of geological storage.",
  "cpc": [
    "E21B 43/006",
    "B65G 5/00",
    "C09K 8/62",
    "E21B 21/068",
    "E21B 41/0057",
    "E21B 43/12",
    "E21B 43/164",
    "E21B 43/2405",
    "E21B 43/2605",
    "E21B 47/11",
    "E21B 49/00",
    "E21B 49/0875",
    "E21B 49/088",
    "Y02P 20/133"
  ],
  "ipc": [
    "B65G 5/00",
    "E21B 21/06",
    "E21B 41/00",
    "E21B 43/00",
    "E21B 43/12",
    "E21B 43/16",
    "E21B 43/26",
    "E21B 49/08"
  ],
  "assignees": [
    "Terrah2 LLC"
  ],
  "inventors": [
    "Eva Vinegar",
    "Harold J. Vinegar"
  ],
  "filing_date": "2022-11-23",
  "publication_date": "2025-07-22",
  "grant_date": "2025-07-22",
  "priority_date": "2021-02-08",
  "application_number": "US-202217993688-A",
  "family_id": "82703679",
  "cited_by_count": 0,
  "citations": [
    "US4709577A",
    "US5085274A",
    "US8760657B2",
    "US20040200393A1",
    "US7121342B2",
    "US20050109504A1",
    "US7152675B2",
    "US20050220704A1",
    "US20140245827A1",
    "US20090115190A1",
    "US20140102885A1",
    "RU2493366C2",
    "US20090255181A1",
    "US20110000133A1",
    "US8230929B2",
    "US20110223100A1",
    "US20130240369A1",
    "US20110229780A1",
    "US20160046443A1",
    "US20140161533A1",
    "US20150285032A1",
    "US20160060738A1",
    "US10131593B2",
    "US9810064B2",
    "US20160010220A1",
    "US20150321846A1",
    "US20160060038A1",
    "US20170341936A1",
    "US20160251217A1",
    "US20160354625A1",
    "US20160354622A1",
    "US20180312935A1",
    "US20190219558A1",
    "US20210404439A1",
    "US20220064770A1",
    "US20220034448A1",
    "US20220146048A1",
    "US20220251935A1",
    "US20230077276A1",
    "US20230160284A1",
    "US20230167719A1",
    "US20230167720A1",
    "US11680466B2",
    "US11959364B2"
  ]
}