Offshore systems and methods may be configured for offshore power generation and carbon dioxide injection for enhanced gas recovery for gas reservoirs. For example, a method may include: providing an offshore facility including a gas turbine, and a gas separator; producing a produced gas from a gas reservoir to the offshore facility; combusting the produced gas in a gas turbine to produce power and a flue gas; at least partially removing nitrogen from the flue gas in a gas separator to produce a carbon dioxide-enriched flue gas and a nitrogen-enriched flue gas; compressing the carbon dioxide-enriched flue gas in a gas compressor to produce a compressed gas; and injecting the compressed gas from the gas compressor into the gas reservoir, wherein 80 mol % or more of hydrocarbon in the produced gas is combusted and/or injected into the gas reservoir.

A method including precipitating a precipitate including one or more divalent cation carbonates from a solution including the divalent cation of each of the one or more divalent cation carbonates, and storing at least a portion of the precipitate downhole by placing the at least the portion of the precipitate downhole via a well. Precipitating can include contacting the solution with a gas, such as atmospheric air, including carbon dioxide (CO.sub.2). The method can further include separating the precipitate from the solution, and forming a slurry including the at least a portion of the precipitate. Placing the at least the portion of the precipitate downhole via the well can include pumping the slurry downhole via the well. A system is also provided. Via the system and method, CO.sub.2 can be sequestered downhole.

CO.sub.2 in the liquid or super-critical state is delivered by at least one carrier vessel from at least one CO.sub.2 storage site, which may be an onshore site, to an integrated offshore facility. The integrated offshore facility is provided with at least one on-site storage tank or vessel adapted to store CO.sub.2 in the liquid or super-critical state and with equipment for marine transfer of CO.sub.2 in the liquid or super-critical state. CO.sub.2 is utilised as required from said at least one on-site storage tank or vessel for EOR at said offshore site or for EGR at said offshore site by injection into a sub-sea oil or natural gas bearing reservoir and recovery of oil and/or natural gas from a resulting production stream.

A method of hydraulic fracturing in a subterranean formation includes injecting a fluid including a proppant into the subterranean formation, wherein the proppant includes a material adapted to sequester at least one target species, and exposing or contacting at least one of the proppant or the material to/with the at least one target species either prior to injecting the proppant or subsequent to injecting the proppant.

A system and method for converting carbon dioxide into biomass within subterranean formations or cavities by introducing chemolithoautotrophic microbes and microbe supporting compounds in the formation so as to cause the chemolithoautotrophic microbes to fix carbon dioxide within the formation into biomass, which can then be used in the production of renewable energy and carbon-based products.

The present invention relates to a method of storing CO.sub.2 in a geological formation, said method comprising (i) injecting a first composition comprising CO.sub.2 into said formation; and (ii) injecting a second composition comprising CO.sub.2 and at least one CO.sub.2 soluble polymer into said formation, wherein steps (i) and (ii) are performed separately and in any order and wherein said first and second compositions are different.

A CCUS system for exploiting a thickened oil reservoir based on an optimal flue gas CO.sub.2 enrichment ratio. The CCUS system comprises a flue gas CO.sub.2 enrichment unit, a flue gas injection unit, a thickened oil thermal production well group unit and a produced gas recovery unit; the fuel gas CO.sub.2 enrichment unit comprises an air separating enrichment unit and a boiler injection gas premixed tank; the air separating enrichment unit comprises an air separating primary device used for separating air into oxygen and nitrogen preliminarily, and an air separating secondary device used for further enriching a part of the oxygen which is subjected to the preliminary separation; and the boiler injection gas premixed tank is used for mixing the preliminarily separated nitrogen, the preliminarily separated part of the oxygen and/or the further enriched oxygen.

The method and the system (100) according to the invention relate to the injection of gas into an underground formation, enhanced by the simultaneous injection of liquid (IL). Mixing of the gas and the liquid can occur at different levels in the well in order to facilitate the flow and to limit the gas pressure necessary for reinjection at the wellhead. Thus, the system (100) and the method require less energy and the associated gas compression equipment is less expensive.

The invention notably applies to geothermal energy applications, underground gas storage, notably CO.sub.2, or to enhanced recovery in petroleum reservoirs.

FIG. 3a to be published.

The present disclosure provides a system, method and apparatus for the removal of natural gas/methane from in situ loci within shale reservoirs to (i) provide fully de-carbonized surplus electricity, and (ii) power re-injection of the resulting carbon formed (CO.sub.2) upon combustion in an electric generator along with large volumes of atmospheric CO.sub.2, such as for large scale removal of CO.sub.2 from the Earth's surface/atmosphere.

Methods and an alarming system for long-term carbon dioxide sequestration in a geologic reservoir are described. The geologic reservoir may be a water filled sandstone reservoir or a carbonate reservoir. A reservoir model is constructed to show the effects of varying injection pressures, the number of injection wells, the arrangement of injection wells, the boundary conditions and sizes of the reservoir on caprock uplift, fracture formation and fracture reactivation. The alarming system generates an alarm when caprock uplift that surpasses a threshold is detected. The injection pressures and the number of injection wells operating may be varied in response to the alarm.