An Economic Analysis of In-Situ Hydrogen Production from Natural Gas Wells with Subsurface Carbon Retention

Abstract

An economic analysis for a wellbore methodology that promotes sustainable natural gas conversion to hydrogen is presented. The methodology uses at-source, wellbore gasification of methane for hydrogen production, incorporating the simultaneous in-situ sequestration of carbon for both climate and economic benefit. The proposal is for a wellbore completion tool, to take natural gas (methane) production from the reservoir and perform gasification within the wellbore tool (not within the reservoir). This would not interfere with reservoir management, allowing standard reservoir management practices to be used. The proposed process is for natural gas fields and not for use in the gasification of heavy oils (which is covered by other “combustion type” reservoir management processes performed deep within the reservoir geology). The proposed methane gasification tool, when located deep within the wellbore, takes maximum advantage of the “free” energy provided by the elevated temperatures and pressures of the surrounding fluid-connected geology. The combination of surface-injected fluids and geofluids, mixed inside the wellbore gasification tool at depth, significantly reduces the excess process energy input from the surface and lessens feedstock consumption for power. The proposed system is neither electricity cost dependent nor fuel cost dependent, as both are provided in situ and through heat recovery and reserves. There are therefore several process steps and significant energy and cost savings to be gained by this method when compared with surface-based methane reformation facilities, as well as infrastructure longevity benefits. In addition, CO2 life cycle climate savings are made, as zero carbon is produced to the surface, eliminating the harm greenhouse gases (GHGs: CH4 and CO2) do while transitioning through the environment. The proposed methodology therefore avoids the expense and energy consumption of the subsequent, only partial, downstream recapture of the CO2 released from the combustion of this same methane. To help maintain consistency and ensure comparability for hydrogen production types, the standardized H2A template of the National Renewable Energy Laboratory (NREL) of the U.S. Department of Energy was used in our analysis. This economic template contains several cost model scenarios used to illustrate the possible magnitudes of economic advantages using this wellbore methodology. Based on the model’s comparative cost analyses, such a proposed system could produce hydrogen from natural gas wells consistently below 1 USD/kg H2, leading to cost-competitive wellbore hydrogen production when compared with surface-based steam methane reformation facilities. Using several scenarios for cost analysis, we found that the cost cannot be higher than 2 USD/kg H2. In our uncertainty quantification, we included the effects of the number of wells that can be used as well as mixing H2 with CH4 (v/v%).