Flare and stranded gas bitcoin mining: what has to be true

Associated gas comes up with the oil. Alberta calls it solution gas, which the Alberta Energy Regulator defines as "gas separated from condensate, oil, or bitumen production." Without its own route to market, the gas is burned or released.

The missing route is usually infrastructure, not technology. The World Bank's June 2026 Global Gas Flaring Tracker says that in every active shale oil basin, oil and associated gas production "have regularly run ahead of installation of adequate gas collection and export infrastructure capacity," while output from each shale oil well "declines rapidly." Texas writes the same fact into Statewide Rule 32: one situation it lists as showing the necessity for an exception is, "for casinghead gas only, the unavailability of a gas pipeline or other marketing facility." The World Bank's press release of 23 June 2026 calls the wider barrier "not technical but structural": regulation, capital, market infrastructure, and the priority operators and governments give to reduction.

The usual cure is a pipeline. The World Bank names the Matterhorn Express, in service at the end of 2024, as a key driver of a 13 percent fall in Permian flaring volumes in 2025. A pipeline arriving is usually good news for a producer, and can end a mining load on that pad.

Globally, a lot, and rising. The tracker estimates flaring at 167 billion cubic metres in 2025, up 6 percent from 157 bcm in 2024, the third annual rise in a row and the highest level since 2019. It attributes 429 million tonnes of CO2-equivalent emissions to it, 50 million from unburned methane. The volumes are estimated from satellite observations (VIIRS Nightfire), not operator reports.

In the tracker's estimate the United States went the other way: a 0.4 bcm, 7 percent reduction in 2025, the largest absolute fall of any country. The EIA's series, released 31 August 2026, reports 335,163 million cubic feet vented and flared in 2024, about 0.7 percent of gross withdrawals of 45,867,761 million cubic feet. The two national figures are not comparable: the EIA's combines venting and flaring, and the World Bank's is a satellite estimate of flaring alone.

In July 2026 North Dakota flared 173.3 million cubic feet a day and captured 95.3 percent of its gas, against an Industrial Commission goal of 91 percent in force since 1 November 2020. Alberta's ST60B-2025, published December 2025, reports 914.5 million m3 of solution gas flared in 2024, up 19.3 percent, with 96.5 percent of solution gas conserved.

A national total shows the resource exists. What decides a project is your meter, over time.

Gas leaves the separator, is conditioned to remove liquids and contaminants, and fuels an engine-generator; a transformer feeds the miners in their containers. The flare example on our energy page shows that equipment, with the flare kept for upsets and for any time the gas is taken back.

The arithmetic needs two assumptions, stated so you can replace them. Both are on a higher heating value (HHV) basis.

• Heating value. Natural gas delivered to US end users averaged about 1,037 Btu per cubic foot in 2025. Associated gas at the wellhead can be much richer. An Energy & Environmental Research Center presentation on Williston Basin associated gas, dated 20 August 2013, assumed rich wellhead gas at 1,400 Btu per cubic foot, and 1,210 to 1,250 once natural gas liquids were removed. This example uses 1,200 Btu/scf, taken as an HHV figure.
• Heat rate, the fuel burned per kilowatt-hour. EPA's catalog of combined heat and power technologies (March 2015, reciprocating engines) lists 12,637 Btu/kWh for a 100 kW natural gas genset and 9,896 Btu/kWh for a 633 kW unit, HHV basis, for gensets available in 2013. This example uses 10,000 Btu/kWh on an HHV basis: about 34 percent HHV efficiency, dividing 3,412 Btu per kWh by the heat rate as the EIA does. Engine data sheets quote heat rates on a lower heating value basis, EPA notes, and for natural gas HHV is about 10 percent greater, so raise a data-sheet figure by about a tenth first.

1 Mcf x 1,200 Btu/scf               = 1.2 MMBtu
1.2 MMBtu / 10,000 Btu per kWh      = 120 kWh per Mcf
500 Mcf/day x 120 kWh per Mcf       = 60,000 kWh per day
60,000 kWh / 24 hours               = 2,500 kW average

The 500 Mcf a day is gas delivered to the engines. Removing liquids cuts volume as well as heating value: the EERC assumed lean gas at 85 percent of the rich-gas flow, so 500 Mcf a day on a wellhead meter would leave about 425, or about 2,100 kW at 1,200 Btu/scf.

At 1,037 Btu/scf the same 500 Mcf a day gives about 2,160 kW; at 1,400, about 2,920 kW. Heating value alone moves the answer by more than a third, so a gas analysis comes before any sizing.

That is fuel-limited generation, not power at the miners. From the same EPA catalog, what takes it down, and what to check:

• Site conditions. Output and efficiency fall roughly 4 percent per 1,000 feet of altitude above 1,000 feet, and about 1 percent for every 10°F above 77°F.
• Part load. For a typical lean-burn engine, efficiency at half load is about 8 to 10 percent below full load, so an engine oversized for a declining well burns more gas per kWh.
• Rating basis. This sets what you buy, not what the gas yields. Baseload ratings are typically 70 to 75 percent of standby, and mining is baseload duty, so 2.5 MW around the clock needs gensets rated for 2.5 MW at baseload.

Cooling and other site loads come off before anything reaches a miner. The calculator takes gas volume, heating value and genset heat rate as inputs; enter the heating value from your own gas analysis. What a megawatt-hour of mining earns is covered in our note on energy hashprice.

The facts whose absence ends most conversations:

1. Metered volume over months, and a view of decline. A test rate is not a supply profile. Ask for daily volumes over as long a period as exists, and a forecast, and size to the gas you expect in year two, not month one.
2. A current, extended gas analysis. The EPA catalog notes that field gas "often contains more than 5 percent by volume of heavy ends (butane and heavier), as well as water, salts and H2S and usually requires some scrubbing before use in natural gas engines." Heavier hydrocarbons autoignite more easily, and sulfur compounds form acids in combustion that can corrode equipment.
3. Room and access. A graded area for generation, containers, setbacks and cooling, with access for construction and maintenance.
4. Clear rights to the gas. Who owns it at the separator, whether the lease and any gathering or purchase contract allow this use, and how royalty owners are treated.
5. Approvals for a power plant, not a flare. EPA's New Source Performance Standards for stationary spark-ignition engines, 40 CFR Part 60 Subpart JJJJ, cover nitrogen oxides, carbon monoxide and volatile organic compounds.

Texas. Statewide Rule 32 (16 TAC §3.32, last amended effective 18 February 2025) says all gas from any oil or gas well "shall be utilized for purposes and uses authorized by law." Flaring is the exception with a clock on it: gas may be released for up to ten producing days after completion, as the Railroad Commission summarises, and beyond that an operator needs an exception. An administrative exception "shall not exceed a period of 180 days"; exceptions for more than 180 days and more than 50 mcf of hydrocarbon gas a day need a final order signed by the Commission. The rule does not mention power generation. Whether a particular on-site use qualifies is a question for regulatory counsel.

North Dakota. Under Section 38-08-06.4 of the Century Code, and as permitted under Industrial Commission rules, gas produced with oil may be flared for one year from first production. After that, flaring must cease and the well must be capped, connected to a gathering line, or "equipped with an electrical generator that consumes at least seventy-five percent of the gas from the well," among other options. For a well operated in violation, the producer must pay royalties to royalty owners on the value of the flared gas. An exemption requires showing that a gathering connection is economically infeasible or no market is available, and that a generator or collection system is too.

Alberta. Directive 060, released 27 March 2026, says in section 4.5 that "power generation is a means of conserving solution gas." Section 4.1 requires conservation where, among other criteria, combined flare and vent gas exceeds 900 m3/day per site and the economic evaluation returns an NPV greater than minus Cdn$55,000; section 4.1(4) says conserving facilities must be designed for 95 percent conservation efficiency with a minimum in-service operating time of 90 percent a year. Power plants need Alberta Utilities Commission approval and, above one megawatt at peak load, an approval issued by Alberta Environment and Protected Areas under the Environmental Protection and Enhancement Act. Our Alberta note covers why a load behind the fence is not in the grid queue.

• Decline. A generator sized for today's rate runs at part load, at worse efficiency, as the well falls away, and fixed costs spread over fewer kilowatt-hours.
• A pipeline arrives. When gathering capacity reaches a pad, selling the gas may beat burning it on site, and the load may have to move. The contract should say what happens then, and who pays.
• Downtime and curtailment. Engines need maintenance, the operator's work interrupts supply, and a mining load may be switched off when hashprice falls. Where the flare is the backup, every hour off is an hour of flaring. North Dakota's generator option requires consuming at least 75 percent of the gas, and Alberta sets an in-service requirement for conserving facilities, so read curtailment terms against the rules, not only the economics.
• Redeployment. Containerized equipment can move, at a cost, to a new site that needs its own approvals. Ownership and removal are covered in who carries which risk in a stranded-gas deal.
• Emissions accounting. For greenhouse gases, the main difference between an engine and a flare is how much methane survives. The World Bank's estimates assume flares are always lit and destroy 98 percent of methane, and it says that at an effective 94 percent, flaring's methane emissions would triple. A 2022 study in Science found flares in three basins responsible for more than 80 percent of US flaring effectively destroying 91.1 percent of methane. Engines are not methane-free either: EPA's AP-42 emission factors for natural gas engines include methane, whose global warming potential EPA puts at 27 to 30 over 100 years and 81 to 83 over 20. Replacing venting is a different claim from replacing a well-run flare, and who owns any environmental attributes should be written down either way.

The arithmetic uses round assumptions, and the Williston Basin heating values and genset heat rates both date from 2013. They show the method, not your answer. The regulatory sections describe published rules in three jurisdictions; they are not legal advice, they change, and sites elsewhere sit under other rules. And Proton sits on the mining side of this conversation.

Our energy page sets out what we look at on a gas site and the model Proton offers: the owner funds and owns the build, and Proton pays per kWh for the electricity its placed miners use. It also has a form for submitting a site.

If you do not yet have metered volumes and a gas analysis, getting them is the useful next step, whoever you talk to. If you do, put them through the calculator with your own heating value and heat rate first.