Canada's 2030 Venting Ban: What Oil Producers Must Do

Canada's federal methane rules ban routine venting at existing upstream oil and gas facilities from 1 January 2030. If your wells vent casing gas or your tanks breathe to atmosphere, you likely need a plan to end it, unless an exception or a provincial equivalency agreement applies (both are explained below). Equipment lead times, tie-ins and winter access all take time, so start well before the deadline.

This article sets out what the rules say, with links to the regulations, and the options for the two venting sources most oil producers have: casing gas and tank vapours.

What changes in 2030

The federal government registered the final amendments to its upstream methane regulations on 12 December 2025 and published them in the Canada Gazette, Part II, on 31 December 2025 (SOR/2025-280). They apply to upstream facilities in Canada's onshore oil and gas sector, defined to include facilities extracting, processing or transporting hydrocarbons.

The key dates:

• 1 January 2028: facilities that begin operating on or after this date must meet the venting ban and the other Part 1 requirements from the day they start. The fugitive emissions (leak) detection and repair program comes into force for all facilities.
• 1 January 2030: the venting ban, the gas destruction rules and the other Part 1 requirements apply to facilities that began operating before 2028.

The core rule is short: "hydrocarbon gas must not be vented from an upstream oil and gas facility." Instead of meeting that rule and the other Part 1 requirements, an operator can choose an alternative, performance-based pathway (Part 2). It requires an emission monitoring system and a facility emission intensity below set reference standards, such as 0.2% of the hydrocarbon gas produced at a production facility.

The government's stated goal is to cut oil and gas sector methane emissions by at least 75% below 2012 levels by 2030. The regulations themselves do not set a reduction target for each operator.

The exceptions

Venting is still allowed when:

• it is part of planned equipment maintenance or a planned temporary depressurization, and venting is minimized;
• it is necessary to avoid serious risk to health or safety in an emergency;
• the gas's heating value or flow rate is too low to sustain continuous destruction;
• destroying or conserving the gas would prolong an interruption of gas supply to the public.

A fifth exception covers small, older oil sites. A facility that produces crude oil, began operating before 1 January 2028, and in the previous calendar year produced no more than 600 m³ of crude oil and vented no more than 12,000 m³ of hydrocarbon gas may keep venting up to 12,000 m³ a year. Venting from gas-driven pneumatic devices does not qualify, and the operator must take steps to minimize venting.

Saskatchewan, Alberta and British Columbia

Between late 2024 and 2025, the federal government entered into new equivalency agreements with Saskatchewan, British Columbia and Alberta to continue to stand down the federal methane regulations in those provinces. The government's analysis of the 2025 amendments adds: "As a result of the amendments, new equivalency agreements with provinces would be needed to stand down the amended Regulations." So if you operate in one of these provinces, follow the provincial rules today, and watch for new agreements before 2030. The federal equivalency agreements page lists the agreements currently in place.

Saskatchewan. A federal order says the federal methane regulations do not apply in Saskatchewan (except at federal works and undertakings). The order ends when the Canada-Saskatchewan equivalency agreement ends. That agreement accepts Saskatchewan's Oil and Gas Emissions Management Regulations and parts of Directives PNG036 and PNG017 as equivalent. It terminates on 31 December 2029 at the latest, and either side can end it earlier with three months' written notice.

The agreement also committed Canada to reassess equivalency once the final federal amendments were published, which happened on 31 December 2025. It provided that, if the reassessment did not show equivalent outcomes, Canada would give three months' notice and the agreement would terminate on 31 December 2026. Check the federal equivalency agreements page for the current status before you plan around it.

Saskatchewan's own rules apply now. The Ministry of Energy and Resources requires licensees to manage venting and flaring under Directive PNG036, and says any oil well or facility where "the combined vented and flared volumes of associated gas are greater than 900 m³/day may be subject to an audit by the ministry."

Alberta. A 2025 Canada-Alberta equivalency agreement also stands down the federal methane regulations in Alberta. AER Directive 060 governs flaring, incinerating and venting. A new edition took effect on 27 March 2026. Its changes that start on 1 January 2030 include:

• automatic or continuous ignition for flares installed, replaced or relocated on or after that date;
• conserving or controlling methane from glycol dehydrators installed, replaced or relocated on or after that date;
• fugitive emissions screening every two weeks on active flares, unless the flare has automatic or continuous ignition;
• monthly reporting of unlit flare gas volumes.

Ask your compliance lead how the federal and provincial rules apply to each of your licences.

What counts as venting at a typical oil well

Casing gas is gas that collects in the annulus between the casing and the tubing. Many wells release it through a vent line to keep casing pressure down. That is venting.

Tank vapours are gas that flashes out of oil in storage tanks and leaves through the vent or thief hatch. That is venting too.

Pneumatics are a third source. Gas-driven controllers and pumps release gas as they work. The federal cost analysis lists replacing pneumatic pumps with electric pumps, and pneumatic instruments with non-emitting ones, among the compliance actions.

Your options

The government's analysis expects facilities to either destroy the gas, use it as fuel, or sell it, and notes that fuel use and sales are sometimes called "conservation".

1. Conserve it into a sales or gathering line. This earns revenue and ends the venting. It needs a line within reach and enough pressure to get into it. Casing gas and tank vapours are usually at low pressure, so this usually means a compressor.

2. Use it as fuel on site. It cuts fuel purchases, but it only ends the venting if the site can burn as much gas as it would otherwise vent. Any surplus still needs another destination.

3. Destroy it in a flare, combustor or catalytic oxidizer. Destruction is allowed, with conditions. Combustion equipment must have a carbon conversion efficiency of at least 98%. Outside emergencies, destruction must be supported by an engineering study that concludes using the gas to produce useful heat or energy is not feasible. An engineer must reassess that study every 12 months, and if its conclusion no longer holds, the destruction must stop. You earn nothing from the gas.

4. Compress it. A compressor lifts casing gas or tank vapour to flowline or sales line pressure, so you can conserve it instead of destroying it. On a well, drawing gas off the casing also lowers casing pressure.

What the federal analysis expects

The government's cost-benefit analysis estimates that conservation would be feasible at roughly 5,300 facilities, while about 36,000 would destroy their gas instead. It assumes conserving facilities install a vapour recovery unit (VRU), with roughly 500 of them also building a pipeline tie-in. Its average cost estimates are $140,700 to buy and install a VRU, about $1.5 million for a pipeline tie-in, $52,800 for a combustor and $37,100 for a catalytic oxidizer. These are the government's estimates, not IJACK prices.

The same analysis looks separately at surface casing vent flow: gas rising through the annulus between the surface casing and the production casing. It counts about 5,900 such wells. It assumes wells venting 5 to 100 m³/day will send the gas to a combustor or incinerator, and wells above 100 m³/day will install compressors to capture it, about 900 wells. Its estimated capital cost is $111,700 per well for recovery and combustion, and $90,900 per well for recovery and compression.

How a casing gas compressor helps

Gas pressure in the casing pushes back on the formation. Lowering it can let more fluid flow into the wellbore. IJACK's EGAS data sheet puts it this way: "Lower casing pressure may increase inflow from the formation and increase fluid levels." The best candidates are wells close to or at a pumped-off state, or with low formation pressure. See Benefits of Casing Gas Compression for Increasing Oil Production for more.

IJACK builds three products for casing gas and tank vapours, and a multiphase pump that can also take the place of a casing gas compressor.

• EGAS is a stand-alone, automated compressor. You set the casing or tank pressure you want and it adjusts to hold it. It runs independently of the pumping unit, needs no scrubber or VFD, and discharges gas-associated fluids into the flowline. It can lower casing pressure on one well or several, and also works as a vapour recovery unit for tanks and vessels. IJACK states the system can be installed and compressing gas in less than three hours with a picker or boom truck, a local crew of two and an electrician.
• DGAS bolts onto the walking beam of a conventional pumping unit and needs no external power. A dual-action compressor relieves casing gas from the annulus and sends it through the flowline. Several wells can tie into one unit.
• VRU removes vapours from tanks, lowers tank top pressure to as low as 0 psi, and sends recovered vapours and condensates to a facility. It can also discharge into a knockout, sending condensates to a tank and vapours to a gas sales line or compressor.
• The XFER multiphase pump moves oil, water, gas and solids from the wellhead to the battery, lowering casing, well and flowline pressures. IJACK states it can replace a conventional casing gas compressor.

How much gas these units move

IJACK publishes capacity tables for each model. A few figures from them:

• EGAS: at 5 psi suction and 60 psi discharge, the EGAS units summary lists capacities from 0.64 e³m³/d (23 Mcf/d) for the 828 to 11.5 e³m³/d (406 Mcf/d) for the 2245HF. Capacity rises with suction pressure, and parallel units add volume. Imperial version.
• DGAS: at 5 strokes per minute, the DGAS model sheet lists maximum gas volumes from 3.9 Mcf/d (5" model, 5 psi intake) to 492.4 Mcf/d (18" heavy-duty model, 50 psi intake). The 12" to 18" heavy-duty units are only available for specific pumpjack brands and models.

For scale, Saskatchewan's 900 m³/day audit threshold is 0.9 e³m³/d, which is within the range of a single EGAS unit in that table. Your own volumes and pressures decide the right model, so send IJACK your well data rather than picking from a table.

Field results

IJACK has published anonymized results from XFER installations in Benefits of Multiphase Pumping for Oil and Gas Extraction. In one, a two-stage XFER system on a mountain pad project reduced pipeline pressure back to the three producing pads from 650 psi to 70 psi, eliminated venting and flaring, and avoided building a satellite facility. In another, an XFER lowered a plunger pad's line pressure from 250 psi to 10 psi, all gas reached the sales line, and gas and fluid production increased.

Grants

IJACK's VRU page states that the VRU is eligible for government emission reduction grants, and IJACK's casing gas compression article makes the same claim for EGAS. Programs and criteria change, so check what is open before you count on one.

A 12-month checklist

1. List every vent. Walk each site and record casing vents, tank hatches, pneumatics and dehydrators, with a measured or estimated volume.
2. Confirm which rules apply. Federal rules, PNG036 in Saskatchewan, or Directive 060 in Alberta. Check whether your province's equivalency agreement is still in force.
3. Check the exceptions. Does any site qualify for the small oil facility exception? Document why, and keep the venting records the rules require.
4. Find a destination for each gas stream. Sales line, fuel or destruction. Check line pressure and gathering capacity.
5. Rank sites by volume, and by wells that could gain from lower casing pressure.
6. Send data sheets for your top sites. IJACK's online application forms ask for the inputs needed to size a unit.
7. Plan installs for dry, accessible months, and finish well before the deadline.

Talk to IJACK

Tell us about the well or tank, the gas volume and the line you can tie into. IJACK's team will size a unit, or tell you plainly if another option fits better. Contact us, or read more about EGAS, DGAS, VRU and XFER.

This article is general information, not legal or regulatory advice. Check the regulations and your licence conditions before you decide.

Sources

• Canada Gazette, Part II, Vol. 159, No. 27 (31 December 2025), SOR/2025-280, Regulations Amending the Regulations Respecting Reduction in the Release of Methane and Certain Volatile Organic Compounds (Upstream Oil and Gas Sector), including the Regulatory Impact Analysis Statement: gazette.gc.ca
• Environment and Climate Change Canada, Canadian Environmental Protection Act equivalency agreements (Saskatchewan, Alberta and British Columbia methane agreements): canada.ca
• Order declaring that the federal methane regulations do not apply in Saskatchewan, SOR/2024-270: gazette.gc.ca
• Canada-Saskatchewan equivalency agreement respecting the release of methane from the oil and gas sector (sections 6.2 and 6.3): canada.ca
• Government of Saskatchewan, Reducing Venting and Flaring of Associated Gas: saskatchewan.ca
• Alberta Energy Regulator, Bulletin 2026-12, new edition of Directive 060: aer.ca, and Directive 060
• IJACK product pages and data sheets: EGAS, DGAS, VRU, XFER, EGAS models, EGAS units summary, DGAS models