Develop a basis for the evaluation of your emissions reduction efforts in your sites. With some basic quantities, we can use our project experience to estimate the costs of the reduction implementation as well as the impact of lowering your Green House Gas (GHG) footprint.
Global energy demand is on the rise and LNG facilities are playing a bigger role than ever. LNG is a flexible, lower-emission fuel, and a way to transport and trade natural gas that was once landlocked by domestic demand. Natural gas demand is expected to grow 32% by 2050 with no peak in sight. This massive growth is driven by:
Kindra Snow-McGregor, PE, from PetroSkills delivered a technical presentation for the WOGA (Women in Oil and Gas Association) April Technical Luncheon – “LNG Market Drivers & Technology”. Lila Salley attended and in this article she shares her key takeaways.
The North American market is rushing to build out LNG infrastructure, as shown in the figure below, to capture more of the international demand and there are numerous challenges. Understanding the market and project development landscape is critical if you want your LNG plans to run smoothly — and profitably.
Lila breaks down what Kindra shared about the current market considerations.
LNG is natural gas cooled to -260°F to become a liquid, reducing its volume and then shipped at atmospheric pressure. This makes it far more efficient to store and transport — especially over long distances. In fact, LNG is more transportation-efficient than pipeline gas for distances over 1,500 miles and maintains its efficiency even up to 8,000 miles.
LNG’s uses span across:
LNG is emerging and North America is playing catch-up fast.
The LNG market is hot, but that doesn’t make execution easy. Here are some of the biggest hurdles operators face today.
1. LNG Facility Costs & Scale are Staggering
Liquefaction facilities are capital-heavy: $1 billion per 1 million tonnes per year (mtpy) of capacity is the norm. A 5 mtpy plant, a mid-size operation, needs:
That’s before you factor in the 7–8% of gas burned internally just to run the plant.
Operator challenge: Building at scale while maintaining fuel efficiency and hitting commercial milestones.
LNG specs are tight — especially around acid gas and mercury content. Many upstream sources don’t meet this standard without significant pretreatment.
Operator challenge: Designing flexible front-end systems to handle varying feedstock quality without ballooning costs.
Operator challenge: Balancing long-term fixed fee structures with market uncertainty.
Each has trade-offs in footprint, energy intensity, and startup cost. Choosing the wrong one can delay timelines or limit flexibility later.
If you are curious and would like to discuss these, connect with us.
Operator challenge: Matching process technology to project goals, gas characteristics, and long-term offtake strategy.
LNG fuelled vessels produce 23% less greenhouse gases. The typical LNG carrier size is 175,000m3, the scale of which can be seen in Figure 3 below. It’s cargo values between $21 to $39 million FOB.
Marine transport requires specialized LNG carriers, and receiving terminals must have the infrastructure for regasification, storage, and delivery. On land, LNG Virtual Pipelines are increasingly being used for off-grid power generation, truck refueling stations, and supplying gas to remote communities — all requiring small-scale storage hubs and flexible distribution networks.
Operator challenge: Designing for both large-scale export and decentralized delivery. As LNG applications diversify, infrastructure must be adaptable, scalable, and aligned with local demand — without driving up costs or complexity.
The EU Methane Regulation was updated in August of 2024 and applies to both new and existing LNG supply contracts.
Importers are now required to submit details on methane measurement, reporting, and verification (MRV) methodologies from both the exporter and the producer, as well as methane intensity data. Importers must also take “all reasonable efforts” to ensure the MRV measures at the level of the producer are equivalent to those defined by the EU Methane Regulation.
Operator challenge: In the United States market, the importer often does not have a direct contractual relationship with the producer. It is important to be aware of this complexity in order to comply with the reporting requirements.
LNG operators who succeed will be the ones who design for variability, build for efficiency, and plan for volatility.
Kindra referenced the Shell LNG Outlook for 2025. It is a current resource with various tools for you to learn more about the current state of LNG – in-depth report, key facts and figures video, infographics and more.
The team at CANUSA found Kindra’s PetroSkills presentation incredibly valuable and extend appreciation to WOGA for hosting the event.
EPA 40 CFR Part 60 establishes emission reduction standards for the control of methane and other VOCs emitted from onshore facilities. Subpart OOOO(a/b/c) of EPA 40 CFR Part 60 detail measures for proper Closed Vent System (CVS) design.
CANUSA EPC is here to help with code interpretation, requirement clarification, compliance evaluation, and certification. Enclosed is a framework detailing steps to prepare for a OOOO(a/b/c) Closed Vent System Compliance Evaluation.
As the Oil & Gas industry adapts to new environmental standards introduced through the EPA regulation OOOOb, operators are looking for low-emission substitutes for traditional instrument gas systems for pneumatic devices. Factors like power availability, extreme climates, retrofit feasibility, and long-term operating costs influence the most economical and technically viable instrument gas alternatives factor into the decision.
Although instrument air is a popular choice for pneumatic devices, there are a variety of instrument gas alternatives that are worth considering. These options include using liquid nitrogen tanks to supply gas to pneumatic devices, using electric actuators on valves, using a combustion-based or compressor-based vent capture system, and implementing low-emission alternatives to traditional pneumatic devices.
Natural gas-driven pneumatic devices have been the standard across upstream and midstream oil and gas sites for decades. These systems are simple, reliable, and easy to integrate, but they are a significant source of methane and VOC emissions in the oil and gas industry.
In the U.S., regulatory frameworks like EPA “OOOOb” (and soon, “OOOOc”) have required the transition away from traditional instrument gas systems. EPA Subpart OOOOb section 60.5390b requires operators to “design and operate each process controller affected facility with zero methane and VOC emissions to the atmosphere”, beginning January 22, 2027. The regulation includes mandatory monitoring and reporting for all facilities.
In Canada, producers are adopting emissions reduction strategies to align with both internal and external ESG targets, investor expectations, and net-zero commitments.
Controlling instrument gas emissions by implementing low-emission alternatives is the future of the industry.
The challenge? Each instrument gas alternative comes with its own trade-offs. Let’s evaluate!
These three considerations often stall progress or lead to overbuilt systems that don’t actually meet site needs. These are the top 3 we see:
Instrument air is one of the most established alternatives to gas-driven pneumatics, particularly in midstream facilities. These systems use electric-driven compressors to deliver clean, dry air to valves and controllers, eliminating methane emissions entirely.
Pros:
Cons:
Best for: Midstream or central facilities with power availability.
Vendors Offering Compression: UECompression Packages
An option for remote or off-grid sites, liquid nitrogen provides a zero-emission, power-free alternative for driving pneumatic equipment. Suppliers deliver nitrogen in pressurized vessels, and nitrogen is passed through regulators to send vaporized nitrogen to drive pneumatic devices.
Pros:
Cons:
Best for: Small well pads or facilities without power infrastructure.
Vendors Offering Liquid Nitrogen Systems: Kathairos Solutions
Electric actuators provide an emissions-free solution to control valve actuation, eliminating the need for access to pneumatic supply lines. They’re ideal for on/off valves in remote pipeline applications.
Pros:
Cons:
Best for: Remote oil and gas sites with few pneumatic valves, and no additional pneumatic users.
Vendors Offering Electric Actuation: Emerson
This strategy captures emissions from gas-driven pneumatics and routes them to a combustor, converting natural gas into CO₂. Although this method requires continued reporting with the EPA, it can offer OOOOb compliance with minimal disruption in operations.
Pros:
Cons:
Best for: Facilities with an existing combustor and limited resources for a full system overhaul.
This approach captures small amounts of vented gas from compressors and reuses it to power pneumatic devices. It’s a creative way to minimize waste and emissions using existing infrastructure.
Pros:
Cons:
Best for: Sites looking to improve compressor efficiency or reduce emissions without installing new systems.
There are numerous technologies available to reduce or eliminate emissions from instrument gas lines, whether it be implementing solutions within an existing instrument gas system, adopting instrument air or vaporized nitrogen, or utilizing electrically actuated valves. Although instrument air has been the most widely used pneumatic signal alternative within the industry, operators should understand that other technologies exist and may be a more practical solution for eliminating instrument gas emissions.
The technologies available allow for flexibility in a wide range of applications. There are options for sites with limited power availability, existing facilities looking to retrofit or upgrade their traditional instrument gas system, remote pipeline operations, and new facilities looking to build out with an emissions-free pneumatic system.
At CANUSA EPC, we help operators make informed decisions based on real-world experience. We’ve seen the nuances of site power, valve density, weather risk, and regulatory targets.
When you’re ready to talk instrumentation upgrades or emissions strategies, we’d be happy to share what’s working in the field.
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Instrument Gas Alternatives Comparison Guide
To accompany this blog, we have created a free comparison guide for your convenience. Download the Instrument Gas Alternatives Comparison Guide.
OOOO(b) for Compression Sites: Cost-Management Strategies for Methane Reduction
Want to ensure you meet budget and timelines? Read on for 7 strategies to consider.
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Megan Hurley, Engineer I
Importing industrial equipment into Alberta is not as simple as crossing the border. Alberta regulates pressure vessels, pressure piping, and related systems at the provincial level through the Alberta Boilers Safety Association (ABSA), creating unique requirements for owners, EPCs, and equipment suppliers.
Failure to address these requirements early—especially when importing used or surplus equipment—can result in customs delays, rejected equipment, forced retrofits, or extended commissioning timelines. This article outlines the key regulatory requirements governing pressure equipment in Alberta and explains how proactive compliance planning reduces project risk.
Pressure equipment in Alberta is governed under the Pressure Equipment Safety Regulation (PESR), administered by the Alberta Boilers Safety Association (ABSA). ABSA is responsible for ensuring the safe design, construction, installation, and operation of pressure vessels, pressure piping, boilers, and fittings.
More information on ABSA’s role and authority can be found at:
https://www.absa.ca
Pressure vessels imported into Alberta must comply with ASME Section VIII and be formally registered with ABSA prior to installation.
Key requirements include:
Used pressure vessels often require additional engineering review to validate original design conditions, service history, and suitability for continued operation.
Pressure piping systems require formal design registration with ABSA, regardless of where fabrication occurs.
Commonly applied codes include:
Design submissions typically include P&IDs, line designation tables, piping specifications, stress analysis (where required), and P.Eng-stamped documentation.
ABSA guidance on piping design registration is available at:
https://www.absa.ca/registration/pressure-piping
Manufacturers and contractors may be required to maintain an ABSA-registered Quality Management System (AQP) to fabricate or assemble pressure equipment for use in Alberta.
These systems govern welding procedures, welder qualifications, NDE, pressure testing, document control, and material traceability. Details on ABSA quality programs can be found at:
https://www.absa.ca/quality-management
Pressure equipment compliance must be coordinated with electrical and structural requirements.
Electrical systems must comply with:
Structural systems must meet:
Used equipment introduces additional risk due to incomplete documentation, unknown modification history, and outdated codes of construction. Alberta regulators frequently require engineering assessments or re-registration before acceptance.
CANUSA EPC has executed multiple projects involving reused equipment, including the NGL Fractionation Train Project, where previously utilized process equipment was integrated into a new fractionation facility while meeting Alberta pressure equipment and ABSA regulatory requirements:
NGL Fractionation Train
Similarly, the Expandable Gas Treatment Facility Project demonstrates how phased facility development and redeployed equipment can be successfully executed when regulatory compliance is addressed early in the design process:
Expandable Gas Treatment Facility
For additional insight into the regulatory challenges associated with used equipment, view our Used Equipment Webinar:
https://youtu.be/u26kI4QzzvQ?si=yQ1Hrxwhs5By6LTo
Addressing Alberta compliance requirements before equipment is shipped:
Projects involving reused pressure vessels or expandable process facilities benefit significantly from early engineering alignment with ABSA requirements.
Conclusion
Importing industrial equipment into Alberta requires more than ASME code compliance. Provincial registration, ABSA oversight, and P.Eng involvement are mandatory—particularly for pressure vessels and pressure piping systems.
Early compliance planning is especially critical for projects incorporating used or surplus equipment. With proper regulatory alignment, these assets can be successfully redeployed while maintaining safety, schedule certainty, and long-term operability.
If you are planning to import new or used industrial equipment into Alberta, our team can support ABSA registration, CRN management, engineering assessments, and full EPC execution. Contact us early to reduce regulatory risk and protect your project schedule.
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Beckie Ryan
The EPA’s latest methane rule – OOOO(b) – mandates zero-emission process controllers and pneumatic pumps, pushing gas compression facilities to invest in compliance projects. Want to ensure you meet budget and timelines? Read on for 7 strategies to consider in your compliance project program.
This whitepaper compiles data from previous projects and studies to support the financial analysis for power generation projects for operators determining what is the best onsite power solution for their project.
For operators tasked with reducing emissions from pneumatic devices, the ‘best’ instrument gas alternative isn’t always clear cut. With so many factors to consider (power availability, emissions goals, retrofit complexity) comparing your options, side by-side, can help! Our matrix summarizes key characteristics of each pneumatic signal alternative.
While no single solution fits every application, this overview can help narrow your focus and guide internal discussions about what’s realistically achievable at your facility. Determining the right solution means striking a balance of cost, complexity, and regulatory compliance.
Concerned about water saturated CO2 causing reliability and integrity issues? Trying to determine the right dehydration technology for your CO2 injection project? Download the presentation CANUSA EPC’s Tevin Champagne delivered at the GPA Midstream 2025 Technical Conference.
The Client needed to convert the instrument gas devices at (4) natural gas compression facilities in Oklahoma to instrument air service in a 6-month period.
OOOO(b) requires that process controllers emit no identifiable emissions. Instrument air systems are inherently emissions free, so they are not subject to requirements specified in subpart 60.5390b.
CANUSA EPC conducted site visits to audit all the instrument gas users at the facility, as-build the P&IDs for IA users, and validate facility electrical capacity to add an instrument air skid. Sizing requirements for the instrument air compressor skid were provided to account for all users and start air for the natural gas compressors.
The design and construction packages were executed in sequential order to meet accelerated schedule deadlines.
Engineering
Design
Reduction in fugitive emissions and venting from previous IG users and compression start-up
The Client was venting excessive vapors from their produced water tank battery due to higher operating pressure in their inlet separator. Operations had determined that the pressure drop between the slug catcher and the storage tank was resulting in entrained gas venting above OOOO(b) limits.
CANUSA EPC provided engineering and design to install an emission control device. An intermediate knockout drum and combustor were added to the facility. Liquids were routed from the slug catcher to the lower-pressure intermediate knockout, allowing more gases to flash off before sending the remaining liquids to the water tanks. All flashed gases were sent to the combustor.
Engineering
Design
Reduction in vented vapors from the tank battery
