Resource Type: Blog Posts

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: 

• Artificial intelligence 
• Switch fuel  
• Backup fuel, and 
• Transport fuel. 

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.  

Figure 1: Existing and under construction LNG facilities in North America (2016-2028) 

Lila breaks down what Kindra shared about the current market considerations. 

What is LNG and Why It Matters 

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 Nominal Gas Transportation  

Figure 2: Nominal natural gas transportation efficiency 

LNG’s uses span across: 

• Power generation and heating 
• Transportation fuel 
• Industrial heat source 
• Chemical feedstock 

LNG is emerging and North America is playing catch-up fast.  

• We are projected to double LNG exports by 2028 
• US produces 26% of international natural gas consumption demand 
• 64% of US LNG exports went to Europe in 2024 

LNG Liquefaction Facilities 

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: 

• 715 MMscfd of feed gas 
• 302,000 horsepower in electricity 
• 150 fin fan air-cooled exchangers 

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. 

2. Feed Gas Quality is a Hidden Risk 

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. 

3. US LNG Trading Long-Term vs. Spot Market 

• Fixed fee of $2.25-3.50 per MMBtu is paid irrespective of lifted volume 
• Shipping and re-gasification costs are covered by the buyer 
• Trading driven by margin between Henry Hub price and regional spot market

Operator challenge: Balancing long-term fixed fee structures with market uncertainty. 

4. Technology Choice Can Make or Break ROI 

• ConocoPhillips Optimized Cascade® is a process that utilizes pure propane, ethylene, and methane as refrigerants in a three-stage closed loop circuit. A heavies removal unit (HRU) and/or a nitrogen rejection unit (NRU) can be added to the LNG train depending on the feed composition and downstream requirements.  
• APCI-C3MR includes a pre-treatment train to sweeten, dehydrate, and pre-cool the feed gas. Four stages of propane chilling are used to cool the mixed refrigerant which then enters a cryogenic heat exchanger to liquefy the pre-treated gas stream. 
• Chart IPSMR™ technology utilizes a heavy hydrocarbon removal system to remove freezing components from the feed gas before liquefaction.  A single mixed refrigerant and a cold box comprised of brazed aluminum heat exchangers are then used to liquify the pre-treated gas stream.  

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. 

5. LNG Storage and Shipping 

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. 

Figure 3: LNG is pumped directly into the interior of the double hulled carrier for shipment. 

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.

6. European ESG Standards 

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 Outlook for 2025 

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.  

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. 

 

Controlling Instrument Gas Emissions 

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! 

 

Key Considerations 

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: 

1. Site Limitations 
   
   Power availability, space constraints, and environmental conditions will determine what is feasible.
2. Budgeting & ROI 
   
   Every solution requires both CAPEX & OPEX. Liquid nitrogen systems, while low in initial cost, come with recurring delivery fees. Electric actuators are expensive, power-intensive, and, on existing sites, require retrofitting of every actuated valve.
3. Technology Trade-offs 
   
   Each alternative has a unique set of pros and cons. Some offer zero emissions but require significant upfront investment. Others are easier to implement but come with ongoing operational costs or limited scalability. 

 

Comparing the Top Alternatives for Traditional Instrument Gas Systems  

Instrument Air Systems

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: 

• Easy integration  
• Eliminates all process controller emissions – OOOO(b) compliant with no continued reporting 
• Compatible with most existing pneumatic devices 
• Product saved – no longer using sales gas to operate pneumatic devices 
• Air is non-corrosive and abundant 
• Expandable to pneumatic pumps and other emission reduction efforts (i.e. start air) 

Cons: 

• Introduces an additional piece of rotating equipment  
• Requires power and space for compressors and dryers  
• Higher upfront capital costs  
• Possible rework of existing piping   
• Introduces an oxidizer into pneumatic lines  
• Increased operational effort due to required maintenance and troubleshooting  

Best for: Midstream or central facilities with power availability.

Vendors Offering Compression: UECompression Packages 

• 5 HP or 15 HP Reciprocating Packages 
• Duplex Recip. Package 
• 5 HP Rotary Scroll  
• Custom Packages 

 

Liquid Nitrogen Supply Systems 

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: 

• Easy integration 
• Eliminates all process controller emissions – OOOO(b) compliant with no additional reporting 
• Product saved – no longer using sales gas to operate pneumatic devices 
• Pros over air – no additional rotating equipment 
• Pros over gas – removes requirements for reporting to the EPA 
• N2 is inert and does not provide an oxidizer into the process 
• No additional power requirements 
• Easily scalable & reliable  
• No upfront capex requirements 
• Minimal operator involvement 
• Minimal seasonal, weather, or temperature implications 

Cons: 

• Requires regular nitrogen delivery (every 30–60 days) – adds to OPEX, delivery scheduling, risk of delays/impact to schedule 
• Safety concerns with the addition of a pressurized vessel 
• Not yet widely used, may face internal approval challenges 

Best for: Small well pads or facilities without power infrastructure.

Vendors Offering Liquid Nitrogen Systems: Kathairos Solutions  

• Provides services through the full timeline for integration, from site assessment to commissioning, monitoring, reporting, and operation. 

 

Electric Valve Actuators 

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: 

• Emission-free 
• Self-calibrating 
• Low energy requirement 
• Can be used in low temperature operation 
• No need for routing of pneumatic lines 
• Remote monitoring and configuration are available 
• Solar-powered options are available – remote, power-free pipeline applications 

Cons: 

• Significant upfront capex – not realistic for large facilities with many actuated valves  
• Slow response time – not suitable for tight process control  
• Not suitable or realistic for existing facilities – requires significant modification to existing valves  
• May not eliminate the need for pneumatic systems; other pneumatic signal users may exist apart from control valves  
• Limited applicability as an emissions reduction technology in industry   
• New technology – lack of familiarity or approval with clients and operators  
• Although additional energy requirement and cable routing.   
• Cannot operate on loss of power  

 Best for: Remote oil and gas sites with few pneumatic valves, and no additional pneumatic users. 

Vendors Offering Electric Actuation: Emerson  

• Varied applications suited for shut-down valves and control valves.  
• Offering range of sizes and duty cycles. 

 

Combustion-Based Vent Gas Capture 

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: 

• Can continue to use instrument gas, no need to modify existing piping  
• Eliminates need for additional rotating equipment, leading to equipment and operational savings  
• Low initial Capex (if combustor is existing on site)  
• No additional power requirements  
• Possible tank battery applications – routing captured pneumatic emissions to tank venting header  

Cons: 

• Requires design and installation of a cover that can capture emissions from existing equipment 
• Only realistic if there is an existing combustor that captured emissions can be routed to 
• Significant engineering and design time 
• Does not fully eliminate emissions from pneumatic devices. Monitoring and reporting are still required for OOOO(b) compliance 

Best for: Facilities with an existing combustor and limited resources for a full system overhaul.

 

Capturing Compressor Emissions for Instrument Gas Use 

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: 

• Reduces total emissions from compressors 
• Removes the need for header routing to compressors 
• No additional power requirements 
• Marginal increase in sales of gas 
• OOOO(b) compliance for compressor emissions capture and process controllers 

Cons: 

• Significant engineering and design time, modification of on-skid piping 
• Does not fully eliminate emissions from pneumatic devices. Monitoring and reporting are still required for OOOO(b) compliance. 

Best for: Sites looking to improve compressor efficiency or reduce emissions without installing new systems. 

 

Which Pneumatic Emissions Reduction Technology is Best?  

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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FURTHER EMISSIONS-REDUCTION READING  

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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Author(s) 

Megan Hurley, Engineer I 

External Sources 

1. https://www.epa.gov/natural-gas-star-program/rulemakings-policy-and-laws-address-methane-emissions-oil-and-gas-sector#:~:text=Methane%20Emissions%20Standards,-Final%20Rules%20to&text=In%202024%2C%20EPA%20issued%20a,methane%20emissions%20from%20existing%20sources.&text=In%202016%20%2D%20EPA%20issued%20three,permitting%20requirements%20for%20the%20industry. 
2. eCFR :: 40 CFR Part 60 Subpart OOOOb — Standards of Performance for Crude Oil and Natural Gas Facilities for Which Construction, Modification or Reconstruction Commenced After December 6, 2022  
3. https://www.canada.ca/en/services/environment/weather/climatechange/climate-plan/2035-emissions-reduction-target.html 

Introduction

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.

1. ABSA Jurisdiction and Pressure Equipment Regulation

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

2. Pressure Vessel Requirements for Imported Equipment

Pressure vessels imported into Alberta must comply with ASME Section VIII and be formally registered with ABSA prior to installation.

Key requirements include:

• Canadian Registration Number (CRN)
• P.Eng-stamped design calculations
• Manufacturer’s Data Reports
• ABSA-recognized fabrication and inspection records
• Material traceability and NDE documentation

Used pressure vessels often require additional engineering review to validate original design conditions, service history, and suitability for continued operation.

3. Pressure Piping Design Registration

Pressure piping systems require formal design registration with ABSA, regardless of where fabrication occurs.

Commonly applied codes include:

• ASME B31.3 – Process Piping
• CSA Z662 – Oil and Gas Pipeline Systems

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

4. Quality Management and Fabrication Controls

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

5. Electrical and Structural Compliance

Pressure equipment compliance must be coordinated with electrical and structural requirements.

Electrical systems must comply with:

• Canadian Electrical Code (CSA C22.1)
• CSA or UL-C certified components
• P.Eng-stamped electrical drawings

Structural systems must meet:

• Provincial building code requirements
• CSA W59 welding standards
• Site-specific wind and snow load criteria

6. Special Considerations for Used and Surplus Equipment

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

7. Why Compliance Before Shipping Matters

Addressing Alberta compliance requirements before equipment is shipped:

• Reduces border delays
• Avoids field rework
• Prevents inspection failures
• Protects project schedules and capital budgets

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.

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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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Author(s)

Beckie Ryan

Introduction

In January 2026, the U.S. Environmental Protection Agency finalized long-awaited updates to the New Source Performance Standards (NSPS) for stationary combustion turbines—marking the first major revision since 2006. With power generation developers increasingly dependent on flexible, rapid-deployment solutions such as temporary turbines and trailer-mounted generation, these changes bring important implications for project scheduling, emissions compliance, and technology selection.

This blog outlines what has changed, how the new temporary turbine subcategory works, and what developers should consider as they plan new installations or short-term power solutions.

Updated NOx Standards for Modern Turbines

The EPA’s final rule restructures emissions requirements by grouping turbines into subcategories based on:

• Heat input (MMBtu/hr)
• Thermal efficiency (≥38% or <38%)
• Expected utilization (12-month capacity factor)
• Fuel type and load conditions

The changes align emissions expectations with what modern combustion controls and SCR technology can realistically achieve.

Key NOx Standard Revisions

• Large, high-utilization turbines (>850 MMBtu/hr, >45% CF) must now meet single-digit NOx emissions using combustion controls + SCR.
• Medium and small turbines retain combustion-controls-only pathways with updated ppm limits.
• Natural gas remains the basis for hourly emissions performance.
• SO₂ standards remain unchanged, with more flexible compliance options.

For developers, these updates will influence technology specifications, EPC execution planning, and permitting timelines.

The New Temporary Turbine Subcategory

The 2026 rule introduces a dedicated regulatory framework for stationary temporary combustion turbines, addressing an industry need for short-term, flexible power during outages, commissioning, construction sequencing, or emergency support.

Key Features of the Temporary Turbine Category

• Applies to turbines up to 850 MMBtu/hr
• Limited to 24 months at a given location
• NOx standard: 25 ppm using combustion controls only
• Reduced monitoring and recordkeeping
• Exempts certain portable Title II-covered engines
• Prevents “serial swapping” to extend temporary status

This category enables faster, more efficient deployment of turbine temporary power and trailer-mounted power generation systems—without excessive compliance burden.

MW Output Estimates Based on EPA Heat Input Categories

Because EPA regulates turbines by heat input (MMBtu/hr), developers often need a practical translation into MW output. Using typical turbine thermal efficiencies, here is a rough guide:

Turbine Category	Heat Input	Efficiency	Approx. MW Output
Large	>850 MMBtu/hr	≥38%	~95 MW
Medium	50–850 MMBtu/hr	≥38%	5–95 MW
Small	≤50 MMBtu/hr	30–38%	4–6 MW
Temporary Turbines	≤850 MMBtu/hr	30–38%	5–95 MW

These estimates help developers size temporary solutions and anticipate the emissions requirements tied to turbine selection.

Economic and Project Delivery Implications

According to EPA’s Economic Impact Analysis, the updated rule is expected to:

• Reduce annual NOx emissions by up to 296 tons by 2032
• Save industry up to $87 million over eight years
• Focus SCR deployment only on large, high-duty units where it is cost-justified

For developers, this results in:

• Lower capital costs for many turbine classes
• Continued viability of non-SCR combustion turbines
• Streamlined permitting for temporary deployments
• Enhanced flexibility in project scheduling and outage planning

The regulatory environment now better supports short-term and contingency power solutions.

What Developers and Turbine Representatives Should Do Now

1. Assess Turbine Classification Early
Efficiency, utilization, and heat input now directly determine regulatory requirements.

2. Factor in Temporary Power Strategy
Temporary turbines provide cost-effective coverage for outages, interconnection delays, and commissioning.

3. Coordinate with OEMs and EPC Partners
Thermal efficiency thresholds and NOx limits influence model selection and long-term operating strategy.

4. Review Documentation Requirements
Temporary status requires manufacturer certification and periodic (five-year) testing records.

Conclusion

The EPA’s updated NOx standards significantly modernize the emissions landscape for new and modified turbines. For developers and OEM representatives, the changes reinforce the need to plan turbine selection and temporary power strategies early in the project lifecycle. With the introduction of the temporary turbine subcategory, the industry gains a more flexible, streamlined path for meeting both short-term and long-term power generation needs.

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If you need support navigating the new NOx standards, evaluating turbine options, or planning temporary generation during outages and construction, our team is here to help you develop a compliant and cost-effective strategy.

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Author(s)

Marc Collins

At one of our recent ethanol projects, we were tasked with developing a relief solution for a dense-phase CO2 system. Like most early-stage sequestration sites in the U.S., this one had no simple way to recycle or offload off-spec product during a process upset. When working with dense-phase CO2, roughly 300 psi and as cold as -15°F, you’re dealing with a unique beast. It’s cold, high-pressure, and doesn’t behave like most fluids in a natural gas processing plant.

If the transport offtake shuts in or the CO2 goes off spec, the challenge becomes: how do you relieve this safely? What makes it especially challenging is how rapidly it changes states under relief conditions. This phase change can cause various operational issues and presents a massive safety hazard. API STD 521 is considered the bible, but this was one of those times when we had to look beyond the basic code.

Problems with Relieving Dense-Phase CO2

Safe operational design of CO2 capture facilities requires relief designs for dense-phase CO2 through a PSV.  Relieving the CO2 liquid will induce a pressure drop and phase change, dramatically reducing the temperature during the relief. As the liquid expands, it pulls heat from its surroundings and transforms into a solid, sublimation effect. Dry ice begins to form at around -130°F. Relief temperatures can dip even lower, closer to -180°F. At these temperatures, you’re almost guaranteed to get solids that can:

• Clog or choke the relief device,
• Reduce flow capacity, or
• Completely block the path to relief.

A blocked relief device means the vessel is no longer protected. Leaving you with a serious safety issue. As more CO2 capture and processing facilities are constructed, the normal approaches for relieving unsafe conditions won’t work for CO2. This requires that we develop solutions that protect the equipment while leveraging best practices from the industry.

Code API STD 521 and Solid CO2 Plugging Risks

API STD 521: Guide for Pressure-relieving and Depressuring Systems is the go-to standard for pressure-relieving systems, as it acknowledges this flash freezing issue. Section 4.9.2 touches on “Liquid-Vapor Mixture and Solids Formation” and warns about the potential for flashing fluids to cause choking or blockages. It also cites wet propane as an example of a fluid that can form solids.

However, there’s an issue. API STD 521 states that “some fluids (e.g. carbon dioxide and wet propane) can form solids when they are discharged through the relieving device. No uniformly accepted method has been established for reducing the possibility of plugging”.

There’s no established method to reliably predict or mitigate plugging caused by solid CO2 formation. It tells you the hazard exists but leaves the solution up to you. This was the biggest gap we have found and had to address in the design of our CO2 capture facilities.

An Approach to Pressure Relief for CO2 Processing: “Burping” CO2 Safely

We started with a question: What’s the safest way to handle relief of pressure for dense-phase CO2 that can’t be recycled or sent down the line?

One solution we have designed in our processing facilities for CO2 is to block and hold the system and send large volumes of the dense phase liquid to the distillation column through control valves that trigger based on plant upsets. The column is capable of holding large volumes of CO2 and any amount that vaporizes while being held can naturally vent through the overhead vent.

Thermal relief valves (TRV’s) are used to protect any equipment and piping that can possibly be isolated by check valves and can’t be sent to the distillation column during a block and hold scenario. While a pipeline is shut in, and if the pipeline is exposed to a heat source, such as heat from solar radiation or even ambient conditions during hot summer months, the internal process material will also heat up, expand, and increase pressure. In this case, the CO2 is at the bubble point and can vaporize with heat exposure. If thermal expansion occurs, these TRV’s will relieve this isolated high-pressure vapor, and prevent over pressurization of the system. Once the vapor is relieved, the TRV will reseat, and not allow further relieving.

This constant relieving and reseating, or “burping” of warm, vaporized CO2 will reduce the risk of relieving dense phase CO2. This approach avoided the extreme phase change that commonly resulted in dry ice plugs.

The Trading Off to Venting CO2: Safety vs. Speed

Burping CO2 is a potentially time-consuming process. The maximum amount of dense phase CO2 possible is sent to the distillation column. However, this CO2 still has to vaporize naturally. The CO2 is condensed at bubble point temperature, so the delta temperature it has to overcome is relatively small, allowing the CO2 to vaporize in a relatively reasonable amount of time. The phase change, however, still imposes temperature issues due to the Joules-Thomson effect, and still has risk of plugging up the vent piping. Careful pressure monitoring of this vent is implemented to mitigate this risk.

The remaining CO2 to be relieved by the thermal relief valves will naturally reset once vaporized CO2 is relieved, naturally mitigating the risk of freezing and plugging. Considering the size of a plant, this can quickly take a long time to relieve an entire process. At CANUSA, we believe that this careful vapor relief vs. the prevention of piping freezing and plugging method is the safest known relief strategy for dense-phase CO2 if no recycle solution is available.

CO2, unlike the relief of natural gas, is heavier than air and will sink or collect in low-lying areas.  Therefore, venting locations need to be considered for safe release to ensure that de-oxygenated zones don’t form and there is adequate dispersion. Typical solutions include a vent pipe from the CO2 relief valves to higher elevations to allow the CO2 to disperse.  A slower release using the Burping method will release smaller amounts of CO2 over a longer period, reducing the risk the accumulation to unsafe concentrations. OSHA incidents for CO2 handling indicate how important dissipation considerations are for the safe operations of these facilities.

Considering Process Solutions to Reduce CO2 Venting

Reducing the scenarios of release to the atmosphere not only increases the safety of the operations, but less vented CO2 will also contribute to higher capture rates and more revenue.

To reduce the scenarios of vented CO2, recycle designs can be incorporated into the process. For some facilities, a recycling approach using a closed-loop system via a cooler and blower can reduce the need to vent altogether.

This isn’t always economical. Controlled heating of dense-phase CO2 to transition to a gas phase takes considerable energy. The CAPEX of this type of system is often cost prohibitive for the low increase in recapture rate, but it could mean a true 100% capture operation.

Engineering Safety into CO2 Capture Facilities

This project made one thing very clear: the CO2 sequestration industry is evolving quickly, but the standards aren’t updating at the same speed.

We’re seeing more clients face similar problems – like what to do when a process upset sends off-spec CO2 surging through the system? API STD 521 offers the “what,” but not the “how”. Safety is vital; so, sharing solutions for the “how” is important.

Our client for this carbon capture project required:

1. Thoughtful engineering to manage dense phase CO2 during upsets
2. Minimal contamination of dense phase CO2 product – less than 10 ppm O2 in product
3. Limited venting to the atmosphere

Our team developed a practical, field-ready solution. It’s not fast. But it satisfied all of our clients’ requirements and was the safest design.

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Author(s)

Nick Brown | Project Engineer

 

External Sources:

https://www.apiwebstore.org/standards/521

https://www.osha.gov/publications/hib19960605

 

 

 

 

 

 

 

 

As Colorado increases its efforts to combat climate change, the regulatory landscape for industrial operators (particularly in the natural gas processing plant and gathering system sectors) is evolving rapidly. The latest development, Colorado Air Quality Control Commission (AQCC) Regulation 22, introduces stringent greenhouse gas (GHG) reporting and reduction mandates that will significantly impact how midstream infrastructure is designed, operated, and maintained.

Understanding Regulation 22

Regulation 22, formally titled Colorado Greenhouse Gas Reporting and Emission Reduction Requirements (5 CCR 1001-26), establishes a comprehensive framework for monitoring, reporting, and ultimately reducing GHG emissions across multiple sectors of the state’s economy. For midstream operators (those responsible for gathering systems, natural gas processing plants, and transportation), this regulation will require balancing the development needs of producers and the emissions caps related to GHGs.

The rule mandates that Annual GHG reporting will be required for facilities that emit over 25,000 metric tons of CO₂e per year, as well as multiple sources if they fall below the federal reporting thresholds (e.g., the 25,000 metric ton CO₂e threshold under EPA’s 40 CFR Part 98).

Emission reduction targets are aligned with Colorado’s broader climate goals: a 26% reduction by 2025, 50% by 2030, and 90% by 2050 (from 2005 levels) established under  HB 19-1261.

On February 14, 2025, regulatory provisions became effective requiring every midstream company to participate in the emissions reduction program. They must achieve a collective midstream segment cap of 3,930,228 metric tons CO₂e by December 31, 2030, and maintain company-specific caps annually thereafter.

Implications for Midstream Project Development

From a project development perspective, Regulation 22, which was adopted in October 2024 and went into effect in early 2025, requires a paradigm shift. No longer can emissions be an afterthought. GHG emission reduction and methane reduction must be embedded from the earliest stages of project planning.

Here’s what midstream developers will need to consider with their emissions planning:

Carbon Footprint Assessments for New and Existing Assets

Developers must evaluate the lifecycle emissions of both current and planned infrastructure. This includes emissions from:

• Compressors and natural gas processing plants
• Fugitive methane leaks from gathering systems and pipelines
• Combustion sources such as flares and engines

Integrating carbon modeling tools into the front-end engineering design (FEED) process is now essential to determine how overall emissions levels will be impacted for the operator. The company-specific emissions caps are calculated using each operator’s 2021 MFCE GHG emissions.  October 2025 will require reporting under this program.

Technology Integration for Emission Reduction at Existing Assets

To meet reduction targets, midstream operators will consider solutions to lower the overall GHG emissions:

• Electrification of engines at compressor stations and natural gas processing plants
• Deployment of low-bleed or zero-bleed pneumatic devices
• Advanced leak detection and repair (LDAR) programs
• Carbon capture and storage (CCS) feasibility for large emitters

Operators will expect to see increased CapEx costs for compliance with marginal increases in processing capacity.  Some assets may be consolidated and decommissioned before the planned end of useful life. Client will focus on reducing their methane emissions first, considered 25 times more potent than CO2 emissions. CANUSA EPC has various solutions documented for ideas, check out a novel capture application for Turbine Seal Gas Capture.

Regulatory Compliance Strategy

Operators must establish robust compliance systems that include:

• Real-time emissions monitoring
• Accurate data collection and reporting mechanisms
• Internal audits and third-party verification

Failure to comply could result in penalties and reputational damage, especially as public scrutiny of fossil fuel infrastructure intensifies.

Civil penalties for midstream operators, under C.R.S. § 25-7-122, outline that violators may face civil penalties of up to $47,357 per day, per violation, with the amount adjusted annually for inflation. These penalties apply to a wide range of noncompliance issues, including failure to meet greenhouse gas (GHG) reduction targets, inadequate emissions reporting, and violations of leak detection and repair (LDAR) or combustion control requirements. In severe cases, the Colorado Department of Public Health and Environment (CDPHE) may also seek injunctive relief through the courts to compel compliance or halt operations.

In egregious circumstances (such as willful misconduct, repeated violations, or incidents causing serious harm), operators may also face permit suspension or revocation under C.R.S. § 34-60-121, enforced by the Energy and Carbon Management Commission. While this statute is relevant to upstream operators, it is not directly applicable to midstream GHG violations under Regulation 22 is not clearly defined. These consequences underscore the importance of strict regulatory compliance, accurate emissions tracking, and timely communication with regulators.

Looking Ahead for Natural Gas Processing Plants

Colorado’s Regulation 22 is not just a regulatory hurdle—it’s a signal of the energy transition underway. For midstream operators, aligning with these mandates is not only about compliance but also about future-proofing assets and maintaining social license to operate.

CANUSA EPC’s Role in Supporting Emissions Reductions

At CANUSA EPC, we understand the complexities of midstream development in a carbon-constrained world. Our multidisciplinary teams are equipped to:

• Conduct GHG impact assessments
• Design low-emission natural gas processing plants
• Integrate carbon capture and methane reduction technologies
• Engineer and plan electrical system upgrades

Have any questions or concerns?

Reach out to our team or start a free Class V estimate today to evaluate pathways to low-cost compliance for lower emission operations.

 

Author(s)

Forrest Churchill

 

External Sources:

https://www.sos.state.co.us/CCR/GenerateRulePdf.do?ruleVersionId=11724&fileName=5%20CCR%201001-26

https://www.sos.state.co.us/CCR/GenerateRulePdf.do?ruleVersionId=12032&fileName=5%20CCR%201001-9

https://cdphe.colorado.gov/changes-to-colorados-greenhouse-gas-reporting-requirements

https://leg.colorado.gov/bills/HB19-1261

https://www.sos.state.co.us/CCR/GenerateRulePdf.do?ruleVersionId=11843&fileName=5%20CCR%201001-9

The recently passed One Big Beautiful Bill Act preserved and enhanced carbon capture and storage (CCS) opportunities. One of the most impactful provisions for carbon capture is the expansion of the 45Q tax credit to $85 per metric ton for CO₂ used in Enhanced Oil Recovery (EOR) when the CO₂ is permanently stored in geological formations. 

This update significantly improves the financial outlook for oil and gas developers pursuing CO₂-EOR projects that meet geological sequestration criteria. In this article, we break down the implications of this policy shift and how project developers can capitalize on it. 

 

What’s New in 45Q Under the One Big Beautiful Bill? 

The One Big Beautiful Bill Act preserves and enhances the 45Q tax credit structure, with a critical clarification: CO₂ used in EOR now qualifies for the full $85/ton credit if it is geologically sequestered. This aligns EOR with saline storage projects in terms of credit value, provided the CO₂ is not vented or recycled but permanently stored underground in accordance with the EPA Class VI well regulations. 

Key Provisions:

• $85/ton for CO₂ captured and geologically stored, including via EOR 

• $60/ton remains for CO₂ used in EOR without geological storage 

• Transferability and direct pay options remain intact 

• No sunset clause, offering long-term certainty for developers 

This change reflects growing recognition of EOR’s role in both emissions reduction and domestic energy production. 

 

Three 45Q Benefits for CO2-EOR Project Developers 

1. Higher Credit Value = Better IRR 

The jump from $60 to $85/ton for qualifying EOR projects can significantly improve project economics. For example, a facility capturing 500,000 tons of CO₂ annually, means an additional $12.5 million/year in direct payments. 

2. Geological Storage Is Now a Strategic Differentiator 

Projects that integrate Class VI-compliant injection wells and robust monitoring, reporting, and verification (MRV) protocols can now access the higher credit tier. This incentivizes developers to design for permanence and compliance from day one. 

3. Financing Becomes More Attractive 

With higher credit values and continued transferability, tax equity investors are more likely to participate. This opens the door for alternative financing solutions like non-recourse project financing and joint ventures. 

Modular Deployment Reduces Risk and Cost in 45Q-Qualified Projects 

CO2 projects requirements still incentivize modular execution. Incorporating modular process packages and construction not only reduces risk related to field construction, it’s a strategic tool for moving scope that is governed by 45Q labor requirements onsite to offsite scope; providing lower costs overall and less liability due to prevailing wage. 

 

Why Modular Execution Matters: 

Reducing Risk for 45Q Wage Requirements

• Offsite labor is not subject to prevailing wage reporting or apprenticeship metrics, allowing the project to source market rate labor offsite and lowering the burden cost for the project.

• Only onsite labor requires detailed reporting for compliance tests for 45Q.  Shifting scope to offsite locations reduced the cost of compliance. 

Cost Control 

• Onsite scope is exposed to risks from weather delays and increased mobilization costs to site.  These costs can be better controlled in a fabrication facility, reducing contingency estimates for the project. 

• Labor demands in regions are affected by activity from all operators and the limited local skill pool.  Leveraging offsite fabrication allows for the scheduling of resources will limit risk to shortages. 

Timeline Optimization for 45Q Eligibility 

• Developers can begin construction on initial modules to meet IRS “begin construction” rules under Safe Harbor, securing eligibility while continuing to develop the rest of the project. 

CANUSA EPC’s execution model brings practical modularization to your project. Read more about some of our projects using modular approaches such as the Helium Multiwell Purification Battery or 50 MMSCFD Gas Compressor Station. 

 

Technical Requirements for Qualifying CO₂-EOR Projects 

According to the DOE’s CCUS Appendix H, projects must meet several technical criteria to qualify for the $85/ton credit: 

• High-purity CO₂ supply (typically >95%) 

• Compression systems capable of delivering CO₂ at 1,200–2,200 psi 

• Reservoirs with sufficient porosity and caprock integrity 

• EPA Class VI injection wells for geological storage 

• MRV plans approved by the EPA or equivalent state authority 

Developing a low-cost injection project requires selection of the proper dehydration approach for water-saturated CO2.  CANUSA EPC has released dehydration studies for CO2 projects, helping you select the correct technology for your CO2 project. 

 

Strategic Recommendations for CO2 EOR Evaluations 

• Determine Key Performance Metrics: Execute a FEED study to determine the proper metrics for financial investment; levelized cost per mton of CO2 product, carbon intensity to capture and process the CO2, and utility requirements. 

• Leverage Modular EPC Execution: Accelerate lead times, improve cost control, and reduce compliance costs with modularized systems. 

• Engage Tax Equity Partners Early: The $85/ton credit makes your project more bankable — capitalize on it. 

• Audit Your CO₂ Source: Ensure your CO₂ stream meets purity and volume thresholds to qualify. 

 

Conclusion 

The One Big Beautiful Bill Act has solidified the opportunity landscape for CO₂-EOR projects. By extending the $85/ton 45Q credit to EOR with geological storage, it rewards projects that combine carbon mitigation with energy production. For developers ready to meet the technical and regulatory requirements, the path to profitability just got a lot clearer. 

Ready to design a CO₂-EOR project that qualifies for $85/ton?
Connect with us to explore FEED support, modular compression systems, and turnkey EPC execution tailored for carbon capture and EOR. 

 

PAPER AUTHORS  

Forrest Churchill 

 

External Sources: 

https://www.congress.gov/bill/119th-congress/house-bill/1/text

https://www.epa.gov/uic/final-class-vi-guidance-documents

https://energy.sustainability-directory.com/term/non-recourse-financing/ 

https://www.energy.gov/sites/default/files/2022-10/CCUS-Appendix_H-030521.pdf  

https://www.globalccsinstitute.com/news-media/latest-news/u-s-preserves-and-increases-45q-credit-in-one-big-beautiful-bill-act/  

Production Gas Gathering: Liquid Management Strategies for Compression Systems Design

Safe and efficient compressor systems design for operations is more critical than ever in today’s competitive energy landscape. We see our clients focusing on increasing reliability and availability with their design by reducing site releases and shutdowns related to liquid management. Not only are they increasing their availability to serve their clients, but they are also reducing reporting and emission costs as well.

Liquid management for compressor systems has become increasingly complex – balancing safety, emissions regulations, and operational efficiency isn’t always simple. If your current setup still relies on direct drainage to atmospheric tanks or outdated separation equipment, you may face added risks, product loss, or compliance challenges. In this article, we cover more efficient alternatives to traditional liquid handling methods that reduce emissions, add protection, and improve overall system performance.

Directly Draining Slug Catcher Liquids to Atmospheric Tanks – Not Recommended

CANUSA EPC does not recommend draining condensate directly from the slug catcher to atmospheric storage tanks. While these direct setups were once common practice, they inherently limit the ability to provide effective relief protection. The atmospheric tanks could be exposed to station inlet pressure in the event of a level control valve failure at the slug catcher, which is a risk that undermines the overall safety of the facility. This realization has driven us to incorporate design for liquid management that safeguards critical process equipment during unexpected failures.

Enhancing Safety with Low Pressure Separators

One innovative solution we have implemented is to use a Low Pressure (LP) Separator to manage liquids leaving the slug catcher. The LP Separator acts as an intermediate stopping point, preventing flow directly into atmospheric tanks. By degassing the slug catcher liquids in the LP Separator, the flash vapors are directed to a Vapor Recovery Unit (VRU), reducing methane emissions on the facility.

This dual action:

• Protects the tanks in the unlikely event of a control valve failure, and
• Improves emissions reduction and enhances overall site reliability.

How Vapor Recovery Units (VRUs) Reduce Methane Emissions in Compressor Stations

Directing vapors from the LP Separator to the VRU plays a crucial role in improved VRU performance, thus reducing methane emissions. According to the EPA, Vapor Recovery Units are a proven method for capturing vented methane and reducing emissions from LP gas sources like compressor stations or storage tanks. This recovery supports environmental compliance, such as OOOO(b), and improves the overall efficiency by reducing product losses. In an industry where both safety and environmental stewardship are paramount, this strategy represents a win-win scenario for compressor station design.

This is a practical solution that checks two important boxes at once in compressor station design:

• Protecting your people and equipment, and
• Keeping emissions in check.

Overcoming Limitations of Coalescers with High Pressure Separation

In addition to LP Separators, CANUSA EPC’s engineering approach advocates for the use of a High Pressure (HP) Separator downstream of gas compression, yet upstream of the coalescer. Coalescers are traditionally used for gas/liquid separation; however, they’re not ideally suited for separating hydrocarbon liquids from water. Liquids are more efficiently removed when incorporating an independent HP separator into the process. Through separating high-pressure hydrocarbon liquids from water before they reach the coalescer, the HP separator will provide value through three key aspects:

1. Eliminates bulk liquid separation at coalescer
2. Improves separation efficiency
3. Extends the life of the coalescer

Preventing Hydrate Formation in Drain Systems

An important benefit of the HP Separator is its capacity to use separate drains for water and hydrocarbons. There is an increased risk of hydrate or ice formation when high-pressure fluids are discharged into a comingled line – this can cause costly blockages and potential safety incidents. The risk of hydrate formation is mitigated by directing water and hydrocarbon drain streams back to the inlet slug catcher via individual lines.

Driving Industry Reliability and Best Practices

The use of low-pressure and high-pressure separators in compressor stations represents the evolution of best practices for compressor systems and compressor station design. At CANUSA EPC, our designs incorporate integrated safety and efficiency best practices. By revising outdated practices, such as direct draining from slug catchers, we protect atmospheric storage tanks while improving liquid management and emissions reduction performance. These process engineering design principles enhance safety, reduce downtime, and decrease emissions in an increasingly cost-sensitive industry.

Key Takeaways: Improving Compressor Station Design for Safer Liquid Management

Innovation in compressor station design is vital for meeting today’s rigorous safety and environmental standards. Incorporation of LP and HP separators in compressor system designs demonstrates how thoughtful engineering can directly impact reliability, operational excellence, and environmental compliance.

We look forward to exploring further advancements, from automated control systems to predictive maintenance technologies, that will shape the future of compressor station operations. As the oil and gas industry continues to evolve, the pursuit of smarter, more resilient designs will remain at the forefront of our efforts.

PAPER AUTHORS: 

Ted Zeiger, PE, Project Engineering Lead
Connect on LinkedIn

External Sources:

https://www.epa.gov/natural-gas-star-program/vapor-recovery-units

The development of carbon capture, utilization, and storage (CCUS) projects presents unique opportunities and challenges for investment firms looking to deploy capital into the carbon capture space. CANUSA EPC, with its extensive experience in evaluating and developing carbon capture projects, offers valuable insights and strategies to navigate this complex landscape.

Determining Your Levelized Cost of CO2

Determining the internal rate of return requires accurate Capital Expenditures as well as Operational Expenditures to determine the levelized cost of capture and transport of the CO2.

The CapEx for the facility encompasses the construction of the capture process to provide the CO2 product. A large portion of CO2 project equipment costs will be tied up in compression equipment. Typically, large compression systems are custom-fabricated and require specialized services that are not readily available. Instead, CANUSA EPC recommends deploying compression systems with smaller units in parallel designs. This solution is more likely to:

• be readily available (compress schedule),
• allow for efficient capacity modulation of the system,
• provide efficient scalability for capacity, and
• produce higher reliability for the project.

The OpEx to run the facility is predominately based on power consumption. There are important strategies to ensure the facility runs efficiently and power costs are structured appropriately. VFDs and soft starts can be used in combination to lower demand spikes and electricity bills. Read more about electrical drive approaches.

Technology Development for CO2 Capture

Capturing CO2 from sources with higher concentrations of CO2 (greater than 8%) leads to lower separation costs and less energy consumption. High concentrations of CO2 present de-risked capture technology, as they can rely on traditional methods. Recent technological deployments for engine emission applications are trending towards $40 per metric ton of CO2. CANUSA EPC highlights that CO2 emissions from amine plants and ethanol facilities are relatively pure and can be economically delivered to pipeline or beverage grade specifications. Read a detailed case study: CO2 Injection & Amine Emissions Capture.

Transportation: Best By Truck, Rail, or Pipeline?

Transporting CO2 from the capture site can be done via truck, rail, or pipeline, similar to oil or bulk goods. Trucking is suitable for smaller projects, topping out around 150 metric tons per day (MTPD) due to logistical complexities. Rail applications are viable for projects approaching 400 MTPD when there is an existing train line near the facility. Pipelines are the most efficient way to transport large amounts of CO2 to hubs for injection or distribution to industrial users. CANUSA EPC advises focusing on injecting CO2 into saline reservoirs close to the emitter source in states with primacy over Class II injection wells, as these projects are quicker to approve¹.

What Government Incentives are Applicable to CO2 Capture?

The long-term commercial use of CO2 as an emission removal tool is still developing. Government programs, such as those funded under the Inflation Reduction Act (IRA), support many active projects through reimbursement programs like 45Q or 45Z. CANUSA EPC emphasizes the importance of executing projects in a manner that meets IRA requirements to take advantage of these incentives. This approach provides flexibility to adapt to any changes in the program. Read more about rebates for your project.

Approaching Carbon Developments Wisely

To successfully navigate the complexities of CO2 project development, it’s crucial to consider:

• developing a levelized cost of carbon that accounts for CapEx and OpEx,
• leveraging reliable CO2 capture technologies,
• optimizing transportation methods or remove them with onsite injection, and
• capitalizing on government incentives.

By implementing these strategies, investment firms can enhance the efficiency and profitability of their CO2 projects while contributing to a sustainable future.

 

Let’s work together to help build a financial model for your CO2 project.  With just a few data points, we will provide a report that will bring clarity to your project’s feasibility – request a free Class V Estimate.

 

Source: ¹ https://www.epa.gov/uic/primary-enforcement-authority-underground-injection-control-program-0

 

Gas compression facilities in the USA must adapt to the EPA’s latest methane regulations (Final Rule¹), Subpart OOOO(b), which mandate significant reductions in methane emissions from key equipment. Executing emission reduction projects presents opportunities to leverage a strategic approach to engineering, procurement, and construction (EPC) to maintain cost efficiency.

What is OOOO(b) Compliance?

The EPA’s OOOO(b) Rule is a major regulatory update aimed at curbing methane emissions from oil and gas operations. The EPA’s Rule mandates “strict performance standards for new, modified, and reconstructed sources”.

For gas compression facilities, compliance requires a shift in operational practices. There are three distinct applications that apply:

Process Controllers & Pneumatic Pumps – Natural gas-driven controllers and pneumatic pumps, which historically vented methane into the atmosphere, must be replaced with zero-emission alternatives (IE. instrument air-driven controllers).

Dry Seals for Compressors – Dry-seal centrifugal compressors must maintain a volumetric flow rate at or below 10 standard cubic feet per minute (scfm) per compressor seal to minimize emissions.

Storage Vessels/Tank Batteries – Storage tanks at compression stations must now achieve a 95% reduction in methane and VOC emissions, significantly changing how operators manage emissions control systems.

GET THE OOOO(b) GUIDE

Compliance Dates with EPA 40 CFR Part 60, Subpart OOOO?

Originally published in December 2023, EPA’s Final Rule⁽¹⁾ provided lead time for industry to comply. This subpart establishes emission standards and compliance schedules for the control of volatile organic compounds (VOC) and sulfur dioxide (SO2) emissions from affected oil and gas facilities that commence construction, modification, or reconstruction after December 6, 2022.

Compliance with the new performance standards is stated in section 60.5370b². “You must be in compliance with the standards of this subpart no later than May 7, 2024, or upon initial startup, whichever date is later, except as specified per….”

This deadline has forced operators to focus on upgrades in an accelerated manner. With the right plan in place, you can realize cost savings and operational efficiencies.

Instrument Air Conversions: Save Time & Money

Converting from instrument gas to instrument air across multiple sites is a capital-intensive process. In a recent methane reduction project, CANUSA EPC achieved substantial cost savings and accelerated schedule for their operator using these strategies.

Develop a Compliance Program Team

Project Manager, Josh Hoeft, explains “the most cost-effective approach is to develop a Compliance Program – a structured, regional approach where you select a preferred EPC firm, issue a bulk order on IA package for volume discounting and guaranteed delivery schedules, and contract a regional construction firm familiar with the sites. This eliminates redundancies, reduces costs, and streamlines your path to compliance.”

Template-Based Engineering

“Experienced EPCs should be utilizing a template-based approach to engineering – a copy-paste design format across facilities. This approach:

• expedites execution,
• minimizes engineering re-work, and
• ensures uniformity in documentation for installation

At CANUSA EPC, we’ve realized reduced engineering costs by up to 25% per site when we execute a Compliance Program on multiple sites (as compared to a single site),” says Hoeft.

Package Negotiations

Bulk procurement of IA systems can result in total project cost reductions of 10%. A Compliance Program recognizes savings on the purchase price of equipment, and the schedule for delivery can also be staggered –  allowing the engineering and construction team to streamline their engagements to reduce demobilization costs.

Lessons learned from the first or second installation are incorporated into the execution plan. Every future installation becomes more efficient, creating a ‘snowball effect’. When executing multiple sites concurrently, you do not realize these benefits.

Single-Sourced Contractor

Having a dedicated contractor on multiple sites will improve efficiencies for scope development and allow the contractor to remove risk from their estimates, resulting in site costs that finish on budget. Contractors can develop a plan to support operations and minimize downtime, which often is the largest cost for these compliance projects – missed operating revenue.

OOOO(b) Planning & Operational Efficiencies

From past compliance projects, CANUSA EPC has found critical execution aspects that impact schedule and add risk to project costs.

Engaging Utilities Early

Electrical power capacity and availability must be analyzed early. This determines whether the existing electrical infrastructure (on site and from the utility) can accommodate the new loads required for OOOO(b) projects.

Electrical utilities are often backlogged. Requesting new/upgraded services or electrical equipment, like transformers, can result in long and unexpected lead items. It can take several months for the local power provider to run a new power line or install a new bucket transformer if the utility is the limiting factor.

Engaging utilities early in the design process can prevent significant delays.

Involve Site Operations in Design

From an engineering perspective, early and continuous engagement with operations personnel is critical. Facility staff possess in-depth knowledge of site-specific factors  – existing infrastructure, space constraints, and potential integration challenges. Their input optimizes pipe routing, equipment placement, and ensures IA systems are designed with future facility expansions in mind.

Since operators are responsible for routine inspections and emissions monitoring, their early input ensures new systems are both practical and sustainable.

If your EPC is not involving your operations team from the outset, you may lose foresight on site functionality, long-term maintenance, and accessibility. Collaboration also helps your EPC understand operational priorities, reducing the risk of installing systems that require extensive modifications after deployment.

Planning for Reduced Downtime and Increased Reliability

Facility outages and prolonged downtime affect your bottom line. Engaging operations will plan for final mechanical tie ins and reduce facility downtime. On-site staff are knowledgeable about which equipment is critical for continued operation and can provide tie in plans that may avoid a facility shutdown.

If electrical tie ins require energy isolation, affecting critical equipment like the station PLC, developing a temporary power plan using a generator can be a viable option to keep the station running during the tie ins.

Abnormal operation of natural gas facilities – during start-ups and shutdowns – present the most hazardous operating scenarios when compared to steady state operation. Avoiding facility shutdowns altogether helps mitigate unsafe operating conditions.

Long-Term Benefits and Regulatory Compliance

For gas compression facilities, the implementation of OOOO(b) compliance measures satisfies regulatory requirements and creates opportunities for operational efficiencies. Companies that invest in structured IG-to-IA conversion programs, bulk material procurement, and standardized engineering designs will benefit from reduced compliance costs, improved environmental performance, and increased asset reliability.

Moving Forward with Compliance

Are you confident about what deadlines apply to your facilities?

CANUSA EPC has created a OOOO(b) Guide to help you gain clarity on what EPA Methane Rules apply to your compression operations.

1. Simplified EPA Matrix focusing only on dry seals, pumps, storage vessels, fugitive emissions, and process controllers.
2. Decision-making diagrams to guide you on what OOOO(b) sub-rules are pertinent – dry seal venting of centrifugal compressors, gas pneumatic devices, fugitive emissions, storage vessel, and pumps.
3. Project Profiles detailing specific approaches for dry seal capture, tank venting emissions reduction, and IG-to-IA conversion.

GET THE OOOO(b) GUIDE

 

Connect with Josh Hoeft on LinkedIn 

Connect with Megan Hurley on LinkedIn

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SOURCES:
¹ EPA Methane Final Rule: epa.gov/controlling-air-pollution-oil-and-natural-gas-operations/epas-final-rule-reduce-methane-and-other

² EPA 40 CFR Part 60 New Performance Standards 60.5370b2: ecfr.gov/current/title-40/section-60.5370b