GE to host EV experience tour

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GE has announced it will host an electric vehicle EV tour in seven U.S. cities that will "bring GE experts together with local businesses, industry leaders, and public sector stakeholders for educational workshops, test drives, and dialogue on the business case for EV ecosystems."

GE said it is working with GM, Ford, Toyota, Navistar, Smith Electric Vehicles, Mitsubishi, Coda, Smart, THINK and other organizations on the tour.

The company said it has already committed to purchase 25,000 EVs by 2015 for its own fleet and for fleet customers. GE noted it owns one of the world's largest vehicle fleets, operates a leading global fleet management business, and offers a "portfolio of product solutions including charging stations, circuit protection equipment and transformers that touch every part of electric vehicle infrastructure development."

GE said it is hosting the EV tour help other businesses and key stakeholders understand technical and business approaches for deploying pure electric and plug-in hybrid electric vehicles.

Each day-long stop in cities along the tour will include presentations by GE and community leaders, workshops to help stakeholders with EV planning, deployment, and integration strategies, and test drives.

Scheduled Tour dates are:

• San Francisco, March 10

• Seattle, March 15

• Los Angeles, March 17

• San Diego, March 22

Additional EV Experience Tour dates will be announced in Austin, New York City, and Washington, D.C. for Spring 2011.

"GE is playing a leadership role in the transformation to smarter transportation solutions and a smarter electrical grid," said Luis Ramirez, CEO, GE Energy Industrial Solutions. "Our EV Experience Tour is an important way for us to engage communities across the United States in the discussion about the economic and environmental advantages of EV deployment."

"We're committed to helping our customers learn what electric vehicles can do for their organizations," added Clarence Nunn, president & CEO of GE Capital Fleet Services. "Each of our tour stops will give participants first-hand exposure to the technical and business considerations for EV deployment and put them on a path toward adoption."

In support of the tour, GE is making an electric vehicle readiness toolkit is available on its ecomagination.com website to help municipalities, customers, and individuals prepare for wide-scale electric vehicle deployment.

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Ontario Teachers Pension Plan agrees to acquire a 25% stake in SSEN Transmission

Ontario Teachers SSEN Transmission Investment advances UK renewable energy, with a 25% minority stake in SSE plc's electricity transmission network, backing offshore wind, grid expansion, and Net Zero 2050 goals across Scotland and UK.

 

Key Points

A 25% stake by Ontario Teachers in SSE's SSEN Transmission to fund UK grid upgrades and accelerate renewables.

✅ £1,465m cash for 25% minority stake in SSEN Transmission

✅ Supports offshore wind, grid expansion, and Net Zero targets

✅ Partnering SSE plc to deliver clean, affordable power in the UK

 

Ontario Teachers’ Pension Plan Board (‘Ontario Teachers’) has reached an agreement with Scotland-based energy provider SSE plc (‘SSE’) to acquire a 25% minority stake in its electricity transmission network business, SSEN Transmission, to provide clean, affordable renewable energy to millions of homes and businesses across the UK, reflecting how clean-energy generation powers both the economy and the environment.

The transaction is based on an effective economic date of 31 March 2022, and total cash proceeds of £1,465m for the 25% stake are expected at completion. The transaction is expected to complete shortly.

Measures such as Ontario's 2021 electricity rate reductions have aimed to ease costs for businesses, informing broader discussions on affordability.

SSEN Transmission, which operates under its licenced entity, Scottish Hydro Electric Transmission plc, transports electricity generated from renewable resources – including onshore and offshore wind and hydro – from the north of Scotland across more than a quarter of the UK land mass amid scrutiny of UK electricity and gas networks profits under the regulatory regime. The investment by Ontario Teachers’ will help support the UK Government’s Net Zero 2050 targets, including the delivery of 50GW of offshore wind capacity by 2030.

Charles Thomazi, Senior Managing Director, Head of EMEA Infrastructure & Natural Resources, from Ontario Teachers’ said, noting that in Canada decisions like the OEB decision on Hydro One's T&D rates guide utility planning:

“SSEN Transmission is one of Europe’s fastest growing transmission networks. Its network stretches across some of the most challenging terrain in Scotland – from the North Sea and across the Highlands – to deliver safe, reliable, renewable energy to demand centres across the UK.

We’re delighted to partner again with SSE and are committed to supporting the growth of its network and the vital role it plays in the UK’s green energy revolution.”

Investor views on regulated utilities can diverge, as illustrated by analyses of Hydro One's investment outlook that weigh uncertainties and risk factors.

Rob McDonald, Managing Director of SSEN Transmission, said:

“With the north of Scotland home to the UK’s greatest resources of renewable electricity we have a critical role to play in helping deliver the UK and Scottish Governments net zero commitments.  Our investments will also be key to securing the UK’s future energy independence through enabling the deployment of homegrown, affordable, low carbon power.

“With significant growth forecast in transmission, bringing in Ontario Teachers’ as a minority stake partner will help fund our ambitious investment plans as we continue to deliver a network for net zero emissions across the north of Scotland.” 

Ontario Teachers’ Infrastructure & Natural Resources group invests in electricity infrastructure worldwide to accelerate the energy transition with current investments including Caruna, Finland’s largest electricity distributor, Evoltz, a leading electricity transmission platform in Brazil, and Spark Infrastructure, which invests in essential energy infrastructure in Australia to serve over 5 million homes and businesses.

In Ontario, distribution consolidation has included the sale of Peterborough Distribution to Hydro One for $105 million, illustrating ongoing sector realignment.

 

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California's Next Electricity Headache Is a Looming Shortage

California Electricity Reserve Mandate requires 3.3 GW of new capacity to bolster grid reliability amid solar power volatility, peak demand, and wildfire-driven blackouts, as CPUC directs PG&E, Edison, and Sempra to procure resource adequacy.

 

Key Points

A CPUC order for utilities to add 3.3 GW of reserves, safeguarding grid reliability during variable renewables and peaks

✅ 3.3 GW procurement to meet resource adequacy targets

✅ Focus on grid reliability during peak evening demand

✅ Prioritizes renewables, storage; limits new fossil builds

 

As if California doesn’t have enough problems with its electric service, now state regulators warn the state may be short on power supplies by 2021 if utilities don’t start lining up new resources now.

In the hopes of heading off a shortfall as America goes electric, the California Public Utilities Commission has ordered the state’s electricity providers to secure 3.3 additional gigawatts of reserve supplies. That’s enough to power roughly 2.5 million homes. Half of it must be in place by 2021 and the rest by August 2023.

The move comes as California is already struggling to accommodate increasingly large amounts of solar power that regularly send electricity prices plunging below zero and force other generators offline so the region’s grid doesn’t overload. The state is also still reeling from a series of deliberate mass blackouts that utilities imposed last month to keep their power lines from sparking wildfires amid strong winds. And its largest power company, PG&E Corp., went bankrupt in January.

Now as natural gas-fired power plants retire under the state’s climate policies, officials are warning the state could run short on electricity on hot evenings, when solar production fades and commuters get home and crank up their air conditioners. “We have fewer resources that can be quickly turned on that can meet those peaks,” utilities commission member Liane Randolph said Thursday before the panel approved the order to beef up reserves.

The 3.3 gigawatts that utilities must line up is in addition to a state rule requiring them to sign contracts for 15% more electricity than they expect to need. Some critics question the need for added supplies, particularly after the state went on a plant-building boom in the 2000s.

But California’s grid managers say the risk of a shortfall is real and could be as high as 4.7 gigawatts, especially during heat waves that test the grid again. Mark Rothleder, with the California Independent System Operator, said the 15% cushion is a holdover from the days before big solar and wind farms made the grid more volatile. Now it may need to be increased, he said.

“We’re not in that world anymore,” said Rothleder, the operator’s vice president of state regulatory affairs. “The complexity of the system and the resources we have now are much different.”

The state’s three major utilities, PG&E, Edison International and Sempra Energy, will be largely responsible for securing new supplies. The commission banned fossil fuels from being used at any new power generators built to meet the requirement — though it left the door open for expansions at existing ones.

Some analysts argue California is exporting its energy policies to Western states, making electricity more costly and less reliable.

PG&E said in an emailed statement that it was pleased the commission didn’t adopt an earlier proposal to require 4 gigawatts of additional resources. Edison similarly said it was “supportive.” Sempra didn’t immediately respond with comment.

 

Extending Deadlines

The pending plant closures are being hastened by a 2020 deadline requiring California’s coastal generators to stop using aging seawater-cooling systems. Some gas-fired power plants have said they’ll simply close instead of installing costly new cooling systems. So the commission on Thursday also asked California water regulators to extend the deadline for five plants.

The Sierra Club, meanwhile, called on regulators to turn away from fossil fuels altogether, saying their decision Thursday “sets California back on its progress toward a clean energy future.”

The move to push back the deadline also faces opposition from neighboring towns. Redondo Beach Mayor Bill Brand, whose city is home to one of the plants in line for an extension, told the commission it wasn’t necessary, since California utilities already have plenty of electricity reserves.

“It’s just piling on to that reserve margin,” Brand said.

 

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B.C.'s Green Energy Ambitions Face Power Supply Challenges

British Columbia Green Grid Constraints underscore BC Hydro's rising imports, peak demand, electrification, hydroelectric variability, and transmission bottlenecks, challenging renewable energy expansion, energy security, and CleanBC targets across industry and zero-emission transportation.

 

Key Points

They are capacity and supply limits straining B.C.'s clean electrification, driving imports and risking reliability.

✅ Record 25% imports in FY2024 raise emissions and costs

✅ Peak demand and transmission limits delay new connections

✅ Drought reduces hydro output; diversified generation needed

 

British Columbia's ambitious green energy initiatives are encountering significant hurdles due to a strained electrical grid and increasing demand, with a EV demand bottleneck adding pressure. The province's commitment to reducing carbon emissions and transitioning to renewable energy sources is being tested by the limitations of its current power infrastructure.

Rising Demand and Dwindling Supply

In recent years, B.C. has experienced a surge in electricity demand, driven by factors such as population growth, increased use of electric vehicles, and the electrification of industrial processes. However, the province's power supply has struggled to keep pace, and one study projects B.C. would need to at least double its power output to electrify all road vehicles. In fiscal year 2024, BC Hydro imported a record 13,600 gigawatt hours of electricity, accounting for 25% of the province's total consumption. This reliance on external sources, particularly from fossil-fuel-generated power in the U.S. and Alberta, raises concerns about energy security and sustainability.

Infrastructure Limitations

The current electrical grid is facing capacity constraints, especially during peak demand periods, and regional interties such as a proposed Yukon connection are being discussed to improve reliability. A report from the North American Electric Reliability Corporation highlighted that B.C. could be classified as an "at-risk" area for power generation as early as 2026. This assessment underscores the urgency of addressing infrastructure deficiencies to ensure a reliable and resilient energy supply.

Government Initiatives and Investments

In response to these challenges, the provincial government has outlined plans to expand the electrical system. Premier David Eby announced a 10-year, $36-billion investment to enhance the grid's capacity, including grid development and job creation measures to support local economies. The initiative focuses on increasing electrification, upgrading high-voltage transmission lines, refurbishing existing generating facilities, and expanding substations. These efforts aim to meet the growing demand and support the transition to clean energy sources.

The Role of Renewable Energy

Renewable energy sources, particularly hydroelectric power, play a central role in B.C.'s energy strategy. However, the province's reliance on hydroelectricity has its challenges. Drought conditions in recent years have led to reduced water levels in reservoirs, impacting the generation capacity of hydroelectric plants. This variability underscores the need for a diversified energy mix, with options like a hydrogen project complementing hydro, to ensure a stable and reliable power supply.

Balancing Environmental Goals and Energy Needs

B.C.'s commitment to environmental sustainability is evident in its policies, such as the CleanBC initiative, which aims to phase out natural gas heating in new homes by 2030 and achieve 100% zero-emission vehicle sales by 2035, supported by networks like B.C.'s Electric Highway that expand charging access. While these goals are commendable, they place additional pressure on the electrical grid. The increased demand from electric vehicles and electrified heating systems necessitates a corresponding expansion in power generation and distribution infrastructure.

British Columbia's green energy ambitions are commendable and align with global efforts to combat climate change. However, achieving these goals requires a robust and resilient electrical grid capable of meeting the increasing demand for power. The province's reliance on external power sources and the challenges posed by climate variability highlight the need for strategic investments in infrastructure and a diversified energy portfolio, guided by BC Hydro review recommendations to keep electricity affordable. By addressing these challenges proactively, B.C. can pave the way for a sustainable and secure energy future.

 

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Pickering nuclear station is closing as planned, despite calls for refurbishment

Ontario Pickering Nuclear Closure will shift supply to natural gas, raising emissions as the electricity grid manages nuclear refurbishment, IESO planning, clean power imports, and new wind, solar, and storage to support electrification.

 

Key Points

Ontario will close Pickering and rely on natural gas, increasing emissions while other nuclear units are refurbished.

✅ 14% of Ontario electricity supplied by Pickering now

✅ Natural gas use rises; grid emissions projected up 375%

✅ IESO warns gas phaseout by 2030 risks blackouts, costs

 

The Ontario government will not reconsider plans to close the Pickering nuclear station and instead stop-gap the consequent electricity shortfall with natural gas-generated power in a move that will, as an analysis of Ontario's grid shows, hike the province’s greenhouse gas emissions substantially in the coming years.

In a report released this week, a nuclear advocacy group urged Ontario to refurbish the aging facility east of Toronto, which is set to be shuttered in phases in 2024 and 2025, prompting debate over a clean energy plan after Pickering as the closure nears. The closure of Pickering, which provides 14 per cent of the province’s annual electricity supply, comes at the same time as Ontario’s other two nuclear stations are undergoing refurbishment and operating at reduced capacity.

Canadians for Nuclear Energy, which is largely funded by power workers' unions, argued closing the 50-year-old facility will result in job losses, emissions increases, heightened reliance on imported natural gas and an electricity supply gap across Ontario.

But Palmer Lockridge, spokesperson for the provincial energy minister, said further extending Pickering’s lifespan isn’t on the table.

“As previously announced in 2020, our government is supporting Ontario Power Generation’s plan to safely extend the life of the Pickering Nuclear Generating Station through the end of 2025,” said Lockridge in an emailed response to questions.

“Going forward, we are ensuring a reliable, affordable and clean electricity system for decades to come. That’s why we put a plan in place that ensures we are prepared for the emerging energy needs following the closure of Pickering, and as a result of our government’s success in growing and electrifying the province’s economy.”

The Progressive Conservative government under Premier Doug Ford has invested heavily in electrification, sinking billions into electric vehicle and battery manufacturing and industries like steel-making to retool plants to run on electricity rather than coal, and exploring new large-scale nuclear plants to bolster baseload supply.

Natural gas now provides about seven per cent of the province’s energy, a piece of the pie that will rise significantly as nuclear energy dwindles. Emissions from Ontario’s electricity grid, which is currently one of the world’s cleanest with 94 per cent zero-emission power generation, are projected to rise a whopping 375 per cent as the province turns increasingly to natural gas generation. Those increases will effectively undo a third of the hard-won emissions reductions the province achieved by phasing out coal-fired power generation.

The Independent Electricity System Operator (IESO), which manages Ontario’s grid, studied whether the province could phase out natural gas generation by 2030 and concluded that “would result in blackouts and hinder electrification” and increase average residential electricity costs by $100 per month.

The Ontario Clean Air Alliance, however, obtained draft documents from the electricity operator that showed it had studied, but not released publicly, other scenarios that involved phasing out natural gas without energy shortfalls, price hikes or increases in emissions.

The Ontario government will not reconsider plans to close the Pickering nuclear station and instead stop-gap the consequent electricity shortfall facing Ontario with natural gas-generated power in a move that will hike the province’s greenhouse gas emissions.

One model suggested increasing carbon taxes and imports of clean energy from other provinces could keep blackouts, costs and emissions at bay, while another involved increasing energy efficiency, wind generation and storage.

“By banning gas-fired electricity exports to the U.S., importing all the Quebec water power we can with the existing transmission lines and investing in energy efficiency and wind and solar and storage — do all those things and you can phase out gas-fired power and lower our bills,” said Jack Gibbons, chair of the Ontario Clean Air Alliance.

The IESO has argued in response that the study of those scenarios was not complete and did not include many of the challenges associated with phasing out natural gas plants.

Ontario Energy Minister Todd Smith asked the IESO to develop “an achievable pathway to zero-emissions in the electricity sector and evaluate a moratorium on new-build natural gas generation stations,” said his spokesperson. That report, an early look at halting gas power, is expected in November.

 

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Beating Covid Is All About Electricity

Hospital Electricity Reliability underpins ICU operations, ventilators, medical devices, and diagnostics, reducing power outages risks via grid power and backup generators, while energy poverty and blackouts magnify COVID-19 mortality in vulnerable regions.

 

Key Points

Hospital electricity reliability is steady power that keeps ICU care, ventilators and medical devices operating.

✅ ICU loads: ventilators, monitors, infusion pumps, diagnostics

✅ Grid power plus backup generators minimize outage risk

✅ Energy poverty increases COVID-19 mortality and infection

 

Robert Bryce, Contributor

During her three-year career as a registered nurse, my friend, C., has cared for tuberculosis patients as well as ones with severe respiratory problems. She’s now caring for COVID-19 patients at a hospital in Ventura County, California, where debates about keeping the lights on continue amid the state’s energy transition. Is she scared about catching the virus? “No,” she replied during a phone call on Thursday. “I’m pretty unflappable.”

What would scare her? She quickly replied, “a power outage,” a threat that grows during summer blackouts when heat waves drive demand. About a year ago, while working in Oregon, the hospital she was working in lost power for about 45 minutes. “It was terrifying,” she said. 

C., who wasn’t authorized by her hospital to talk to the media, and thus asked me to only use the initial of her first name, said that COVID-19 patients are particularly reliant on electrical devices. She quickly ticked off the machines: “The bed, the IV machine, vital signs monitor, heart monitor, the sequential compression devices...” COVID-19 patients are hooked up to a minimum of five electrical devices, she said, and if the virus-stricken patient needs high-pressure oxygen or a ventilator, the number of electrical devices could be two or three times that number. “You name it, it plugs in,” she said.  

Today In: Energy

The virus has infected some 2.2 million people around the world and killed more than 150,000,including more than 32,000 people here in the U.S. While those numbers are frightening, it is apparent that the toll would be far higher without adequate supplies of reliable electricity. Modern healthcare systems depend on electricity. Hospitals are particularly big consumers. Power demand in hospitals is about 36 watts per square meter, which is about six times higher than the electricity load in a typical American home, and utilities are turning to AI to adapt to electricity demands during surges. 

Beating the coronavirus is all about electricity. Indeed, nearly every aspect of coronavirus detection, testing, and treatment requires juice. Second, it appears that the virus is more deadly in places where electricity is scarce or unreliable. Finally, if there are power outages in virus hotspots or hospitals, a real risk in a grid with more blackouts than other developed countries, the damage will be even more severe. 

As my nurse friend in Ventura County made clear, her ability to provide high-quality care for patients is wholly dependent on reliable electricity. The thermometers used to check for fever are powered by electricity. The monitors she uses to keep track of her patients, as well as her Vocera, the walkie-talkie that she uses to communicate with her colleagues, runs on batteries. Testing for the virus requires electricity. One virus-testing machine, Abbott Labs’ m2000, is a 655-pound appliance that, according to its specification sheet, runs on either 120 or 240 volts of electricity. The operating manual for a ventilator made by Hamilton Medical is chock full of instructions relating to electricity, including how to manage the machine’s batteries and alarms. 

While it may be too soon to make a direct connection between lack of electricity and the lethality of the coronavirus, the early signs from the Navajo reservation indicate that energy poverty amplifies the danger. The sprawling reservation has about 175,000 residents, but it has a higher death toll from the virus than 13 states. About 10 percent of Navajos do not have electricity in their homes and more than 30 percent lack indoor plumbing. 

The death rate from the virus on the reservation now stands at 3.4 percent, which is nearly twice the global average. In the middle of last week, the entire population of Native American tribes in the U.S. accounted for about 1,100 confirmed cases of the virus and about 44 deaths. Navajos accounted for the majority of those, with 830 confirmed cases of coronavirus and 28 deaths. 

On Saturday night, the Navajo Times reported a major increase, with 1,197 positive cases of COVID-19 on the reservation and 44 deaths. Other factors may contribute to the high infection and mortality rates on the reservation, including  high rates of diabetes, obesity, and crowded residential living situations. That said, electricity and water are essential to good hygiene and health authorities say that frequent hand washing helps cut the risk of contracting the virus. 

The devastation happening on Navajoland provides a window into what may happen in crowded, electricity-poor countries like India, Pakistan, and Bangladesh. It also shows what could happen if a tornado or hurricane were to wipe out the electric grid in virus hotspots like New Orleans, as extreme weather increasingly afflicts the grid nationwide. Sure, most American hospitals have backup generators to help assure reliable power. But those generators can fail. Further, they usually burn diesel fuel which needs to be replenished every few days. 

The essential point here is that our hospitals and critical health care machines aren’t running on solar panels and batteries. Instead, they are running on grid power that’s being provided by reliable sources — coal, natural gas, hydro, and nuclear power — which together produce about 89 percent of the electricity consumed in this country, even as Russian hacking of utilities highlights cyber risks. The pandemic — which is inflicting trillions of dollars of damage on our economy and tens of thousands of deaths — underscores the criticality of abundant and reliable electricity to our society and the tremendous damage that would occur if our health care infrastructure were to be hit by extended blackouts during the fight to stop COVID-19.

In a follow-up interview on Saturday with my friend, C., she told me that while caring for patients, she and her colleagues “are entirely dependent on electricity. We take it for granted. It’s a hidden assumption in our work,” a reminder echoed by a grid report card that warns of dangerous vulnerabilities. She quickly added she and her fellow nurses “aren’t trained or equipped to deal with circumstances that would come with shoddy power. If we lost power completely, people will die.”

 

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Climate Solution: Use Carbon Dioxide to Generate Electricity

Methane Hydrate CO2 Sequestration uses carbon capture and nitrogen injection to swap gases in seafloor hydrates along the Gulf of Mexico, releasing methane for electricity while storing CO2, according to new simulation research.

 

Key Points

A method injecting CO2 and nitrogen into hydrates to store CO2 while releasing methane for power.

✅ Nitrogen aids CO2-methane swap in hydrate cages, speeding sequestration

✅ Gulf Coast proximity to emitters lowers transport and power costs

✅ Revenue from methane electricity could offset carbon capture

 

The world is quickly realizing it may need to actively pull carbon dioxide out of the atmosphere to stave off the ill effects of climate change. Scientists and engineers have proposed various carbon capture techniques, but most would be extremely expensive—without generating any revenue. No one wants to foot the bill.

One method explored in the past decade might now be a step closer to becoming practical, as a result of a new computer simulation study. The process would involve pumping airborne CO2 down into methane hydrates—large deposits of icy water and methane right under the seafloor, beneath water 500 to 1,000 feet deep—where the gas would be permanently stored, or sequestered. The incoming CO2 would push out the methane, which would be piped to the surface and burned to generate electricity, whether sold locally or via exporters like Hydro-Que9bec to help defray costs, to power the sequestration operation or to bring in revenue to pay for it.

Many methane hydrate deposits exist along the Gulf of Mexico shore and other coastlines. Large power plants and industrial facilities that emit CO2 also line the Gulf Coast, where EPA power plant rules could shape deployment, so one option would be to capture the gas directly from nearby smokestacks, keeping it out of the atmosphere to begin with. And the plants and industries themselves could provide a ready market for the electricity generated.

A methane hydrate is a deposit of frozen, latticelike water molecules. The loose network has many empty, molecular-size pores, or “cages,” that can trap methane molecules rising through cracks in the rock below. The computer simulation shows that pushing out the methane with CO2 is greatly enhanced if a high concentration of nitrogen is also injected, and that the gas swap is a two-step process. (Nitrogen is readily available anywhere, because it makes up 78 percent of the earth’s atmosphere.) In one step the nitrogen enters the cages; this destabilizes the trapped methane, which escapes the cages. In a separate step, the nitrogen helps CO2 crystallize in the emptied cages. The disturbed system “tries to reach a new equilibrium; the balance goes to more CO2 and less methane,” says Kris Darnell, who led the study, published June 27 in the journal Water Resources Research. Darnell recently joined the petroleum engineering software company Novi Labs as a data scientist, after receiving his Ph.D. in geoscience from the University of Texas, where the study was done.

A group of labs, universities and companies had tested the technique in a limited feasibility trial in 2012 on Alaska’s North Slope, where methane hydrates form in sandstone under deep permafrost. They sent CO2 and nitrogen down a pipe into the hydrate. Some CO2 ended up being stored, and some methane was released up the same pipe. That is as far as the experiment was intended to go. “It’s good that Kris [Darnell] could make headway” from that experience, says Ray Boswell at the U.S. Department of Energy’s National Energy Technology Laboratory, who was one of the Alaska experiment leaders but was not involved in the new study. The new simulation also showed that the swap of CO2 for methane is likely to be much more extensive—and to happen quicker—if CO2 enters at one end of a hydrate deposit and methane is collected at a distant end.

The technique is somewhat similar in concept to one investigated in the early 2010s by Steven Bryant and others at the University of Texas. In addition to numerous methane hydrate deposits, the Gulf Coast has large pools of hot, salty brine in sedimentary rock under the coastline. In this system, pumps would send CO2 down into one end of a deposit, which would force brine into a pipe that is placed at the other end and leads back to the surface. There the hot brine would flow through a heat exchanger, where heat could be extracted and used for industrial processes or to generate electricity, supporting projects such as electrified LNG in some markets. The upwelling brine also contains some methane that could be siphoned off and burned. The CO2 dissolves into the underground brine, becomes dense and sinks further belowground, where it theoretically remains.

Either system faces big practical challenges, and building shared CO2 storage hubs to aggregate captured gas is still evolving. One is creating a concentrated flow of CO2; the gas makes up only .04 percent of air, and roughly 10 percent of the smokestack emission from a typical power plant or industrial facility. If an efficient methane hydrate or brine system requires an input that is 90 percent CO2, for example, concentrating the gas will require an enormous amount of energy—making the process very expensive. “But if you only need a 50 percent concentration, that could be more attractive,” says Bryant, who is now a professor of chemical and petroleum engineering at the University of Calgary. “You have to reduce the [CO2] capture cost.”

Another major challenge for the methane hydrate approach is how to collect the freed methane, which could simply seep out of the deposit through numerous cracks and in all directions. “What kind of well [and pipe] structure would you use to grab it?” Bryant asks.

Given these realities, there is little economic incentive today to use methane hydrates for sequestering CO2. But as concentrations rise in the atmosphere and the planet warms further, and as calls for an electric planet intensify, systems that could capture the gas and also provide energy or revenue to run the process might become more viable than techniques that simply pull CO2 from the air and lock it away, offering nothing in return.

 

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