Hybrid power plant on schedule

Edmonton Electricity Rate Increase signals Alberta RRO changes as the UCP ends the NDP price cap; kilowatt-hour rises to 7.5 cents, raising energy bills for typical households by 3.9 percent in December.

Key Points

The end of Alberta’s RRO cap lifts kWh to 7.5 cents, raising an average Edmonton home’s bill about 3.9% in December.

✅ RRO price cap scrapped; kWh set at 7.5 cents in December.

✅ Average 600 kWh home pays about $7.37 more vs November.

✅ UCP ends NDP-era cap after stakeholder and consumer feedback.

Electricity will be more expensive for some Edmontonians in December after the UCP government scrapped a program that capped rates amid prices spiking in Alberta this year.

Effective Nov. 30, the province got rid of the consumer price cap program for Regulated Rate Option customers.

In 2017, the NDP government capped the kilowatt per hour price at 6.8 cents under a consumer price cap policy, meaning Edmontonians would pay the market rate and not more than the capped price.

In December, kWh will cost 7.5 cents amid expert warnings to lock in rates across Alberta. Typical Edmonton homes use an average of 600 kWh, increasing bills by $7.37, or 3.9 per cent, compared to November.

In Calgary, electricity bills have been rising as well, reflecting similar market pressures.

The NDP created the capacity system to bring price stability to Albertans, though a Calgary retailer urged scrapping the market overhaul at the time.

Energy Minister Sonya Savage said the UCP decided to scrap it after "overwhelming" feedback from consumers and industry stakeholders, as the province introduced new electricity rules earlier this year. 

Related News

• Electricity Forum News

• Energy Policy News

Gaza Power Plant Shutdown underscores the Gaza Strip's fuel ban, Israeli blockade, and electricity crisis, cutting megawatts, disrupting hospitals and quarantine centers, and exposing fragile energy supply, GEDCO warnings, and public health risks.

Key Points

An abrupt halt of Gaza's sole power plant due to a fuel ban, deepening the electricity crisis and straining hospitals.

✅ Israeli fuel ban halts Gaza's only power plant

✅ Available supply drops far below 500 MW demand

✅ Hospitals and COVID-19 quarantine centers at risk

The only electricity plant in the Gaza Strip shut down yesterday after running out of fuel banned from entering the besieged enclave by the Israeli occupation, Gaza Electricity Distribution Company announced.

“The power plant has shut down completely,” the company said in a brief statement, as disruptions like China power cuts reveal broader grid vulnerabilities.

Israel banned fuel imports into Gaza as part of punitive measures over the launching incendiary balloons from the Strip.

On Sunday, GEDCO warned that the industrial fuel for the electricity plant would run out, mirroring Lebanon's fuel shortage challenges, on Tuesday morning.

Since 2007, the Gaza Strip suffered under a crippling Israeli blockade that has deprived its roughly two million inhabitants of many vital commodities, including food, fuel and medicine, and regional strains such as Iraq's summer electricity needs highlight broader power insecurity.

As a result, the coastal enclave has been reeling from an electricity crisis, similar to when the National Grid warned of short supply in other contexts.

The Gaza Strip needs some 500 megawatts of electricity – of which only 180 megawatts are currently available – to meet the needs of its population, while Iran supplies about 40% of Iraq's electricity in the region.

Spokesman of the Ministry of Health in Gaza, Ashraf Al Qidra, said the lack of electricity undermines offering health services across Gaza’s hospitals.

He also warned that the lack of electricity would affect the quarantine centres used for coronavirus patients, reinforcing the need to keep electricity options open during the pandemic.

Gaza currently has three sources of electricity: Israel, which provides 120 megawatts and is advancing coal use reduction measures; Egypt, which supplies 32 megawatts; and the Strip’s sole power plant, which generates between 40 and 60 megawatts.

Related News

• Electricity Forum News

• Power Generation News

California Public Safety Power Shutoffs highlight wildfire prevention as PG&E outages disrupt schools, businesses, and rural communities, driving generator use, economic hardship, and emergency preparedness across Northern California during high-wind events.

Key Points

Utility outages to reduce wildfire risk during extreme winds, impacting homes and businesses in high-risk California.

✅ PG&E cuts power during high winds to prevent wildfires

✅ Costs rise for generators, fuel, batteries, and spoiled food

✅ Rural, low-income communities face greater economic losses

The intentional blackout by California’s largest utility this week put Forest Jones out of work and his son out of school. On Friday morning Mr. Jones, a handyman and single father, sat in his apartment above a tattoo parlor waiting for the power to come back on and for school to reopen.

“I’ll probably lose $400 or $500 dollars because of this,” said Mr. Jones, who lives in the town of Paradise, which was razed by fire last year and is slowly rebuilding. “Things have been really tough up here.”

Millions of people were affected by the blackout, which spanned the outskirts of Silicon Valley to the forests of Humboldt County near the Oregon border. But the outage, which the power company said was necessary to reduce wildfire risk across the region, also drew a line between those who were merely inconvenienced and those who faced a major financial hardship.

To have the lights on, the television running and kitchen appliances humming is often taken for granted in America, even as U.S. grid during coronavirus questions persisted. During California’s blackout it became an economic privilege.

The economic impacts of the shut-off were especially acute in rural, northern towns like Paradise, where incomes are a fraction of those in the San Francisco Bay Area.

Both wealthy and poorer areas were affected by the blackout but interviews across the state suggested that being forced off the grid disproportionately hurt the less affluent. One family in Humboldt County said they had spent $150 on batteries and water alone during the shutdown.

“To be prepared costs money,” Sue Warhaftig, a massage therapist who lives in Mill Valley, a wealthy suburb across the Golden Gate Bridge from San Francisco. Ms. Warhaftig spent around two days without electricity but said she had been spared from significant sacrifices during the blackout.

She invested in a generator to keep the refrigerator running and to provide some light. She cooked in the family’s Volkswagen camper van in her driveway. At night she watched Netflix on her phone, which she was able to charge with the generator. Her husband, a businessman, is in London on a work trip. Her two sons, both grown, live in Southern California and Seattle.

“We were inconvenienced but life wasn’t interrupted,” Ms. Warhaftig said. “But so many people’s lives were.

Pacific Gas & Electric restored power to large sections of Northern California on Friday, including Paradise, where the electricity came back on in the afternoon. But hundreds of thousands of people in other areas remained in the dark. The carcasses of burned cars still littered the landscape around Paradise, where 86 people died in the Camp Fire last year, some of them while trying to escape.

Officials at power company said that by Saturday they hoped to have restored power to 98 percent of the customers who were affected.

The same dangerous winds that spurred the shut-off in Northern California have put firefighters to work in the south. The authorities in Los Angeles County ordered the evacuation of nearly 100,000 people on Friday as the Saddleridge Fire burned nearly 5,000 acres and destroyed 25 structures. The Sandalwood Fire, which ignited Thursday in Riverside County, had spread to more than 800 acres and destroyed 74 structures by Friday afternoon.

While this week’s outage was the first time many customers in Northern California experienced a deliberate power shut-off, residents in and around Paradise have had their power cut four times in recent months, residents say.

Many use a generator, but running one has become increasingly expensive with gasoline now at more than $4 a gallon in California.

On Friday, Dennis and Viola Timmer drove up the hill to their home in Magalia, a town adjacent to Paradise, loaded with $102 dollars of gasoline for their generators. It was their second gasoline run since the power went out Tuesday night.

The couple, retired and on a fixed income after Mr. Timmer’s time in the Navy and in construction, said the power outage had severely limited their ability to do essential tasks like cooking, or to leave the house.

“You know what it feels like? You’re in jail,” said Ms. Timmer, 72. “You can’t go anywhere with the generators running.”

Since the generators are not powerful enough to run heat or air conditioning, the couple slept in their den with an electric space heater.

“It’s really difficult because you don’t have a normal life,” Ms. Timmer said. “You’re trying to survive.”

To be sure, the shutdown has affected many people regardless of economic status, and similar disruptions abroad, like a London power outage that disrupted routines, show how widespread such challenges can be. The areas without power were as diverse as the wealthy suburbs of Silicon Valley, the old Gold Rush towns of the Sierra Nevada, the East Bay of San Francisco and the seaside city of Arcata.

Ms. Cahn’s cellphone ran out of power during the blackout and even when she managed to recharge it in her car cell service was spotty, as it was in many areas hit by the blackout.

Accustomed to staying warm at night with an electric blanket, Ms. Cahn slept under a stack of four blankets.

“I’m doing what I have to do which is not doing very much,” she said.

Further south in Marin City, Chanay Jackson stood surrounded by fumes from generators still powering parts of the city.

She said that food stamps were issued on the first of the month and that many residents who had to throw away food were out of luck.

“They’re not going to issue more food stamps just because the power went out,” Ms. Jackson said. “So they’re just screwed until next month.”

Strong winds have many times in the past caused power lines to come in contact with vegetation, igniting fires that are then propelled by the gusts, and hurricanes elsewhere have crippled infrastructure with Louisiana grid rebuild after Laura according to state officials. This was the case with the Camp Fire.

Since higher elevations had more extreme winds many of the neighborhoods where power was turned off this week were in hills and canyons, including in the Sierra Nevada.

The shut-off, which by one estimate affected a total of 2.5 million people, has come under strong criticism by residents and politicians, and warnings from Cal ISO about rolling blackouts as the power grid strained. The company’s website crashed just as customers sought information about the outage. Gov. Gavin Newsom called it unacceptable. But his comments were nuanced, criticizing the way the shut-off was handled, not the rationale for it. Mr. Newsom and others said the ravages of the Camp Fire demanded preventive action to prevent a reoccurrence.

Yet the calculus of trying to avoid deadly fires by shutting off power will continue to be debated as California enters its peak wildfire season, even as electricity reliability during COVID-19 was generally maintained for most consumers.

In the city of Grass Valley, Matthew Gottschalk said he and his wife realized that a generator was essential when they calculated that they had around $500 worth of food in their fridge.

“I don’t know what we would have done,” said Mr. Gottschalk, whose power went out Tuesday night.

His neighbors are filling coolers with ice. Everyone is hoping the power will come back on soon.

“Ice is going to run out and gas is going to run out,” he said.

Related News

• Electricity Forum News

• Utility Operations News

Ontario Global Adjustment and ICI balance hydro rates, renewable cost shift, and peak demand. Class A and Class B customers face demand response decisions amid pandemic occupancy uncertainty and volatile GA charges through 2022.

Key Points

A pricing model where GA costs and ICI peak allocation shape Class A/B bills, driven by renewables cost shifts.

✅ Renewable cost shift trims GA; larger Class A savings expected.

✅ Class A peak strategy returns; occupancy uncertainty persists.

✅ Class B faces volatile GA; limited levers beyond efficiency.

Ontario’s large commercial electricity customers can approach the looming annual decision about their billing structure for the 12 months beginning July 1 with the assurance of long-term relief on a portion of their costs, amid changes coming for electricity consumers that could affect planning. That’s to be weighed against uncertainties around energy demand and whether a locked-in cost allocation formula that looked favourable in pre-pandemic times will remain so until June 30, 2022.

“The biggest unknown is we just don’t know when the people are coming back,” Jon Douglas, director of sustainability with Menkes Property Management Services, reflected during a webinar sponsored by the Building Owners and Managers Association (BOMA) of Greater Toronto last week. “The occupancy in our office buildings this fall, and going into the new year, could really impact the outcome of the decision.”

After a year of operational upheaval and more modifications to provincial electricity pricing policies, BOMA Toronto’s regularly scheduled workshop ahead of the June 15 deadline for eligible customers to opt into the Industrial Conservation Initiative (ICI) program had a lot of ground to cover. Notably, beginning in January, all commercial customers have seen a reduction in the global adjustment (GA) component of their monthly hydro bills after the Ontario government shifted costs associated with contracted non-hydroelectric renewable supply to reduce the burden on industrial ratepayers from electricity rates to the general provincial account — a move that trims approximately $258 million per month from the total GA charged to industrial and commercial customers. However, they won’t garner the full benefit of that until 2022 since they’re currently repaying about $333 million in GA costs that were deferred in April, May and June of 2020.

Renewable cost shift pares the global adjustment
For now, Ontario government officials estimate the renewable cost shift equates to a 12 per cent discount relative to 2020 prices, even as typical bills may rise about 2% as fixed pricing ends in some cases. Once last year’s GA deferral is repaid at the end of 2021, they project the average Class A customer participating in the ICI program should realize a 16 per cent saving on the total hydro bill, while Class B customers paying the GA on a volumetric per kilowatt-hour (kWh) basis will see a slightly more moderate 15 per cent decrease.

“This is the biggest change to electricity pricing that’s happened since the introduction of ICI,” Tim Christie, director of electricity policy, economics and system planning for Ontario’s Ministry of Energy, Northern Development and Mines, told online workshop attendees. “The government is funding the out-of-market costs of renewables. It does tail off into the 2030s as those contracts (for wind, solar and biomass generation) expire, but over the next eight-ish years, it’s pretty steady at around just over $3 billion per year.”

Extrapolating from 2020 costs, he pegged average electricity costs at roughly 9.1 cents/kWh for Class A commercial customers and 13.2 cents/kWh for Class B, a point of concern for Ontario manufacturers facing high rates as well. However, energy management specialists suggest actual 2021 numbers haven’t proved that out.

“In commercial buildings, we’re averaging 10 to 12 cents for Class A in 2021, and we’re seeing more than that for about 14, 15 cents for Class B,” reported Scott Rouse, managing partner with the consulting firm, Energy@Work.

GA costs for Class B customers dropped nearly 30 per cent in the first four months of 2021 compared to the last four months of 2020, when they averaged 11.8 cents/kWh. Thus far, though, there have been significant month-to-month fluctuations, with a low of 5.04 cents/kWh in February and a high of 10.9 cents/kWh in April contributing to the four-month average of 8.3 cents/kWh.

“In 2020, system-wide GA very often averaged more than $1 billion per month,” Rouse said. “This February it dropped to $500 million, which was really quite surprising. So it is a very volatile cost.”

Although welcome, the renewable cost shift does alter the payback on energy-saving investments, particularly for demand response mechanisms like energy storage. When combined with pandemic-related uncertainty and a series of policy and program reversals alongside calls to clean up Ontario’s hydro policy in recent years, the industry’s appetite for some more capital-intensive technologies appears to be flagging.

“Volatility puts a pause on some of the innovation,” said Terry Flynn, general manager with BentallGreenOak and chair of BOMA Toronto’s energy committee. “It could be a leading edge, but it might be a bleeding edge that won’t bear any fruit because the way the commodity costs are structured will change.”

“There’s kind of a wait-and-see approach on some of these bigger investments,” Douglas concurred.

Industrial Conservation Initiative underpins commercial class divide
Turning to the ICI, Class A customers — defined as those with average monthly energy demand of at least 1 megawatt (MW) — encountered some unexpected changes to the program rules during 2020. Meanwhile, Class B customers — encompassing the vast share of commercial properties smaller than about 350,000 square feet — confront the persistent reality of electricity cost allocation that offloads the burden from larger players onto them.

Through the ICI, participating Class A customers pay a share of the global adjustment that’s prorated to their energy use during the five hours of the period from May 1 to April 30 when the highest overall system demand is recorded. This gives Class A customers the opportunity to lock in a favourable factor for calculating their share of monthly system-wide global adjustment costs if they can successful project and curtail energy loads during those five hours of peak demand. On the flipside, Class B customers pay the remainder of those system-wide costs, on a straightforward per-kWh basis, once Class A payments have been reconciled.

“Class B has sometimes been regarded as the forgotten middle child of the customer classes in Ontario where all the shifted costs in the system kind of pile up,” acknowledged Mark Olsheski, vice president, energy and environment, with Sussex Strategy Group. “Likewise, there can be big unpredictable and uncontrollable swings in the global adjustment rate from month to month and, outside of pure energy efficiency, there really is precious little opportunity or empowerment for a Class B customer to take actions to lower their bills.”

Nevertheless, COVID-19 presents a few extra hiccups for Class A customers this year. Conventionally, late May is when they receive notification of the cost allocation factor that would be used to determine their GA for the upcoming July 1 to June 30 period. This year, though, all current ICI participants will retain the factor they secured by responding to the five hours of peak demand during the 12 months from May 1, 2019 to April 30, 2020 after the Ontario government placed a temporary halt on the peak demand response aspect of the program last summer. Regardless, eligible ICI participants must formally opt into the program by June 15 or they will be billed as Class B customers.

Peak chasing resumes for summer 2021
Since peak demand hours conventionally occur from June to September, Class A customers will once again be studying forecasts intently and preparing to respond via Peak Perks as the heat wave season sets in. That should help alleviate some of the system stresses that arose last summer — prompting policy-makers to reject lobbying for a continued pause on peak demand response.

“The policy rationale was to allow consumers to focus on their operations when recovering from COVID as opposed to reducing peaks. The other issue was that we did not expect the peaks to be high last summer given COVID shutdowns,” Christie recounted. “But due to some hot weather, more people at home and also the lack of ICI response, we saw peaks we haven’t seen in many, many years come up last summer. So the peak hiatus has ended and this summer we’ll be back to responding to ICI as per normal.”

Among Class A customers, owners/managers of office and retail facilities generally have the most to lose from a billing formula tied to the energy demand of more densely occupied buildings in the summer of 2019. However, they could be much more competitively positioned for 2022-23 if their buildings remain below full occupancy and energy demand stays lower than usual this summer.

“Where we can improve is the IESO (Independent Electricity System Operator) and the LDCs (local distribution companies) need to help customers get their real-time data, especially in light of the phantom demand issue, interpret their bills and their Class A versus B scenarios much more easily and comprehensively,” urged Lee Hodgkinson, vice president, technical services, sustainability and ESG, with Dream Unlimited. “ I look for APIs (application programming interface) and direct data flow from the LDCs to the building owners so that we can access that data really easily.”

Given Class A’s historic advantages, few eligible ICI participants are expected to migrate out to Class B. From a sustainability perspective, there’s perhaps more cause to question how the ICI’s 1-MW threshold encourages strategies to move in the other direction.

“You could jack up demand in some buildings and get them into Class A basically by firing up the chillers on the weekend and then pouring cooling outside to get rid of it,” Douglas noted. “That has nothing to do with climate change strategy or sustainability, but it’s a cost- saving strategy, and, sometimes, when you look at the math, it’s hundreds of thousands of dollars you can save.”

Brian Hewson, vice president, consumer protection and industry performance with the Ontario Energy Board (OEB), confirmed the OEB is currently scrutinizing the discrepancy that leaves Class B as the only consumer group with no flexibility to curtail energy load during higher-priced periods, and will be providing advice to the Ministry of Energy. In the interim, that status does, at least, simplify tactics.

“Just reduce your kWh and it doesn’t matter what time of day because you’re paying that fixed rate for 24 hours a day. So if you can curb your demand at night, you get a big bang for your dollar,” Rouse advised.

“We do talk about rates a lot, but if you’re not using it, you’re not paying for it,” Flynn agreed. “A lot of our focus is still on really to try to reduce the number of kilowatts that we use. That seems to be the best thing to do.”

Related News

• Electricity Forum News

• Energy Policy News

Germany Nuclear Power Extension debated as Olaf Scholz weighs energy crisis, gas shortages from Russia, slow grid expansion in Bavaria, and renewables delays; stress test results may guide policy alongside coal plant reactivations.

Key Points

A proposal to delay Germany's nuclear phaseout to stabilize power supply amid gas cuts and slow grid upgrades.

✅ Driven by Russia gas cuts and Nord Stream 1 curtailment

✅ Targets Bavaria grid bottlenecks; renewables deployment delays

✅ Decision awaits grid stress test; coalition parties remain split

The German chancellor on Wednesday said it might make sense to extend the lifetime of Germany's three remaining nuclear power plants.

Germany famously decided to stop using atomic energy in 2011, and the last remaining plants were set to close at the end of this year.

However, an increasing number of politicians have been arguing for the postponement of the closures amid energy concerns arising from Russia's invasion of Ukraine. The issue divides members of Scholz's ruling traffic-light coalition.

What did the chancellor say?
Visiting a factory in western Germany, where a vital gas turbine is being stored, Chancellor Olaf Scholz was responding to a question about extending the lifetime of the power stations.

He said the nuclear power plants in question were only relevant for a small proportion of electricity production. "Nevertheless, that can make sense," he said.

The German government has previously said that renewable energy alternatives are the key to solving the country's energy problems.

However, Scholz said this was not happening quickly enough in some parts of Germany, such as Bavaria.

"The expansion of power line capacities, of the transmission grid in the south, has not progressed as quickly as was planned," the chancellor said.

"We will act for the whole of Germany, we will support all regions of Germany in the best possible way so that the energy supply for all citizens and all companies can be guaranteed as best as possible."

The phaseout has been planned for a long time. Germany's Social Democrat government, under Merkel's predecessor Gerhard Schröder, had announced that Germany would stop using nuclear power by 2022 as planned.

Schröder's successor Angela Merkel — herself a former physicist — had initially sought to extend to life of existing nuclear plants to as late as 2037. She viewed nuclear power as a bridging technology to sustain the country until new alternatives could be found.

However, Merkel decided to ditch atomic energy in 2011, after the Fukushima nuclear disaster in Japan, setting Germany on a path to become the first major economy to phase out coal and nuclear in tandem.

Nuclear power accounted for 13.3% of German electricity supply in 2021. This was generated by six power plants, of which three were switched off at the end of 2021. The remaining three — Emsland, Isar and Neckarwestheim — were due to shut down at the end of 2022. 

Germany's energy mix 1st half of 2022
The need to fill an energy gap has emerged after Russia dramatically reduced gas deliveries to Germany through the Nord Stream 1 pipeline, though nuclear power would do little to solve the gas issue according to some officials. Officials in Berlin say the Kremlin is seeking to punish the country — which is heavily reliant on Moscow's gas — for its support of Ukraine and sanctions on Russia.

Germany has already said it will temporarily fire up mothballed coal and oil power plants in a bid to solve the looming power crisis.

Social Democrat Scholz and Germany's energy minister, Robert Habeck, from the Green Party, a junior partner in the three-way coalition government, had previously ruled out any postponement of the nuclear phasout, despite debate over a possible resurgence of nuclear energy among some lawmakers. The third member of Scholz's coalition, the neoliberal Free Democrats, has voiced support for the extension, as has the opposition conservative CDU-CSU bloc.

Berlin has said it will await the outcome of a new "stress test" of Germany's electric grid before deciding on the phaseout.

Related News

• Electricity Forum News

• Power Generation News

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.

Related News

• Electricity Forum News

• Climate Change News