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Proposed Science Center in Mgtn. Industrial Park
by DUANE NICHOLS 16 Dec '21

16 Dec '21

Sean. Please let me know anytime you can what is proposed for a Science Center. It sure sounds fishy to me, as I’ve been doing science since 1953. I started a Physics Department at a small college and was head of the Department for five years. I also served as Director of the Nuclear Radiation Laboratory after training by the U. S. Atomic Energy Commission. Then, years later in my last full time job, I supervised data acquisition and processing for CONSOL R & D; this included on-site work inside coal fired electric generating stations. I can tell you more about digital computers, computation algorithms, on-line data transfer, and output modes, as time allows. Your work on expanding internet access will be beneficial to many of our residents. The bandwidth or data rate should not be compromised by facilities not in the public interest. And, at some point in time, our county needs to take climate change seriously? There could even be foreign companies behind some of the confidential financing that goes into West Virginia, certainly out-of-state ones. If it is a Bitcoin Mining Center, or other gaming scheme, our organization wants to oppose it. If we don’t find out something soon, I would assume that it is not in the public interest? Thank you for all you do in the public interest. Duane Nichols, Coordinator Mon Valley Clean Air Coalition

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Joe Manchin's blind trust does not include his family's coal company, contradicting his claims as he votes on climate bills - The Washington Post
by DUANE NICHOLS 13 Dec '21

13 Dec '21

https://www.washingtonpost.com/politics/2021/12/13/manchin-blind-trust-ener… Manchin cites a blind trust to justify climate votes. But much income from his family’s coal company isn’t covered. Sen. Joe Manchin III (D-W.Va.) with reporters after a vote on Capitol Hill on Oct. 21 in Washington. (Jabin Botsford/The Washington Post) In Sen. Joe Manchin III’s hilly West Virginia home county, his family’s business has made millions by taking waste coal from long-abandoned mines and selling it to a power plant that emits air pollution at a higher rate than any other plant in the state. That enterprise could have taken a hit under a key part of President Biden’s climate agenda, a $150 billion plan to push coal plants toward cleaner energy. One lawmaker, though, played a central role in killing that proposal: Manchin, who has earned hundreds of thousands of dollars annually from the family coal company while using his role as a Democratic swing vote in a 50-50 Senate to dictate Biden’s policies. When pressed about whether he has a conflict of interest, Manchin bristles. “I have been in a blind trust for 20 years. I have no idea what they’re doing,” the senator told reporters in September, referring to his family’s coal firm. “You got a problem?” But contrary to his public statements, documents filed by the senator show the blind trust is much too small to account for all his reported earnings from the coal company, as of his latest financial disclosure report, which covers 2020 and was filed in May. Manchin’s latest financial disclosure report says that the West Virginia family coal business that he helped found and run, Enersystems, paid him $492,000 in interest, dividends and other income in 2020, and that his share of the firm is worth between $1 million and $5 million. He signed a sworn statement saying he is aware of these earnings, underscoring that he is not blind to them. Excerpts from Manchin's financial disclosure reports. By contrast, Manchin set up a blind trust with $350,000 in cash in 2012. In his latest financial disclosure report, the senator reported that the Joseph Manchin III Qualified Blind Trust earned no more than $15,000 last year and is worth between $500,000 and $1 million. By design, it is not possible to know precisely what’s in the blind trust. But the financial disclosure records show that it doesn’t include all of Manchin’s income from Enersystems. If Manchin’s coal interests are not in a blind trust, ethics experts said, it calls into question the impartiality of a senator who in October forced Biden to drop the plan in his Build Back Better bill to phase out the same kinds of coal plants that are key to his family company’s profitability. The senator’s effort to dismiss questions about his coal interests by declaring he has a blind trust is “misleading and at worst it’s just not true,” said Don Fox, a former general counsel and acting director of the Office of Government Ethics in the Obama administration, who examined Manchin’s financial records at The Washington Post’s request. He cited the vast difference between Manchin’s reported income from the trust and his family’s coal business. “The question I would ask him would be, when he says it’s in a blind trust, ‘Well, your public financial disclosure report that you sign and swear is true does not have Enersystems in the blind trust,’ ” Fox said. “And if the blind trust is truly blind, how do you know what’s in it?” Manchin declined an interview request. The Post sent his spokeswoman, Sam Runyon, a list of detailed questions and a copy of the document establishing the blind trust. She did not directly respond to queries about the blind trust and conflict of interest. Instead, she emailed a statement that said in full: “Senator Manchin is in full compliance with Senate ethics and financial disclosure rules. He continues to work to find a path forward on important climate legislation that maintains American leadership in energy innovation and critical energy reliability, as exemplified by the many provisions to address climate change in the Energy Act of 2020 and the bipartisan Infrastructure Investment and Jobs Act.” It is legal for Manchin to make millions of dollars from his coal interests even as he chairs the Senate Energy and Natural Resources Committee and legislates on matters affecting the industry. That is because members of Congress are not required to divest their assets to avoid a potential industry conflict. Senate rules prohibit members from using their position to pass legislation in which “the principal purpose” is to benefit themselves or family members. There is no evidence Manchin has taken action solely to benefit himself or the family company, though critics say that by killing the clean electricity provision in Biden’s agenda, he is helping all coal-related companies — potentially including Enersystems. Congressional rules are more lenient than, for example, those governing many top executive branch officials, whose assets would be reviewed by the Office of Government Ethics for potential conflicts of interest, making them subject to a requirement to divest, recuse or seek a waiver. Craig Holman, an ethics expert at Public Citizen, said that regardless of the congressional rules, Manchin’s declaration in the trust that he wants to “avoid any conflict of interest, or any appearance of such a conflict” is undercut by his simultaneous earnings from a coal business and his work against climate policies. “It is a very blatant conflict of interest,” Holman said, citing the senator’s financial disclosures. “Manchin is not only very wealthy, but most of his assets and wealth are invested in a single industry, coal.” Holman said Manchin’s financial position is one of the most conflicted of any member of Congress he has studied because so much of the senator’s financial stake is in the coal industry while he is playing a key role on climate policies. Nonetheless, he said, “what Manchin is doing is not illegal. The conflict of interest code for Congress is just way too weak.” Sen. Tina Smith (D-Minn.), who sought for months to convince Manchin to support the plan to transition power companies to cleaner forms of energy, said the West Virginia senator ultimately balked. Manchin’s opposition effectively killed one of the most far-reaching climate policies in the bill, outraging environmentalists and leading to an increased focus on his family’s coal business and his own earnings. “After working on the Clean Electricity Performance Program, which I think is the strongest and best way of getting the utility sector to net-zero emissions as quickly as possible, Sen. Manchin ultimately said he just couldn’t get there,” Smith said in an interview. “And I think that was a mistake — I think the [program] would have been a powerful tool to get the emissions reductions we need, while keeping utility rates low.” She stressed that she is still having “good conversations” with Manchin and is negotiating on other parts of the bill affecting climate change, but she has “no expectation that any kind of clean electricity plan will be included.” Manchin could further scale back Biden’s climate change efforts. The senator has also objected to a measure in the Build Back Better bill designed to reduce emissions of methane, the main component of natural gas, and a tax credit for electric cars. He has not yet announced his support for the Democrats’ spending bill. A view of East Fairmont and downtown Fairmont in West Virginia. (Kristian Thacker for The Washington Post) Questions about a conflict between Manchin’s coal interests and his government service go back decades, a review by The Post found. Manchin helped found and became president of Enersystems, a coal brokerage firm, in 1988. One of its customers since 1993 has been a power plant in Grant Town, W.Va., that uses waste coal to produce energy. In the mid-1990s, when Manchin was a state senator, he backed legislation that gave plants such as the one in Grant Town a property tax break. When a group of local citizens complained that Manchin had a conflict of interest, he responded that he had avoided any ethical problem by giving the break to all similar projects. Had the bill only benefited the Grant Town plant, Manchin said at the time, “I would have excused myself from voting,” according to a contemporaneous account in the Charleston Gazette. But by backing a broad measure, Manchin said ethics officials told him it was allowed, notwithstanding the benefit for Grant Town. After Manchin was elected West Virginia’s secretary of state in 2000, he gave control of Enersystems to his son Joseph Manchin IV, who still runs it. The younger Manchin did not respond to a request for comment. After Manchin was elected governor in 2005, he said he put his company shares in a blind trust. He reported receiving hundreds of thousands of dollars from his coal business on a state financial disclosure form in 2009 and 2010, and told the news service Greenwire in 2011 that his holdings had “absolutely not” affected his policies, adding, “I have been in a blind trust for a long time.” In his successful 2010 bid for the U.S. Senate, Manchin ran an ad that showed him shooting at President Barack Obama’s proposed legislation to address climate change “because it’s bad for West Virginia.” Between 2011 and 2020, Manchin earned $4.8 million from Enersystems, according to a tally by the Center for Responsive Politics. His net worth as of 2020 was between $4.4 million and $12.8 million, the center said. Enersystems is a private company based in Fairmont, W.Va., near Manchin’s hometown of Farmington. Public records show that the business is among those that benefit from federal programs to clean up long-shuttered coal mines, where mountains of mining debris, known as waste coal, have been piled and abandoned. The company sells the waste coal to the only power plant in the state that still burns it: the Grant Town Power Plant, an 80-megawatt electricity-generating facility in Manchin’s home county of Marion. Compared with ordinary coal plants, power plants that burn waste coal, or what the industry calls “gob,” are dirtier and don’t generate as much electricity. The Grant Town plant emits more greenhouse gases and the main components of acid rain — nitrogen oxides and sulfur dioxide — into the air per megawatt-hour of electricity produced than any other power plant in West Virginia, according to the Environmental Protection Agency’s most recent data. Only a handful of waste-coal-burning plants still operate nationally. They are such heavy polluters that the Trump administration created a separate category for them, weakening the air pollution standards they had to meet. “Burning waste coal, like burning trash, turns pollution on the ground into pollution in the air,” said Eric Schaeffer, executive director of the Environmental Integrity Project, a nonprofit founded by former EPA officials. The environmental benefits of clearing waste coal from mining sites are questionable, he added. Although removing the piles of gob can reduce acid runoff, the process of burning it creates an enormous amount of ash that can release toxins into streams or groundwater. The Manchin family doesn’t own or operate the Grant Town plant, which is run by American Bituminous Power Partners, a limited partnership registered in Delaware. But records of coal transactions from last year suggest the power plant is Enersystems’ primary customer. It is the only publicly recorded buyer of Enersystems’ waste coal. In response to written questions from The Post, American Bituminous Power Partners Executive Director Ken Niemann said the Grant Town plant “is in full compliance with all its state and federal air emissions controls and limitations.” As the economics of burning coal have become less favorable, the Grant Town plant has come close to shutting down at least twice. In 2006, when Manchin was governor, the state’s Public Service Commission rescued the plant by approving rate increases, which the utility passed on to customers. The commission’s chair at the time was a Manchin appointee. Those higher prices were supposed to be temporary until 2017. But by 2015, the power plant’s owners were back before the commission, claiming financial difficulties. The commissioners sided with the plant, and the higher rates became permanent. The Grant Town plant faced a new threat this year: Democrats’ plans to rapidly shift the electricity sector away from coal and toward cleaner sources of energy. The clean electricity program would have rewarded utilities for purchasing more electricity from wind, solar and other emissions-free sources — and penalized those that did not. If the program had become law, the power company that buys electricity from the Grant Town plant would have faced growing financial pressure to shift away from coal power, increasing the odds that Grant Town would eventually close, said James Van Nostrand, director of West Virginia University law school’s Center for Energy and Sustainable Development. The clean electricity program “would have helped us out a lot,” Van Nostrand said. West Virginia’s embrace of coal power over less expensive alternatives like gas, wind and solar has contributed to a decade of rising electricity bills. According to Van Nostrand’s analysis, between 2010 and 2019 West Virginians’ electricity costs increased about five times more than the national average. “By definition, if the federal government is going to help us transition to cheaper, cleaner electricity, then our electricity bills would either go down or wouldn’t go up as fast as they are now,” he said. Manchin during a Senate Energy and Natural Resources Committee hearing in Washington on Oct. 19. (Stefani Reynolds for The Washington Post) In 2019, Manchin co-authored an op-ed with Sen. Lisa Murkowski (R-Alaska) in The Post that said: “There is no question that climate change is real or that human activities are driving much of it. We are seeing the impacts in our home states.” They said they were working to find “pragmatic policies that can draw strong and enduring support” and pinned much of their hope on what they called “the next scientific breakthrough” for “game-changing technology.” They opposed what they called “drastic, unattainable measures to reduce greenhouse-gas emissions.” Manchin’s role as the potentially decisive vote in the Senate and his opposition to efforts at abandoning the filibuster have given him outsize power, which he’s used in part to reduce the Build Back Better bill from more than $3 trillion to $1.75 trillion. Manchin has argued that the clean electricity plan he insisted on removing from the bill is unnecessary because coal companies are already moving toward other energy sources. “The only thing they want us to do is pay $150 billion for what’s already happening,” Manchin told reporters in October in explaining his opposition to the measure. “We’ve transitioned.” The legislation that passed the House last month still contains $555 billion in tax credits, grants and other efforts to lower planet-warming greenhouse gases, which would be the largest clean energy investment in U.S. history. The bill’s tax incentives would make it easier to install solar panels, build wind turbines and retrofit buildings with energy-saving upgrades. Electric vehicles would become less expensive, reducing a barrier that has prevented many Americans from purchasing them. Around the time Manchin helped kill the clean electricity provision, he was asked during a walk with reporters on Capitol Hill about whether he has a conflict of interest and was pressed on the fact that his son runs the family coal company. Manchin responded, “I’m very proud of my son. He does a good job. You’d do best to change the subject now.” Manchin’s critics said that while the senator was not violating any law, he is violating the premise of his promise to avoid the appearance of conflict of interest. Dylan Hedtler-Gaudette, manager of government affairs at the Project on Government Oversight, said the best way to prevent such a conflict of interest would be to require members of Congress to divest most investments. If such a policy were adopted, Manchin would be required to liquidate his shares in the coal company and put the assets in a blind trust, and authorize a trustee to invest the money in any way deemed appropriate, and without his knowledge. “Under the current framework, you are not required to divest anything,” he said. “I think there should be someone in Congress who introduces a bill that says, ‘Look, if you become a member of Congress, you have to divest basically everything except for a widely diversified mutual fund.’ ” But Hedtler-Gaudette said he has not found a single member of Congress willing to sponsor such legislation. As a result, he hopes Manchin’s case will prompt legislators to consider requiring divestment of any asset — not just publicly traded stock — that could be perceived as a conflict of interest. “If you don’t like it, that’s fine,” Hedtler-Gaudette said. “There isn’t anyone who requires you to be a member of Congress.” xxx

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Researchers developing wearable pollution-measuring technology | The University Record
by DUANE NICHOLS 23 Nov '21

23 Nov '21

Here we have a pipe dream worthy of pursuit! dgn https://record.umich.edu/articles/researchers-developing-wearable-pollution… Researchers developing wearable pollution-measuring technology By Nardy Baeza Bickel, University of Michigan News, November 18, 2021 A walk in the park could soon include getting real-time measurements of pollutants in the air and updated walking routes to avoid the most toxic ones, all while wearing a gadget the size of a smartwatch. With the support of a $2.78 million grant from the National Institutes of Health, researchers at the University of Michigan, Michigan State University and Oakland University are teaming up to develop wearable technology able to identify particulate matter pollution such as soot and toxic metals generated by cars, trucks and industrial sources. “When we look at the global burden of disease, particulate matter is by far the biggest driver of premature deaths from exposure to air pollution,” said Tim Dvonch, associate professor of environmental health sciences at U-M’s School of Public Health. Until now, most research required big and expensive outdoor monitors or several-pound devices workers use in occupational settings, he said. “Some of the most vulnerable people to adverse effects from air pollution exposure happen to be children, pregnant women and women of childbearing age,” he said. “Having an easily wearable device would help monitor the air they’re exposed to, and hopefully provide healthier alternatives in near real time.” Dvonch said the team first started working in wearable technology in 2013 to detect pollutant gases but are now focusing on particulate matter, given that it’s responsible for an estimated 7 million premature deaths every year, according to new air quality guidelines published in September by the World Health Organization. That’s roughly one in nine deaths globally. “Air pollution and, specifically, airborne particulate matter has a huge impact on health, on respiratory and cardiovascular illnesses, and it’s also associated with a number of other adverse health outcomes,” Dvonch said. “Vulnerable populations include prenatal exposures, young children and the elderly, and we know it also disproportionately affects communities of lower socioeconomic status and communities of color who may live near air pollution sources like motor vehicle traffic, incinerators, refineries or power plants.” Within the team, Andrew Mason, a professor at MSU’s College of Engineering, focuses on developing the microscale sampling device, while Xiangqun Zeng, professor of chemistry at Oakland University, is developing the chemical sensor technology. Once the device is developed, Dvonch and the U-M team will oversee field-testing it in communities in metro Detroit, measuring it against existing monitors for accuracy and designing walking maps throughout neighborhoods that are known to have variable levels of air quality, to further evaluate the device. Many of the pollutants that affect hearts, lungs and brains are invisible to human eyes. And many of the current technologies used to monitor air pollution take days or weeks to collect and process data. “That’s helpful for epidemiological studies, but it doesn’t tell you what’s going on today,” Mason said. Adding a network of wearable devices would provide unprecedented data about air quality over space and time, helping inform policies and interventions to help protect the most vulnerable, the researchers said. But developing those devices is no small feat. The research team will need to build technology that can count particles, characterize what each particle is made of, and also determine particle size down to nanometer scale. On top of all that, the team has challenged itself to become the first to fit such technology into something the size of a wristwatch. “Currently, there is no personal monitoring device available because of the complexity,” Zeng said. “The most exciting aspect of this project is its significance and innovation.” Dvonch said it will be a challenge to accomplish all of the project goals, but “the project team is very organized and efficient, and I expect this will allow us to overcome the challenges we may face.” “Not only will the developed monitoring devices from our project be applicable to assessing air pollution exposures across many parts of the globe, importantly, our project will be able to test, evaluate and begin to address these particulate matter exposure issues right here in Michigan communities,” he said. Tags: National Institutes of Health pollution School of Public Health wearable technology Sent from my iPad

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Coal-fired power plants, including two in Pa., to close after new wastewater rule | StateImpact Pennsylvania
by DUANE NICHOLS 23 Nov '21

23 Nov '21

https://stateimpact.npr.org/pennsylvania/2021/11/22/coal-fired-power-plants… Coal-fired power plants, including two in Penna., due to new wastewater rule From an Article by Michael Rubinkam (Associated Press), State-Impact Penna., November 22, 2021 [AP] Climate change isn’t what’s driving some U.S. coal-fired power plants to shut down. It’s the expense of stricter pollution controls on their wastewater. Dozens of plants nationwide plan to stop burning coal this decade to comply with more stringent federal wastewater guidelines, according to state regulatory filings, as the industry continues moving away from the planet-warming fossil fuel to make electricity. The new wastewater rule requires power plants to clean coal ash and toxic heavy metals such as mercury, arsenic and selenium from plant wastewater before it is dumped into streams and rivers. The rule is expected to affect 75 coal-fired power plants nationwide, according to the Environmental Protection Agency. Those plants had an October deadline to tell their state regulators how they planned to comply, with options that included upgrading their pollution-control equipment or retiring their coal-fired generating units by 2028. The national impact of the wastewater rule is still coming into focus, but at least 26 plants in 14 states said they will stop burning coal, according to the Sierra Club, which has been tracking state regulatory filings. Twenty-one of the plants intend to shut down, and five indicated they may switch to natural gas, the environmental group said. “The free ride these plants have been getting is ending in a lot of ways,” said Zack Fabish, a Sierra Club lawyer. “And them choosing to retire by 2028 probably reflects the reality that a lot of the subsidies they have been getting in terms of being able to dump their wastewater into the commons, they are not going to be able to do that in the future.” The rule will reduce the discharge of pollutants into the nation’s waterways by about 386 million pounds annually, according to EPA estimates. It’s expected to cost plant operators, collectively, nearly $200 million per year to implement. Those that intend to close include two of Pennsylvania’s largest coal-fired power plants, Keystone and Conemaugh outside Pittsburgh, which said they will stop using coal and retire all of their generating units by Dec. 31, 2028, according to regulatory notices obtained separately by The Associated Press. The plants opened more than 50 years ago and together employ about 320 full-time workers and 170 contractors. They generate enough power for perhaps 1.5 million homes, according to industry averages for coal plants of their size. In addition to Pennsylvania, states with power plants that plan to stop using coal by 2028 are Arkansas, Georgia, Indiana, Louisiana, Maryland, Michigan, North Carolina, Ohio, Oklahoma, South Carolina, Tennessee, Texas and West Virginia, the Sierra Club data shows. Power producers that say they will shutter coal-fired units as a result of the new rule include Atlanta-based Southern Co. and Houston-based NRG. Southern, which operates electric utilities in Georgia, Alabama and Mississippi, said it will shutter two-thirds of its coal fleet, including units at the nation’s two largest coal-fired power plants, Scherer and Bowen, both in Georgia. NRG said it plans to stop burning coal at its domestic plants outside Texas, and install new pollution controls at its two Texas plants. The electric power sector has spent years transitioning from coal to cheaper, cleaner-burning natural gas and renewables like wind and solar. Nationwide, about 30% of generating capacity at coal plants has been retired since 2010, according to the Energy Information Administration. (Coal use at power plants is expected to surge more than 20% this year because of sharply higher natural gas prices — the first such increase since 2014 — but the energy agency said it expects that trend to be temporary.) The long-term move away from coal has been pronounced in Pennsylvania, the nation’s No. 3 coal-producing state after Wyoming and West Virginia. Coal’s share of electrical power generation in the state declined from nearly half in 2010 to 10% last year, with operators taking advantage of a statewide boom in natural gas drilling in the Marcellus Shale, the nation’s largest gas field. Seventeen Pennsylvania coal plants have been retired since 2009. “The smallest, oldest (coal) plants were generally the ones the economics killed first. They were too expensive and too small to be retrofitted to meet new EPA standards,” said Jean Reaves Rollins, president of The C Three Group, a market research firm focused on energy infrastructure and utilities. She said coal plants in competitive electricity markets like Pennsylvania’s have also come under pressure. “It is clear in the case of the two Pennsylvania plants, the cost of compliance will put them out of the economic running,” she said. Pennsylvania and neighboring Ohio have accounted for 20% of all coal-fueled power plant shutdowns in the U.S. in recent years, according to federal data. The Keystone and Conemaugh plants are owned by a consortium of private investors, with Texas-based power producer Talen Energy also holding a stake. Talen referred questions to the plants’ chief operating officer, who did not return phone calls and emails. Industry officials contend the mothballing of so many coal plants carries consequences for the nation’s electric grid. Michelle Bloodworth, president and CEO of America’s Power, a trade organization that advocates on behalf of coal-fueled electricity, cited recent blackouts in Texas and elsewhere as examples of “what happens when you go too far too fast.” “We are monitoring the situation currently but we do remain concerned that overly aggressive policies that lead to the premature retirement of dispatchable generation like the coal fleet will jeopardize the reliability and resilience of the electricity grid,” Bloodworth said. Experts have pointed out that in the case of last winter’s massive Texas blackout, most of the megawatts that went offline were generated by gas, coal and nuclear plants. In Pennsylvania, the planned retirements of Keystone and Conemaugh come as building trade unions, industry groups and coal communities fight the state’s planned entry into the Regional Greenhouse Gas Initiative, a multi-state consortium that imposes a price on carbon dioxide emissions from power plants that use coal, gas and oil. Pennsylvania would be the first major fossil fuel state to adopt such a carbon pricing policy. David Masur, executive director of PennEnvironment, an environmental group, said the closures show that “with or without policies to reduce carbon pollution, the companies who own these antiquated power plants intend to shut them down or convert many of them anyway.” The planned shutdowns could leave Homer City Generating Station as the last large, traditional coal-fired power plant in the state still operating by decade’s end. Homer City, which is east of Pittsburgh and is the largest coal plant in Pennsylvania, has told state regulators it plans to keep operating and abide by the new wastewater limits. Owners of shuttering plants are responsible for environmental cleanup, according to the EPA. StateImpact Pennsylvania is a collaboration among WITF, WHYY, and the Allegheny Front.

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Getting Joe Manchin's vote on BBB could come down to one of the weirdest situations of the century
by DUANE NICHOLS 22 Nov '21

22 Nov '21

https://www.dailykos.com/stories/2021/11/20/2065377/-Getting-Joe-Manchin-s-… Getting Joe Manchin's vote on BBB could come down to one of the weirdest situations of the century Stitch that all together, and you get a Politico report on how the Grant Town power plant near Morgantown, West Virginia has put forward a proposal to turn itself into a giant, coal-powered, cryptocurrency “mine.” If that proposal moves forward, it could ensure that the lone contract that defines Manchin’s “coal brokerage firm” will continue to hand him over $500,000 a year for doing very close to nothing. Then maybe we can all have nice things. Or, if the crypto-plant proposal fails, Manchin could still hold the entire bill hostage to his personal interest in fossil fuels. Cryptocurrency is a still a phenomenon that leaves many people scratching their heads. Whether it’s a Bitcoin or a Sol, cryptocurrency doesn’t exist as a block of gold in a vault, a physical coin in a drawer, or a promissory note backed by a government. It’s a series of numbers embedded in a blockchain, which is itself a kind of storage system for these numbers that makes it very difficult to falsify or alter information. The numbers can’t be guessed, and don’t follow a regular pattern. They can only be calculated using a laborious set of equations that can discover the next sequence in a process popularly called “mining.” Through mining, new “blocks” of verified transactions are added to the blockchain. Those blocks are owned by the miners. In the early days, discovering these sequences was relatively easy and could even be done on generic desktop computers. But finding new crypto “coins” rapidly becomes more difficult, and the equations aren’t really optimized to work on the kind of generic microprocessors at the heart of most laptops and desktops. Systems expanded to allow many computers to work together in discovering a block. Then computer gamers and graphic artists found that the dedicated graphics cards they needed were simply unavailable, because cryptocurrency miners had discovered that the type of processors on these cards was much better suited to digging up that next coin. That’s still true today to some extent, but in large part, crypto mining has moved on to even more specialized hardware, designed expressly to deal with the particular equations involved in uncovering a new transaction. This dedicated hardware has taken crypto mining well beyond the limits of what many early adherents of Bitcoin or other currencies thought to be practical. Over time, the real cost of mining a new block has become defined by one thing: power. Anyone trying to mine a Bitcoin at home these days is almost certain to spend more money on the power it costs to mine that coin than the coin is actually worth. At the other end of the mining spectrum, rooms full of specialized mining machines, all digging away at the blockchain, consume a lot of energy, but the cost of the power is still lower than the profit that can be returned—especially when the crypto market is surging. Rather than the cost of power, the availability of power has become a constraint on these high-end mining operations. There are systems out there that need more power than a mid-sized town to handle their ongoing search for that next transaction. So where do they get it? They buy a power plant. There are some rather ingenious alternatives being put forward—including solar-powered EV charging stations that would use all solar power to mine for cryptocurrency using any excess energy—but all too often, the easiest form of power for the crypto-hungry to find can be defined in one word: coal. Across the nation and in many parts of the world, coal power plants are closing for the simplest reason: They cost too much. The cost of operating a coal-powered plant is now so far above adding new power in the form of solar or wind, that systems are finding it cheaper to overbuild renewables and close down the aging coal plants. Some plants are being converted to burn natural gas instead. Others are just being shuttered. A plant that’s about to be written off and remaindered is a great target for a crypto operation. Using that dedicated hardware, they can afford the higher cost of the coal-based power. That’s led to crypto miners buying up multiple plants in Pennsylvania and in New York. That New York plant had been used as a “peaker” plant, filling in when there was high demand on the grid. Its continuous use in powering crypto mining has reportedly made a nearby glacial lake used to cool the plant “feel like a bathtub.” In the case of the Grant Town plant in West Virginia, operating it for power no longer makes any sense. It’s a relatively small power plant, only 80 megawatts. It’s also the only plant in the state that still burns “waste coal.” Coal mines often generate a spoil pile of mostly non-coal material that is picked off the conveyor belt, often by hand, and pitched aside. Before the coal is sent to the power plant, it is often sent through a “prep plant,” where the coal is crushed to a more uniform size and sent through a series of chemical baths in which the lighter coal floats, while heavier minerals—especially those rich in sulfur—sink. This leaves behind a second spoil pile of waste material. Producing waste coal requires going back through the spoil piles for coal that was missed the first time. That coal is worse in almost every way than what was produced on the first pass. It contains more non-coal material, lowering the energy output and increasing the amount of ash. It also contains more sulfur and heavy metals, creating toxins that either go up the smokestack or into the coal slurry at the plant. All coal is dirty, but waste coal is the dirtiest form of coal. Waste coal is what Joe Manchin sells. Using waste coal made a tiny amount of sense in 2008, when the coal market was at its peak and supply was having a hard time keeping up with demand. It makes no sense now, when a majority of mines have been idled and there is still enormous overcapacity. But Manchin has a contract, and that contract has netted him over $5 million in the last decade. The result of all this is that Grant Town isn’t just the dirtiest plant using the dirtiest fuel, it’s also the most expensive plant in the state, in terms of dollars per megawatt. That plant has lost $117 million in just the last five years while paying Manchin $500,000 a year—not even for the waste coal itself, but just to manage the contract that delivers the waste coal. Joe Manchin is almost singularly responsible for removing $1.8 trillion in funding from the Build Back Better legislation. Thanks to Sen. Manchin’s refusal to support the bill as it was originally proposed, dozens of major programs have already been reduced in scope or eliminated completely. Some of the things that were removed—including two years of free community college—seemed like complete no-brainers which would have not only decreased the debt students now face upon emerging from college, but given the U.S. a competitive advantage by creating a more educated work force. The funds for climate change included in the legislation that just passed the House are much smaller than those included in the original proposal that came from the White House. However, they do include over $500 billion in funds dedicated to expanding the use of renewable energy and electric vehicles. Funds for the creation of the Civilian Climate Corps are also still in there, which would create jobs dedicated to restoring and maintaining lost areas of forest and wetland. Also still included is a program that will give utilities a bonus for the switching production to renewable power. As Popular Science explains, that program could be a massive game-changer when it comes to transitioning not just coal plants, but also natural gas-powered plants, to solar or wind. Manchin has specifically opposed that program, saying, “Why pay the utilities for something they're going to do anyway, because we're transitioning?” This is why. Because the program supporting those increased payments is expected to speed the transition by 4% a year. And that adds up. A 4 percent yearly increase would get the energy mix to about 70 to 80 percent in 2030, whereas business as usual would put Americans around 48 percent by the same date. If the U.S. is even going to come close to meeting the goals that must be met to ward off the worst of the climate crisis, it needs Manchin to vote for inclusions of the Clean Energy Performance Program as part of Build Back Better. And getting that vote may depend on whether or not the Grant Town plant gets turned into a dedicated crypto mining plant … all so that Joe Manchin can continue to sell the dirtiest coal, to the dirtiest plant, to line his pocket with the dirtiest money. Sent from my iPad

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Weirton residents are against a potential construction of a gas well pad to be built in their neighborhood | WTRF
by DUANE NICHOLS 18 Nov '21

18 Nov '21

https://www.wtrf.com/video/weirton-residents-are-against-a-potential-constr… Weirton residents are against a potential construction of a gas well pad to be built in their neighborhood Rebecca Little, WTRF News 7, Wheeling, WV, November 18, 2021 UPDATE: Southwestern Energy provided the following statement regarding the gas well pad in Weirton. “Protecting the health and safety of our workers, community and the environment are core Southwestern values that guide our ongoing and future operations. We welcome constructive input and feedback from local residents as this important economic development project moves forward, and we are committed to responsibly developing natural gas in the region, as well as being a good neighbor and steward of the environment.” Southwestern Energy WEIRTON, W.Va.- (WTRF) One by one Weirton residents are starting to stand up to the potential construction of a gas well pad that is supposed to be built off of Park Drive. It is proposed to be built on a 300-acre piece of property and on Wednesday night the small crowd showed up at the Weirton Milsop Community Center for a town hall meeting in hopes of putting a stop to the Southwestern Energy project from ever happening. The meeting was spearheaded by former Weirton City Manager and Attorney Joe DiBartolomeo encouraged residents, who live in the area of Three Springs Drive, to write to the West Virginia Department of Environmental Protection detailing their grievances. 14 residents have already written to the director of permitting for gas wells to voice their opposition to the proposed site that is within the city limits. Among the concerns, according to residents, the close proximity of the gas well pad site to their homes, churches, schools, restaurants and hotels, not to mention the noise plus the danger of a potential accident at the site. “I am concerned what it might do to the city aquifers as far as water contamination. There’s no question that there will be noise problems with all these heavy trucks. I am sure there will be accidents the damages to the road. There are all sorts of issues and the property values are going to go down and we’re trying to attract people to the city of Weirton. That isn’t going to get it done.” Joe DiBartolomeo, Concerned Resident DiBartolomeo says the Weirton Zoning Board voted twice against granting Southwestern Energy the permit to build the gas well pad. He says the energy company is appealing that decision along with another appeal in the Brooke County Circuit Court. Sent from my iPad

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The life-or-death race to improve carbon capture
by DUANE NICHOLS 12 Nov '21

12 Nov '21

NOTE ~ Here is the best technical review of Carbon Capture technology that is currently available, dated July 18, 2021. It’s from an official publication of the American Chemical Society, the most trusted organization of chemistry & chemical engineering. Even so, this article is biased toward an optimistic view of current R&D as well as industrial development projects. We all know that R&D and development projects cannot in and of themselves be relied upon to be successful! Notice one of the leading sentences, “Carbon capture isn’t about saving Earth.” [Rather, radical changes in our collective life-styles must take place! Governmental actions are required to make this happen! DGN] >>> Duane G. Nichols, Ph.D., Chemical Engineer, October 5, 2021. https://cen.acs.org/environment/greenhouse-gases/capture-flue-gas-co2-emiss… The life-or-death race to improve carbon capture Chemical & Engineering News, American Chemical Society, July 18, 2021 The technology works, but we’ll need better chemistry and engineering to reach the scale required to avoid a climate disaster Carbon capture isn’t about saving Earth. Earth is a wet rock floating through space; it doesn’t care if we drown our coastal cities or turn our farmland into desert. Rather, carbon capture is one of the technologies we will need if we want Earth to continue to be a tolerable place for humans to live. In brief The carbon-capture chemistry we have today is too expensive. It works, and it makes economic sense in a few settings. But to meet the global-consensus goal of net-zero carbon dioxide emissions by 2050 and dodge the worst consequences of climate change, we need to deploy more than 150 times as much carbon-capture capacity as we have now. That means reducing costs and making more options available for a wide range of CO2 emission sources. Read on about the growing number of businesses, government labs, nonprofits, and academic researchers racing to bring the next generation of carbon-capture technology up to scale and into the market. In 2020, we sent 40 billion metric tons (t) of carbon dioxide into Earth’s atmosphere. We need to cut that number to 0 by 2050 if we are to avoid the worst consequences of climate change, according to the Intergovernmental Panel on Climate Change (IPCC). If we don’t, the natural systems that keep Earth’s climate relatively peaceful and comfortable will start to tip. The shift will be chaotic, and the new normal might not be conducive to life as we know it. To reach net-zero CO2 emissions by 2050, we need an all-of-the-above approach. Efficiency improvements can reduce our energy needs, and renewable and nuclear power may eventually be able to supply enough electricity for our homes, offices, and cars. But nuclear power is expensive and lacks public support, and renewables are struggling to find the land they need to be deployed at scale. On top of that, activities such as aviation and iron smelting are currently impossible to carry out commercially without releasing CO2. That’s where carbon capture comes in. Removing carbon dioxide from point sources such as the flue gas of power plants and locking it away underground can be a big part of the path to net zero. Related technologies known as direct air capture can remove CO2 that is already in the ambient air. But all of it depends on carbon capture getting a lot bigger, cheaper, and more efficient — and doing so quickly. Slow start Capturing the CO2 from power plants’ flue gas is where most of the action is. “Decarbonization of the power sector becomes the backbone that the decarbonization of the rest of the economy happens on,” says John Northington, director of the National Carbon Capture Center, a research facility near Birmingham, Alabama. What’s your gas stream? Different emission sources require different carbon-capture methods. Ammonia, ethanol, natural gas processing: Emit gas streams with more than 80% CO2. The CO2 is captured with compression and dehydration, membranes, or physical solvents. Chemical plants, iron, steel and paper mills: Emit gas streams with 15–80% CO2. The CO2 can be captured with physical solvents, solid sorbents, or membranes. Coal and natural gas power plants and boilers: Emit gas streams with less than 15% CO2. The CO2 can be captured with chemical solvents. Ambient air: Has a CO2 concentration around 0.041%. The CO2 can be captured with metal-organic frameworks or chemical systems. Sources: Global CCS Institute, National Petroleum Council. But just one commercial power plant has carbon capture: the coal-fired Boundary Dam Power Station in Saskatchewan, which captures 1 million t of CO2 per year on one of its four generators. Carbon capture elsewhere on other industrial processes, such as natural gas production, adds another 27 plants and gathers 25 million t per year. Not nearly enough. The people developing the technology that will make capturing carbon practical have gained unlikely allies in the past couple of years: the oil and gas companies responsible for the lion’s share of CO2 emissions. Though these firms have had their eyes on carbon capture for some time, Northington says, they’re investing serious money in it now. Data from the patent research firm Patent Seekers bear that notion out. Oil companies have gotten the largest number of carbon-capture patents in recent years, followed by government agencies and research institutes, universities, and engineering and technology companies. Klaus Lackner, an engineering professor working on direct air capture at Arizona State University, says the change in attitude is a result of pressure from two directions: competition from cheap renewable energy and public demand for low-carbon options. Major changes are coming to the energy market, Lackner says. “The question isn’t ‘Will we have a transition?’ We will. The Exxons and Shells and other companies have to figure out how to make it through that transition. Their business model falls apart if you can’t have liquid fuels.” Lackner says he’s been pushing fossil fuel companies on this point for years, telling them, “Your societal license to dump CO2 into the air will go away. You need to figure out how to operate without needing that license.” Matt Steyn, a senior adviser with the advocacy wing of the Global CCS Institute (GCCSI), a carbon-capture-and-storage think tank, says the change is also driven by the scientific consensus expressed by the IPCC and the International Energy Agency. “The target has been set; the timeline has been set,” he says. The conversation has shifted from “What do we do?” to “How do we do it?” As we deploy more plants, costs will come down, just as they have done in every other sector. Steve Oldham, CEO, Carbon Engineering Carbon capture of all types is a gas-separation problem. The goal is pure CO2, ideally at high pressure so it can go into a pipeline and be injected safely underground. For some industrial processes, the capture technology available today works fine. In ammonia and corn ethanol plants, for example, the gas exiting exhaust pipes is 80% or more CO2 and just needs to be dried and compressed for transport. As the CO2 in emissions gets more dilute, the energy required to extract it rises. The emissions coming from steel plants and many chemical processes tend to be between 15 and 80% CO2. The flue gas from fossil fuel combustion in air, such as in coal or natural gas–fired power plants, is generally less than 15% CO2. Capture with solvents Carbon dioxide–rich flue gas flows up a contact tower and mixes with a solvent that is trickling down (left). Reduced-CO₂ gas vents from the top, while CO₂-rich solvent exits at the bottom and flows to the top of a stripping tower. There, the solvent is heated, usually by steam, as it trickles down. The heat forces the CO₂ out of solution and up to a collection system. The refreshed solvent heads back to the contact tower to start again. Credit: Adapted from CO2CRC Ironically, oil companies are some of the biggest practitioners of carbon capture today because they use solvents, membranes, and other technologies to remove CO2 from natural gas deposits found in locations such as Russia and west Texas. When they use or sell that CO2 instead of venting it, that counts as carbon capture. That’s why ExxonMobil can claim to capture more CO2 than any other company, even if it uses most of that to push more oil out of the ground. Amine-based extraction systems developed for natural gas processing have been adapted for other CO2 sources, such as the power plant in Saskatchewan, but the energy cost of using such systems on more dilute streams is crushingly high. Second-generation solvent systems are poised to come to market next, followed by membranes and solid sorbents. And numerous innovative and experimental approaches are racing to catch up. Syrie Crouch, vice president for carbon capture and storage at Shell, which built the Saskatchewan plant, says deploying capture where it’s simple is an important start. US ethanol makers, for example, capture only 3 million t of the 43 million t of CO2 their plants produce each year. “The key is to capture that lowest-hanging fruit first and then work on down the cost curve,” she says. Incumbent amines The most mature carbon-capture technologies today use solvents. These systems pump emissions through a solution that absorbs CO2 but lets through other gases, such as nitrogen. The CO2-rich solvent then flows into a boiler, where heat drives the pure CO2 back out of solution. That stripping step is the energy hog. Though the terminology is harsh to a chemist’s ears, carbon-capture solvents are considered either chemical or physical. Chemical solvents, mostly amines such as the industry standard 30% monoethanolamine in water, get a CO2-solubility boost through reversible chemical reactions with water and CO2 that form carbonates, bicarbonates, and carbamates. Physical solvents such as methanol rely on intermolecular interactions to dissolve CO2. Companies including Linde, Air Products, and UOP offer such systems commercially. They use less energy than chemical solvents but require high pressures and low temperatures. They’re not suitable for combustion flue gas but have been used for many years to remove CO2 from natural gas. Almost like a filter Membranes separate gas mixtures on the basis of size or chemical properties. Some molecules can pass through, and others cannot. Credit: Adapted from CO2CRC Amine solvents have the advantage of being mature technology. The systems are well understood, with well-characterized economics and risk profiles that investors know how to analyze. Dow, Shell, Fluor, and others offer monoethanolamine solutions for carbon capture. Boundary Dam Unit 3 uses amines, as did NRG Energy’s Petra Nova plant in Texas, which captured more than 1 million t of CO2 per year from 2017 until NRG shut it down in 2020. BASF, Linde, General Electric, and the start-up Carbon Clean are among those working on advanced amines. These systems use chemicals such as piperazine alongside or instead of monoethanolamine to get better stability, kinetics, and thermodynamics. The US Department of Energy recently awarded Linde and the University of Illinois at Urbana-Champaign $47 million to build a 200 t per day pilot facility using an advanced amine solvent from BASF at a coal-fired power plant near Springfield, Illinois. But capturing CO2 with amines comes at a steep cost. Fitted onto a power plant’s systems, they consume 30–50% of the plant’s energy output. Most experts, including Shell’s Crouch, expect that amine systems can get only 10–20% more efficient. At the same time, amines can seem like a safe bet compared with a next-generation technology. “If you’re making your first investment in carbon capture and storage, you don’t necessarily want to be taking massive risks on something new and untested,” the GCCSI’s Steyn says. The next generation At the National Carbon Capture Center (NCCC) and the Wyoming Integrated Test Center (ITC), two next-generation carbon-capture technologies that look promising are solid sorbents and membranes. CO2 Solutions, now part of Saipem, engineered carbonic anhydrase to fit the demands of carbon capture. The NCCC and ITC sites are essentially coal-fired power plants that can pipe their flue gas into a series of testing bays. The NCCC tests systems at scales from less than 1 t per day up to about 25 t per day; tests at the ITC run between 25 and 450 t per day. The sites, which use a combination of public and private financing, serve as technology development bridges between lab-scale carbon-capture concepts and pilot-scale tests on commercial power plants. The NCCC’s Northington says the incumbent amine systems can capture carbon at a cost of $60–$65 per metric ton. Advanced amines and other second-generation solvents are about $40 per metric ton. A handful of commercial installations that will use advanced amines are in early-stage engineering now, he says. Solid sorbents, membranes, and other transformational technologies will reach $30 or less per metric ton, he predicts. “We want choice in the marketplace,” says William Morris, technical director of the ITC. “People are really trying to figure out what works for them, not only in their industry but in their specific circumstance.” Solid sorbents include zeolites, metal-organic frameworks (MOFs), activated carbon, and porous silica particles. They’re often functionalized with amine groups to increase their activity and make them more selective for CO2. Merry-go-round In Svante's solid-sorbent capture system, flue gas first flows down (left) through a rotating disk loaded with a sorbent material that removes the carbon dioxide. At the next station (right), steam flows through the sorbent, stripping the now-pure CO2 out for collection. A third station (rear) refreshes the sorbent on the way back around to the flue gas station. Generally, solid sorbents have faster absorption kinetics than amines and require less energy to release the CO2 again. They can also hold more CO2 per unit volume than most solvents. That means that solid-sorbent systems can be smaller, reducing capital costs, and can be stripped of their CO2 using vacuum or modest heat. The start-up Svante forms solid sorbents into large, nanoporous disks divided into slices like a pizza. On a giant turntable, the disk slowly rotates each slice through a flue gas stream, a CO2-stripping module, and one or two sorbent preparation stations. The firm has a 10,000 t per year demonstration plant on a natural gas–fired boiler in Canada. It raised $75 million in February to advance a design for cement plants. In addition to Svante, ExxonMobil, Kawasaki Heavy Industries, TDA Research, and others are testing solid-sorbent systems for flue gas capture. Shell, which is shifting its R&D to solid sorbents, tested a system that uses amine-functionalized solid sorbents on a wood-burning power plant in Austria; it is now readying a scaled-up test at a manure-to-power plant in the Netherlands. After these trials, Crouch says, Shell will offer the technology on the open market. Membranes are even further along than solid sorbents, Morris says. Membrane systems use selectively permeable materials that exploit the small chemical and physical differences between CO2 and the rest of a gas mixture to achieve separation. Like amines, membranes are already being used in natural gas processing and other areas where CO2 pressure and content are high. “The next technology outside of amines that will deploy will be membranes,” Morris predicts. He says membranes are coming fast for capturing CO2 from flue gas at power plants. And Northington expects membranes will play a big role in carbon capture for the chemical industry and heavy manufacturing, which have moderate to high CO2 concentrations. Getting any new carbon capture technology to market won’t be cheap. Morris says getting a robust set of data from testing at the ITC can cost seven figures. One membrane maker, Membrane Technology and Research (MTR), won $52 million in funding in May from the US Department of Energy to do just that. MTR ran a 20 t per day version of its system for 1,400 h at the NCCC in 2015 and will use the funds to scale it up to 150 t per day in Wyoming. The company expects to demonstrate capture at less than $40 per metric ton. MTR’s membrane polymers are isoporous, meaning their pores are uniform in size and arranged geometrically, unlike the randomly arranged, multisize pores in most gas-separation membranes. The regular pore pattern lets molecules flow more smoothly through the material, lowering the amount of pressure needed relative to conventional membranes. And a tighter distribution of pore sizes increases selectivity for CO2. Another membrane maker, Compact Membrane Systems (CMS), also seeks to decrease costs by reducing pressure. CMS uses facilitated transport membranes, which are specialized fluoropolymers coated onto a porous substrate. CEO Erica Nemser likens the mechanism to Tarzan swinging through the jungle on vines. The CO2 is Tarzan, and fluoropolymers decorated with activating groups act as the vines, passing CO2 along, with minimal pressure needed. The firm’s systems are already being used to separate olefins from paraffins and to remove water and dissolved gases from solvents, oils, and lubricants. The system that will capture CO2 in flue gas will be a modification of one that’s in field trials now for removing CO2 from biomethane. Chemical changes to the fluoropolymer make the membrane selective toward different chemical species, Nemser says. CMS’s units are built around membrane cartridges about twice the size of a can of spray paint—hence the “compact” in the company’s name. The bigger the gas stream to be treated, the more cartridges the system uses. Chief Technology Officer Hannah Murnen says such modular systems will make carbon capture accessible for a wide range of CO2 point sources. In contrast, the towers needed to mix amine solvents with a gas stream and strip the CO2 out later make economic sense only at enormous scales, she says. CMS says it will be able to deliver carbon capture for as little as $20 per metric ton. “It’s time for membranes. It’s membranes’ day in the sun,” Murnen says. Tomorrow’s tech Amines may dominate carbon capture today, and membranes and solid sorbents may be right on their heels, but a need this serious—and a market this big—is attracting plenty of other contenders. And a good-enough concept could leap ahead if the people behind it can show it works and is scalable. Saipem and Chart Industries both hope to adapt technology and equipment already in use in other chemical processes. In January 2020, Saipem, an energy technology and engineering firm, acquired CO2 Solutions, a start-up that is using enzymes to boost the carbon-capture kinetics of aqueous potassium carbonate. K2CO3 reacts with CO2 and water to form potassium bicarbonate, KHCO3. The bicarbonate solution releases its CO2 at relatively low temperatures—around 75 °C under reduced pressure—meaning it can tap low-grade heat that most industrial processes would waste. That chemistry has been used to scrub CO2 from the air in submarines and other closed environments and in some high-CO2-concentration settings. The trouble is that the absorption kinetics are too slow for it to work well at flue gas concentrations and pressures; the contact towers would have to be even bigger than those used with amines. To solve that problem, Saipem catalyzes the reaction with the enzyme carbonic anhydrase. Natural carbonic anhydrase is already one of the fastest enzymes, speeding up the formation of HCO3– by a factor of 107. The team at CO2 Solutions modified the enzyme to make it even faster and keep it active at higher temperatures. “The first time I saw carbon capture with the enzyme, my jaw just dropped, because the catalyst is magic,” says Richard Surprenant, who came to Saipem from CO2 Solutions and is now commercial manager for carbon-capture technologies. Any industrial or postcombustion application is fair game for the firm’s technology, Surprenant says, and anywhere with low-grade waste or geothermal heat is an opportunity, because it doesn’t need the high-grade heat, a resource many plants already use in other ways. The firm is in the midst of restarting CO2 Solutions’ first commercial plant, a 30 t per day facility in Quebec that extracts CO2 from a paper mill and sells it to a nearby greenhouse. Chart Industries, an energy and industrial gas equipment firm, is also moving into carbon capture through acquisition and investment. In late 2020, Chart acquired Sustainable Energy Solutions, a start-up making cryogenic carbon-capture systems for combustion flue gas. In June of this year, it invested in Earthly Labs, which uses cryogenics to capture CO2 from breweries. Credit: Mosaic Materials Mosaic Materials' carbon-capturing metal-organic frameworks. In the simplest terms, both cryogenic systems chill their target gas streams until the CO2 condenses into a solid or liquid. Nitrogen, still a gas at those temperatures, is pumped off. The basic process, often called cryogenic distillation, is already used to purify other industrial gases, such as oxygen and nitrogen. The challenge for flue gas is in the engineering, not the chemistry, according to Chart CEO Jill Evanko. If water and CO2 freeze in the wrong places, they can clog pipes and block heat exchangers. But with clever heat management, system design, and integration with the rest of the equipment, Chart and its partners can deliver carbon capture of flue gas at half the cost of conventional amines, Evanko says, and make brewery carbon capture profitable enough to pay off the equipment in 18 months. Several other technologies are in early-stage development. Solvents that use less water or no water at all, including organic solvents and ionic liquids, could reduce the amount of mass that needs to be heated to release the purified CO2. Allam cycle power plants burn hydrocarbons in a mix of O2 and CO2, sidestepping the need to separate CO2 from nitrogen. And FuelCell Energy is commercializing its molten carbonate fuel cell, which can capture flue gas carbon while generating additional electricity from natural gas. It’s an exciting time for technology development, the ITC’s Morris says. “Decarbonization is going to be very, very difficult, and it’s probably not going to be possible without technologies that are currently in the development stage.” State of play Carbon capture is in its early days, especially for combustion flue gas, such as the emissions of a coal-fired power plant. Researchers are working on each of the technologies below to make them cheaper and more efficient and to get them to work on a wider variety of gas streams. A single commercial-scale installation could let a new technology pass its competitors or even take the lead. Sources: Global CCS Institute, National Petroleum Council, International Energy Agency, C&EN reporting. Direct air capture Point-source carbon capture won’t be enough. The technology still lets 2–10% of the carbon through. And it’s hard to deploy on sources with diffuse or mobile emissions, such as airplanes, sprawling petrochemical plants, and wide-open wastewater treatment facilities. Besides, the atmosphere has too much carbon already. The goal of net-zero CO2 emissions will require methods to remove carbon from the air. This direct air capture, or DAC, works on chemical principles similar to those for point-source capture. The big difference is that our ambient air, although overloaded, is still only 410 ppm, or 0.041%, CO2, much lower than even the most dilute industrial point sources. And that changes a lot about the devices and their economics. Because flue gas and other point sources are releasing new carbon into the atmosphere, the goal is to capture as much of it as possible—90% is a common target. In DAC, the amount of carbon left behind isn’t important; it’s all about how much CO2 can be removed per dollar spent. “My goal is not to make CO2-free air. My goal is to take CO2 out of the air, and I can choose where the optimal efficiency is,” says Lackner, the Arizona State engineer, who is also developing DAC technology. But however you look at it, DAC is expensive. Carbon capture at an ethanol plant can cost as little as $10 per metric ton. At a coal-fired power plant, the cost is around $60. DAC companies don’t like to talk about their costs, but industry insiders estimate they are around $500 per metric ton. Lackner and other experts generally peg $100 as the point at which DAC will become cost competitive with other decarbonization methods. Oxy Low Carbon Ventures, a carbon-reduction subsidiary of Occidental Petroleum, thinks it can reach that level in partnership with the start-up Carbon Engineering. The firms plan to build in the southwestern US what they say will be the world’s first commercial-scale DAC plant. It will capture 1 million t of CO2 per year, to be used mainly to boost production in Occidental’s oil wells in the region. The largest existing DAC plant captures a mere 2,000 t per year, according to Ryan Edwards, low-carbon policy adviser for Oxy Low Carbon. Carbon Engineering uses chemical looping to capture carbon from the air. In its process, intended to run on renewable energy, giant fans blow air over plastic surfaces that have aqueous potassium hydroxide flowing over it. The KOH reacts with CO2 to form potassium carbonate, K2CO3, which then flows into a pellet reactor containing aqueous calcium hydroxide, Ca(OH)2. The calcium and potassium switch places to form CaCO3, which precipitates out as solid pellets, as well as KOH, which is ready to cycle back to the plastic surfaces. The pellets then pass into a calciner, a heater that decomposes the CaCO3 into solid CaO and pure CO2. The CO2 is cooled and pressurized, and the CaO heads back to the pellet reactor, where it mixes with water and re-forms Ca(OH)2. The system sounds complicated, but it’s built mostly out of reactions and equipment already in use in industry. The pellet reactor is adapted from papermaking. Calciners running the same chemical reaction are central to cement production, and other versions come into play in glass, uranium, petroleum coke, and gypsum processing. The Dry Fork power station in Wyoming sends some of its flue gas to the Wyoming Integrated Test Center, where users test new carbon-capture technologies. Carbon Engineering published its process in 2018, projecting costs between $94 and $232 per metric ton (Joule, DOI: 10.1016/j.joule.2018.05.006). CEO Steve Oldham says the firm is “extremely confident” its costs will be in that range and expects that second and third generations will ensure a cost of $100 or less. “As we deploy more plants, costs will come down, just as they have done in every other sector,” Oldham says. Mosaic Materials, a developer of MOFs and one of C&EN’s 10 Start-Ups to Watch in 2019, pivoted to DAC from point-source capture 2 years ago, according to CEO Thomas McDonald. In the past 3 months, McDonald says, he’s seen a sharp increase in interest in DAC. The firm’s MOFs use a flavor of CO2-amine chemistry that McDonald calls cooperative binding, in which the CO2 inserts itself between a magnesium ion and an amine ligand. The mechanism gives the material high capacity and fast kinetics, and it reverses at relatively low temperatures to release the CO2, according to McDonald. MOFs are more expensive than other solid sorbents such as silica or activated carbon. Mosaic researchers are working to improve the materials’ capacity and stability to reduce operating costs, McDonald says. But the firm is focused more on lowering manufacturing costs and optimizing complete systems around its materials. Mosaic worked with ExxonMobil on flue gas capture in 2017 and 2018 and has some ongoing work in that area, along with collaborations with NASA and the US Navy on life-support systems, McDonald says. But he sees DAC as the best way to build his company. “We see the fastest, least-capital-intensive, least-risky path is by achieving early scale on projects through direct air capture.” We will require something roughly the size of the current oil and gas industry, but with the molecules going in reverse. Syrie Crouch, vice president for carbon capture and storage, Shell Lackner says DAC is a good fit with renewable energy. If a natural gas power plant is off because of low demand, so is any point-source carbon-capture device attached to it. DAC, on the other hand, can run on renewable energy and stabilize electricity prices by being a customer of last resort. In addition to his academic work, Lackner is working to commercialize his own DAC concept, which he calls MechanicalTrees. The “trees” eliminate the cost of running fans by relying on wind to move air across sorbents loaded onto disks arranged in a tower. When saturated with CO2, the towers drop into a chamber where heat and vacuum remove the CO2 at roughly 95% concentration. Paying for it All cool ideas, but who’s putting up the cash? A provision of the US tax code called 45Q offers tax credits for capturing carbon. When the provision is fully in place in 2026, carbon that is captured and sequestered will be worth $50 per metric ton. CO2 used to extract more hydrocarbons, a widespread and controversial practice called enhanced oil recovery, gets $35. That $35 credit plus the $40 per metric ton that enhanced oil recovery operators pay for CO2 on average make that market the most profitable for non-food-grade CO2, even with the lower credit (Front. Clim. 2019, DOI: 10.3389/fclim.2019.00005). That makes the economic rationale for carbon-capture products dependent on the price of oil. That dynamic is what doomed the Petra Nova carbon-capture facility when the price of oil got too low during the pandemic. Still, Oxy Low Carbon executives are prepared to depend on enhanced oil recovery for their southwestern US DAC project. Despite such bumps, carbon capture offers a way to decarbonize combustion and other CO2-emitting processes so they can remain part of a net-zero world. That’s both a selling point and a point of criticism. Critics such as Greenpeace say carbon capture diverts resources away from renewables and keeps polluters in business. Your societal license to dump CO2 into the air will go away. You need to figure out how to operate without needing that license. Klaus Lackner, engineer, Arizona State University Critics also point out that almost all the CO2 captured to date has been used in enhanced oil recovery. In the best cases, enough CO2 stays permanently in the ground after such oil extraction that the resulting fuel has net-negative CO2 emissions. But many enhanced oil recovery projects don’t meet that goal (Energies 2019, DOI: 10.3390/en12030448). “To put it very brutally, in the beginning, I don’t care” where the captured CO2 goes, Lackner says. The technology needs to start scaling up now. He points to a recent report from the International Energy Agency detailing a path to net zero by 2050. In that scenario, point-source capture has to scale up from about 40 million t per year today to 6.6 billion t in 2050, and DAC has to grow from a few thousand metric tons per year to almost 1 billion t in 2050. If enhanced oil recovery operators are willing to be early adopters that get carbon capture down to a cost that the market will bear, Lackner says, that’ll have to do. “The only way you get there is by learning. Most industries gain 10–20% in cost reduction for every doubling of cumulative output,” he says. “If we follow normal learning curves, I’m allowed to be optimistic. If it turns out we derail from that, the sooner we know, the better off we are.” Shell’s Crouch agrees that industry needs to start deploying carbon capture now to reach the necessary scale. “We will require something roughly the size of the current oil and gas industry, but with the molecules going in reverse,” she says. Building all those plants will cost $655 billion to $1,280 billion over the next 3 decades, according to a recent analysis by the GCCSI. That’s a lot of money, but Brad Page, CEO of the GCCSI, points out in a press release that “investing around one trillion dollars over almost 30 years is well within the capacity of the private sector which invested almost two trillion dollars in the energy sector in 2018 alone. Government decisions hold the key to enabling the requisite private sector capital being allocated for [carbon capture and storage] deployment.” One proposal the US Congress is considering now would add a higher credit for carbon captured from the air. The idea has broad bipartisan support, according to Oxy Low Carbon’s Edwards. At a recent panel discussion hosted by the nonprofit OurEnergyPolicy, he expressed confidence that enhanced incentives, R&D and deployment support, and funding for infrastructure for CO2 transport and storage could all become law in the current session of Congress. Jeremy Harrell, the managing director for policy at the energy-transition nonprofit ClearPath and another OurEnergyPolicy panelist, said he expects the Biden administration to launch a 50:50 cost-sharing initiative to deploy a first wave of carbon-capture facilities. “We think that sends a really important market signal to the private sector as they look to invest in these technologies,” he said at the event. “The politics here are going to play out well over the next 18 months, and people should stay tuned.” The administration’s proposed budget for the next fiscal year includes a 61% increase in spending at the Department of Energy on carbon capture, use, and storage, though the $368 million total is far short of what many climate activists would like to see. Edwards says 45Q has opened the door to commercial-scale carbon-capture projects. Since Congress extended 45Q in 2018 and removed the cap on the number of credits available, 30 to 40 new projects have been publicly proposed, he says, which would more than double the global number. Between projects that are being kept quiet for now and new ones that will be unlocked if Congress expands 45Q, that increase is “just the tip of the iceberg,” Edwards says. It’ll need to be. Right now, 28 point-source capture and DAC plants are active, including at Boundary Dam and nonpower installations, according to the GCCSI. The world will need 2,000 large facilities by 2050, along with transportation and storage infrastructure, to reach net zero by then. “The reality is, we’ve only got a certain amount of time left,” the GCCSI’s Steyn says. “We’re now pushing against the clock.” Considering how long it takes to finance, engineer, and build a trillion dollars of industrial equipment, he says, “If you’re going to actually make inroads toward net-zero 2050, it’s got to happen this decade. This is the make-or-break decade.” Chemical & Engineering News, ISSN 0009-2347 Copyright © 2021 American Chemical Society

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Scars from the Mountain Valley Pipeline by Autumn Crowe – WV Rivers
by DUANE NICHOLS 10 Nov '21

10 Nov '21

https://wvrivers.org/2021/11/mvpscars/?fbclid=IwAR3T-UgEIcdAwxG4gXzlzwy4HEK… Scars from the Mountain Valley Pipeline As we rumble down the runway, my heart beats with anticipation as the plane picks up enough speed and the wheels lift off the ground to get that feeling of floating, airborne! I glance back at Jenny Harnish, our videographer who films and edits our pipeline video series, smiles plastered on our faces. We look down as our familiar little town of Lewisburg passes by underneath our wings and we head toward the Greenbrier River Valley. Our first waypoint is near Pence Springs, where MVP proposes to drill under the Greenbrier River. But the river valley is still fogged in so we continue north. Out of the fog appears a large swath denuded of trees going straight up the mountainside. Little trucks and heavy equipment can be seen moving dirt around below. The scar continues along the ridgeline until it cuts down into the valley and stream below. The pilot slows the plane and does a few circles so Jenny can point her video camera out the window to attempt to capture the rugged terrain and steepness of the slopes. Seeing the construction from the air brings a different perspective. The pipeline scar continues along ridgetops as far as the eye can see in either direction dropping down into the valley and then appearing again on the next ridge. Seeing the land from a plane really conveys the incredible impact humans have on the landscape. When flying in Alaska, there were great distances where I couldn’t see any human impact, so much of the landscape was wild and untouched. But flying over this region of WV, I was hard-pressed to find a spot that didn’t have an imprint of Man. At one point near Quinwood, we were seeing pipeline construction, coal mining, timbering and windmills all in the same viewshed.

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Mon County Coal Communities Workgroup Listening Session - Nov 10
by DUANE NICHOLS 08 Nov '21

08 Nov '21

From: Hansen for House <hansenforwv(a)hansenforhouse.emailnb.com> > Date: November 8, 2021 at 8:48:07 AM EST > To: Duane Nichols <Duane330(a)aol.com> > Subject: Mon County Coal Communities Workgroup Listening Session - Nov 10 > > > > Duane -- > > The Mon County Coal Communities Workgroup Listening Session is this Wednesday, November 10. I hope you can join us! We kicked things off in Logan and Beckley recently, and the sessions went very well, with high attendance and lots of constructive ideas. Here's some news coverage in the Gazette-Mail and Metro News. > > The Workgroup's goal is to develop policy recommendations to help revitalize West Virginia’s coal communities. We're talking with local residents, as well as community and business leaders, to find out what our coal communities need to succeed and what tools are already available that we can build on. We aim to facilitate the flow of federal, state, and private foundation resources into communities to diversify economies. > > Everyone with ideas on how to make our community better is encouraged to attend. > > Monongalia County Coal Communities Workgroup Listening Session > Wednesday, November 10, 6:30 pm > The Shack, 537 Blue Horizon Dr, Pursglove, WV 26546 > > If the Shack parking lot is full, then you can park along the road or across the road at the post office. > > Hope to see you there! > > Evan > Hansen for House > http://www.hansenforwv.com/ > > Hansen for House · PO Box 139, Morgantown, WV 26507, United States > > >

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ARMY CORPS OF ENGINEERS — Public Hearing(s) on “Mountain Valley Pipeline”
by DUANE NICHOLS 01 Nov '21

01 Nov '21

https://www.frackcheckwv.net/2021/11/01/army-corps-of-engineers-%e2%80%94-p… ARMY CORPS OF ENGINEERS — Public Hearing(s) on “Mountain Valley Pipeline” MOUNTAIN VALLEY PIPELINE in WV & VA NOTICE OF VIRTUAL PUBLIC HEARINGS — Mountain Valley Pipeline in WV & VA NOTICE IS HEREBY GIVEN that virtual public hearings will be conducted by the United States (U.S.) Army Corps of Engineers (Corps) to solicit the views of interested persons regarding the permit application submitted by Mountain Valley Pipeline (MVP), LLC. The Corps is reviewing the application under the authority of Section 10 of the Rivers and Harbors Act of 1899 and Section 404 of the Clean Water Act. SUBJECT: The applicant has requested a Department of the Army (DA) permit from the Huntington District, the Pittsburgh District and the Norfolk District for the permanent discharge of dredged and/or fill material into 1,179 linear feet of streams (0.2527 acre) and 0.485 acre of wetlands, the temporary discharge of dredged and/or fill material into 38,083 linear feet of streams (8.0757 acres) and 17.57 acres of wetlands, and work in five (5) navigable waters of the U.S. (the Elk, Gauley and Greenbrier Rivers in West Virginia and the Roanoke and Blackwater Rivers in Virginia) associated with construction of the project known as the MVP Project[1]. The proposed pipeline project would be approximately 304 miles in length and begin at the existing Equitrans, L.P. transmission system near the Mobley processing facility in Wetzel County, West Virginia and end at the Transcontinental Gas Pipe Line Company, LLC’s (Transco) Zone 5 Compressor Station 165 in Transco Village, Pittsylvania County, Virginia. The proposed project is contained within the states of West Virginia and Virginia. The proposed project crosses three (3) Corps Regulatory District boundaries including Huntington and Pittsburgh Districts in West Virginia and Norfolk District in Virginia. Details of the proposed project can be found at: https://www.lrh.usace.army.mil/Missions/Regulatory/Public-Notices/Article/2… Public Notice Nos. LRH-2015-00592-GBR, LRP-2015-798 and NAO-2015-0898 issued by the Corps on March 29, 2021 advertised the applicant’s proposal. The public notice comment period was subsequently extended for an additional 30 days. The public notice version of the DA permit application and appendices are available under the IP Applications tab for public download at: http://www.mountainvalleypipeline.info/news-info/ PURPOSE: The purpose of the public hearings is to acquire information which will be considered in evaluating the permit application and to afford the public an opportunity to present their views, opinions, and information on the proposed permit action. Given the broad geographic scope of the proposed project and the extent of expressed public interest in the proposed project, it has been determined that two (2) public hearings, one (1) in West Virginia and one (1) in Virginia, will be held to better accommodate public participation. The Corps will hold these public hearings in the evening hours in order to accommodate maximum participation. Recognizing the health and safety concerns associated with the ongoing COVID-19 pandemic and the Health Protection Conditions that the limit occupancy of District office facilities in the permitting Districts, it has been determined that the public hearings will be held on the WebEx virtual platform. Participants may participate either by telephone and/or computer. The public hearings will be held in accordance with the procedures in 33 CFR Part 327. Public Notice Attachment: LRH-2015-00592-GBR, LRP-2015-798, NAO-2015-0898 — Public Hearing Attendance Information §— November 1: West Virginia Hearing Information — Attendee Instructions The conference begins at 6:00 PM Eastern Time on November 01, 2021; you may join the conference 10 minutes prior. To join the conference, click: https://ems8.intellor.com/login/840973 Join the Webex event and follow the prompts to connect audio by computer or telephone. Need to join via phone only? 888-251-2949 or 215-861-0694 – Need an international number? Access Code: 8624273# . § — November 4: Virginia Hearing Information — Attendee Instructions The conference begins at 6:00 PM Eastern Time on November 04, 2021; you may join the conference 10 minutes prior. To join the conference, click: https://ems8.intellor.com/login/840982 Join the Webex event and follow the prompts to connect audio by computer or telephone. Need to join via phone only? 888-251-2949 or 215-861-0694 – Need an international number? Access Code: 3683150# . § — November 9: Alternate Date Information (Only to be held in the event of technical issues with the primary hearing dates) Attendee Instructions — The conference begins at 6:00 PM Eastern Time on November 09, 2021; you may join the conference 10 minutes prior. To join the conference, click: https://ems8.intellor.com/login/840995 Join the Webex event and follow the prompts to connect audio by computer or telephone. Need to join via phone only? 888-251-2949 or 215-861-0694 – Need an international number? Access Code: 9003633# . Participants are encouraged to log in several minutes early. For additional assistance please contact Webex Support: 888-793-6118. For additional information, including information related to attending on a mobile device, please visit: https://help.webex.com/en-US/article/8l0y08/Join-a-Webinar-in-Webex-Events- (New)#Cisco_Generic_Topic.dita_fc78570c-5cf7-403a-a1a1-993a4fd36eb3 >>>>>……………>>>>>……………>>>>> RSVP — If you wish to provide oral comments on the proposed project you are strongly encouraged to RSVP with your intent to speak at the public hearing to CELRP-MVP(a)usace.army.mil with the statement “RSVP to Speak at West Virginia Public Hearing” or “RSVP to Speak at Virginia Public Hearing” as appropriate and include your full name, email address, and contact phone number with area code. You may also request an advance copy of any visual presentation material by e-mail to CELRP-MVP(a)usace.army.mil. If time allows, unscheduled speakers may be allowed to provide oral public comments by following the directions of the moderator. AGENDA: The public will be able to submit electronic statements through the webinar application beginning at 6 p.m. on the date of each scheduled hearing respectively. The audio and visual portions of the hearing will also begin at 6 p.m. Attendees may join the conference 10 minutes prior to the scheduled meeting time. Introduction by Corps, Overview of Regulatory Program, Project Description, Oral Public Comments >>>>>>>…………………>>>>>>>…………………>>>>>>> CLOSE OF COMMENT PERIOD: The Huntington District has been designated as the lead Corps District, thus all written comments should be submitted electronically by email at CELRP-MVP(a)usace.army.mil by midnight Eastern Standard Time on November 19, 2021. If you are unable to submit comments via email, they may be sent by the United States Postal Service and postmarked on or no later than November 19, 2021 to the following address: United States Army Corps of Engineers, Huntington District, ATTN: CELRH-RD-E Public Notice: LRH-2015-00592-GBR, LRP-2015-798, NAO-2015-0898 502 Eighth Street, Huntington, West Virginia 25701-2070. Sent from my iPad

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