Oxidential Petroleum plans to build the world’s largest “direct air carbon” removal facility

From the Article by Ari Phillips, Oil and Gas Watch, January 24, 2023

A subsidiary of Occidental Petroleum is planning to build the world’s largest plant designed to capture carbon dioxide (CO2) directly from the air in the oil and gas fields of West Texas, with a start-update sometime in 2024.

Once fully operational, the plant will capture up to 500,000 metric tons of carbon dioxide per year, with the capability to scaleup to 1 million metric tons per year. Direct air capture is a nascent technology that extracts CO2 directly from the atmosphere and stores it underground (or uses it to make fizzy drinks or other products).

While many carbon sequestration experts see the technology as a promising, if expensive, process to remove climate-warming greenhouse gases from the air, major concerns remain about how much of the captured carbon will be pumped back down into the Permian Basin to help Occidental to extract more oil or gas from difficult-to-reach reserves. Critics also wonder how trustworthy the monitoring will be, and how communities and the environment might be impacted by its large-scale application.

For now, Occidental – one of the largest petroleum producers in the country – has a subsidiary, called 1PointFive, that is taking advantage of billions of federal decarbonization dollars up for grabs under new government subsidies to invest in climate tech solutions to global warming. Meanwhile, Occidental will still be pumping out oil and gas responsible for heating the atmosphere. It will be simultaneously profiting from fossil fuel extraction and carbon capture.

The oil and gas company is also attracting revenue from corporate partners. These partners claim that it is good for the climate that they will be paying Occidental to “offset”– or make up for – their greenhouse gas emissions through direct capture while the partners continue to pollute.

For example, the National Football League’s Houston Texans recently announced that they have selected Occidental’s subsidiary as a “preferred carbon removal partner” to offset their flight emissions. Occidental is marketing not only carbon credits but also what they call “net-zero oil” to NFL teams and airlines. According to Occidental, net-zero oil will be attained by removing, via direct air capture, enough emissions to offset all the emissions associated with the oil’s lifecycle from extraction to consumption.

In November, Occidental announced plans for an even bigger direct air capture site in Texas. Occidental has leased 106,000 acres of the 825,000-acre King Ranch, located in South Texas near the Eagle Ford Shale oil and gas field. The company says the land can support up to 30 direct air capture projects that could potentially remove up to 30 million metric tons of CO2 per year, storing up to up to 3 billion metric tons of CO2 in the geologic reservoirs below the ranch.

This storage capacity would be orders of magnitude larger than that provided by the 18 existing direct air capture plants around the world, which capture just 0.01 million metric tons of CO2 each year.

While the latest United National Intergovernmental Panel on Climate Change (IPCC) climate report calls carbon removal essential to meeting climate targets, it also warns of over-relying on notions like direct air capture, which may lull policymakers and perhaps the general public into a false sense of security as to the necessity of deep cuts to emissions now.

Anthony R. Kovscek, a professor of petroleum engineering at Stanford University who studies carbon sequestration, worries that the public might reach a different misunderstanding relating to direct air capture.

“My most substantial concern about direct air capture is that lack of public understanding of the capture process will lead to negative opinions and the withdrawal of government support before the technology is fully developed and evaluated,” said Kovscek.

Currently, initiatives taken through the Inflation Reduction Act and Bipartisan Infrastructure Law aimed at reducing greenhouse gas emissions are providing the incentive to advance carbon sequestration projects and for businesses to seek out credits. Federal tax credits within the Inflation Reduction Act designate direct air capture projects a $180-per-metric-ton credit, far above the previous $50 allotment.

Kovcek believes Occidental’s efforts to be aimed at developing a technology that allows them to use their existing engineering and geosciences expertise as well as sequestration storage space that the company already has rights to use.

“If it’s successful, they will have a new business that potentially outlasts hydrocarbon production and performs a necessary service,” said Kovcek. “Because they are trying to develop a new business, I don’t think that what they are doing is greenwashing.”

Greenwashing or not, for the time being direct air capture and carbon sequestration overall face no shortage of obstacles on the road to contributing significantly to decarbonization. The process remains very expensive and energy intensive and could divert resources and attention from renewable energy projects with more clear-cut benefits. Furthermore, the geologic reserves capable of sequestration are often located far away from carbon emitters such as steel plants and might require substantial investment in new pipelines.

Kenneth B. Medlock III, Senior Director of the Center for Energy Studies at Rice University’s Baker Institute for Public Policy, said he believes even if Occidental is not generating truly “net-zero” oil, it is still resulting in a net CO2 reduction, which can buy time for other technologies.

“It is an intriguing step in the multitude of options being presented for reducing the net carbon footprint of energy,” Medlock said. “It also can leverage existing infrastructures and business models, which can bode well for its future as the technology develops.”

The Infrastructure Bill designated $3.5 billion towards the establishment of large-scale, regional direct air capture hubs across the U.S. In response to the announcement, the Climate Justice Alliance released a letter calling direct air capture, “an unproven technology that allows fossil fuel extraction and use to continue, resulting in ongoing harm to frontline communities.”

“To have any significant effect on global CO2 concentrations, DAC would have to be rolled out on a vast scale, demanding very large amounts of water and energy, and raising environmental justice concerns about the toxic impacts of the chemical absorbents used in the process,” the letter states.

Medlock believes that environmental justice (EJ) concerns about Occidental’s direct air capture are minimal, since the projects are set in remote locations, but that going forward they must be kept front-and-center in the discussion.

“As with all new energy infrastructure, EJ assessments are critical to siting and operation,” he said regarding Occidental’s plans. “So, it is incumbent on the industry to internalize EJ asit moves forward, which requires direct engagement with communities and a conscious effort to avoid injustices.”
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Erin Burns, Executive Director of Carbon180, a climate nonprofit organization focused on carbon removal solutions, said that direct air capture is “an effective means of removing emissions that drive climate impacts and injustice.” But she added that, more broadly: “carbon removal can’t slow efforts to rapidly decarbonize and can’t be an excuse to keep using fossil fuels in the US.”

Because of this, Burns believes that federal government should not fund enhanced oil recovery projects in which the sequestered CO2 is used to extract more fossil fuels , such as the Occidental Permian Basin project, and Carbon180 has advocated for its specific exclusion from key federal direct air capture projects.

Burns said trust underpins the success of this field and the ability to achieve gigaton scale carbon removal by 2050.

“But before we can build trust in direct air capture, robust monitoring, reporting, and verification – MRV – is a fundamental prerequisite,” Burns said. “MRV is the process of accounting for all the emissions, energy use, environmental and public health impacts associated with a carbon removal project to determine its net climate impact. It tells us if the work was done safely and effectively and provides receipts.”

According to Occidental’s agreement with the Houston Texans, the carbon credits purchased will not be linked to any new oil and gas extraction. Instead, the CO2 will be sequestered in reserves not associated with fossil fuel production. However, this agreement is specific to a carbon offset agreement with one NFL team. And it is not clear how much independent verification there will be, or if – in other business agreements or contexts — Occidental will use captured carbon to inject into shale formations to help extract oil and gas.

Aside from the two Texas direct air capture projects, Oil & Gas Watch is also tracking the Sweetwater Carbon Storage Hub, a proposed direct air capture project in Wyoming that would consist of modular carbon capture units capable of removing 12,000 tons of CO2 per year from the air.

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See Also: Direct Air Capture: 5 Things You Need to Know About This Climate Scam ~ Oakley Shelton-Thomas & Mia DiFelice, Food & Water Watch, January 25, 2023

Four workers & fireman injured in multiple explosions in Texas

Article from the News Staff, Reuters News Service, August 1, 2018

HOUSTON (Reuters) – A series of natural gas pipeline explosions in Midland County, Texas sent five people to hospital with critical burn injuries, and interrupted energy pipeline operations in the area, officials said.

The region is the home to the Permian Basin, the largest U.S. oilfield, and is crisscrossed by oil and gas pipelines. The cause of the explosion and fire were not immediately known.

Five workers with critical injuries were airlifted to University Medical Center in Lubbock, Texas, and were being treated at the center’s burn unit, said University Medical Center spokesman Eric Finley.

Pipeline operator Kinder Morgan said on Wednesday it had isolated a portion of its El Paso Natural Gas Pipeline (EPNG) as a precaution, after being alerted to the fire near its line. One of its employees was injured and taken to hospital, spokeswoman Sara Hughes said.

“There was a third-party pipeline involved that also experienced a failure, and preliminary indications are that the third-party line failure occurred before the EPNG line failure,” Kinder Morgan’s Hughes said in an email.

The company is investigating the cause of the fire and evaluating any damage to its property. Regulatory agencies and customers were notified of the incident, she added.

“Fire Department personnel suppressed the fire, however approximately one hour later a second and third small explosion followed,” said Elana Ladd, public information officer for the city of Midland, in emailed comments.

Multiple pipelines are located near the site, Ladd said, adding that first responders were focusing on shutting off pressure and flow to the pipelines at the site.

The pipeline explosion occurred on a rural road, FM 1379, about five miles south of Highway 158 at around 11:30 a.m. local time (1630 GMT), Ladd said, adding that the road had been closed. Ladd identified one of the injured as a firefighter.

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See also: Accident sends 20,000 gallons of drilling fluid into Maumee River tributary in Ohio, July 27, 2018

EOG's iSteer guidance for shale drilling

Fracking 2.0: Shale Drillers Pioneer New Ways to Profit in Era of Cheap Oil

From an Article by Erin Ailworth, Dow Jones Newswire, March 30, 2017

MIDLAND, Texas — Using a proprietary app called iSteer, Brian Tapp, a geologist for EOG Resources Inc., dashed off instructions to a drilling rig 100 miles away. This tool is among the reasons the little-known Texas company says it pumps more oil from the continental U.S. than Exxon Mobil Corp. — or any other producer.

A rig worker received Mr. Tapp’s iPhone alert and tweaked the trajectory of a drill bit thousands of feet underground, to land more squarely in a sweet spot of rock filled with West Texas crude.

U.S. shale drillers transformed the energy industry over the past decade with hydraulic fracturing and horizontal drilling, in the early days using brute force to unleash a torrent of oil and gas that altered the balance of power among oil-producing nations and triggered a global glut.

Now, with oil currently trading near $50 a barrel, these producers are trying to unleash fracking 2.0, the next step in the technological transformation of the sector that is aimed at extracting oil even faster and less expensively to eke out profits at that level.

The promise of this new phase is potentially as significant as the original revolution. If more producers can follow EOG’s lead and profitably ramp up output from shale drilling even at lower prices, the sector could become a lasting force that challenges OPEC’s ability to control market prices.

For a sector in which the previous era’s success was tied to the rapid expansion of output, the shift toward finding more cost-effective ways to get to that oil and gas is full of challenges. When oil prices dropped, critics wondered if the shale industry — rife with heavily indebted companies that had never turned a profit — would collapse.

EOG, with its longtime focus on low-cost production, is the producer many hope to emulate, thanks to the iSteer app and dozens of other homegrown innovations. Dubbed the “Apple of oil” by one analyst, EOG made its name as a pioneer in horizontal drilling and in finding ways to get oil out of shale — often dense layers of rock that hold oil and gas in tiny pores — a feat many once believed impossible.

Competitors such as Chesapeake Energy Corp. and Pioneer Natural Resources Co. also are finding new ways to profit amid low energy prices. Many are experimenting with longer, supersize wells, and fracking them with millions of pounds of sand. Other producers, however, have said the industry needs oil prices of at least $55 to $60 to truly rebound.

The price of oil plunged about 75% from its peak of more than $100 a barrel in mid-2014, and the natural-gas price sank by half in the same period. More than 420,000 oil and gas jobs world-wide have been lost, according to energy consulting firm Graves & Co., and, since the start of 2015, over 200 U.S. energy companies have filed for bankruptcy, according to law firm Haynes & Boone LLP.

EOG, part of Enron Corp. until 1999, now drills horizontal wells in West Texas more than a mile long in 20 days, down from 38 days in 2014. It has done it in as few as 10 1/2 days. It estimates it can get at least a 30% rate of return on wells at $40 a barrel, and that at $50 it can boost oil production at least 15% a year through 2020.

The company said it produced roughly the same amount of oil last year as it did in 2014 with a budget that was 67% smaller. The iSteer app and other proprietary programs EOG designed are partly why.

EOG uses iSteer to help navigate through rock thousands of feet underground, landing in identified layers with more precision. A device behind the drill bit underground transmits information — including depth and direction but also readings to identify types of rock and the presence of gas — to a geologist at the office. The numbers are crunched, using EOG’s databases on the location’s rock layers and on previous wells, and course corrections are sent to the driller on the rig.

EOG said adjustments can happen in minutes, instead of a process that in the past took at least 30 minutes. The quick modifications keep the drill in a 10-to-15 foot window, which EOG said improves the output and consistency of a well.

The apps help employees work at the “speed of thought,” said Sandeep Bhakhri, EOG’s chief information officer. The company now uses 65 apps it designed after realizing it needed tools with capabilities it couldn’t find off the shelf. Along the way, it boosted its staff of data scientists, and over the past three years has hired recent computer-science graduates from the University of Texas at Austin.

The apps help EOG answer a range of questions, such as how much pressure to use to crack a particular geologic stratum, to identifying ideal trajectories for drills, to more mundane queries, such as the fastest route to drive from one drilling site to the next.  ”I look at [the apps] first thing in the morning, on the exercise bike or during breakfast — it gives me a head start on the day,” said Ezra Yacob, general manager of EOG’s Midland operations.

Tinkering, core to the company’s culture, was evident on a recent visit to the division office in Midland, a city of about 124,000 at the heart of the oil-rich Permian Basin in West Texas.

There, geologists, engineers and technicians could be found constantly on their computers and iPhones using EOG’s apps. The company says all workers are encouraged to fiddle and find novel solutions to problems. It’s an outgrowth of the company’s habit of ignoring conventional wisdom as it looks for ways to become a better producer.

In the early 2000s, EOG was determined to show that vast supplies of natural gas could be unlocked by drilling horizontally through shale. It drilled 15 uneconomic wells in the Dallas-Fort Worth-area field known as the Barnett, while its employees experimented to find better techniques, according to former CEO Mark Papa. It succeeded on the 16th.

As the shale boom took off, scores of producers borrowed heavily to lease land for drilling. EOG moved in the opposite direction, keeping debt low and favoring technological innovation and returns over rapid growth.

When Mr. Papa in 2007 realized gas prices were headed for a drop, he said the company started shifting to oil. At the time, few in the industry thought oil could be economically extracted from shale formations.

A bespectacled EOG geologist named Bill Thomas, then the head of the company’s Fort Worth office, was among those who did. He became CEO in 2013, and now can often be found in his 35th-floor office at EOG’s headquarters in Houston scrutinizing data about well productivity. Instead of a secretary, the assistant outside his office is one of the company’s top geo-technicians, responsible for analyzing information.

The company’s market cap is now $55 billion. Shares closed at $97 Wednesday, down 18% from their price at oil’s mid-2014 peak, beating the SPDR S&P Oil and Gas Exploration and Production ETF, a common industry benchmark, which dropped 55% in that time.

EOG regularly solves problems in-house. When, in the early days of drilling for crude in North Dakota’s Bakken Shale, the company hit logistical problems getting its oil to market, it built a rail terminal and pipeline to help move it from North Dakota to the trading hub near Cushing, Okla.

These days, it designs its own motors to power drill bits, allowing its engineers to constantly incorporate fixes that improve performance. Oil is pumped into olive-green storage tanks made to EOG’s specifications, cutting down costs and the number of tanks it needs in the field.

It often works with smaller services contractors, instead of giants such as Schlumberger Ltd. and Halliburton Co., so it can negotiate costs and find expertise tailored to its needs. The partnerships save it money and give it more control over the logistics and supplies needed for any given project, EOG said.

For example, a larger services company might ask EOG to use a particular sand supplier or employ a standard mix of sand, water and chemicals when fracking a well. With a smaller services company, EOG can potentially use sand from a company-owned mine — it bought one in 2008 when the specialized grains started becoming hard to find — and design fracks to meet specific needs.

Heath Work, an EOG drilling manager in Midland, compared the way the company operates to a championship Nascar driver and crew, who make small adjustments that add up over time. “Jimmie Johnson has won seven times and he does it with the same engine as his competitors; he just figures out how to change tires faster,” Mr. Work said.

Competitors are innovating too, as producing oil for less becomes more important than merely finding and pumping new supplies. Chesapeake Energy recently used a record 50 million pounds of sand to frack a megawell in Louisiana, reaping cost savings via economies of scale. Chesapeake, which some believed was close to bankruptcy in early 2016, said the giant wells are part of its turnaround strategy.

Pioneer Natural Resources said it saves money by mining some of its own sand and has been building its own system to transport the water it needs. Chief Executive Tim Dove said those operations are integral to the company’s goal of producing one million barrels of oil equivalent a day by 2026 while still having cash to cover expenditures.

Critics have questioned EOG’s habit of quickly ramping up production from individual wells, arguing that can cause wells to peter out prematurely. The company used the strategy to supercharge returns in the Eagle Ford, an oil-rich region of South Texas where it was ahead of the pack in leasing more than 500,000 acres for a tiny percentage of what others would pay later.

Mr. Thomas, the CEO, said trial and error has proven its Eagle Ford wells aren’t damaged when allowed to flow aggressively. “You increase your returns because the wells pay out so much quicker,” he said. “If you get a higher return and it doesn’t damage the well, then why not do it?”

See also: www.FrackCheckWV.net

Murray's water well to fracked gas well = 2060 ft.

Scientists Link Fracking to Explosion That Severely Injured Texas Family

From an Article by Lorraine Chow, EcoWatch.com, March 10, 2017

Scientists have determined that methane from a fracked well contaminated a Texas family’s water supply and triggered an explosion that nearly killed four members of the family. The family’s ranch in Palo Pinto County is located only a few thousand feet away from a natural gas well.

Scientists have found that methane escaped from a poorly constructed natural gas well and leached into a Texas family’s water well, causing it to explode.WFAA

In August 2014, former oil field worker Cody Murray, his father, wife and young daughter were severely burned and hospitalized from a “fireball” that erupted from the family’s pump house.

A year later, the family filed a lawsuit against oil and gas operators EOG Resources and Fairway Resources, claiming the defendants’ drilling and extraction activities caused the high-level methane contamination of the Murrays’ water well.

“At the flip of the switch, Cody heard a ‘whooshing’ sound, which he instantly recognized from his work in the oil and gas industry, and instinctively picked his father up and physically threw him back and away from the entryway to the pump house,” the complaint states. “In that instant, a giant fireball erupted from the pump house, burning Cody and [his father], who were at the entrance to the pump house, as well as Ashley and A.M., who were approximately twenty feet away.”

While the state’s oil and gas regulator—the Texas Railroad Commission—has yet to definitely prove what caused the blast, new scientific studies commissioned by the Murrays’ attorneys has directly linked the explosion to fracking operations.

As the Texas Tribune detailed, the studies found that methane and drilling mud chemicals had escaped from a poorly sealed Fairway gas well and traveled through underground fractures and eventually into the Murrays’ water supply.

The hired experts include Thomas Darrah, a geochemist at Ohio State University; Franklin Schwartz, an Ohio State University hydrologist; Zacariah Hildenbrand, chief scientific officer at Inform Environmental; and Anthony Ingraffea, a civil engineering professor at a Cornell University with expertise in fracking.

“The timing is undeniable, the location is undeniable, the chemistry of the gas is undeniable,” Chris Hamilton, the Murray’s attorney, told news station WFAA. “This is not naturally occurring gas. This is gas that came from 4 to 6-thousand feet below the ground.”

Hamilton shared a video with WFAA that shows the bubbling, methane-saturated water that caused the 2014 explosion.  ”What you can see in the video here is just super carbonated water that is saturated with methane gas that’s bubbling out of the Murray’s water,” he explained.

“This is an explosive gas,” Hamilton added. “Large bubbles and pockets of this methane escaping from a water well, any sort of spark will start a fire.”

Groundwater contamination is one of the biggest concerns about unconventional oil and natural gas development. While the industry maintains the safety of the process, in December the U.S. Environmental Protection Agency released its highly anticipated final report identifying cases of impacts on drinking water at each stage in the hydraulic fracturing water cycle.

Incidentally, the Texas Sunset Advisory Commission—a state legislative body that reviews agencies—has been highly critical of the Texas Railroad Commission’s effectiveness at regulating the oil and gas industry.

As WFAA reported:

“It’s the 3rd such report since 2010, and is critical of Railroad Commission’s effectiveness and operations. ‘The commission’s lack of a strategic approach to enforcement and inability to provide information persists.’ The report cites: ‘no accurate counts of major violation,’ ‘no accurate measure of violations referred for legal enforcement action’ and ‘(Oil and gas) operators have a reasonable expectation they will not be penalized.’”

Fairway Resources declined to provide a comment to WFAA due to the ongoing lawsuit. The Texas Railroad Commission also declined to comment citing their ongoing investigation.

See also: www.FrackCheckWV.net

Percent Change in Jobs with & without Fracking

The false promise of fracking and local jobs

From an Article by Susan Christopherson, Professor, Department of City and Regional Planning at Cornell University, January 27, 2015

In a surprise decision that led to consternation in the oil and gas industry and elation among fracking opponents, New York Governor Andrew Cuomo in December banned fracking in the state. He attributed his decision to unresolved health risks associated with this drilling technique, but the governor surely also weighed the economics and the politics.

During the past five years, I’ve researched and written about the economic impacts of fracking and, as a long-time resident of New York, I have observed its fractious politics. What I’ve found is that most people, including politicians and people in the media, assume that fracking creates thousands of good jobs.

But opening the door to fracking doesn’t lead to the across-the-board economic boon most people assume. We need to consider where oil and gas industry jobs are created and who benefits from the considerable investments that make shale development possible. A look at the job numbers gives us a much better idea of what kind of economic boost comes with fracking, how its economic benefits are distributed and why both can be easily misunderstood.

Not a recession buster

Pennsylvania is one of the centers of dispute over fracking job numbers. In Pennsylvania, the job numbers initially used by the media to describe the economic impact of fracking were predictions from models developed by oil and gas industry affiliates. For example, a Marcellus Shale Coalition press release in 2010 claimed:

“The safe and steady development of clean-burning natural gas in Pennsylvania’s portion of the Marcellus Shale has the potential to create an additional 212,000 new jobs over the next 10 years on top of the thousands already being generated all across the Commonwealth.”

These job projections spurred enthusiasm for fracking in Pennsylvania and gave many people the impression that oil and gas industry employment would lead Pennsylvania quickly out of the recession. That didn’t happen.

Pennsylvania’s unemployment roughly tracked the national average throughout the state’s gas boom. While some counties benefited from the fracking build-up, which occurred during the “great recession,” the state economy didn’t perform appreciably better than the national economy.

Nationally, the oil and gas industry employs relatively few people compared to a sector like health care and social assistance, which employed over 16 million Americans in 2010. The drilling, extraction and support industries employed 569,000 people nationwide in 2012, according to the Energy Information Administration (EIA).

Although it grew faster than other sectors of the economy, the core of oil and gas employment constitutes only one half of one percent of total US private sector employment. This total includes jobs unrelated to shale development and jobs that preceded the shale boom. As for job growth, the EIA indicates that 161,600 of these jobs were added between 2007 and 2012. Drilling jobs specifically increased by only 6,600.

Impressive growth percentages notwithstanding, that is not a lot of jobs. In 2010, more than 143 million people were employed in the US, according to the Bureau of Labor Statistics (BLS).

In Pennsylvania, the Multi-State Shale Research Collaborative (MSSRC) report on shale employment in the Marcellus states found that shale development accounts for 1 out of every 249 jobs, while the education and health sectors account for 1 out of every 6 jobs.

FedEx drivers?

The central issue with job projections is how many additional jobs are credited to oil and gas development beyond the relatively small number of people directly employed in oil and gas extraction.

In December 2014, Pennsylvania’s Department of Labor and Industry reported that just over 31,000 people were employed in the state’s oil and gas industry. That figure was higher than the federal data indicates, but appears to be reasonable. However, what’s striking is that the Department attributed another 212,000 jobs to shale development by adding employment in 30 “ancillary” industries.

All employment in these related industries – including such major employers as construction and trucking – was included in this attributed jobs figure. Thus, a driver delivering for FedEx or a housing construction worker were “claimed” as jobs produced by the shale industry.

This is eye-rolling territory for economists. They know that attributing two additional jobs to every one directly created in an industry is very generous. The Commonwealth of Pennsylvania attributed seven additional jobs to each one created in the oil and gas industry.

Depending on how broadly you define the state’s oil and gas industry, between 5,400 and 31,000 people were employed in Pennsylvania before many of the rigs started pulling out in 2012 to head west. Certainly, jobs in other sectors were also created, but a generous estimate would be 30,000 to 60,000 rather than the hundreds of thousands claimed by industry promoters.

QCEW is the Quarterly Census of Employment and Wages, a federal-state cooperative program that is based largely on the quarterly Unemployment Insurance reports filed by employers. Multi-State Shale Research Collaborative, Pennsylvania Budget and Policy Center, Author provided.

The MSSRC report demonstrates that only a tiny portion (under 1%) of jobs in many of these 30 industries could be related to shale development activities, and further, that Pennsylvania employment in these industries overall changed little before, during, and after the shale boom.

The real winner: Texas

Beyond the exaggerated numbers, a geographic blindness obscures our view of fracking jobs. Where do the workers extracting gas in Pennsylvania or Ohio live and spend their money? Where are the best jobs located? While the fracking industry may support the national economy as a whole, some places are winners and others are losers.

In Ohio, where extraction continues because its shale holds both natural gas and other valuable “wet gas” hydrocarbons, a series of investigative reports by The Columbus Dispatch showed that at least a third of the workforce in drilling areas are transient workers. In the four Ohio counties with the most shale permits, the number of local people employed actually decreased between 2007 and 2013.

This tells us that the production sites aren’t necessarily the places that get the economic boost. The most skilled workers on drilling crews are from Texas and Oklahoma and they return home to spend their earnings. Northern Pennsylvania drilling crews spent much of their money in the Southern Tier of New York.

My own research on the geography of shale jobs shows that Texas has derived the lion’s share of the benefits from US fracking. Texas has consistently had around half the jobs in the oil and gas industry (currently 47%). During the 2007-2012 shale boom, Pennsylvania gained 15,114 jobs in the drilling, extraction and support industries, but Texas gained 64,515 – over four times as many jobs. Texas not only has much of the skilled drilling workforce, but the majority of the industry’s managers, scientists and experts, who staff the global firms headquartered in Houston. Still, even in Texas, energy-related jobs constitute only 2.5% of the state’s now more diversified employment.

What does this tell us about New York’s decision on fracking? Andrew Cuomo may have decided that the state would do better providing finance capital to the oil and gas industry from Wall Street rather than taking on high-risk, low-reward fracking production. _________________________________

See also: www.FrackCheckWV.net

Chevron Phillips Chemicals in TX

CPChem Receives Board Approval for $5 Billion Project in Texas – An Ethane Cracker and Two Polyethylene Units

From an Article of Platts News Service, Houston, TX, October 3, 2013

Chevron Phillips Chemical has received board approval to execute its US Gulf Coast Petrochemical Project, the company said Thursday. The project, announced in March 2011, includes building two polyethylene units with annual capacity of 500,000 metric tonne (mt) and one 1.5 million mt/year ethane cracker.

The company has awarded an engineering, procurement and construction contract to Gulf Coast Partners, a partnership between Zachry Industrial and Technip USA, for the construction of the two polyethylene facilities. The ethane cracker EPC contract was awarded to a joint venture between JGC (USA) and Fluor Enterprises.

The company announced August 13 it had secured air permits from the Texas Commission on Environmental Quality for the project and a greenhouse gas permit from the US Environmental Protection Agency for for the cracker.

The two polyethylene units will be built at a site in Old Ocean, Texas, near Chevron Phillips Chemical’s Sweeny plant, while the ethane cracker will be built at Chevron Phillips Chemical’s Cedar Bayou plant in Baytown, Texas.

The projects are expected to be completed by 2017, the company said. Site preparation is in progress, critical equipment for the project has been ordered, expansion of the supporting infrastructure has commenced and the company has executed a contract for the fabrication of the railcars needed to supply product, it said.

“We are able to realize this important milestone thanks to continued strong growth in demand for our products, shale resource development in the United States, and the tremendous support of our owners,” said Pete Cella, president and CEO of Chevron Phillips Chemical. “We remain in the first-mover position as we take another critical step in executing a project that will benefit our customers, suppliers, local communities and existing and future employees.”

The company, a partnership between Chevron and Phillips 66, previously estimated the total investment in project at $5 billion. CPChem expects the project to create about 400 long-term direct jobs and 10,000 engineering and construction jobs.

The polyethylene units will be capable of producing high and linear low density polyethylene products, including bimodal and metallocene-based polyethylene polymers. In addition to the bimodal and linear low density products, the flexibility of these units will allow for growth of current blow molding, injection molding and film grades currently offered by the company.

Dow Chemical to build new ethane cracker plant in Freeport (Texas) Dow Chemical will create up to 2,000 construction jobs and hundreds of permanent positions by building a Texas ethylene facility scheduled to open in 2017. The move comes as Chevron Phillips Chemical, Lyondell Basell and Shell Chemicals are examining similar U.S. investments. “Constructing this new ethylene cracker at Dow Texas Operations will create a long-term advantage for our downstream businesses and for our company as a whole, and the benefits will accrue not only to Dow but to the state and national economy,” said Dow Chairman and CEO Andrew Liveris. ICIS News (U.K.) (4/19), The Wall Street Journal (4/18), according to the SmartBriefs of the American Institute of Chemical Engineers (AIChE).

Don Hopey of the Pittsburgh Post-Gazette reported on March 26th that these chemical plants bring with them a number of serious environmental problems:  “Such a plant is going to have nitrogen oxide and VOC emissions that play into ozone creation and airborne particulates that add to what is already in the area,” said Jeff Robinson, section chief for air permits at EPA’s Region 6 office in Dallas (Texas), who has extensive experience reviewing cracker facilities (27 of the country’s 44 crackers are in Texas). “Regulators will have to assess the air impacts from the facility when Shell sends a construction permit application to the state (for the Beaver County, Pennsylvania plant).”

Also, Shell has under study a $10 billion methane-to-diesel processing plant in Louisiana, according to a report in the Wall Street Journal on April 4^th, as described on FrackCheckWV on April 11, 2012. This is based upon a similar Shell plant now being brought into production in Qatar, which is very much over budget (at a cost approaching $24 billion). Shell has another Middle Distillate Synthesis (MDS) plant in Bintulu, Sarawak, which uses methane (natural gas) to make fuels and specialty chemicals:

The Shell MDS plant is the first of its kind in the world and is the culmination of over 30 years research into the utilisation of alternative raw materials for the production of fuels and specialty chemicals. This fits well with the Shell Group emphasis on sustainable development. The synthetic fuels and specialty chemicals produced by the Shell MDS plant are unrivalled in terms of purity and paraffinicity.

Shell MDS technology converts natural gas to long chain paraffins which are subsequently either hydrocracked to produce liquid fuels or fractionated to produce chemical feedstocks and waxes. The use of non-associated natural gas as feedstock and the high selectivity of the conversion process ensure a consistency of quality unmatched by equivalent products derived from crude oil.

Shell MDS process incorporates state-of-the-art safety, energy conservation and environmental protection systems. The plant itself is completely integrated such that the only incoming raw material is natural gas and the only outgoing waste products are water and flue gas, which are regulated by highly efficient waste water treatment and flare system respectively.

So we can easily predict a thriving chemical industry world wide, using methane to make synthesis gas and using ethane to make ethylene, as intermediates to various fuels and “petrochemicals.”  But, who can predict the nature and extent of the environmental and infrastructure problems that will be visited upon the general public, mostly at the expense of the tax payers and to the detriment of the public health and welfare.