Tar sands industry is out of control in Canada

From an In-Depth Article by Drew Anderson, The Narwhal News, June 4, 2022

Mapping the growth of the toxic reservoirs shows just how far they’ve expanded since 1975, amid a surge in bitumen (tar) mining.

Picture downtown Toronto. All the condos, subways, roads, office towers and people. Now cover the whole thing with a toxic lake. Maybe you’ve never been there. Have you done the drive from Calgary into the Rockies? Imagine almost the entire 105-kilometre stretch from the city to Canmore as one continuous vista of oilsands tailing ponds.

According to a new report titled “50 Years of Sprawling Tailings” from Environmental Defence and the Canadian Parks and Wilderness Society, those are just two examples of how large the tailings ponds in northern Alberta have grown.

And despite new rules introduced in 2016 around managing tailings, the ponds have continued to grow, according to the report. This growth represents an increasing ecological and economic risk that will cost billions of dollars to clean up and could leave taxpayers footing the bill.

So what exactly does that look like on the ground? And what impact do tailings ponds have?

Here’s a bit of background ~ What are tailings ponds?

First thing to note, and it’s something the authors of the report stress right off the top: the ponds are anything but ponds as most people understand them.

“To be calling them ponds when tailings ponds actually are far larger than anything you would ever describe as a natural pond — it’s deception,” Gillian Chow-Fraser, co-author of the report and boreal program manager for the Canadian Parks and Wilderness Society, says.

“I don’t think it’s being very accountable to the level of destruction that’s happening in northern Alberta.”

One of the largest ponds, notes Chow-Fraser, is eight kilometres long. That’s almost as long as Alberta’s famed Sylvan Lake. Looking further afield, that will almost get you to the top of Mount Everest.

That said, the report uses the term pond to maintain consistency while expounding on the decidedly un-pond-like size of the waste reservoirs.

Inside those ponds is a toxic mix of byproducts from the mining of oilsands, including arsenic, naphthenic acids, mercury, lead and polycyclic aromatic hydrocarbons — all of which can impact ecosystems, wildlife and humans.

The ponds also emit air pollution that extends for kilometres.

The purpose of the ponds is to allow the byproducts of mining to separate from the water and settle at the bottom of the pond, a process that can take decades or more. Once those byproducts are settled, the pond can be drained and capped with soil to achieve some level of reclamation.

Why are Alberta oilsands tailings ponds still growing?

The tailings ponds have been growing for nearly 50 years, increasing in size by nearly 800 per cent in the late 1970s, before continuing to grow at varying rates, depending on factors such as global demand for oil and the state of the economy. Most recently, the size of the tailings ponds grew by over 50 per cent from 2010 to 2015, and then by just over 16 per cent from 2015 to 2020, according to the report.

There are now 30 active ponds in the region, the report also says.

The authors used satellite imagery going back to 1975 to measure the physical growth of the ponds — including the fluids and the related impacts such as berms and areas where dry tailings are stored — but not the volume of tailings they hold.

For that they relied on Alberta Energy Regulator reports (more on that shortly).

Aliénor Rougeot, co-author and climate and energy program manager for Environmental Defence, says they included things like berms and beaches created by the ponds — where you would not want to sunbathe — because all of it impacts the surrounding area.

“That’s the peatlands and boreal forest that were taken away, or that’s the area that the Indigenous communities can no longer have traditional practices on,” she says.

In total, the report says the footprint is 300 square kilometres, big enough to more than twice cover the city of Vancouver or a large chunk of Toronto.

“I live in downtown Toronto, and so I think I know what large means, I think I know what human activity taking over nature looks like,” Rougeot says. “And yet when I saw the scale when I saw those maps, especially the layovers of cities. I mean, that was just baffling to me.”

Ponds increase as new expansions or new mines are approved and the existing ponds fail to shrink.

The report did not trace the rise in the volume of the ponds, but that has also increased over the years, and the report notes current levels are 1.4 trillion litres of tailings based on Alberta Energy Regulator figures.

……. much more in the Article and the Report!

2015 explosion at Exxon Mobil Corp.'s Torrance, Calif., refinery

From an Article by E.A. Crunden, Greenwire, E&E News, December 2, 2020

EPA will not require three major industries to guarantee funding for toxic waste cleanups under federal Superfund law, finalizing a controversial rule in the last months of the Trump administration.

The agency said it would not mandate the chemical manufacturing, oil and gas, and coal power plant industries to provide financial assurance in the event of major accidents and crises.

“EPA has found that existing environmental regulations and modern industry practices are sufficient to mitigate any risks inherent in these industries,” said EPA Administrator Andrew Wheeler in a statement Wednesday.

The agency said it analyzed the need for new financial assurance requirements for those industries under the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA), looking at financial risks associated with those sectors. EPA said it also evaluated a range of other factors including the history of Superfund cleanups, economic trends and input from the public in its assessment.

“EPA reviewed and considered public comments to conclude that the level of risk is addressed by existing requirements and does not warrant new requirements for these industries,” the agency stated in its announcement.

That decision means no new rules will be introduced addressing the issue. It runs counter to the Obama administration’s argument that industries should have the financial means to fund toxic waste cleanups to ease strain on the government.

The decision affecting the three industries follows a similar move on hardrock mining. In 2017, the Trump administration opted not to impose new insurance requirements on that industry, generating significant litigation (Greenwire, Dec. 4).

Advocacy organizations have already slammed EPA’s new rule as detrimental for taxpayers and the environment, as well as vulnerable communities. They say companies often declare bankruptcy to avoid liability for cleanups, something financial assurance can help prevent.

“For years, it’s been the most important rule that nobody knows about,” said Lisa Evans, senior counsel for the group Earthjustice, calling EPA’s findings “really a huge step backwards.”

Evans said the move holds outsize environmental justice implications, as industrial sites are often located near low-income communities and people of color. She said financial assurance both guarantees a source of funding for cleanup and encourages companies to adopt safer backups to begin with, limiting the chances of future Superfund sites.

Superfund experts say the program has suffered from chronic underfunding in recent years under Democratic and Republican administrations alike. That limited budget has hindered the pace of cleanups, with more than 1,300 sites currently on the National Priorities List. Proponents of financial assurance see it as a key mechanism for ensuring a responsible party is attached to a site in the case of a cleanup. Accident insurance is an example of a financial assurance mechanism.

The incoming Biden administration is likely to take a different approach and push forward financial assurance rules, but Evans said that would take some time given the nature of the rulemaking process. She criticized the Trump administration’s decision as a last-minute action that could extend that process by several years.

“We’re back to square one,” Evans said.

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See also: One person killed in Belle chemical plant explosion, Charleston Gazette Mail, December 9, 2020

Explosion and fire disturb Kanawha River valley in West Virginia on 12/9/20

Earthquakes above magnitude 3 out of control (USGS)

From an Article by Emily Brodsky, The Conversation, September 2, 2018

Earthquakes in the central and eastern U.S. have increased dramatically in the last decade as a result of human activities. Enhanced oil recovery techniques, including dewatering and hydraulic fracturing, or fracking, have made accessible large quantities of oil and gas previously trapped underground, but often result in a glut of contaminated wastewater as a byproduct.

Energy companies frequently inject wastewater deep underground to avoid polluting drinking water sources. This process is responsible for a surge of earthquakes in Oklahoma and other regions.

The timing of these earthquakes makes it clear that they are linked with deep wastewater injection. But earthquake scientists like me want to anticipate how far from injection sites these quakes may occur.

In collaboration with a researcher in my group, Thomas Goebel, I examined injection wells around the world to determine how the number of earthquakes changed with the distance from injection. We found that in some cases wells could trigger earthquakes up to 10 kilometers (6 miles) away. We also found that, contradictory to conventional wisdom, injecting fluids into sedimentary rock rather than the harder underlying rock often generates larger and more distant earthquakes.

Transmitting Pressure Through Rock

Assessing how far from a well earthquakes might occur has practical consequences for regulation and management. At first glance, one might expect that the most likely place for wastewater disposal to trigger an earthquake is at the site of the injection well, but this is not necessarily true.

Since the 1970s, scientists and engineers have understood that injecting water directly into faults can jack the faults open, making it easier for them to slide in an earthquake. More recently it has become clear that water injection can also cause earthquakes in other ways.

For example, water injected underground can create pressure that deforms the surrounding rock and pushes faults toward slipping in earthquakes. This effect is called poroelasticity. Because water does not need to be injected directly into the fault to generate earthquakes via poroelasticity, it can trigger them far away from the injection well.

Deep disposal wells are typically less than a foot in diameter, so the chance of any individual well intersecting a fault that is ready to have an earthquake is quite small. But at greater distances from the well, the number of faults that are affected rises, increasing the chance of encountering a fault that can be triggered.

Of course, the pressure that a well exerts also decreases with distance. There is a trade-off between decreasing effects from the well and increasing chances of triggering a fault. As a result, it is not obvious how far earthquakes may occur from injection wells.

Where to Inject?

To assess this question, we examined sites around around the world that were well-isolated from other injection sites, so that earthquakes could clearly be associated with a specific well and project. We focused on around 20 sites that had publicly accessible, high-quality data, including accurate earthquake locations.

We found that these sites fell into two categories, depending on the injection strategy used. For context, oil and gas deposits form in basins. As layers of sediments gradually accumulate, any organic materials trapped in these layers are compressed, heated and eventually converted into fossil fuels. Energy companies may inject wastewater either into the sedimentary rocks that fill oil and gas basins, or into older, harder underlying basement rock.

At sites we examined, injecting water into sedimentary rocks generated a gradually decaying cloud of seismicity out to great distances. In contrast, injecting water into basement rock generated a compact swarm of earthquakes within a kilometer of the disposal site. The larger earthquakes produced in these cases were smaller than those produced in sedimentary rock.

This was a huge surprise. The conventional wisdom is that injecting fluids into basement rock is more dangerous than injecting into sedimentary rock because the largest faults, which potentially can make the most damaging earthquakes, are in the basement. Mitigation strategies around the world are premised on this idea, but our data showed the opposite.

How wastewater injection can make earthquakes: In basement rocks (left), injection activates faults in the small region directly connected to the added water, shown in blue. In sedimentary injection, an additional halo of squeezed rock, surrounds the pressurized fluid and can activate more distant faults.

Why would injecting fluids into sedimentary rock cause larger quakes? We believe a key factor is that at sedimentary injection sites, rocks are softer and easier to pressurize through water injection. Because this effect can extend a great distance from the wells, the chances of hitting a large fault are greater. Poroelasticity appears to be generating earthquakes in the basement even when water is injected into overlying sedimentary rocks.

In fact, most of the earthquakes that we studied occurred in the basement, even at sedimentary injection sites. Both sedimentary and basement injection activate the deep, more dangerous faults – and sedimentary sequences activate more of them.

Although it is theoretically possible that water could be transported to the basement through fractures, this would have to happen very fast to explain the rapid observed rise in earthquake rates at the observed distances from injection wells. Poroelasticity appears to be a more likely process.

Avoiding Human-Induced Quakes

Our findings suggest that injection into sedimentary rocks is more dangerous than injecting water into basement rock, but this conclusion needs to be taken with a rather large grain of salt. If a well is placed at random on Earth’s surface, the fact that sedimentary injection can affect large areas will increase the likelihood of a big earthquake.

However, wells are seldom placed at random. In order to efficiently dispose of wastewater, wells must be in permeable rock where the water can flow away from the well. Basement rocks are generally low permeability and therefore are not very efficient areas in which to dispose of wastewater.

One of the few ways that basement rocks can have high permeability is when there are faults that fracture the rock. But, of course, if these high permeability faults are used for injection, the chances of having an earthquake skyrocket. Ideally, injection into basement rock should be planned to avoid known larger faults.

If a well does inject directly into a basement fault, an anomalously large earthquake can occur. The magnitude 5.4 Pohang earthquake in South Korea in 2017 occurred near a geothermal energy site where hydraulic injection had recently been carried out.

The important insight of this study is that injection into sedimentary rocks activates more of these basement rocks than even direct injection. Sedimentary rock injection is not a safer alternative to basement injection.

Oklahoma energy companies want earthquake lawsuit dismissed

From an Article of the Associated Press, June 3, 2016

Oklahoma City (AP) — Three Oklahoma energy companies want a federal judge to dismiss a lawsuit demanding they reduce injection volumes at wastewater disposal wells that could be triggering earthquakes.

The lawsuit was filed in February by members of the Oklahoma Sierra Club. It asks that Devon Energy Corp., Chesapeake Energy Corp. and New Dominion LLC reduce production waste at wells.

But the companies say in legal filings that the Oklahoma Corporation Commission is already taking action to reduce volumes of wastewater in disposal wells, The Oklahoman reported Friday (http://bit.ly/22COFoL ).

The commission has issued a series of voluntary directives covering more than 600 disposal wells. In addition, the Coordinating Council on Seismic Activity brings together regulators, researchers and energy industry representatives to respond to seismicity.

“Through the efforts of the governor, the state Legislature, the OCC and other state agencies, Oklahoma is in the midst of implementing a coherent, well-coordinated and comprehensive public policy to address seismicity,” Chesapeake Energy said in a court filing.

While the three companies were responsible for about two-thirds of the wastewater injected in 2014, they said any injunction against them wouldn’t cover other operators who might also be contributing to induced seismicity.

The companies also said anybody with concerns should go through the OCC to modify injection well permits.

In response, the Sierra Club said it had no issues with the state’s response, but believes more could be done. It said commission action hasn’t stopped the earthquakes, with more than 300 recorded since the beginning of the year with magnitude greater than 3.0.

The group said it hasn’t had any opportunity to oppose permits because all the volume reductions so far have been voluntary.

“The OCC has not yet issued a mandatory order to reduce injection,” the Sierra Club said. “In addition, the voluntary directives issued to date have not stopped the earthquakes, or even reduced their frequency or intensity.”

In its answer to the lawsuit, Devon disclosed it is selling some disposal wells as part of a previously announced $200 million deal to sell noncore assets in Oklahoma’s Mississippian formation. White Star Petroleum LLC, formerly American Energy-Woodford LLC, is the buyer.

——  See also: www.FrackCheckWV.net

Other Large Diesel Trucks on Country Roads

Truck overturns, spills drilling wastewater that taints reservoir

From an Article by Laura Arenschield, Columbus Dispatch, March 9, 2016

A truck hauling drilling wastewater overturned in eastern Ohio early this morning, sending thousands of gallons of toxic water into a nearby creek and contaminating a reservoir in Barnesville in Belmont County.

The truck crashed along a curve just after 3 a.m. today, said Barnesville Fire Chief Bob Smith. The driver, Hiley Wogan of Chesterhill, Ohio, was flown by helicopter to a hospital in Columbus, Smith said.

About 5,000 gallons of drilling wastewater spilled into a field, then a creek and finally into one of Barnesville’s three reservoirs.

Smith said the reservoir is closed while the Ohio Environmental Protection Agency tests the water. James Lee, an EPA spokesman, said the agency is investigating the spill.

Smith said the truck is owned by ECM, a brine hauling company with a location in Cambridge, Ohio, not far from Barnesville.

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Injections of wastewater rise in Ohio despite lull in fracking

From an Article by Laura Arenschield, The Columbus Dispatch, March 7, 2016

The amount of fracking wastewater pumped underground in Ohio increased by more than 15 percent last year, even as shale drilling has slowed nationwide, according to new numbers from the Ohio Department of Natural Resources.

Ohio took in nearly 29 million barrels of fracking wastewater in 2015, according to a Dispatch analysis of department data. That is about 4 million more barrels than in 2014.

Fracking involves pumping a mixture of water, sand and chemicals at high pressure into deep wells to fracture shale formations and free oil and natural gas trapped underground.

The water can be recycled for reuse but eventually must be dumped somewhere. Ohio, which is situated to accept wastewater from states that don’t allow injection waste wells, has more than 200 injection wells. Fewer than 10 have been approved in Pennsylvania, where much of the fracking boom in this part of the country has taken place. West Virginia has about 60.

That means about 13 million barrels a year comes from Pennsylvania and West Virginia, according to the Natural Resources data.

Ohio typically takes more fracking wastewater from outside Ohio than inside. But last year, about 55 percent of the fracking wastewater that ended up in Ohio injection wells came from Ohio, the Dispatch analysis shows.

Wastewater generally travels in tanker trucks on Ohio’s highways until it reaches injection well sites, which are primarily in eastern and southeastern Ohio.

Athens County, for example, took more than 4 million barrels of fracking wastewater in 2015, an increase of 1.1 million barrels, or nearly 40 percent. Most of that wastewater was injected into wells in the eastern part of the county, near the village of Coolville and the unincorporated area of Torch.

Residents there, worried about drinking-water contamination and earthquakes associated with injection wells, have fought unsuccessfully to keep wastewater out.

“Something’s got to give,” said Teresa Mills, program director for the Buckeye Forest Council, an environmental-advocacy group. “Athens County, Coshocton, Guernsey (counties) — these are environmental-justice communities, and we have to stop burdening them.”

Exact numbers about drilling patterns and oil and gas production in Ohio in 2015 are not yet available. Companies were required to report that information to Natural Resources by Feb. 14, said Matt Eiselstein, an agency spokesman. The department will not make the numbers public until it reviews them, he said.

Industry trends nationwide show that drilling slowed in 2015, hampered by low gas and oil prices. A weekly drilling report by the U.S. Energy Information Administration released Feb. 25 showed that the nation’s number of natural-gas rigs was its fewest since 1987.

Jackie Stewart, a spokeswoman for Energy In Depth, an advocacy group for the oil and gas industry, said that even though drilling is down, production per well could be increasing. Drillers also are probably drilling longer horizontal cuts to access oil and gas, she said. That would require more water, which would in turn produce more wastewater.

See also: www.FrackCheckWV.net

WV Marcellus drilling & fracking operation

Bill Would Make It Easier to Build Drilling Waste Landfills, Hurt Local Solid Waste Authorities

Legislative Alert from Julie Archer, WV-SORO, March 6, 2016

A bill that would make it easier to site and build landfills for drilling waste will be voted on by the House of Delegates later this week. SB 601 has been changed dramatically more than once since it was introduced. It started as a bill that would have made it easier to issue permits for solid waste facilities that accept only drilling waste. This would have been done by taking away the local control county and regional solid waste authorities currently have to approve siting of such facilities and eliminating the requirement that these facilities obtain a certificate of need from the WV Public Service Commission (PSC). The WV Department of Environmental Protection (DEP) would have been the sole regulatory agency for such facilities, but their role would have been limited.

Last Sunday, SB 601 was hastily rewritten in the Senate Judiciary Committee and turned into a purported recycling bill. The amended version of the bill contained no reference to or mention of oil and gas solid waste. Instead the bill removed two types of “recycling” facilities, “materials recovery facilities” and “mixed waste processing facilities,” from the PSC’s jurisdiction. Under the amended version of the bill, these “recycling” facilities would still have to get siting approval from local or regional solid waste authorities, but would not be required to get a certificate of need.

Unfortunately, despite SB 601′s transformation into a “recycling” bill, there were concerns that solid waste authorities had that we did not know about until the bill had already passed the Senate. To make matters worse, after the bill was reported to the House it appeared almost immediately on the House Judiciary Committee agenda, where the oil and gas solid waste provisions were amended back in.

It is not as bad as the original introduced version. Oil and gas waste, materials waste recovery facilities and mixed waste processing facilities would still have to get siting plan approval from the local solid waste authority, but would not be required to get a certificate of need from the PSC and would be completely removed from PSC jurisdiction.

So what’s wrong with SB 601?

1) It removes an important step in the permitting process for oil and gas solid waste facilities. More specifically it would be easier to site and build such facilities because they would no longer be required to get a certificate of need from the WV Public Service Commission and would be completely removed from the PSC’s jurisdiction. The WV Department of Environmental Protection would still be involved in the environmental aspects of the permitting process, but the DEP has no authority to limit the number of facilities that could be built or where they could be sited relative to other facilities accepting the same type of waste.

2) Local and regional solid waste authorities have concerns that SB 601 will put them at a competitive disadvantage with the “materials recovery facilities” and “mixed waste processing facilities” that are being deregulated by the bill, jeopardizing the public funding solid waste authorities have invested in their facilities.

There will most likely be an amendment on the floor to take out the oil and gas provisions, but we have to make phones ring and get emails in to delegates opposing this. So please call or email your delegates and tell them that SB 601 is bad because the Public Service Commission’s oversight is important, and prevents unneeded waste dumps from being built. However, the oil and gas provisions are not the only concern. SB 601 also puts our local and regional solid waste authorities at a competitive disadvantage with the so-called “recycling” facilities that are being deregulated, jeopardizing the public investment in these facilities.

Your senators need to hear a similar message. They may not be aware that the bill has changed, and some were likely unaware of the problems with the version they passed.
–
Julie Archer, Project Manager, WV Surface Owners’ Rights Organization
1500 Dixie Street,Charleston, WV 25311
(304) 346-5891, www.wvsoro.org

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Wetzel County Landfill Operator Sues Waste Authority Head

From an Article by Glynis Board, WV Public Broadcasting, March 4, 2016

The operating company of a landfill in Wetzel County is suing a member of the county’s solid waste authority for slowing its ability to accept horizontal drilling waste.

Bill Hughes, chairman of the Wetzel County Solid Waste Authority, is being sued by the company that operates the Wetzel County landfill because of a petition filed with the Public Service Commission. The petition is interrupting the landfill’s application to dedicate portions of the landfill to Marcellus Shale drilling waste.

The complaint says Hughes acted on behalf of the authority without the express permission of the authority. It accuses Hughes of acting on his own to advance his own political agenda, as Hughes is an outspoken opponent of gas drilling practices. Hughes’ attourney said in a public meeting last night that they intend to file a motion to dismiss the case.

Lackawanna Transport Company is the legal owner of the Wetzel County Landfill, which is near New Martinsville. The company offers no comment on the pending federal suit. The complaint was filed in the U.S. District Court for the Northern District of West Virginia on February 22nd.

>>> See also: www.FrackCheckWV.net

What We Are Learning From Shale Drilling – Earth Sciences

Analysis by S. Tom Bond, Retired Chemistry Professor and Resident Farmer, Lewis County, WV
 
Geologists and petroleum engineers are learning that the earth is really much more complicated than the simple conceptual diagrams that are in their textbooks and that they put out to the companies that want to drill.  Those diagrams are a bit like a layer cake.  They appear to have uniform thickness and consist of uniform, homogenous, single component layers. 

However, buried landscapes, compression and extension, lateral thrusts, percolating waters of various compositions, often highly corrosive or oxidizing, radioactivity, an immense amount of detail which changes unpredictably in a few yards vertically or a few tens of yards horizontally are left out.
 
They have to be, because every location is different.  Fracking gives an opportunity to find details which don’t appear in published diagrams.  Things like abandoned wells, cracks large enough for migration at depth, variations in the thickness and quality of the target rock.  Terry Engelder is quoted here as saying certain joints in the source rocks may “break out of the gas shales and populate the rock above these gas shales. [This] joint set may appear about 1000 feet above or even as much as 4000 feet above the gas shales.”  The industry vigorously denies this.  The economic value of shale varies tremendously within a few miles.  Nobody (almost) says anything about this.
 
Chesapeake Energy began selling investments with the assumption all drilling locations were more or less identical, and the wells would provide economic amounts of gas for 30 or 40 years, like conventional wells.  This has not proven true.
 
Something petroleum geologists and petroleum engineers are learning that they did not suspect is the rapid decline in production and the spottiness of production within a field.   Look up graphs of decline rates for various shale fields here.

Much more information for a sample of the Marcellus is printed here, but the graphs are harder to read.  Each diamond shape indicates a well’s production decline as of June 30, 2013.  The months it has been in production is along the horizontal axis and the percent decline is a long the vertical axis.  For example, the extreme right upper diamond represents a well in production for 48 months (just a little left of the 50 months line) and it has lost 79% of its production in that time.  Another, the diamond shape lowest in the left has lost 58% of its production in 12 months time. The beauty of this reference is that the information reported to Pennsylvania DEP (which by law is open to the public) is printed along with the graphs.  No argument can be made with this!

If you read much about shale drilling, you are already aware of the rapid decline in production of shale wells, compared to drilling in conventional reservoirs.  James Stafford quotes Arthur Berman: “… nobody thinks very much about is the decline rates shale reservoirs. Well, I’ve looked at this. The decline rates are incredibly high. In the Eagleford shale, which is supposed to be the mother of all shale oil plays, the annual decline rate is higher than 42%. They’re going to have to drill hundreds, almost [thousands of] wells in the Eagleford shale, every year, to keep production flat. Just for one play, we’re talking about $10 or $12 billion a year just to replace supply.”  What this means is illustrated in an article about the Barnette in The Oil Drum.  Instead of drilling wells and being able to sit back and relax and count on initial production to hold up for years at nearly the initial level, tens of billions of additional investment will be required to maintain initial levels. 

Another big thing discovered is what happens when pressures of thousands of pounds per square inch are applied to liquids pumped down disposal wells in volumes equal to several houses day after day, with only cracks and pores the size of a grain of sand in them to receive it.  Rumble, rumble!  It takes about 4.0 on the Richter Scale to cause damage, but one in South Texas got up to 4.8.  The Richter is a logarithmic scale so 4.8 is 6.3 times the magnitude of 4.0.  Definitely connected with the well, as many small quakes have between verified to be connected to disposal wells. 

Cliff Frohlich, speaking at WVU, recently identified one of 5.7.  He thinks injection wells shouldn’t be sited in cities, but out in the country is OK.  (The “country hicks” don’t care if they are injured or their property is destroyed?  The insurance companies will compensate them for their losses?)  Earthquakes don’t happen at all disposal wells, but when one considers the facts above, then one has to wonder just where these toxic waste liquids do go and how long they will stay put.
 
Frohlich has the life expectancy of the Marcellus field down to less than 30 years (to 2040).  That’s assuming future wells do as well as the present wells, no doubt, in spite of the fact drillers avidly seek out the “sweet spots” and highest returns first.  And, assuming the investors are willing to cough up money to drill and drill and drill. 

Then there will be all those wells to plug.  Any body willing to say this generation of drillers will be more responsible about plugging their wells than those in the past?  What do you suppose it takes to plug a well that takes 3 to 8 million to drill?  Don’t you think that expense will be left for the public, just as wells and mines worked in the past must be remediated by government money, our taxes, or not at all?
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