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From the Open-Publishing Newswire
Out Of The Monterey Shale Downgrade Rises Wind On The Wings Of A Rising Solar Phoenix
Whatever PR and debate surrounds production of oil from the Monterey Shale Formation, in no way affects non-associated - Northern California Tight Gas production, North Coast Tight Sands (tight gas) exploration and production targets i.e., the Eel River Basin in Humboldt County, or the lust for new offshore leases on the North Coast of oil, natural gas and methane hydrates. One day before the EIA reduced the estimates of the Monterey Shale deposits, the Mendocino County Board of Supervisors by majority vote directed County Counsel Douglas Losack to prepare a County Ordinance To Ban Fracking In Mendocino County. Read the ordinance as of August 12, 2014, which may have to wait for a new Board in January. But, The Frac King Is Dying, Long Live The Peas and Trees (Peasantry)
Out Of The Monterey Shale Downgrade;
Rises Wind On The Wings Of A Rising Solar Phoenix
“Because the Bakken and Eagle Ford shale plays currently generate nearly 70 percent of U.S. unconventional oil and gas, experts say the downgrade to Monterey does little to alter the near-term trajectory of the energy renaissance. However, they added it does bring into focus two major red flags: A well depletion factor that ramps up the urgency of finding new shale plays, and the need to upgrade new technology for that same purpose.”
“Yet the practical impact of the EIA’s downgrade puts a spotlight on an element of the shale boom that often goes unremarked by fracking advocates. Shale wells are prone to rapid depletion rates, as spots in North Dakota’s Bakken can lose 85 percent of their capacity within a few years.”
“The Monterey was a huge field wiped out with a stroke of a pen: That’s like two Bakkens off the table in one fell swoop. If the U.S. boom is to be sustained beyond 2020, new shale plays will need to be discovered within the next few years.” J. David Hughes, Post Carbon Institute
It's only been 3 months and - 08172014
China Slashes Shale Gas Production Estimates by 60%
“Early this month, Wu Xinxiong, head of China’s National Energy Administration, cut the country’s 2020 production target for shale gas to 30 billion cubic meters. The goal, immediately before the reduction, had been 60-80 bcm.”
“The National Energy Administration cited geology and high costs for cutting its 2020 target, but that is unconvincing. It’s true that China’s reserves are in hard-to-reach locations, there is a lack of water in many of those places, the reserves are generally buried deep in the earth, and the shale has too much clay, but all of these factors were known when Beijing announced its initial 2020 goal of 60-100 bcm in the country’s 12th Five-Year Plan.”
“As for costs, that’s the name of the game when it comes to shale. The technology of hydraulic fracturing; fracking and horizontal drilling have been known for decades. What produced the shale boom in the United States, now the world’s No. 1 gas producer and No. 1 pumper of hydrocarbons overall, is that Americans figured out how to make the extraction of gas economically feasible.”
But don’t thank major oil companies for the cost reductions.... Shale No! Thank Wall Street!
Wall Street Investors and Goldman Sachs, Merrill Lynch.... and others who first funded and then recently sold the US fracking boom-debt of the Mid-west and eastern US to China and Malaysia for cash. US shale assets are now half owned by dictatorial regimes.
The original estimates of the 'Monterey Shale' (Southern California from San Joaquin to San Diego) have now been reduced by 96% (May 21, 2014 – EIA). One day before the EIA reduced the estimates of the Monterey Shale deposits, the Mendocino County Board of Supervisors by majority vote directed County Counsel Douglas Losack to prepare a County Ordinance To Ban Fracking In Mendocino County. Read the ordinance as of August 12, 2014:
Press releases from late May and June, 2014 follow- none mention any impact to estimates of natural gas production in Northern California.
Post Carbon Institute
Shale Energy Insider - U.S. Energy Information Administration Independent Statistics & Analysis
From the EIA Assessment update - EIA Administrator Adam Sieminski's Presentation
In 2011, the EIA published a report by INTEK Inc. that estimated there were 15.4 billion barrels of technically recoverable shale oil, or “tight oil” in the Monterey Formation.
Sometime in 2012, the EIA reduced this estimate to 13.7 billion barrels. Now, the agency plans to release a report in the coming months that will explain why it has decided to severely reduce the estimate to 600 million barrels.
BUT, whatever PR and debate surrounds the reduced estimates for production of oil from the Monterey Shale Formation, in no way affects non-associated - Northern California Tight Gas production, North Coast Tight Sands (tight gas) exploration and production targets i.e., the Eel River Basin in Humboldt County, or the lust for new offshore leases on the North Coast of oil, natural gas and methane hydrates. Ditto, for offshore fields north of Point Arena beyond the boundaries of the Marine Sanctuary Expansion Act.
The International Energy Agency (IEA) World Energy Investment Outlook
The last decade's rising oil prices have been driven primarily by rising production costs. After the release of the IEA's World Energy Outlook last November, Deutsche Bank's former head of energy research Mark Lewis (who now heads up energy transition and climate change research at a leading investment firm) noted that massive levels of investment have corresponded to an ever declining rate of oil supply increase:
"Over the past decade, the oil and gas industry's upstream investments have registered an astronomical increase, but these ever higher levels of capital expenditure have yielded ever smaller increases in the global oil supply. "More than 80% of this spending, is required just to keep production at today's levels, that is, to compensate for the effects of decline at existing fields. The figure is higher in the case of oil (at close to 90% of total capital expenditure)."
The Risk Of Insufficient Investment Is Not A Hypothetical Matter (Dr. Nafeez Ahmed)
Since 2000, the oil industry's investments have risen by 180% - a threefold increase - but this has translated into a global oil supply increase of just 14%. Two-thirds of this increase has been made-up by unconventional oil and gas. In other words, the primary driver of the cost explosion is the shift to more expensive hydrocarbons (extreme extraction methods of unconventionals) since the peak and plateau in conventional oil production since 2005.
“We just don't get the same quality of energy from shale oil and gas as cheap crude - and what we do get comes at a higher cost.”
Other factors likely to push oil prices higher over coming decades include:
1) the increasing reliance on shale gas "to fill the supply gap… in the face of stalling crude-oil production since 2005," which has "significantly lower energy density than crude oil";
2) "declining exports of crude oil globally since 2005 as OPEC consumes more and more of its own production"; and
3) "the ever-present but recently heightened geopolitical risks in key oil-producing regions."
"Renewables, especially rooftop solar, will take a leading role in a distributed power revolution now underway. The biggest solutions to the coming deliverability crisis will be residential solar, energy storage and improved grid management, (which) the incumbent utilities will fight very aggressively. In this context, throwing more money at the dying industry of yesteryear is clearly not the answer - no matter how much they disingenuously clamour for it. Cold, hard economic reality is staring us in the face: we need to ramp-up investments in the clean, decentralized technologies of tomorrow.”
The Inevitable Demise Of The Fossil Fuel Empire (full article)
“The Inevitable Demise Of The Fossil Fuel Empire” article originally written by:
Dr. Nafeez Ahmed - an international security journalist, academic and author.
“A User's Guide to the Crisis of Civilization: And How to Save It” (book, Dr. Nafeez Ahmed)
The Frac King Is Dying, Long Live The Peas and Trees (Peasantry)
The frac focus in California has been mostly on the Monterey Formation in Southern California. An oil producing region of mature oil fields, and 'enhanced oil recovery' methods alongside newer extreme extraction methods. Authors such as Robert Collier helped to expand the conversation to include acidization (the preferred well stimulation treatment in California).
A new report “Fracking Beyond The Law,” published August 13, 2014 by (EIP) The Environmental Integrity Project (a nonpartisan, nonprofit organization established in March of 2002 by former EPA enforcement attorneys to advocate for effective enforcement of environmental laws) details continued use downhole of diesel, by industry on a large scale.
Diesel fracking the vertical wells of the Sacramento Region, the Delta, and Northern California was the preferred method for decades in the production of conventional natural gas and was only recently halted by the EPA, though not completely, there are always loopholes.
Diesel Downhole And The Safe Drinking Water Act
Loopholes are permitted approved uses. In the case of diesel and the SDWA, the EPA requires a permitting process. “But The Environmental Integrity Project identified these 351 wells and found no evidence that any of the wells’ operators applied for or received a Safe Drinking Water Act permit. A June 2014 report by the U.S. Government Accountability Office addressed the continued use of diesel in the fracking process, and specifically noted that none of the state programs reviewed for the report had issued Safe Drinking Water Act permits.”
Frac-focus The Website; Fails As A Public Disclosure chemical Registry Database
Through its investigation, “EIP learned that some well operators have replaced and continue to replace their original FracFocus disclosures (that reported the injection of diesel fuel) with new disclosures that no longer indicate injection of diesel fuel. This is curious given that many of the disclosures EIP first identified were changed after EPA issued its draft guidance on the use of diesel in hydraulic fracturing in May 2012 and then others were replaced after the guidance became final in February 2014.”
“Lawmakers had allowed the agency to retain its authority in the Safe Drinking Water Act to regulate underground injection of diesel fuels. This is because diesel contains chemicals such as benzene, toluene, ethylbenzene, and xylene (known as BTEX) that are highly mobile in groundwater and pose significant threat to human health. EPA regulates the injection of diesel fuels by prohibiting the practice except where the permitting authority (either EPA or states that have been granted primacy to enforce the program) has issued a Safe Drinking Water Act permit. Well operators who inject diesel fuels must first obtain a permit designed to ensure that no fluid escapes the well and threatens an underground source of drinking water.”
Despite industry assurances that diesel use had been discontinued, dating back as far as 2003, the 2011 Congressional investigation by Henry Waxman concluded otherwise. In fact, 12 of the 14 companies that agreed to voluntarily disclose the ingredients of their fracking fluids to Congressional investigators including proprietary and trade secret products admitted using millions of gallons of diesel fuels between 2005 and 2009. The letter to Lisa Jackson noted that the failure of these companies to obtain permits for diesel fuel use in hydraulic fracturing appeared to be a violation of the Safe Drinking Water Act.
A little over a year later (May 2012), EPA sought comments on draft guidance clarifying the definition of “diesel fuels” for Safe Drinking Water Act permitting purposes.
EPA issued its final guidance on February 12, 2014, citing the health risk and high mobility of certain aromatic hydrocarbon compounds, including BTEX, present in diesel fuel. 10 Instead of adopting the definition of diesel fuels proposed in 2012, or any of the other broader, more inclusive definitions considered in the draft guidance, the agency directed federal and state permit writers to consider a smaller group of products
“A report issued by the United States Government Accountability Office (GAO) in June 2014 stated that seven of the eight state programs it reviewed were under the impression that diesel was no longer being used in their states. In 2014, more than three years after being confronted with a Congressional investigation that yielded irrefutable evidence to the contrary, EPA issued a final guidance issued that significantly narrowed the range of chemisrty of diesel fuels now subject to Safe Drinking Water Act permitting requirements. Following the release of the 2014 guidance, the drilling industry continues to suggest that use of diesel fuel in fracking is a non-issue because it has been discontinued.”
“The EIP purchased data from PIVOT Upstream Group, a Houston-based consulting firm that has taken the well-known FracFocus data and aggregated it into a searchable database that can be readily analyzed. Although PIVOT aggregates the data and packages it for sale, the firm retains copies of all of the disclosures it obtained through FracFocus and records the date on which each disclosure was collected.”
There was an obvious indication that diesel use had been removed from all 143 of these well disclosures. “But at some point between June and October 2012 (when PIVOT conducted its data collections), the six operators of these 143 wells reported the combined injection of 168,971 gallons of diesel fuel as defined by EPA in its February 2014 guidance.”
“Yet searching FracFocus today, there is no way to discover that these companies ever had reported any diesel use. Curiously, all of these disclosures were changed after EPA issued the May 2012 draft guidance. Through the process of verification of PIVOT’s data, as well as subsequent FracFocus searches and responses obtained from EPA public records requests, EIP determined there were at least 351 wells fracked with diesel, by 33 different operators across 12 states, between 2010 and mid-July 2014. Most of these wells were fracked with either kerosene (CAS no. 8008-20-6) or diesel (CAS no. 68476-34-6). EIP verified, at least once between June 18 and August 5, 2014, that the FracFocus disclosures for all 351 wells indicated the use of diesel. “
Of the 351 wells identified in this report, up to 25,896 gallons of diesel fuel identified as CAS No. 68476-34-6 was used to frack 61 wells. This CAS number is commonly known as Diesel Fuel #2. The report, “Fracking Beyond The Law,” it was found that since 2010 fossil fuel companies have used more than 30,000 gallons of diesel fuel across the country to frack for oil and gas without obtaining the required federal permits and that at least 33 companies fracked at least 351 wells across 12 states with fluids containing diesel.
Diesel fuels, which contain high levels of benzene, ethylbenzene, toluene, or xylene, known carcinogens and neurotoxins, remain under the jurisdiction of the EPA as part of the Safe Drinking Water Act. The industry has repeatedly asserted that the use of diesel fuel in fracking no longer occurs and those denials continued along with the release of this report.
“The EIP investigation asserts that the 351 wells they found using diesel is likely an underestimate as some oil and gas companies have been changing their FracFocus disclosures to remove indication of past diesel injections. FracFocus is a voluntary submission site that companies have agreed to use and which allows operators to update or replace previous disclosures without justification. EIP planned to release its report June 19 identifying 497 wells that used diesel, but when they double-checked their results they discovered 146 of the FracFocus entries had been altered to eliminate all references to diesel.”
Since updating its policy for clarification in February 2014, the EPA has clearly stated the kerosene counts as diesel when it comes to requiring a permit under the Safe Drinking Water Act (SDWA).
The New York Times is always good for historical context.
Learn More About Diesel Fracking The Sacramento
Diesel Fracking In California Used 26,381 gallons between 2005-2009. View the updated Letter from Reps. Henry A. Waxman, Edward J. Markey, and Diana DeGette who sent a letter to the Environmental Protection Agency Administrator Lisa Jackson regarding the results of an investigation into the use of diesel fuel in hydraulic fracturing fluids.
October 25, 2011 update analysis: Hydraulic Fracturing Statistics to EPA
Northern California is all gas (minor oil), dry gas, tight gas, tight sands. The unassociated gas fields of Northern California were left out of the original (DOGGR) Division's conversation with the Legislature and the public. Only by the insistence of the public, with presentations that verified a lot of the same concerns as surrounds the oil fields, were Californian's concerns for natural gas extraction in the north State revealed.
Sacramento is surrounded by natural gas fields, to think that there are no politics involved in naeive. Perhaps the augmented economic hype focused on the Monterey Shale to distract the public's eye from the oil and gas industry's new investments north of the Monterey.
According to the industry's shift in oil and gas rig counts (curtailment and shift in investments), if oil is such a loser, will there be renewed interest in the Gas Fields of California's North State, DOGGR District 6 contains both USGS Region 9 (inland north state), Region 7 (northcoast).
What kind of “Risk Assessment” criteria was considered in the EIR for the California Well Stimulation Regulations? The California Division of Oil Gas and Geothermal Resources and The Department Of Conservation used a “Risk Assessment Analysis” to determine reporting requirements covering inter-wellbore communication – where fracking one well impacts another nearby well or distant well.
Sustained Casing Pressure Risk Analysis
The graphic is from the 2010 Society Of Petroleum Engineers, Sustained Casing Pressure Risk Assessment Analysis. Allowed (permitted) flows of toxic pollutants globally from (new) subsea oil and gas production (on the rise) include releases of drilling muds into ocean waters, flowback and wastewater releases, sustained casing pressures and well integrity failures (tolerable by degree under certain risk assessment conditions).
What of the biocides that return to the surface, in this instance, through the water column of the marine environment? There is the problem of external pipeline corrosion and internal pipeline corrosion in any marine environment.
On the Criticality Of Wells: Sustained Casing Pressure Guidelines
Well Integrity Workshop Presentation 26th May 2011 Jan Sæby, Norske Shell
“If Failed Barrier, Only Activity In Well Should Be To Restore Well Integrity”
Sustained Casing Pressure – US Regulations
• The US Minerals Management Service (MMS) regulations (30 CFR Part 250) require elimination of SCP.
• MMS also grants waivers ("departures") permitting operation of wells with small SCP problems.
Norway - SCP - Subsea wells,
• Shall be possible to secure well in the event of failure
• If failed barrier, only activity in well should be to restore Well Integrity
The Sacramento Delta has to consider the potential for diesel fuel BTEX migration and contamination of sub-basin aquifers. The diesel frac was/is preferred for sandstones and clays. A fracking well in Glenn County is only six-tenths of a mile from the Sacramento River, and one in Colusa County is only a scant quarter-mile from the river.
Ordinance To Ban Fracking In Mendocino County. Read the ordinance as of August 12, 2014:
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STEAM INJECTION IS LITERALLY GLOBAL WARMING
constant comments, and informative research links;
Specific correction - Ordinance To Ban Fracking In Mendocino County. The ordinance as of August 12, 2014 put forth with meticulous care by Mendocino County Counsel at the Direction of the Board of Supervisors of Mendocino County on May 20, 2014: