Source: https://eem.jacksonkelly.com/2009/07/index.html
Timestamp: 2019-04-26 12:20:50+00:00

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A Department of Energy sponsored project in Hopkins County, Kentucky has begun injecting carbon dioxide into a mature oil field to assess the region's CO2 storage capacity and feasibility for enhanced oil recovery.
The project is part of DOE's Regional Carbon Sequestration Partnership (RCSP) program and is being conducted by The Midwest Geological Sequestration Consortium (MGSC). The project is part of the RCSP's "validation phase," where field tests are being conducted nationwide to assess the most promising sites to deploy carbon capture and storage technologies.
The Kentucky test is designed to inject up to 8,000 tons of CO2 over a period of 6-8 months into an existing brine-water injection well at depths of about 1,900 feet. At this depth, the CO2 will remain in a gaseous state and will only partially mix with the oil it encounters.
This type of enhanced oil recovery, termed an "immiscible" CO2 flood, can recover an additional 5–10 percent of a reservoir's original oil-in-place. Following injection, the oil, gas, and water produced will be measured to evaluate the field’s enhanced oil recovery characteristics.
To monitor the fate of the CO2, the MGSC, with technical support from the Kentucky Geologic Survey, will implement a monitoring program at the site. The program will consist of tracking the rate and volume of injected CO2, and the pressures and temperatures within the well. These measurements will provide an indication of how efficiently the CO2 displaces oil within the reservoir and how efficiently the reservoir stores the CO2.
Ambient air quality around the wells will also be continuously monitored to ensure worker safety, as will groundwater quality to ensure that injected CO2 is not leaking from the oil reservoir.
Projects by Basin Electric Power Cooperative and Hydrogen Energy International LLC have been selected for up to $408 million in funding from the American Recovery and Reinvestment Act. The selection of the two projects is part of the third round of the Clean Coal Power Initiative (CCPI).
Post Combustion CO2 Capture Project - Basin Electric Power Cooperative will partner with Powerspan and Burns & McDonnell to demonstrate the removal of CO2 from the flue gas of a lignite-based boiler by adding CO2 capture and sequestration (CCS) to Basin Electric's existing Antelope Valley Station, located near Beulah, N.D. Powerspan's ECO2® ammonia-based technology will be used to capture CO2 on a 120-megawatt electric-equivalent gas stream from the 450 megawatt Antelope Valley Station Unit 1. The net result will be 90 percent removal of CO2 from the treated flue gas, yielding 3,000 short tons per day (1,000,000 tons per year) of pipeline-quality CO2. The ammonia based SO2 scrubbing system will also produce a liquid stream of ammonium sulfate that will be processed into a fertilizer by-product.
Hydrogen Energy California Project: Commercial Demonstration of Advanced IGCC with Full Carbon Capture - Hydrogen Energy International LLC, a joint venture owned by BP Alternative Energy and Rio Tinto, will design, construct, and operate an integrated gasification combined cycle power plant that will take blends of coal and petroleum coke, combined with non-potable water, and convert them into hydrogen and CO2. The CO2 will be separated from the hydrogen using the methanol-based Rectisol process. The hydrogen gas will be used to fuel a power station, and the CO2 will be transported by pipeline to nearby oil reservoirs where it will be injected for storage and used for enhanced oil recovery. The project, which will be located in Kern County, California, will capture more than 2,000,000 tons per year of CO2.
Australia’s most comprehensive post-combustion CO2 capture research facility has opened at International Power’s Hazelwood Power Station in Victoria’s Latrobe Valley.
The project is using the 30 metre high solvent capture plant installed by International Power as part of the Hazelwood Carbon Capture Project to test and evaluate new and improved solvents, compare equipment performance, investigate impurities removal and optimise solvent capture processes.
The project will use purpose-built research modules to evaluate two new technologies for CO2 capture; membranes and adsorbents.
New types of membranes can be used to sieve out CO2 molecules from gas streams and can be integrated with solvent systems.
Adsorbents are solids that can capture CO2 on their surface, release it by reducing the pressure and be reused over and over.
The project will allow CO2CRC to use the existing research base of its capture activities in Victoria. The University of Melbourne is developing solvent and membrane technologies while Monash University performs research and development on adsorbents.
This article was excerpted from publically available information, and was assembled by Rachel Shanteau, Acacia Environmental Group LLC. For more information on the author see here.
On June 26, 2009, H.R. 2454, the American Clean Energy and Security Act of 2009 (“ACESA”), passed the United States House of Representatives by a vote of 219 to 212, with strong bipartisan opposition that included forty-four Democrats. Kentucky Representatives John Yarmuth (D-3rd District) and Ben Chandler (D-6th District) voted in favor of the bill. Kentucky Representatives Ed Whitfield (R-1st District), Brett Guthrie (R-2nd District), Geoff Davis (R-4th District), and Hal Rodgers (R-5th District) voted against the bill.
H.R. 2454 was introduced by the House Committee on Energy and Commerce Chairman Henry Waxman (D-CA) on May 15, 2009. Just days before the House voted on the bill, the legislation text grew from 946 pages to 1,201 pages. It was accompanied by a 743-page committee report. The final text of the bill was not released until 3:09 a.m. the morning of June 26, 2009.
In an op-ed article posted on his website1, Rep. Yarmuth states that ACESA will reduce our nation’s dependence on foreign oil and create thousands of jobs in Kentucky and millions more across the nation. On the advice of Louisville Gas and Electric, a utility company that serves 318,000 natural gas and 390,000 electric customers in Louisville and the surrounding counties, Rep. Yarmuth opposed an earlier version of the bill that would have unduly impacted Louisville consumers. However, both Rep. Yarmuth and LG&E believe that the final draft of the bill is the best possible bill that could have come out of the House. Rep. Yarmuth notes that the bill has support from a diverse cross-section of interests, including General Electric, the Union of Concerned Scientists, the Evangelical Climate Initiative, the U.S. Conference of Catholic Bishops, Dupont, Shell Oil, the Sierra Club, the League of Conservation Voters, UAW, Duke Energy, ALCOA, and the U.S. Steelworkers of America. Rep. Yarmuth also noted that if Congress had not acted, the Environmental Protection Agency would be required by law to set its own emission standards. Rep. Yarmuth believes that any EPA standards will likely be very strict and not include provisions to protect Kentucky families from sizeable electricity rate increases.
In statement released shortly after the vote, Rep. Chandler also noted that he had concerns about early versions of this bill2. However, he successfully advocated for significant changes in the bill that he believes positively will impact Kentucky. He cites provisions granting $30 million dollars in additional allowances for Kentucky rural electric cooperatives and a $60 billion dollar investment in clean coal. Rep. Chandler believes that this bill will, with time, fundamentally change the way Kentucky produces and uses energy, while creating better opportunities for its people. He believes that the bill will create more jobs, promote cleaner industry, and spur strong economic growth in the Commonwealth.
Rep. Whitfield voted against ACESA citing an enormous negative impact on the use of coal, a vital resource for Kentucky, and drastically higher energy costs for Kentucky consumers.3 Rep. Whitfield noted that, by some estimates, electricity prices could increase by as much as 65% under ACESA. Additionally, he believes that the bill would require Kentucky to transfer over $385 million in wealth to other countries, and the United States as a whole over $15 billion. Rep. Yarmuth believes that this shift of wealth will cost Kentucky and the rest of the nation hundreds of thousands of jobs. Lastly, Rep. Whitfield noted his concern that Kentucky power generators will not get all of the allocations they need to cover their carbon dioxide emissions as mandated under the legislation, while states such as California, Washington, and New Jersey would receive more emissions credits than they need. Consequently, the bill will cost Kentuckians an additional $543.3 million to purchase emission permits from other states in addition to the costs required to bring on new technologies. Whitfield pointed out that this discrepancy will unfairly hurt consumers in Kentucky who will be forced to pay much higher electricity costs while rates in other states decrease by comparison.
Rep. Davis noted his strong opposition to ACESA, calling the bill “nothing more than the economic colonization of the heartland States by States like New York and California to subsidize their social programs.”4 He went on to say that “[t]his legislation is not just about energy; it has become about confiscating wealth.” Rep Davis cites a report by the non-profit Heritage Foundation which concludes that ACESA would cost Kentucky nearly 22,000 jobs in 2012, the year that ACESA would go into effect. The same Heritage Foundation report predicts a $1.8 billion drop in Kentucky’s gross state product in 2012 directly attributable to ACESA. The report further predicts that the drop in Kentucky’s GSP would average $3.5 billion in the years between 2012 and 2035.5 Rep. Davis notes that ACESA is opposed by multiple local and national organizations, including: the House of Representatives of the General Assembly of the Commonwealth of Kentucky; the Senate of the General Assembly of the Commonwealth of Kentucky; the Kentucky Chamber of Commerce; the Kentucky Association of Electric Cooperatives; the Kentucky Association of Manufacturers; the Kentucky Farm Bureau Federation; the National Association of Home Builders; the Center for Fiscal Responsibility; the National Cattleman Beef Association; the American Farm Bureau; Greenpeace; the U.S. Chamber of Commerce; the National Association of Manufacturers; and the National Federation of Independent Businesses.
In a very strongly worded statement following the vote, Rep. Rogers called ACESA “reckless,” “disturbing,” and “unimaginable” and condemned its supporters as “irresponsible.”6 Rep. Rogers noted that an independent analysis predicted that 2.3 to 2.7 million jobs would be lost nationwide over the next 20 years due to ACESA. Rep. Rogers has also expressed his concern over the disproportionate affect of ACESA on Kentucky in particular. He notes that the enormous tax on coal-burning companies will necessarily be passed onto consumers. He states that the bill will cost Kentucky electric consumers an estimated $561 million in 2012. Furthermore, Rep. Rogers states that when the increased costs of gasoline, diesel, food, and goods are taken into consideration, some studies show that ACESA would cost each Kentucky family an additional $4600 a year when fully implemented.
USEPA has authority to “veto” “fill” permits issued by the Corps of Engineers pursuant to Section 404 of the Clean Water Act. Representatives of USEPA met with representatives of the coal industry on July 13, 2009 to discuss USEPA’s new 404 Permit “screening” tool for the coal industry in Central Appalachia. EPA’s MIRA (Multi-Criteria Integrated Resource Assessment) is a tool that it intends to use for winnowing out those proposed Clean Water Act “fill” permits that it will subject to “enhanced” review. USEPA unveiled a PowerPoint that showed a “hierarchical” tool that will look at: the size of the mine; the number of valley fills; the efficiency of the mine design (the amount of coal generated per length of stream filled); and the condition of the watershed in which the mine is proposed. USEPA did not distribute the PowerPoint, but indicated that it might choose to do so later.
The uses that will be made of the tool are not clear. USEPA’s representatives opened the meeting by saying that the criteria it uses will be used ONLY to screen permits that it will subject to enhanced review, and that any permit “vetoes” will be based on the 404(b)(1) Guidelines. Later, though, other representatives said that the criteria it will use in the MIRA are “essentially the same” as those set out in the 404(b)(1) Guidelines. Despite characterizations of the MIRA as “robust,” “transparent” and “iterative,” USEPA claimed that it has not developed any “thresholds” that will cause one application to undergo enhanced review and another to avoid it. This tool is being developed by Regions 3, 4 and 5 jointly.
West Virginia Department of Environmental Protection Cabinet Secretary, Randy Hoffman, has appointed the Carbon Capture and Sequestration Working Group and scheduled its first meeting for August 12, 2009 at DEP’s offices in Charleston.
· Research needed to better understand and quantify the processes of carbon dioxide sequestration and long-term strategy for the regulation of carbon dioxide sequestration in West Virginia.
1. Advised WVDEP that EPA had earlier waived its right to review NPDES permit applications for coal mines that discharge less than 500,000 gpd, but that EPA will no longer waive that right. It has asked WVDEP to supply it with: all coal NPDES permit applications; draft permits and “supporting documentation” for NPDES permits associated with surface coal mining permits.
5. Advised that it is conducting a “permit quality review” of mining permits in all of the Region 3 States with significant mining operations.
West Virginia Department of Environmental Protection is proposing revisions to the oil and gas permit rule, W. V. Code St. R. §35-4-1 et seq., relating to gas operations. These revisions will affect the common industry practice of hydraulic fracturing (high pressure injection of water, sand, and chemicals through deep, horizontally drilled wells to break apart the rock and release the natural gas), but focuses on the management of surface impoundments. The revisions will amend the rules dealing with the storage of necessary process water and fluids. It is designed to protect ground and surface water from the constituents contained in the stored process water. These rule changes may increase the cost associated with hydraulic fracturing.
The definitions have been revised to create a distinction between “wastewater pits” and “freshwater impoundments” as opposed to the current general term “pits.” More importantly, both “wastewater pits” and “freshwater impoundments” will require the use of synthetic liners (the current rule contains no such requirement and, if suitable, soil is an acceptable liner).
Additionally, these revisions shall include the addition of a new rule section regulating the construction of pits and impoundments with capacity of greater than five thousand (5,000) barrels. See proposed W. V. Code St. R. §35-4-21. This new section is designed to regulate large operations and requires: 1) agency notice prior to construction of wastewater pits and freshwater impoundments; 2) professional engineer must design, inspect, and certify the construction of both wastewater pits and freshwater impoundments; and, 3) some specific design criteria.
This is likely only the beginning of new regulations targeting hydraulic fracturing. Due to the Court’s decision in Leaf v. EPA, 118 F.3d 1467, requiring EPA oversight of the Alabama program, under the Underground Injection Control Program (“UIC”), EPA only regulates hydraulic fracturing in the State of Alabama. The 2005 Energy Policy Act excludes hydraulic fracturing from the Safe Drinking Water Act legislation.
Currently, both EPA and Congress are being pressured, by environmental groups, to deal with the environmental effects of hydraulic fracturing and greater federal oversight is expected in the near future.
On June 1, 2009 EPA provided notice that via a letter signed on April 24, 2009, EPA granted a petition for reconsideration dated February 10, 2009, submitted by Earthjustice on behalf of the National Resources Defense Council (NRDC) and the Sierra Club, with respect to the May 16, 2008 final rule implementing the New Source Review (NSR) program for fine particulate matter, that is, particles with an aerodynamic diameter less than or equal to a nominal 2.5 micrometers, generally referred to as “PM2.5”) (73 FR 28321-28350) which was effective July 15, 2008. In addition, EPA has administratively stayed one of the provisions to which the petitioners objected—a “grandfathering” provision for PM2.5 in the PSD program. EPA will publish notification in the Federal Register establishing a comment period and opportunity for a public hearing for the reconsideration proceeding.
Consistent with 40 CFR 52.21(i)(1)(x), wherein EPA grandfathered sources or modifications with pending permit applications based on PM from the PM10 requirements established in 1987, EPA will allow sources or modifications who previously submitted applications in accordance with the PM10 surrogate policy to remain subject to that policy for purposes of permitting if EPA or its delegate reviewing authority subsequently determines the application was complete as submitted. This is contingent upon the completed permit application being consistent with the requirements pursuant to the EPA memorandum entitled “Interim Implementation of New Source Review Requirements for PM2.5” (Oct. 23, 1997) recommending the use of PM10 as a surrogate for PM2.5. States were allowed to revise their PSD programs based on EPA’s 2008 final rule. Any sources with pending New Source Review permits involving PM 10 will be severely adversely affected by this abrupt reversal in EPA’s position.
Over the years, New Jersey has been the subject of many jokes and cheap shots. We know all about that in West Virginia. So it’s not my intent to take any cheap shot at the fine people of New Jersey. It is my intent to question the wisdom of the political leaders of New Jersey regarding their headlong rush towards a so-called “Green Economy” in the midst of the worst economic downturn in that state and the nation since the Great Depression. Proponents of the new Green Economy consider renewable/alternative energy sources to be a cornerstone of that movement.
This article will briefly summarize the current economic situation in New Jersey, and then contrast that with the aggressive expansion of the state’s renewable energy portfolio standard.
The citizens of New Jersey already put up with one of the highest state tax burdens. For example, New Jersey has the highest property taxes in the nation, averaging more than $7,000 per household. Now they are faced with the prospects of potential new tax increases and slashed state and local government services due to the state’s current year and projected future multi-billion dollar budget shortfalls. For the 2010 fiscal year, New Jersey is likely to cut their state budget by about $3.5 billion because of a steep drop in revenues. Even with those cuts, there are already worries that the state will still not have sufficient revenue in the next fiscal year to avoid another massive budget deficit. The state’s unemployment rate in June 2009 was 8.8%.
Yet in the face of a true economic crisis, New Jersey’s elected representatives, along with their appointed agency bureaucrats, are moving forward with blinding speed to substantially increase the requirements for alternative energy generation. The inevitable result of this government intervention in the energy marketplace will be to substantially increase the cost of electricity to the residents and businesses of New Jersey.
The remainder of this article will summarize New Jersey’s rush into the brave new world of alternative power generation by government fiat.
On April 12, 2006, the New Jersey Board of Public Utilities (BPU) approved new regulations that significantly expanded the state’s renewable portfolio standard. New Jersey's renewable portfolio standard (RPS) -- one of the most aggressive in the United States -- requires each supplier/provider serving retail customers in the state to include in the electricity it sells 22.5% qualifying renewables by 2021. The previous New Jersey RPS had called for 4% renewable generation of electricity. The 2006 RPS substantially increases the required percentages of "Class I" and "Class II" renewable energy, as well as the required separate percentage of solar electricity. By reporting year 2021, 2.12% solar electricity is required.
"Class I" renewable energy is defined as electricity derived from solar energy, wind energy, wave or tidal action, geothermal energy, landfill gas, anaerobic digestion, fuel cells using renewable fuels, and -- with written permission of the New Jersey Department of Environmental Protection (DEP) -- certain other forms of sustainable biomass.
"Class II" renewable energy is defined as electricity generated by hydropower facilities no greater than 30 megawatts, and resource-recovery facilities approved by the DEP and located in New Jersey. Electricity generated by a resource-recovery facility outside New Jersey qualifies as "Class II" renewable energy if the facility is located in a state with retail electric competition and the facility is approved by the DEP.
Virginia (SB 297- Alternative & Renewable Energy Portfolio Act), New Jersey does not consider innovate uses of coal (clean coal combustion, coal-to-liquids, and other advanced coal technologies) to fall within the definition of renewable energy.
And it doesn’t end there -- the New Jersey BPU will adopt rules to determine the minimum percentages for reporting year 2022 and beyond. These minimum percentages will be equal to or greater than the minimum percentages required for reporting year 2021.
Included as one of the EMP’s primary goals is the following: “GOAL 3: Strive to surpass the current RPS goals with a goal of achieving 30% of the State’s electricity needs from renewable sources by 2020.
While the EMP’s new RPS goal is just that, a goal, it is fascinating to note that the state has gone in a few short years from a 4% RPS to a 22.5% RPS to a 30% RPS.
In a state where customers have seen double-digit increases in electric bills in recent years, the EMP relies on some new and unproven technologies to reduce the state's reliance on fossil fuels for generating electricity.
Ed Selover, general counsel for Public Service Enterprise Group, which operates the state's largest utility and three nuclear generators in South Jersey, said the company welcomes the opportunity to get more involved in energy efficiency and conservation programs. But he warned of the cost of putting too much emphasis on developing renewable energy. "Energy efficiency, if it's done right and the utilities are involved, can end up reducing usage and reducing bills," Selover said. "When you get into renewables, that tends to increase bills. I don't think there's price relief here."
“It looks like we're heading to a very high-cost energy future," said Jeff Tittel of the Sierra Club of New Jersey.
This article was excerpted from publically available information, and was authored by Rick Wilson, Acacia Environmental Group LLC. The opinions expressed in this article are those solely of the author. For more information on the author see here.
On July 6, 2009, the Administration announced that it intended to nominate Joe Main as the Assistant Secretary of Labor for Mine Safety and Health, and Joe Pizarchik as the Director of the Office of Surface Mining in the U.S. Department of Interior.
According to the Administration’s pres release, Joe Main worked in various capacities for the UMWA for nearly thirty years, and most recently has been a self-employed mine safety consultant. Pizarchik has been Director of the Bureau of Mining and Reclamation in Pennsylvania’s DEP since 2002. He is a lawyer who worked with the Pennsylvania mining program for eleven years prior to becoming Director of the Bureau of Mining and Reclamation in 2002. His nomination was not favored by anti-mining groups, which had hoped for the nomination of either Joe Childers of Kentucky or Pat McGinley, a professor at West Virginia University.
Ownership of coalbed methane (“CBM”) is an important, unresolved issue that continues to plague oil and gas companies, coal companies and landowners alike. The law on this subject is developing in several states, including West Virginia and Kentucky, but is not yet settled. In an opinion that may tangle the issue even more, the Supreme Court of Kansas recently addressed ownership of coalbed methane in an opinion that follows a pattern of awarding ownership of CBM to oil and gas owners in states where that industry historically has had a more substantial economic presence than coal.
In a decision entered on February 6, 2009, the Supreme Court of Kansas decided that the owner of a coal seam, severed and held separately from the oil and gas estate within the same property, does not own the coalbed methane (CBM) contained within the coal. Not decided in the appeal is a separate claim for trespass by the coal owner against the oil and gas lessee.
From the late 19th until the mid-20th century, the area of southeast Kansas enjoyed a small but significant coal industry. Between 1924 and 1926 the predecessor to Central Natural Resources, Inc. secured deeds to coal in 16 separate tracts in Labette County in which the landowners conveyed “all coal without reference to quality or quantity . . . together with the right to mine and remove the same.” No coal was ever mined from the tracts, nor did the coal owner attempt to drill for and recover the CBM. The landowners separately leased oil and gas around 2000. The oil and gas lessees secured permits and drilled into the target coal seam without notice to Central Natural Resources. An action to quiet title and in trespass was filed by the coal owner, and the trial court awarded judgment to the defendant oil and gas company solely on the quiet title claim. An interlocutory appeal was filed and granted by the Kansas Supreme Court, which upheld the trial court.
On appeal Central Natural Resources presented every legal theory in favor of CBM ownership by coal owners that have been accepted by the appellate courts in Pennsylvania, Alabama and Illinois. The Kansas Supreme Court considered and rejected each theory of ownership.
The coal owner first proposed that the court recognize that the first severance of a mineral from the fee estate, in this case coal, should be interpreted as including within the conveyance all substances contained within the coal. The court rejected this approach calling it an “artificial rule of law” and held that if a coal deed included the CBM, it must do so based on the parties’ intent.
The court next considered Central Natural Resources argument that the deeds should be interpreted as creating a presumption manifesting the parties’ intent to convey the CBM with the coal. The trial court had found the deeds to be unambiguous, but had nevertheless resorted to extrinsic evidence in the forms of treatises and appellate decisions from other states. The Supreme Court did not expressly state whether the deeds were or were not ambiguous, but did find the ambiguity analysis historically accepted by Kansas courts to be useful in ascertaining the grantors’ intent. Employing longstanding Kansas law, together with a statute that provides what interest in an estate is conveyed by deed, the court declined to accept those principles as creating a presumption that the CBM passed to the Central Natural Resources as the grantee under the 1920 era coal deeds.
Finally, in ascertaining the parties’ intent at the time of severance of coal from the fee estate, the court acknowledged that Kansas law requires it to place itself “as nearly as possible in the situation of the grantors and . . . determine as best it can the purpose of the grantors and the intentions they endeavored to convey.” Notwithstanding its adoption of that temporal principle, the court declined to find that the parties impliedly intended to convey the CBM with the coal. Accepting that the parties recognized that CBM in the 1920’s was a known hazard that exited within coal and coal mines, the court could not “divine that the grantors contemplated that the grantee could separately own and produce the CBM without exercising the right to mine and remove the coal.” In short, the deeds passed ownership of coal, and not the CBM within it.
In reaching its decision, the Kansas Supreme Court systematically considered and rejected every argument that the coal owner advanced for its claim of ownership. In holding that the oil and gas lessee owns the right to recover the CBM, it expressly did not have to reach the independent claim of trespass into the coal seam as this was not addressed by the parties in the motion for summary judgment. Since CBM cannot be recovered without a physical occupation of the coal seam, and the entry into the coal seam was without the express or implied consent of the coal owner, the ultimate disposition of the trespass claim will determine whether commercial recovery of CBM in Kansas will be viable in the absence of the consent of coal owners.
The case is Central Natural Resources, Inc. v. Davis Operating Company, 288 Kan. 234, 201 P.3d 680 (2009). For more information, contact Ken Tawney at 304 340-1189 or Blair Gardner at 304 340-1146.

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