An SAIC Report Prepared for Indiana Center for Technology ......research and analysis contained in...

An SAIC Report Prepared for

The Indiana Center for Coal Technology Research

Indiana and Coal:

Keeping Indiana Energy Cost Competitive

June 2010

Submitted to:

Indiana Center for Coal Technology Research

Submitted by:

Science Applications International Corporation

Indiana Operations Center

14064 East WestGate Court

Crane, IN 47522

www.saic.com

Acknowledgements

A special thanks to Marty Irwin, Director CCTR,

and the rest of the CCTR staff for their

outstanding guidance and support;

and to Dave Seckinger,

SAIC Crane Operations Manager,

for his continued support.

We would like to recognize our SAIC contributors:

Stephen Gootee

Gerald K. Hill

Ronald E. Thompson

Dr. John Timler

We would also like to recognize the vital contribution of:

Dr. J.W. (Jim) Wheeler, Thomas P. Miller & Associates, Inc., Sr. Vice President

Indiana and Coal: Keeping Indiana Energy Cost Competitive

Table of ContentsPage i

Table of Contents Acronyms .......................................................................................................................................iii

1.0 Executive Summary ......................................................................................................... 1‐1

1.1 General Overview ............................................................................................................ 1‐1

1.2 Indiana Energy Overview: Coal is King............................................................................. 1‐1

1.3 Legislative and Regulatory Challenges and Impacts........................................................ 1‐2

1.4 Indiana’s Energy Vision .................................................................................................... 1‐4

1.5 Hoosier Homegrown Energy............................................................................................ 1‐4

1.6 Indiana Major Energy Initiatives ...................................................................................... 1‐5

1.6.1 Expand use of Indiana coal and byproducts through improved logistics and

technology ....................................................................................................................... 1‐5

1.6.2 Implement advanced clean coal technologies for production of energy products ........ 1‐5

1.6.3 Develop biomass and renewable micro grid technologies.............................................. 1‐6

1.6.4 Develop commercial uses and technology solutions for C02 .......................................... 1‐7

1.7 Potential Indiana Energy Project Sites............................................................................. 1‐8

1.8 Conclusions and Recommended Strategies..................................................................... 1‐8

2.0 Indiana and Coal: Keeping Indiana Energy Cost Competitive.......................................... 2‐1

2.1 General Overview ............................................................................................................ 2‐1

2.2 Indiana Energy Overview ................................................................................................. 2‐1

2.2.1 Coal is King ....................................................................................................................... 2‐2

2.2.2 Indiana’s Energy Resources ............................................................................................. 2‐3

2.2.3 Legislative and Regulatory Challenges and Impacts...................................................... 2‐10

2.2.4 Special concerns: impacts on small scale coal facilities and loss of capacity ................ 2‐12

2.2.5 Energy Strategy .............................................................................................................. 2‐14

2.3 Major Energy Initiatives ................................................................................................. 2‐15

2.3.1 Expand use of Indiana coal and byproducts through improved logistics and

technology ..................................................................................................................... 2‐16

2.3.2 Implement advanced clean coal technologies for production of energy products ...... 2‐17

2.3.3 Develop biomass and renewable micro grid technologies............................................ 2‐27

2.3.4 Develop commercial uses and technology solutions for C02 ........................................ 2‐33

2.4 Identify potential sites that meet primary selection criteria for select advanced coal technology projects................................................................................................ 2‐40


Table of ContentsPage ii

2.4.1 Key Site Criteria.............................................................................................................. 2‐40

2.4.2 Priority Sites ................................................................................................................... 2‐43

2.5 Conclusions .................................................................................................................... 2‐54

2.6 Recommendations ......................................................................................................... 2‐54

Bibliography ................................................................................................................................. 3‐1

Table of Figures Figure 2‐1 Coal Destined for Indiana .................................................................................... 2‐2

Figure 2‐2 Annual Indiana Dry Natural Gas Production........................................................ 2‐3

Figure 2‐3 Oil Production in Indiana 1889‐2007................................................................... 2‐4

Figure 2‐4 Average U.S. Daily Global Solar Radiation ........................................................... 2‐5

Figure 2‐5 Indiana’s Wind Power Potential .......................................................................... 2‐6

Figure 2‐6 Geothermal Potential: Heat Flow Contours of the United States ...................... 2‐9

Figure 2‐7 The Underground Coal Gasification Process ..................................................... 2‐19

Figure 2‐8 CBM Basins Across the United States ................................................................ 2‐23

Figure 2‐9 Mine Void and Coal‐Bed Methane Wells in Indiana.......................................... 2‐25

Figure 2‐10 Shale Gas............................................................................................................ 2‐26

Figure 2‐11 An Example of the SAIC Microgrid System in Mobile Configuration................. 2‐28

Figure 2‐12 Schematic of pyrolysis process showing the three byproducts ........................ 3‐31

Figure 2‐13 Schematic of multistage digester process ......................................................... 2‐32

Figure 2‐14 Main Processes for CO2 Capture........................................................................ 2‐34

Figure 2‐15 Potential Denbury CO2 Pipeline Network .......................................................... 2‐36

Figure 2‐16 Denbury Proposed CO2 Pipeline ........................................................................ 2‐37

Figure 2‐17 Indiana Underground Water Map ..................................................................... 2‐42

Figure 2‐18 Sites Selected for Analysis ................................................................................. 2‐44

Table of Tables Table 2‐1 Indiana Facilities Using Coal............................................................................... 2‐13


AcronymsPage iii

Acronyms ACCF American Council for Capital Formation

AEP American Electric Power

ARPA Army Research Projects Agency

ASME American Society of Mechanical Engineers

B Billion

BP British Petroleum

BRAC Base Realignment And Closure

BTU British Thermal Unit

CBM Coal‐Bed Methane

CCS Carbon Capture and Storage

CCTR Center for Coal Technology Research

CH4 Methane

CO Carbon Monoxide

CO2 Carbon Dioxide

CONUS Continental United States

CTL Coal‐To‐Liquid Fuel

DoD Department of Defense

DOE Department of Energy

ECBM enhanced coal bed methane

EIA Energy Information Agency

EOR Enhanced Oil Recovery

EPA Environmental Protection Agency

ESBM enhanced shale‐bed methane

FT Fischer‐Tropsch

GHG Greenhouse Gas

GSP Gross State Product

H2 Hydrogen

IDEM Indiana Department of Environmental Management

IGCC Integrated Gasification Combined Cycle

IMP Indiana Michigan Power

kVA Kilovolt‐Amps

KWH Kilowatt Per Hour

lb/hr Pound Per Hour

M Thousand


AcronymsPage iv

MGT Midwestern Gas Transmission

MMCF Million Cubic Feet

MW Megawatt

MWH Megawatt Hours

N/S North/South

N2 Nitrogen

NAM National Association of Manufacturers

NIMBY Not In My Backyard

NIPSCO Northern Indiana Public Service Company

NOx Nitrogen Oxides

NSA Naval Supply Activity

NSWC Naval Surface Warfare Center

OED Office of Energy Development

PC Pulverized Coal

R&D Research & Development

REMC Rural Electric Membership Cooperative

RFP Request for Proposal

ROI Return on Investment

RPS Renewable Portfolio Standard

SAIC Science Applications International Corporation

SBM Shale‐Bed Methane

SNG Synthetic Natural Gas

SOx Sulfur Oxides

TCF Trillion Cubic Feet

TGTC Texas Gas Transmission Corporation

tpy Tons Per Year

UCG Underground Coal Gasification

USDOE United States Department of Energy


Executive Summary

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1.0 Executive Summary

1.1 General Overview

This report was prepared in response to Center for Coal Technology Research (CCTR) Tasking and grant funding to provide “consultation services related to the development of a state wide strategy for using coal, bio mass, and other Indiana Energy Sources to provide energy and other commercial products to meet the needs of Indiana businesses and citizens”. Significant research and analysis contained in this report was also developed using SAIC independent funding. This report builds on a CCTR/SAIC report of August 2008, which addressed the feasibility of a CTL facility located on or near NSWC Crane, to support the twin goals of advancing coal usage and clean coal technology in Indiana; and, freeing a critical national defense resource, NSWC Crane, from dependence on the fragile national grid. The 2008 report also considered tangentially the negative implications of legislative and regulatory emission controls and discussed the potential for blending coal and biomass as feedstock to offset negative impacts of controls.

This report provides a focused source of information on Indiana clean coal energy initiatives and prospects; recommends initiatives intended to reduce the economic impacts of national mandates, legislation and controls; and documents recommended additions to Indiana’s Energy strategy based on on‐going initiatives and new developments.

Since 2008, dramatic advances have been achieved in biomass and renewable energy technologies, and in microgrid and distributed power systems. Indiana companies are in the forefront in many of these areas, and their efforts can also serve as a basis for building a larger portfolio of future Indiana Energy options. The integration of biomass and renewable technologies into a strategy designed to maintain and enhance Indiana’s coal‐based energy production will be a major theme of this report.

1.2 Indiana Energy Overview: Coal is King

Indiana is perhaps the most coal dependent state in the union, with over 96% (by BTU) of our electricity, and 53% of all energy provided by coal. High reliance on coal has kept Indiana’s energy costs low, which has helped Indiana maintain a competitive environment for business and manufacturing.

Coal, by far, is Indiana’s largest fossil energy asset. Indiana is one of three states in the Illinois Coal Basin, with Illinois and Kentucky, and coal is a major industry in Southwest Indiana.

The Illinois Basin represents about 27% of demonstrated US coal reserves with Indiana some 7.2% of the Illinois Basin or about 2% of the US total. At current rates of extraction, Indiana’s reserves could represent up to 300 years of supply; and, Indiana has the capacity for substantial new coal production.

There is fair potential for discovery of significant new oil and gas reserves in the state. Though much of the state has been thoroughly drilled, this drilling is relatively shallow. Many thousands of feet of potential reservoir exist, especially in the southern portion of the state. The deep subsurface geology details of thermal maturity, migration pathways, and trapping mechanisms are relatively unknown. Further, new technologies to explore for and produce oil and gas could


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prove critical to unlocking Indiana’s oil and gas potential. These new technologies, some of which are being used in the development of the New Albany Shale as an unconventional gas source, include the application of advanced seismic acquisition and processing techniques, new drilling technologies including horizontal drilling, and complex completion techniques such as CO2 stimulation.

Though these potentially exploitable oil and gas resources are important to fuel diversification and import offset for the state, and should be pursued, they are likely to be relatively modest contributions to total state energy production, compared to coal. Prospects to replace coal with other in‐State resources are also modest. The political prospects for nuclear power in Indiana remain distant. Taken together, renewables are many decades away from providing more than a small share of Indiana’s energy needs (currently only 1.5%). Wind power is growing rapidly, but will never represent more than a modest local source of statewide electrical energy production. Biofuels present a small but important contribution to Indiana’s liquid fuel needs. Biomass is showing some applicability for electricity and heat production, and along with solar, could see rapid growth. For the foreseeable future, however, coal will remain the only Indiana energy source that can keep the state’s economy competitive.

1.3 Legislative and Regulatory Challenges and Impacts

With the increasing national focus on legislation and regulation to control CO2, especially for coal fired emissions, future costs of coal based energy may rise significantly, rendering a serious economic blow to Indiana. A wide range of policies to reduce CO2 emissions have been debated, including cap and trade, a carbon tax, renewable mandates and EPA emissions regulation. Cap and trade has emerged as the primary focus of congressional debate, while the EPA has proceeded with draft CO2 regulations. Many states have adopted different variations of a renewable energy standard and several state‐based regional cap and trade systems have been launched. A potential carbon tax has reemerged as an option to cap and trade in response to the opposition to the proposed national legislation. The impacts on states, industries and individuals of all of these proposals are a matter of ongoing debate. Various proposals offer compensatory income redistribution schemes. But, regardless of the policy, the impacts will fall most heavily on areas of the country that are coal dependent and on industries that are energy intensive.

For example, SAIC has performed a study for the National Association of Manufacturers (NAM), and the American Council for Capital Formation (ACCF), that analyses the economic impact of the Waxman‐Markey Bill, HR2454, proposed legislation to reduce Greenhouse Gas Emissions. The study concludes that Indiana will be one of the states most severely impacted, with losses that “will have a lasting effect on the economic base of Indiana”. The report describes the following major losses:

Reduction in jobs by 2030 by between 43,000 to 59,000 due to higher energy prices, costs of complying with emission cuts, and competition from overseas manufacturers with lower energy costs

Reduction in Indiana’s gross state product (GSP) by between $700M to $1.2B by 2020, and $7.4B to $10.1B by 2030


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Reduction in Indiana coal production of over 70%, and in electricity production of over 15% by 2030

The negative impact of the proposed EPA CO2 regulations could be much higher. Following upon an order from the Supreme Court that the EPA had to have an endangerment finding before it could regulate CO2, the EPA issued such a finding. Considerable debate has emerged whether this finding is valid under the Clean Air Act, but based on this finding the EPA has issued draft and now final rules.1 The final announced threshold for regulation of stationary sources identified by EPA was 100,000 tons per year (tpy). EPA’s phased‐in approach will start in January 2011, when Clean Air Act permitting requirements for Greenhouse Gases (GHGs) will kick in for large facilities that are already obtaining Clean Air Act permits for other pollutants. Those facilities will be required to include GHGs in their permit if they increase these emissions by at least 75,000 tpy. In July 2011, Clean Air Act permitting requirements will expand to cover all new facilities with GHG emissions of at least 100,000 tpy and modifications at existing facilities that would increase GHG emissions by at least 75,000 tpy. These permits must demonstrate the use of best available control technologies to minimize GHG emission increases when facilities are constructed or significantly modified.2

The final GHG “tailoring” rule was targeted at 100,000 tpy and is substantially different than the Act's permitting threshold of 250 tons annually for emissions from major sources. In theory the EPA will begin phasing in lower thresholds through 2016.3 It will be virtually impossible to regulate several million schools, hospitals, apartment buildings, restaurants and other small businesses that emit between 250 and 100,000 tons of carbon dioxide and other greenhouse gases annually.

Many states have set standards specifying that electric utilities generate a certain amount of electricity from renewable or alternative energy sources usually in the form of a "Renewable Portfolio Standard" (RPS). An RPS requires a certain percentage of a utility’s power plant capacity or generation to come from renewable or alternative energy sources by a given date. The standards vary greatly among states. Some are quite modest, others very aggressive. Qualifying energy sources vary, and some states require that a certain percentage of the portfolio be generated from a specific energy source, such as solar power. Others offer specific incentives to encourage the development of particular resources.

Historically, climate change has not been the prime motivation behind these standards, but has recently become one of the major supporting arguments. The first RPS was established in 1983. However, most states passed or strengthened their standards after 2000. These efforts have increased the penetration of renewables in some states; others have not been in effect long enough to do so. Many states allow utilities to comply with the RPS through tradable credits.

1 Draft rules are found in, ENVIRONMENTAL PROTECTION AGENCY, [EPA‐HQ‐OAR‐2009‐0597, RIN 2060‐AP87, “Reconsideration of Interpretation of Regulations that Determine Pollutants Covered by Clean Air Act Permitting Programs.” For a summary of the key points in the final rule, see Air News Release (HQ): EPA Sets Thresholds for Greenhouse Gas Permitting Requirements/Small businesses and farms will be shielded, May 13, 2010, http://www.epa.gov/nsr/actions.html. 2 In April 2010, EPA set the first national GHG tailpipe standards for passenger cars and light trucks. GHG emissions limits for

these vehicles go into effect in January 2011. 3 February 22, 2010, U.S. EPA Administrator Lisa P. Jackson, letter responding to an inquiry from eight U.S. Senators about the

Agency’s plans for addressing greenhouse gases in 2010, http://epa.gov/oar/pdfs/LPJ_letter.pdf.


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Costs of such programs will be very state and program specific. Although an RPS has been proposed several times in Indiana legislature, it has not passed.

Most of the public debate swirls around macroeconomic and large scale concerns. However, some of the most consequential impacts can only be seen by drilling underneath the gross numbers and trends. Two of special concern include: replacement of the parasitic load required to support CO2 capture and sequestration; and replacement of the electricity and heat provided by the many small coal‐fired facilities across the nation (largely owned by smaller public utilities, municipal utilities, REMCs, universities, and industry).

The former leads to serious underestimates of the expansion of physical generating capacity required to deliver the gross power required for the same net power delivered to the grid.

For the latter, under virtually all of the policy frameworks under debate, the vast majority of small coal systems may become uneconomic. However, demand will continue. Closures of small coal facilities will result in significant growth in the distribution burden on the weakest edges of the national power grid and potentially large cost increases to residents and businesses in small‐town and rural America.

1.4 Indiana’s Energy Vision

At the highest level, Indiana is pursuing two parallel energy strategies: one, captured in the State energy plan Hoosier Homegrown Energy, which is focused on maintaining cost competitive energy sources (primarily clean coal); deployment of economically viable alternative and renewable energy production and use; and enhanced efficiency; and two, to use Indiana’s extensive engineering and manufacturing base, traditionally focused on products and components, to develop an alternative energy economy and grow additional jobs.

1.5 Hoosier Homegrown Energy

Indiana created a new state energy strategy in 2006 that serves as the basis for guiding state investments and policy, even as external events and national policy have forced changes in specific programs and activities. The key elements of Hoosier Homegrown Energy include:

Vision:

Grow Indiana jobs and incomes by producing more of the energy we need from our own natural resources while encouraging conservation and energy efficiency.

Goals:

Trade current energy imports for future Indiana economic growth

Produce electricity, natural gas, and transportation fuels from clean coal and bioenergy

Improve energy efficiency and infrastructure


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1.6 Indiana Major Energy Initiatives (status and prognosis)

In the course of developing recommendations for input to Indiana’s energy strategy, we analyzed the current status and provide our assessment of the outlook for a set of four relevant initiatives that we believe will be critical to Indiana’s energy future, summarized as follows:

Expand use of Indiana coal and byproducts through improved logistics and technology

Implement advanced clean coal technologies for production of energy products

Develop biomass and renewable micro grid technologies and products

Develop commercial uses and technology solutions for CO2

In order to provide a path to implementation, we also analyzed a set of Indiana locations that have the infrastructure and thus the potential to become high value clean coal project sites.

1.6.1 Expand use of Indiana coal and byproducts thru improved logistics and technology

Approximately 50% of coal consumed in Indiana comes from out of state. Accordingly, the state has sought to promote usage of Indiana coals by:

Supporting clean coal technologies, such as IGCC, that can use higher sulfur coals effectively

Examining rail and water transportation options to take advantage of the increasingly stringent emissions requirements that may open the door for more Indiana (and greater Midwest) use of Indiana coal. These requirements may force Midwest utilities now using low sulfur Powder River Basin coal to invest in scrubbers, thus making the case to shift coal suppliers back to Indiana (at least in part)

Exploring the requirements for shifting away from out of state coals to using Indiana coal in the steel industry’s coke ovens, also requiring improved rail and water transport

Develop the technology for capturing and creating valuable byproducts from coke oven syngas

1.6.2 Implement advanced clean coal technologies for production of energy products

With the construction of Duke’s Edwardsport IGCC plant and the passage of legislation to facilitate the proposed construction of a coal to synthetic natural gas plant at Rockport, Indiana is in the forefront of states seeking commercial adoption of clean coal technologies. CCTR was explicitly formed by the Daniels Administration to help the coal industry and coal users thrive in the current environment. Besides examining a broad range of gasification‐related opportunities (including underground coal gasification), CCTR has examined extracting value from coal fines, and laid the foundation for developing Indiana’s coal‐bed and shale‐bed methane. Indeed, CCTR has identified and funded research on a range of coal‐related opportunities that offer potential to contribute to state energy objectives and present profitable investments for private firms.


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1.6.3 Develop biomass and renewable micro grid technologies

SAIC, in response to Indiana RFP 09‐SEP04‐1, submitted a matching grant proposal on August 28, 2009 to the Indiana Office of Energy Development for a new approach to generating and distributing power, based on local biomass and renewable sources of energy, called a distributed power microgrid. The State of Indiana, in September 2009, recommended to DOE the award of an economic development grant of $1.5M to SAIC as lead integrator. All DOE and state reviews have been completed and the team is currently awaiting formal grant contract signing which will be followed by immediate initiation of the project. The project is to be completed by the end of the 2010 calendar year. The microgrid approach was chosen for approval and funding by Indiana since it satisfied major strategy and RFP goals of creating new jobs in Indiana, based on “green” energy. The SAIC proposed microgrid is based on distributed generation technology. It is designed to integrate locally available alternative and renewable sources of fuel and generate electricity, using the products of Indiana companies, for commercial, homeland security, and military application. In developing this product, SAIC has leveraged previous work funded by the CCTR evaluating various energy technologies and applications.

The proposed microgrid is a fully integrated operational system, accepting inputs from alternative/renewable energy producing components, including solar and a biomass driven thermoconversion process provided by Organic Power Solutions, another Indiana company. Pyrolysis‐based thermal conversion systems can convert the diverse components found in municipal waste, for example, via electrical generators, into electrical power, crude oil, and graphite.

The microgrid can be produced in a mobile configuration, and/or tailored to site‐specific requirements such as the availability of specific feed stocks and energy inputs. The microgrid will thus have the capability to serve multiple local, regional, national, and international markets, including: (a) a wide variety of commercial applications who are seeking a turn‐key solution to the alternative/renewable energy delivery of between 1 and 5MW via a microgrid, (b) approximately 440 military installations in the continental US, (c) approximately 200 overseas installations and Forward Operating Bases, and (d) mobile military applications.

The microgrid product will be integrated and produced at an SAIC facility in Southwestern Indiana and installed for test at NSWC Crane. Proof of the completed commercial product at NSWC Crane, which is the DoD Center for Power Systems and Electronics, will establish instant credibility in both the commercial and military market places and provide a common point in Indiana for military/commercial technology transfer. In addition, DoD and the Navy have made a conscious decision to become leaders in alternative energy and have set goals to meet the Energy Policy Act of 2005 and Executive Order 13423. As recently as April 2010, the DoD re‐emphasized their goal for purchasing or producing 25% of their electricity requirements from renewable resources by the year 20254

4 DoD Facilities Energy, FY‐2009 Annual Energy Report: Overview and Status on NDAA 2010 Studies; FUPWG 14‐15 April 2010.


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It is critical to note that the microgrid installed at NSWC Crane will be identical in function and technology to one which would be installed at any commercial site. After the initial Crane installation, SAIC plans continued tailoring to the microgrid, to maximize both commercial and military application.

The SAIC microgrid plan is included in this discussion since it would be an ideal adjunct to small and medium sized coal fired facilities and rural utilities, to assist in managing CO2 emission regulation, or meeting mandated renewable energy requirements.

In concert with MES LLC, an Indiana technology company, SAIC is developing another “waste to power” system based on a second proven technology, anaerobic digestion. Multi‐stage digesters have the ability to convert high moisture content waste streams, such as animal manure from confined feeding operations or municipal sewage, into electrical power; organic fertilizer; organic animal feed; and nitrogen rich water.

Using one or both of the two waste‐to‐power technologies, an integrated system can process virtually any hydrocarbon‐rich waste stream in a manner that produces electricity, and, carbon credits. Since the byproducts from both of these techniques have commercial value, the waste streams with their associated environmental issues are eliminated as well. The carbon credits produced by microgrids could be used to offset carbon produced by Indiana’s coal plants and provide a cost effective means of keeping them online, in addition to producing significant distributed power, and meeting alternative energy mandates.

The above initiatives have led to the development of a more comprehensive approach to microgrid application, detailed in Section 2.3.3 of the report.

1.6.4 Develop commercial uses and technology solutions for C02

With the high risk of some sort of CO2 control framework, and in the face of great uncertainties regarding technology evolution, legal decisions, liability exposure, and property rights assignments, to name only a few, Indiana has focused on a series of transitional strategies to prepare for and mitigate the costs of whichever CO2 schema emerges. These include:

A primary strategy focused on exploring requirements to facilitate private development of a CO2 pipeline from Indiana to the Jackson Dome in Mississippi to be used to meet the growing demand for CO2 in enhanced (tertiary) oil recovery

Aggressively seeking reasonable policy and regulatory outcomes

Monitoring and supporting preparatory investigation of economically viable pre and post combustion CO2 capture technologies

Supporting characterization of CO2 sequestration potential in Indiana

Identifying and supporting investigation of potential commercial uses of CO2, which Include CO2 injection to stimulate methane in coal and shale beds (so‐called enhanced coal bed methane and enhanced shale‐bed methane), and a variety of potential CO2 applications in support of industrial and agricultural processes.


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1.7 Potential Indiana Energy Project Sites

A major impediment to the development of new clean coal or other major initiatives is typically the lack of availability of a site that meets the necessary requirements. Typical requirements might include large acreage, access to transportation infrastructure, water, feedstock, electric grids, gas pipelines, and community support. Potential sites to be looked at first would include the following categories:

Closed or operational industry/utility owned for similar use

Industrial brownfield or former mine site

Operational or closed military facilities

State or community owned with historical support for energy investment

A quick look across Indiana reveals several high potential sites worthy of further investigation, including, among others, the closed Newport Chemical Weapons facility, the closed Breed power plant site, the Port of Indiana at Mount Vernon, and the closed Indiana Ammunition Plant near Jeffersonville.

1.8 Conclusions and Recommended Strategies

Conclusions

Indiana has limited alternative energy or fossil fuel resources other than coal; the state’s alternative and nontraditional “natural gas” resources will be expensive (compared to coal) and slow to develop

Significant cost increases in Indiana Energy may occur as a result of legislation and policy

On‐going advanced coal strategies hold promise for significant medium‐term reward, e.g. coal gasification and the CO2 pipeline

Biomass, renewable energy, and power management technologies are being matured by Indiana companies and can be used in conjunction with small and medium sized coal plants and certain utilities to help offset future mandates and regulations, and drive new jobs in manufacturing, agriculture and defense

Indiana offers a unique set of sites with the necessary infrastructure to support major advanced coal facilities

Strategy Recommendations

It is recommended that biomass and alternative energy fueled distributed power systems be integrated into the Indiana Energy Strategy to minimize the loss of small and medium coal fired facilities, and impacts on rural utilities and communities, due to CO2 controls or alternative energy mandates. Specifically, the Indiana portfolio of coal fired facilities should be analyzed and priority candidates be identified to be supplemented with a biomass powered microgrid. It is also recommended that a farm or municipal site be chosen with sufficient available waste to demonstrate the effectiveness of waste driven power generation, and to achieve the


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benefits described in this report of baseline power, environmental waste elimination, growth of Indiana agriculture, and the creation of new, green energy jobs.

Indiana’s clean coal strategy has resulted in the development of several initiatives that will positively impact Indiana’s energy future. As described in this report, these initiatives are in various stages of development, from early concept to near completion. It is recommended that a systematic process be applied to the defined initiatives to set priorities and develop the necessary industry and community partners, plans, and resources necessary to push through to completion.

It is also recommended that, given the availability of sites in Indiana with the appropriate infrastructure for major energy projects, that a strategy be focused on publicizing and leveraging these sites, again with appropriate industry and community partnerships, to exploit the potential of each site for a major energy project.


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2.0 Indiana and Coal: Keeping Indiana Energy Cost Competitive

2.1 General Overview

This report was prepared in response to Center for Coal Technology Research (CCTR) tasking and grant funding to provide “consultation services related to the development of a state wide strategy for using coal, bio mass, and other Indiana energy sources to provide energy and other commercial products to meet the needs of Indiana businesses and citizens”. Significant research and analysis contained in this report was also developed using SAIC independent funding. This report builds on a CCTR/SAIC report of August 2008, which addressed the feasibility of a coal‐to‐liquid fuel (CTL) facility located on or near NSA Crane, to support the twin goals of advancing coal usage and clean coal technology in Indiana, and freeing a critical national defense resource, NSWC Crane, from dependence on the fragile national grid. Although this report specifically addresses the potential to create an Energy Island for NSA Crane, the same concept would hold for most any other CONUS military or Homeland Security sensitive site (hospitals and evacuation centers), especially those in relatively rural areas. Technology exists, and in the case of NSA Crane, is already deployed, which allows local electric transmission to be isolated from the national grid at the substation level. This technology also permits automated isolation of connections to the local distribution system to allow distributed renewable power to be directed to a single location such as NSA Crane or a local hospital.

The 2008 report also considered tangentially the negative implications of legislative and regulatory emission controls and discussed the potential for blending coal and biomass as feedstock to offset negative impacts of controls.

This report provides a focused source of information on Indiana’s clean coal energy initiatives and prospects; recommends initiatives intended to reduce the economic impacts of national mandates, legislation, and controls; and documents recommended additions to Indiana’s Energy strategy based upon on‐going initiatives and new developments.

Since 2008, dramatic advances have been achieved in biomass and renewable energy technologies, as well as in microgrid and distributed power systems. Indiana companies are in the forefront in many of these areas, and their efforts can also serve as a basis for building a larger portfolio of future Indiana energy options. The Daniels Administration and the Lt. Governor, through the CCTR and the Indiana State Office of Energy Development (OED), have taken a leadership role with industry, academia, and public utilities to share ideas and technology. These two organizations have partnered with an array of business and academic initiatives focused on energy policy and technologies. Reports and conference presentations sponsored by these groups are included as references in this report. The integration of biomass and renewable technologies into a strategy designed to maintain, and enhance, Indiana’s coal based energy production will be a major theme of this report.

2.2 Indiana Energy Overview

Indiana is perhaps the most coal dependent state in the union, with over 96% (by BTU) of our electricity, and 53% of all energy provided by coal. High reliance on coal has kept Indiana’s energy costs low, which has helped Indiana maintain a competitive environment for business and manufacturing. With the increasing national focus on legislation and regulation to control


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coal fired emissions, future costs of coal based energy may rise significantly, rendering a serious economic blow to Indiana. Various policy and regulatory controls are under debate: a CO2 Cap and Trade system, a carbon tax, EPA source control mandates, and renewable energy standards. Some consequences of these actions are discussed below.

2.2.1 Coal is King

As reported in the 2009, Indiana Coal Report, Indiana was the second largest consumer of coal for electricity generation behind Texas. Over three quarters of the coal consumed was used to produce electric power. Less than half of Indiana’s coal consumption was produced in Indiana mines (Figure 2‐1). The largest single source of imports was from Wyoming –low sulfur Powder River Basin coal for power plants without scrubbers. Remaining imports consist of a mix of low sulfur coals for power plants, coke and anthracite for metals industry use, and other coals with logistics cost advantages over Indiana coals based on river, rail and truck access.

High coal reliance has kept Indiana energy costs relatively low, which in turn has helped Indiana remain a manufacturing leader in the US. Prior to the current recession (2009/2010), Indiana had the highest percentage of state employment and output generated by manufacturing in the nation. Indeed, it also had become the state with the highest concentration of iron and steel manufacturing. Other factors were important as well, but relatively low and stable energy costs provided a major competitive edge for Indiana manufacturing operations. With manufacturing’s energy intensity, any policy that raises energy prices in Indiana relative to

Figure 2‐1. Coal Destined for Indiana

Source: Indiana Coal Report 2009, p. E‐3.

Coal Destined for Indiana (in Thousand Short Tons) & Methods of Transportation


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elsewhere will tend to drive production and jobs toward locations with lower energy costs (primarily offshore).

2.2.2 Indiana’s Energy Resources

2.2.2.1 Coal Resources

Coal, by far, is Indiana’s largest fossil energy asset. Indiana, with Illinois and Kentucky, is one of three states in the Illinois Coal Basin, and coal is a major industry in Southwest Indiana. Besides coal, Indiana has modest recoverable supplies of natural gas and petroleum.5

The Illinois Basin represents about 27% of demonstrated US coal reserves with Indiana some 7.2% of the Illinois Basin or about 2% of the US total. Coal reserves are largest in three Indiana counties of Knox, Gibson, and Posey. At current rates of extraction, Indiana’s reserves could represent up to 300 years of supply. Indiana has the capacity for substantial new coal production. Both the Edwardsport IGCC facility and the proposed coal to SNG facility in Rockport will use Indiana coal.

2.2.2.2 Indiana’s Conventional Natural Gas Resources

The state has a small natural gas producing industry. In 2005 there were 338 active natural gas wells on the Trenton Field. In 2007 Indiana produced more than 3,600 million cubic feet of natural gas (see Figure 2‐2). With new natural gas pipelines being built across the state, we are seeing some increased drilling to take advantage of reduced distribution costs. Even so, Indiana’s production is a tiny share of Indiana consumption (less than 0.7%), and a minuscule share of US natural gas production (less than 0.02%).6

5 Indiana’s industrial expansion of the late 19th century was in part triggered by a natural gas boom in the Trenton Gas Field located in east central Indiana and the most western portion of west central Ohio. Almost all of the natural gas was removed from the field by 1910 (largely wasted using the drilling and flaring techniques of the time), but only about 10% of the oil was removed at that point. The lack of pressure caused by the removal of the gas led to a complete stop of oil production, even though an estimated 900 million barrels of oil remained in the field. Beginning in the late 20th Century oil production resumed at a slow pace after advances in artificial lift technology. (Gray, Ralph D (©1995). Indiana History: A Book of Readings. Indiana: Indiana University Press. ISBN 025332629X.)

6 US Department of Energy, Energy Information Agency, Release Date: 7/29/2009.

Source: U.S. Energy Information Administration, State Energy Data System, Table P6. Energy Production in Physical Units by Source, Indiana, 1960 ‐ 2007; Released: October 30, 2009

Figure 2‐2. Annual Indiana Dry Natural Gas Production


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2.2.2.3 Indiana’s Oil Resources7

Indiana’s recent oil production has been modest and steadily declining (see Figure 2‐3). From a high of some 12 million barrels (bbl) per year in the 1960s, production (mostly from southwestern Indiana) had fallen to some 1.7 million bbl per year by 2007. New technology, deeper exploration, and perhaps CO2 injection might improve the ability to recover existing oil reserves, perhaps even in the Trenton Field.

2.2.2.4 Future Indiana Oil & Gas

There is fair potential for discovery of significant new oil and gas reserves in the State. Though much of the State has been thoroughly drilled, this drilling is relatively shallow. Many thousands of feet of potential reservoir exist, especially in the southern portion of the state. The deep subsurface geology details of thermal maturity, migration pathways, and trapping mechanisms are relatively unknown. Further, new technologies to explore for and produce oil and gas could prove critical to unlocking Indiana’s oil and gas potential. These new technologies, some of which are being used in the development of the New Albany Shale as an unconventional gas source, include the application of advanced seismic acquisition and processing techniques, new drilling technologies including horizontal drilling, and complex completion techniques such as CO2 stimulation.

2.2.2.5 Other In‐State Energy Resources

Although the State of Indiana does not currently have a Renewable Energy Standard or require or mandate Renewable Energy Credits, there is considerable interest among state and local government agencies, utilities and businesses looking for alternative energy opportunities ‐ as

6Sections 2.2.2.3 and 2.2.2.4 are based upon John A. Rupp, “Oil and Gas in Indiana, A Brief Overview of the History of the Petroleum Industry in Indiana,” Indiana Geological Survey, 2008.

Source: John A. Rupp, “Oil and Gas in Indiana, A Brief Overview of the History of the Petroleum Industry in Indiana,” Indiana Geological Survey, 2008.

Figure 2‐3. Oil Production in Indiana 1889‐2007


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viable economic options, in response to perceptions concerning pubic good, and due to the potential for future mandates. This has resulted in significant investment as well as a variety of Federal and State supported grants, tax credits, and loan guarantee programs.

2.2.2.5.1 Solar

Indiana does not rank at the top of the solar power potential list, but a distributed energy source model actually would provide an adequate framework to support a network of smaller distributed solar farms, especially across the southwest quadrant of the State (Figure 2‐4) Individual locations in the 5MW range could provide a valuable source of power with no significant investment in transmission lines required.

2.2.2.5.2 Wind

Over the last 2‐3 years the investment in wind farms in northern Indiana has demonstrated that adequate wind exists in that locale (Figure 2‐5) and that the technology works well in Indiana due to the extensive existing state wide energy grid network. When Homeland Defense benefits are considered, the case can be made for providing Federal and State incentives to separate these systems over a larger area to give the benefit of distributed power as well as reducing the intermittent nature of wind energy generation. Another potential wind benefit exists for sensitive communication system locations such as cell phone towers. A combination of small

Source: Original source: National Renewable Energy Laboratory. Downloaded from: http://www.eia.doe.gov/cneaf/solar.renewables/renewable.energy.annual/backgrnd/fig24.htm.

Figure 2‐4. Average U.S. Daily Global Solar Radiation


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Figure 2‐5. Indiana’s Wind Power Potential

Source: http://www.windpoweringamerica.gov/wind_resource_maps.asp?stateab=in

wind generators with a battery power storage system would provide a reliable power source without the expense of providing and maintaining diesel generators. The CCTR has commissioned a study for a “Green Cell Phone Tower” project. The preliminary report was issued in March 2010 and is very encouraging.8

8CCTR Research Progress Report, “Green Cell Phone Towers,” A302‐10‐PSC‐CTR‐003, by Dr. Afshin Izadian and Dr. Andrew Hsu, Indiana University, March, 02, 2010.


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2.2.2.5.3 Biomass

The Indiana Biomass Working Group in cooperation with Purdue University and the Office of Energy Development has developed a state wide effort to identify biomass sources including new crops which might thrive in the Indiana climate. Research by Purdue University and others have shown potential for corn crop waste, switch grass, miscanta, sorghum, algae and others. Due to the low BTU value of crop type biomass, harvesting costs and transportation costs become governing factors on site selection for economic conversion of biomass to energy.

The State of Indiana has been very proactive in looking at non‐traditional biomass potential which is available from environmentally managed wastes.

IDEM rule change concerning biomass waste to energy

On March 3, 2010, the Indiana Department of Environmental Management (IDEM) issued a First Notice concerning a new biomass waste to energy rulemaking (329 IAC 11.5). This is a significant rule change for IDEM, indicating strong State support for creating renewable energy. The rule would make it much easier to use what is currently considered “environmental regulated/managed solid wastes” as a renewable energy feedstock without a solid waste processing permit. The time requirements for gaining project approval and the application costs were greatly reduced. A key requirement in the new rule limits the user to maintaining only a reasonable stockpile of material on hand. The technology is focused on digesters, gasification and pyrolysis to recover energy or to recover usable material. The interim rule provides an application process which allows immediate consideration of projects.

Specific candidates identified include:

Agricultural crop residues

Animal manure

Food waste

Live stock operation residues

Industrial waste like paper pulp

Ethanol

As one of the Nation’s top corn‐producing States, Indiana has major ethanol production potential. Production efficiencies and improved yeast technology has permitted ethanol production in the Midwest to reduce water consumption and overall production cost, which is making ethanol more competitive with traditional gasoline. There continues to be pressure to reduce domestic production subsidies and import tariffs on foreign produced ethanol. Combined with the recession‐induced declines in oil prices, this has slowed investments in new facilities. This in turn has significantly limited investment in new second generation cellulosic ethanol facilities.

Bio‐diesel

The interest in thermo chemical conversion of biomass to a bio‐diesel, or in most cases a refinery ready bio‐crude, makes the small gasification and small pyrolysis technology an area where innovation is still encouraged. The liquid fuel from gasification is typically taken through


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a Fischer Tropsch process to make a diesel fuel equivalent. Pyrolysis can provide a bio‐crude that can be blended into a refinery’s crude oil process with minimal cleaning and filtering. The small gasification and pyrolysis systems can be located geographically to minimize transportation costs.

Algae in Indiana

Algae continues to be evaluated as a potential feedstock for both biological processing to an algal oil as well as a feedstock for thermo chemical conversion, with significant potential to use coal plant CO2 to enhance the algae growth.

2.2.2.5.4 Other Resources

Hydropower

Although not a common Indiana resource, Hydropower exists in Indiana. For example, a hydroelectric resource exists near NSA Crane on the nearby White River at Williams, IN. Although not currently active it has the potential to provide up to 5MW of power which could contribute to the NSA Crane Energy island concept. Across the State, five active hydroelectric dams have been identified.

Markland Locks and Dam: The Markland Locks and Dam is a concrete dam, bridge, and locks that span the Ohio River. It is 1395 feet (425.2 m) long, and connects Gallatin County, Kentucky, and Switzerland County, Indiana. The locks were placed in operation in May 1959 and the dam was finished in June 1964. The Federal Power Commission granted a license for Cinergy to operate a hydroelectric power plant at the dam. The plant has a capacity of 81,000 kVA.9

Norway Dam: Purchased by the Northern Indiana Public Service Company (NIPSCO), Norway Dam is an intact example of a 1920s dam and hydroelectric facility. Built in 1922‐23, it retains the original dam and spillway structures with few alterations. Original generators and turbines continue to operate, and provide electrical power and recreation for the area. With its four generators, the Norway Dam is capable of producing up to 7.200MW of electricity per hour. Lake Shafer, created by the dam, has the Indiana Beach Amusement Park on its shores.10

Oakdale Hydroelectric Dam: Oakdale Hydroelectric Plant was put in service in 1925 and NIPSCO purchased the plant in 1944. Oakdale Hydroelectric maximum output is 9.2MW. The Oakdale Hydroelectric Dam was built just south of Monticello, creating Lake Freeman.11

Twin Branch and Elkhart Dams: These two small hydroelectric dams are owned by Indiana Michigan Power, a division of American Electric Power (IMP/AEP). Both are on the St. Joseph River in Indiana and are used for hydroelectric power purposes.12

9 http://en.wikipedia.org/wiki/Markland_Locks_and_Dam 10 http://www.lakelubbers.com/lake‐shafer‐479/ and http://www.nipscohydro.com/ 11 http://www.nipscohydro.com/ 12 http://findlakes.com/twin_branch_indiana~in03011.htm and http://www.aep.com/environmental/recreation/hydro/Default.aspx


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IMP/AEP does not provide a site‐by‐site accounting of hydroelectric capacity. The combined capacity for the six Indiana and Michigan sites is only 22.4MW. (Berrien Springs, MI; Buchanan, MI; Constantine, MI; Elkhart, IN; Mottville, MI; and Twin Branch, IN).

Hydroelectric turbine technology continues to progress with smaller systems, utilizing river current, offering significant potential with minimal risk to the environment. With the Ohio, Wabash, the White River West and East Forks, and many smaller rivers and streams, low‐head hydroelectric is a potential worthy of consideration to help meet specific business requirements across Indiana.

Geothermal

Individuals and organizations with longer return on investment (ROI) horizons are adopting geothermal across the State, even though Indiana is not known for high value geothermal assets. Figure 2‐6 provides a high level map of Heat Flow Contours of the United States, which provides a good proxy for total geothermal potential. Technologies have improved and costs have fallen, making some geothermal applications attractive in Indiana. Among the larger adopters, for example, is Ball State University which is replacing its coal fired campus central heating boilers with geothermal heat pump systems (with partial Federal funding of $5M). The Indiana Institute of Technology received $1.3M in federal funds to install geothermal heat pumps using carbon dioxide as the cooling medium.

Original source citation: Energy Information Administration, Geothermal Energy in the Western United States and

Hawaii: Resources and Projected Electricity Generation Supplies, DOE/EIA‐0544 (Washington, DC, September 1991);

Modified after the Geothermal Map of North America, prepared as part of the Geological Society of North America

Decade of North America Geology (DNAG), from Blackwell, D.D., and Steel, J.L., Mean Temperature in the Crust of

the United States for Hot Dry Rock Resource Evaluation (Southern Methodist University, May 1990), pp. 6‐8,

updated by D.D. Blackwell. Source: Downloaded from

http://www.eia.doe.gov/cneaf/solar.renewables/renewable.energy.annual/backgrnd/fig17.htm.

Figure 2‐6. Geothermal Potential: Heat Flow Contours of the United States


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2.2.2.6 Coal will remain King

These various alternative fuels are important to fuel diversification and import offset for the State, and should and will be aggressively pursued. Nonetheless, prospects to replace coal with other in-state resources are slim. Compared to coal, potentially exploitable oil and gas resources are likely to be relatively modest contributions to total state energy production. The political prospects for nuclear power in Indiana remain distant. Taken together, renewables are many decades away from providing more than a small share of Indiana’s energy needs (currently only 1.5%). Wind power is growing rapidly, but may never represent more than a modest local source of statewide electrical energy production. Biofuels present a small but important contribution to Indiana’s liquid fuel needs. Biomass is showing some limited small-scale applicability for electricity and heat production, along with geothermal and solar, and could see rapid growth. For the foreseeable future, however, coal will remain the only Indiana energy source that can keep the State’s economy competitive.

2.2.3 Legislative and Regulatory Challenges and Impacts

With the increasing national focus on legislation and regulation to control CO2, especially for coal fired emissions, future costs of coal based energy may rise significantly, rendering a serious economic blow to Indiana. A wide range of policies to reduce CO2 emissions have been debated, including cap and trade, a carbon tax, renewable mandates, and EPA emissions regulation. Cap and trade has emerged as the primary focus of congressional debate, while the EPA has proceeded with draft CO2 regulations.

13 Many states have adopted different variations of a renewable energy standard and several state‐based regional cap and trade systems have been launched. A potential carbon tax has reemerged as an option to cap and trade in response to the opposition to the proposed legislation.

The impacts on states, industries, and individuals of all of these proposals are a matter of ongoing debate. Various proposals offer compensatory income redistribution schemes. But, regardless of the policy, the impacts will fall most heavily on areas of the country that are coal dependent and on industries that are energy intensive.

As highlighted above, Indiana is perhaps the most coal dependent state in the Union, and its core manufacturing and logistics industrial base is reliant upon the relatively (compared to domestic and foreign competitors) low and stable energy prices provided by coal‐based electrical power. Strong politically‐driven renewable energy mandates, and CO2 policy and regulation offer a special threat to coal‐based electrical power and to the competitiveness of industry across Indiana. Studies show that heavy industry states and coal intensive states suffer disproportionately from such policies, and Indiana is both. Not surprisingly, Indiana tends to rank first among the 50 states in negative economic impacts in studies of policies such as cap

and trade.14 Design details make a vast difference in the actual impact of any CO2 control policy.15

13 The most recent iteration of the national energy policy/CO2 control roller coaster is the release on May 12, 2010 of the new climate legislation proposal from Sens. Kerry and Lieberman. 14 See for example, Science Applications International Corporation (SAIC), Economic Impact of the Waxman‐Markey American Clean Energy and Security Act: Analysis of The Waxman‐Markey Bill “The American Clean Energy and Security Act of 2009” (H.R. 2454) Using the National Energy Modeling System (NEMS/ACCF‐NAM 2), August 12, 2009.


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2.2.3.1 Cap and Trade

For example, SAIC has performed a study for the NAM and the ACCF that analyses the economic impact of Waxman‐Markey Bill, HR2454, legislation proposed to reduce Greenhouse Gas Emissions. The study concludes that Indiana will be one of the most severely impacted states, with losses that “will have a lasting effect on the economic base of Indiana”. The report describes the following major losses:

Reduction in jobs, by year 2030, by 43,000 to 59,000 due to higher energy prices, costs of complying with emission cuts, and competition from overseas manufacturers with lower energy costs

Reduction in Indiana’s GSP by between $700M to $1.2B by 2020, and $7.4B to $10.1B by year 2030

Reduction in Indiana coal production of over 70%, and in electricity production of over 15% by year 2030

2.2.3.2 EPA CO2 Regulation

The negative impact of the proposed EPA CO2 regulations could be much higher. Following upon an order from the Supreme Court that the EPA had to have an endangerment finding before it could regulate CO2, the EPA issued such a finding. Considerable debate has emerged whether this finding is valid under the Clean Air Act, but based on this finding the EPA has issued draft and now final rules.16 The final announced threshold for regulation of stationary sources identified by EPA was 100,000 tons per year. EPA’s phased‐in approach will start in January 2011, when Clean Air Act permitting requirements for GHGs will kick in for large facilities that are already obtaining Clean Air Act permits for other pollutants. Those facilities will be required to include GHGs in their permit if they increase these emissions by at least 75,000 tons per year (tpy). In July 2011, Clean Air Act permitting requirements will expand to cover all new facilities with GHG emissions of at least 100,000 tpy and modifications at existing facilities that would increase GHG emissions by at least 75,000 tpy. These permits must demonstrate the use of best available control technologies to minimize GHG emission increases when facilities are constructed or significantly modified.17

The final Greenhouse Gas “tailoring” rule is targeted at 100,000 tpy, substantially different than the Act's permitting threshold of 250 tons annually for emissions from major sources. In theory the EPA will begin phasing in lower thresholds through 2016.18 It will be virtually impossible to

15 F.T. Sparrow provides a discussion of design elements that would mitigate or intensify the state‐level impacts on Indiana (and similar states). “The Impact of Alternative CO2 Limiting Legislative Designs on Indiana,” CCTR Advisory Panel Meeting, March 4, 2010. 16 Draft rules are found in, ENVIRONMENTAL PROTECTION AGENCY, [EPA‐HQ‐OAR‐2009‐0597, RIN 2060‐AP87, “Reconsideration of Interpretation of Regulations that Determine Pollutants Covered by Clean Air Act Permitting Programs.” For a summary of the key points in the final rule, see Air News Release (HQ): EPA Sets Thresholds for Greenhouse Gas Permitting Requirements/Small businesses and farms will be shielded, May 13, 2010, http://www.epa.gov/nsr/actions.html. 17 In April 2010, EPA set the first national GHG tailpipe standards for passenger cars and light trucks. GHG emissions limits for these vehicles go into effect in January 2011. 18 February 22, 2010, U.S. EPA Administrator Lisa P. Jackson, letter responding to an inquiry from eight U.S. Senators about the Agency’s plans for addressing greenhouse gases in 2010, http://epa.gov/oar/pdfs/LPJ_letter.pdf.


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regulate several million schools, hospitals, apartment buildings, restaurants and other small businesses that emit between 250 and 100,000 tons of carbon dioxide and other greenhouse gases annually.

2.2.3.3 Renewable Portfolio Standards

Many states have set standards specifying that electric utilities generate a certain amount of electricity from renewable or alternative energy sources usually in the form of a "renewable portfolio standard" (RPS). An RPS requires a certain percentage of a utility’s power plant capacity or generation to come from renewable or alternative energy sources by a given date. The standards vary greatly among states. Some are quite modest, others very aggressive. Qualifying energy sources vary, and some states require that a certain percentage of the portfolio be generated from a specific energy source such as solar power. Others offer specific incentives to encourage the development of particular resources.

Historically, climate change was not the prime motivation behind these standards, but has recently become one of the major supporting arguments. The first RPS was established in 1983. However, most states passed or strengthened their standards after 2000. These efforts have increased the penetration of renewables in some states; others have not been in effect long enough to do so. Many states allow utilities to comply with the RPS through tradable credits. Costs of such programs will be very state and program specific. Although an RPS has been proposed several times in Indiana legislature, it has not passed. It has been discussed at the federal level, but has not gained significant traction.

2.2.4 Special concerns: impacts on small scale coal facilities and loss of capacity

Most of the public debate swirls around macroeconomic and large scale concerns. However, some of the most consequential impacts can only be seen by drilling underneath the gross numbers and trends. Two of special concern include: replacement of the parasitic load required to support CO2 capture and sequestration; and replacement of the electricity and heat provided by the many small coal‐fired facilities across the nation (largely owned by smaller public utilities, municipal utilities, Rural Electric Membership Cooperatives (REMCs), universities, and industry).

The former leads to serious underestimates of the expansion of physical generating capacity required to deliver the gross power required for the same net power delivered to the grid.

For the latter, under virtually all of the policy frameworks under debate, the vast majority of small coal systems may become uneconomic and face shut down. However, demand will continue. Closures of small coal facilities will result in significant growth in the distribution burden on the weakest edges of the national power grid and potentially large cost increases to residents and businesses in small‐town and rural America.

Indiana is home to many small and medium scale municipal, REMC, and industrial plants, as well as a significant number of coal fired plants that are used only for heat. A list of most Indiana coal‐using facilities is provided in Table 2‐1.


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Table 2‐1 Indiana Facilities Using CoalLargest Coal Users in Indiana 2007Name Tons of Coal Est. CO2 Emissions (tons) Rockport Power Plant 10,962,000 24,774,120Gibson Power Plant 9,979,000 22,552,120R.M. Schahfer Power Plant 5,541,000 12,522,660Petersburg Power Plant 5,488,000 12,402,880Clifty Creek Power Plant 4,345,000 9,819,700Merom Power Plant 3,108,000 7,024,080Cayuga Power Plant 2,828,000 6,391,280Wabash River Power Plant 2,312,000 5,225,120Tanner Creek Power Plant 2,268,000 5,125,680State Line Energy Power Plant 1,975,000 4,463,500Warrick Power Plant 1,967,000 4,445,420Edwardsport Power Plant 1,800,000 4,068,000A.B. Brown Power Plant 1,616,000 3,652,160Harding Street Power Plant 1,579,000 3,568,540Michigan City Power Plant 1,295,000 2,926,700Gallagher Power Plant 1,247,000 2,818,220F.B. Culley Power Plant 1,218,000 2,752,680Bailly Power Plant 1,116,000 2,522,160Frank Ratts Power Plant 778,000 1,758,280Eagle Valley Power Plant 684,000 1,545,840White Water Valley Power Plant 214,000 483,640C.C. Perry Power Plant 175,108 395,744Lehigh Cement 128,956 291,441New Energy 118,924 268,768General Shale Brick 114,714 259,254Logansport Power Plant 109,000 246,340Tate & Lyle 85,010 192,123University of Notre Dame 78,478 177,360A.E. Staley Sagamore 68,109 153,926Indiana University 67,601 152,788Eli Lilly ‐ Clinton Labs 61,216 138,348Penrod Ricard 59,381 134,201Eli Lilly ‐ Tippecanoe Labs 58,520 132,255International Paper 37,644 85,075Bunge North America 37,434 84,601Jasper Power Plant 36,000 81,360Ball State University 32,559 73,583Danisco Sweetener 19,263 43,534Frito Lay 18,033 40,755Crawfordsville Municipal 13,000 29,380Peru Municipal 13,000 29,380Total 63,651,950 143,853,407* est for 2014 Source: CCTR/IGS

Indiana has some 30 sites with coal‐fired facilities including over 90 generating units totaling nearly 22,000MW. Approximately 25% of Indiana’s coal‐fired electricity generating units are


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under 50MW19. High renewable energy mandates and stringent CO2 control regimes will dramatically impact the costs facing smaller coal using operations. Indeed, the smaller facilities would be at risk of shut down under most proposed CO2 control regimes, with dramatic impacts on available capacity and local electricity prices. This is a far more serious threat across the coal states than is generally recognized in the policy debate and one that requires serious attention.

2.2.5 Energy Strategy

At the highest level, Indiana is pursuing two parallel energy strategies: the first is captured in the Hoosier Homegrown Energy plan; the second is to use Indiana’s extensive second‐tier engineering and manufacturing base, traditionally focused on products and components to develop an alternative energy economy and grow additional jobs.

2.2.5.1 Hoosier Homegrown Energy

Indiana created a new state energy strategy in 2006 that serves as the basis for guiding state investments and policy, even as external events and national policy have forced changes in specific programs and activities. The key elements of Hoosier Homegrown Energy include:20

Vision:

Grow Indiana jobs and incomes by producing more of the energy we need from our own natural resources while encouraging conservation and energy efficiency.

Goals:

Trade current energy imports for future Indiana economic growth

Produce electricity, natural gas, and transportation fuels from clean coal and bioenergy

Improve energy efficiency and infrastructure

Implementation initiatives have included:

Reducing import dependence (both from international and from other US sources) and retaining a larger share of energy spending inside the State

Increasing biofuels production and use

Supporting adoption of clean coal technologies and other policies that increase use of Indiana coals

Supporting wind deployment and manufacturing of windmill components

Promoting efficiency and adoption of alternative and distributed energy when economically viable

19 Sourcewatch.org/index.php?title=Indiana_and_coal#Existing_coal_plants. 20 See Energy.IN.gov for the 2006 plan as well as the recent detailed programmatic enhancements approved by the USDOE under the greatly expanded ARRA funding of the State Energy Program.


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Supporting the growth of manufacturing of energy efficient, energy efficiency, and alternative energy products, with special focus on Distributed power

Transportation vehicles, batteries, and other components

2.2.5.2 Key actors in implementing the State’s energy strategy have included:

The Center for Coal Technology Research: Its primary activities have included:

Identifying and analyzing key coal‐related opportunities

Identifying potential sites across the State where opportunities could be launched

Providing support for select pre‐feasibility analyzes

Assessment of policy and regulatory issues and constraints

Coordinating with other states’ coal leadership

Providing outreach and a forum for networking

The Office of Energy Development: Its primary activities have included:

Primary responsibility for managing and leveraging federal (DOE) programmatic funding

Coordinating energy‐related activity among state agencies and around the State

Supporting investments in energy and energy efficiency projects and programs

Clearinghouse for energy and energy efficiency information

The Energy Systems Network (a new private non‐profit organization whose members include key energy‐related manufacturers and utilities). Its primary activities have included:

Developing of key alternate energy initiatives

Leveraging Indiana companies (especially product and component manufacturing and utilities)

Supporting collaborative funding and resource initiatives

Coordinating collaborative commercialization projects (especially in heavy hybrid electric vehicle systems, smart grid systems to support plug hybrid deployment, and microgrid solutions)

2.3 Major Energy Initiatives

With energy cost a critical component of State economic competitiveness, and coal representing Indiana’s primary energy asset, coal has become a key element in implementing the State’s energy strategy.

The remainder of this report focuses on the coal‐centric elements of Indiana’s energy strategy with special attention to near‐term actions that can be pursued. The report also addresses an approach to incorporate emerging distributed power generation technologies which can serve to accommodate alternative sources and mitigate future policy impacts on coal users. Other components of the State’s energy strategy are discussed as they interact with and support the State’s efforts to maximize the value of its coal resources to grow incomes and wealth for Indiana residents.


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In the course of developing our contribution to Indiana’s energy strategy, we analyzed the current status and provide our assessment of the outlook for a set of four relevant initiatives that we believe will be critical to Indiana’s energy future:

Expand use of Indiana coal and byproducts thru improved logistics and technology

Implement advanced clean coal technologies for production of energy products

Develop biomass and renewable micro grid technologies

Develop commercial uses and technology solutions for C02

We also analyzed a set of Indiana locations that have the infrastructure for possible high value clean coal project sites.

2.3.1 Expand use of Indiana coal and byproducts21 through improved logistics and technology

2.3.1.1 Seek to substitute Indiana coals for Powder River Basin and other imported coals by Midwest coal users

Indiana coal is a relatively high BTU, high sulfur bituminous coal. Its sulfur content (averaging from 1.4% ‐ 5.0% for the four major beds) has been a handicap for power plants without scrubbers, leading to a significant increase in shipments of low‐sulfur coals from out of state.

As air quality standards have tightened, all coal fired power plants power are facing potential decisions to install scrubbers, even those burning low sulfur coals. If installed scrubbers can clean Indiana coals effectively and efficiently, this may create an opportunity to partially shift coal consumption back towards a higher share of Illinois basin coals for some Indiana and other Midwest coal‐fired power plants. Many technical and economic questions remain regarding the viability of this opportunity. CCTR has funded several studies examining this strategy. These studies have focused primarily on the limitations of Indiana’s north‐south rail infrastructure to support large coal shipments. Discussions are underway concerning the rail and water infrastructure investments that such a shift might entail, as well as the price scenarios, and policy and contractual issues that would have to be surmounted. Even with the cost of scrubbers, the low delivered price of Powder River Basin coal is a significant barrier to such a shift, especially in Northern Indiana.22

Next steps toward creation of commercial value associated with these ideas will require:

Validation that the scrubber technologies will meet the necessary emissions control with Indiana coals

Detailed exploration of the potential real demand among coal consumers in northern Indiana and the other Great Lakes states

21 A good summary of CCTR thinking on expanding use of Indiana coals is included in "Expanding the Utilization of Indiana Coals" ~ Brian H. Bowen, Forrest D. Holland, F.T. Sparrow, Ronald Rardin, Douglas J. Gotham, Zuwei Yu, Anthony F. Black (Center for Coal Technology Research, August 18, 2004; Revised August 27, 2008). 22 For an update on the current state of the intra‐state rail transportation analysis see, "Indiana Coal Movement: Indiana Rail Capacity/Potential," Thomas F. Brady, Purdue North Central, presented at the CCTR Advisory Panel Meeting, Bloomington, IN, June 4, 2009.


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Identification of price points that might induce a switch from current suppliers

Engagement with potential industrial and transportation partners/participants required to execute the strategy

Identification of policy and regulatory barriers and options

Examination of the costs and risks of investing in the infrastructure required

Investigation of alternative financing and project structure options

2.3.1.2 Coke Syngas as a valuable byproduct and use of Indiana Coals to Produce Coke23

A related set of investigations is exploring the technical and economic feasibility of using Indiana coals for coke production. Early technical results are promising, but far from conclusive.

Enhanced rail infrastructure between southwest Indiana and the steel mills on Lake Michigan (not including Chicago) also would be required to greatly enhance the economics of such a potential supply shift.

Studies are also exploring the feasibility of capturing the syngas generated from the coking process (now flared), for use as a feedstock for other purposes (SNG, liquid fuels, chemicals). Essentially, a coking oven is a form of gasifier that is already cost‐justified. The results appear promising for commercialization.

It is important to note that these investigations are not just about increasing demand for Indiana coals, but also for maintaining the competitiveness of Indiana’s steel industry.

Next steps include:

Finalize the technical analyses

Develop pre‐feasibility studies for apparently economically viable technical solutions

Engage steel companies in a detailed examination of economic viability

2.3.2 Implement advanced clean coal technologies for production of energy products

2.3.2.1 Coal Gasification – the current strategy

In the context of dealing with coal’s environmental challenges, considerable research has shown that under expected future energy and price scenarios, coal gasification technologies provide higher efficiency, significant enhancement in the control of regulated pollutants, a contribution to national energy security, and a net addition to energy price stability.24

23 For a recent update of CCTR supported projects see, "Coking/Coal Gasification Using Indiana Coal for the Environmentally Clean Production of Metallurgical Coke, Liquid Transportation Fuels, Fertilizer, and Electric Power," Robert Kramer, Energy Efficiency and Reliability Center, Purdue University Calumet, presented at the CCTR Advisory Panel Meeting, Vincennes University, Vincennes, IN, September 10, 2009. 24 These priorities underlie the extensive USDOE investments in gasification technologies. See USDOE program summaries and description at http://www.fossil.energy.gov/programs/powersystems/gasification/index.html. For a recent investigation of the liquid fuels advantages see, Liquid Transportation Fuels from Coal and Biomass: Technological Status, Costs, and Environmental Impacts, National Academies Press; 2009. Also see Coal Gasification and Liquid Fuel ‐ An Opportunity for Indiana, Science Applications International Corporation, July 2008.


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Research also has found that Indiana coals have good gasification characteristics.25 Indiana is also home to a small commercial scale gasification facility that uses the syngas to produce electricity (Wabash).

Indiana also hosts the only full scale IGCC plant currently under construction in the United States (Edwardsport). The State recently passed legislation to pave the way for a proposed coal to synthetic natural gas facility (Rockport) and is actively working with several other companies on proposed coal gasification projects. Although any new coal project receives intense scrutiny, the Indiana Department of Environmental Management has kept the technical and environmental issues open and above board with public hearings receiving strong local input from communities and citizens.

Coal gasification dramatically reduces the emissions traditionally associated with coal‐fired electric and heat production. The environmental benefits of gasification stem from the capability to achieve extremely low SOx, NOx and particulate emissions from burning coal‐derived gases.

Further, gasification byproducts have even better reuse characteristics than from pulverized coal (PC) plants. Not only is sulfur not a significant problem, it is a valuable byproduct of the process. This would only add to Indiana’s high utilization of coal byproducts. Indiana already exceeds the national average in the reuse of coal byproducts. Some 42% of the fly ash, bottom ash and flue gas desulfurization materials are reused, compared to a national reuse rate of 30%.26 It should be noted that past recommendations to co‐fire coal with biomass actually reduces the value of the fly ash and bottom ash for construction materials due to the unknown level of contamination. The result can actually be considered hazardous waste. The preferred method would be separate gasification units so the ash could be kept separate.

Nationwide, many proposed coal gasification projects are on hold, waiting and watching the outcomes in Indiana with Edwardsport and the proposed Rockport coal to SNG facility. Success in Indiana could trigger renewed project activity both in Indiana and nationwide. One of the attractions of gasification technology is the fact that such facilities can be constructed to capture CO2 more efficiently and less expensively than from PC plants.

2.3.2.2 Petcoke as a Gasification resource

Gasification is also an outstanding technology for conversion of petcoke (the remains from the petroleum refining process) into higher value products. Petcoke is a very attractive gasification input. The Indiana Wabash gasification (to electricity) facility has switched from using coal to using 100% petcoke with great success.

The completion of the huge BP refinery in Northwestern Indiana offers a significant supply of petcoke. This presents the potential for development of a gasification project in Northern Indiana. The east west rail system in Northern Indiana would provide excellent access to a

25 "Assessment of the Quality of Indiana Coals for Integrated Gasification of IGCC Performance," Maria Mastalerz et al., Indiana Geological Survey, presented at the CCTR Advisory Panel Meeting and Briefing, Hammond, IN, December 11‐12, 2008. 26 The CCTR presented a report by the University of Kentucky at their March 4, 2010 seminar which covered this issue in detail. (Dr. Jack Groppo, University of Kentucky, Center for Applied Energy Research, Lexington, KY.).


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range of potential sites across the State’s northern tier, perhaps taking advantage of the extensive water availability in the Northeast. Such a project offers a valuable alternative to dealing with this byproduct stream, the refinery will generate a stable feedstock that must be shipped somewhere.

The key next steps include:

Exploring the most valuable output products in the region (electricity, SNG, fertilizer, other chemicals?)

Identifying high potential sites for a gasification complex in the region

Engaging industrial partners for potential project analysis and planning

Developing a high level pre‐feasibility study for the selected priority sites and product mix

2.3.2.3 Explore other alternatives with significant potential

2.3.2.3.1 Underground Coal Gasification (UCG)

CCTR is exploring UCG as an option to exploit some of Indiana’s large un‐minable or uneconomic (by conventional means) coal resources. Surface mining is typically down to 200 feet, subsurface mines are normally from 300 to 500 feet deep. UCG allows use of coal at depths to 1500 feet and deeper. The process is conceptually simple (see Figure 2‐7). Rather than mine the coal and move it to a gasifier, steam and air/oxygen is injected into a coal seam from a surface well.

Through a series of reactions, coal is gasified into four product gases, including CH4, H2, CO and CO2 and released to the production well—the edges of the seam serve as the gasifier reactor. At this point the gas would be dealt with, as with any other gasification process. After cleaning, these gases can be used to generate electric power or synthesize chemicals (e.g. ammonia, methanol and liquid hydrocarbon fuels). Obviously there are many technical, environmental,

Figure 2‐7. The Underground Coal Gasification Process


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and safety concerns about this process. UCG operations are currently open or being developed in Russia, Australia, and Canada, among others. Australia is clearly the world leader in UCG, pilot projects and commercializations, though China probably leads in the absolute number of trials in recent years. Australia has three apparently successful commercial scale trials in progress.27 The Underground Coal Gasification Association (USGA) is a growing organization which holds an annual conference, offers training courses in UCG, and issues quarterly newsletters. The most current status of active and planned projects is detailed in their newsletter.28

CCTR recently commissioned a comprehensive study of the potential for UGC in Indiana.29 The primary purposes of this report were to:

Assess the current state of technology that might be applicable to Indiana circumstances

Determination of selection criteria for available coal resources

Determine potential locations within the state that could serve as candidate areas for possible UCG projects

The study found the UCG process to have several advantages over surface coal gasification:

Lower capital investment costs (due to the absence of a manufactured gasifier)

No handling of coal and solid wastes at the surface (ash remains in the underground cavity)

No human labor or capital for underground coal mining

Minimum surface disruption

No coal transportation costs

Direct use of water and feedstock “in place.”

The CCTR analysis also addressed the major technical, environmental and safety concerns. The key concerns and comments are summarized below:

Linking of injection and production wells within a coal seam

A reliable link between the multiple wells can be established by the appropriate application of specialized directional drilling technologies that are in commercial use today.

Minimization of variation in the composition of the produced gas

To control the composition of the produced gas, the process parameters (e.g. injection pressure and flow rate, oxygen concentration) can be adjusted according to real‐time surface measurements.

27 See UCG Partnership, “Key Facts on UCG,” http://www.ucgp.com/key‐facts/worldwide‐interest/ 28 (UCG Association, Elizabeth House, Duke Street, Woking, Surrey GU21 5AS and www.ucgassociation.org.) 29The Potential for Underground Coal Gasification in Indiana, Final Report to the Indiana Center for Coal Technology Research (CCTR), Evgeny Shafirovich, University of Texas at El Paso, Mechanical Engineering Department, Arvind Varma, School of Chemical Engineering, Purdue University, West Lafayette, IN, Maria Mastalerz, Agnieszka Drobniak, John Rupp, all at Indiana Geological Survey, Bloomington, IN, March 2, 2009.


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Prevention of any degradation of potable groundwater supplies.

Groundwater can be protected by appropriately siting a project, conducting the UCG process at pressures well below lithostatic pressure, and using the water that exists within the coal seam.

Prevention of uncontrolled underground coal fires

Well known accidents with uncontrolled underground coal fires, such as those near Centralia, PA, can cause public concerns about potential loss of control over the UCG process. The Centralia accident occurred in a mine close to the surface with many vents permitting a continuous supply of air to fuel an uncontrollable fire. With UCG the great depth combined with detailed geological knowledge about the thickness, depth, composition and petrophysical character of coal seams, and control over the gasification process by managing injection of oxygen allows for the operator to stop the underground thermal reaction by shutting off the flow of oxygen.

Concerns about subsidence

Since the process is limited to deep seams below 1000 feet there is little possibility of subsidence.

Concerns about building gas pipeline infrastructure

Gas transportation costs can be decreased by optimizing the selection of potential UCG sites and by constructing power‐generation or chemical plants near the UCG production facilities.

UCG provides other benefits when compared to mining operations. Problems with scarring of the surface landscape and disposal of ash and other mining residue are eliminated. Further, the safety of the miner is no longer a concern.

The CCTR report identified two areas that met the optimal values in the defined screening criteria: (1) Knox and Gibson Counties for the Springfield Coal and (2) Vanderburgh, Warrick, Gibson, and Posey counties for the Seelyville Coal. In these two areas, nine promising zones were identified for UCG in Indiana (four for the Springfield and five for the Seelyville Coal). Detailed lists of characteristics were prepared for each of these zones and preliminary recommendations offered on the future selection of a suitable location for potential UCG operations. Detailed maps are available in the cited report, and electronically from the Indiana Geological Survey.

Next Steps

Obviously this level of analysis is preliminary, and considerable further characterization would be required before a front‐end engineering and design study for the construction of a UCG plant could commence. The next steps will require:

Assembling key stakeholders in region to discuss the technical and political feasibility of UGC in the target zones


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Determining interest among potential industrial partners to commit time and resources to pursue a preliminary analysis

Seeking public and private funding for a detailed feasibility analysis.

Continuing to use the CCTR seminars for disseminating current progress on assessing UCG locations and technology

2.3.2.3.2 Extract Value from Coal Fines

Various efforts by DOE and coal states have been devoted to extracting value from coal fines and mine waste. Not only do these decades of accumulated mine residues contain significant potential energy value, there is interest in returning the land they occupy back to more productive uses, and reducing the potential environmental runoff problems that such residue generates.

A variety of approaches and technologies have been explored, and in some locations and under some circumstances, viable uses been developed. In Indiana, for example, Hoosier Energy has adopted a process to capture methane from ash. In Pennsylvania, the state has invested fairly extensively in blending coal mine methane and material extracted from mine waste piles for small scale power generation. To support private efforts such as this, CCTR has funded research designed to identify and map major concentrations of coal waste. These sites offer the highest potential for any application that a company (or research team) might seek to exploit.30

Next Steps

Next steps would require:

A systematic review of potential site‐specific applications and their economic viability at key locations across Indiana’s coal patch.

Should a national carbon control regime be adopted, a policy at the federal level that would allow CO2 offsets from capturing methane otherwise released into the atmosphere would provide an incentive to pursue a coal fine strategy.

2.3.2.3.3 Coal‐Bed Methane (CBM)31

Coal‐bed Methane is natural gas associated with and sourced from coal formations. Methane occurs as gas adsorbed onto coal surfaces, as free gas in fractures, cleats or other porosity, and as gas dissolved in ground water within coal beds. CBM can be produced from abandoned underground coal mines (often referred to a mine voids), as well as from un‐mined single or

30 See http://igs.indiana.edu/survey/projects/Coal_Fines/index.cfm, FINAL REPORT, Reconnaissance of Coal‐Slurry Deposits in Indiana, by Denver Harper, Chris Dintaman, Maria Mastalerz, and Sally Letsinger, Indiana Geological Survey, August 1, 2007.See also, "Reconnaissance of Coal‐Slurry Deposits in Indiana," Denver Harper, Indiana Geological Survey, Bloomington, IN, presented at the CCTR Advisory Panel Meeting, Indianapolis, IN, March 6, 2008, and "Potential for Fine Coal Recovery from Indiana's Coal Settling Ponds," Richard E. Mourdock, R.E. Mourdock & Associates, LLC, presented at the CCTR Advisory Panel Meeting, Hammond IN, December 6, 2006.

31 Unless otherwise cited, this section is heavily extracted from John A. Rupp and Maria Mastalerz, “Coal‐Bed Methane Development in Indiana: Current Status and Future Challenges,” Indiana Geological Survey, July 2008. See also "Coal Bed Methane (CBM) in Indiana," Tom Hite, Hite CBM Operating, presented at the CCTR Advisory Panel Meeting, Vincennes University, Vincennes IN, September 6, 2007.


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multiple seams. There is nationwide interest in the development of CBM as an alternative source of natural gas.

CBM basins across the United States are illustrated in Figure 2‐8.

Key advantages

Low risk reserves (currently being off‐gassed and flared)

Long term production potential

Low cost development of BTU’s (depending upon location and type, some areas would be quite expensive)

Possible Renewable Energy Source (depends upon legislation)

Improved mine safety, and capturing some value from mandated methane control for underground mining

Domestic US energy source

Indiana energy source

Potential option for CO2 sequestration for Enhanced Coal Bed Methane production as an option for dewatering (see below for more detailed discussion)

Source: "Coal Bed Methane (CBM) in Indiana," Tom Hite, Hite CBM Operating, presented at the CCTR Advisory

Panel Meeting, Vincennes University, Vincennes IN, September 6, 2007.

Figure 2‐8. CBM Basins Across the United States


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Key Challenges

Water disposal, weak knowledge of water chemistry and groundwater quality impacts

Infrastructure development, including roads, pipelines, underground storage, and electrical services

Lack of geological, chemical and physical information to guide discovery and production

Untested drilling and capture technologies for cost effective recovery

In 2008, CBM is estimated to have met some nine (9) percent of the dry natural gas demand in the United States, with annual production approaching 2 trillion cubic feet (TCF).

Coal‐bed methane is considered an “unconventional” gas resource. In conventional gas reservoirs, the gas resides in the small pores within the rock. When the pressure is decreased by a well tapping the reservoir, the gas flows out of the pore spaces and into the wellbore. In an unconventional reservoir, however, the gas is attracted to or “adsorbed” onto the organic molecules that make up the coal. The gas is produced by drilling into the coal seam and pumping off the water. Once the water pressure is reduced, the gas molecules detach from the coal and flow to the surface through the wellbore. CBM production (except from mine voids) requires many wells due to the required dewatering of the coal reservoir to induce gas flow. Dewatering also creates a waste water (salty) disposal challenge, often requiring deep well injection into saltwater‐filled reservoirs. Unlike much natural gas from conventional reservoirs, coal‐bed methane contains very little heavier hydrocarbons such as propane or butane, and no natural gas condensate.

Historically, the gas content of Illinois Basin coals was considered to be too low for economical extraction. Data acquired by the Indiana Geological Survey suggest that the gas content of coals, in particular areas within the basin, may be much higher than previously estimated. To date, however, only a very limited amount of this gas has been developed and produced in Indiana. Five counties in southwestern Indiana are currently producing, especially in southeastern Sullivan County; many others have the potential for CBM gas production, especially in light of the emergence of new technologies and practices.

Figure 2‐9 shows the distribution of mine void and coal‐bed methane wells in Indiana.


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Next Steps

Identify key stakeholders in SW Indiana, especially firms already exploiting coal‐bed methane

Discuss with stakeholders the key issues supporting exploitation

Assess priority opportunities to expand CBM

Determine barriers and policy options to expand exploitation.

2.3.2.3.4 Shale bed methane

Though not a “coal‐based” resource, one cannot examine coal‐bed methane in Indiana without also discussing shale‐bed methane (SBM). The geography strongly overlaps, and many related technologies and infrastructure investments would be required for exploitation. Improved technology now allows high potential economic returns for development of reserves in shale reservoirs at the gas prices prevalent in 2006 and 2007. EIA began collecting data on proved natural gas reserves from shale reservoirs only beginning in 2006 (see Figure 2‐10 for an overview of the national distribution of SBM).

Source: Downloaded from http://igs.indiana.edu/Geology/coalOilGas/CBM/index.cfm

Figure 2‐9. Mine Void and Coal‐Bed Methane Wells in Indiana


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For the two years available from 2006 to 2007, proven reserves of shale gas increased 50 percent to about nine percent of the U.S. total.32

More recent unofficial estimates suggest substantial increases in the reserves of SBM. The newfound resources in shale deposits are now estimated to contain 616 TCF of recoverable gas (nearly triple 2007 EIA estimates of proven reserves). 33 Even higher estimates of reserves are emerging as reports from extensive drilling are released.34

Like drilling for CBM, SBM requires extensive drilling using sophisticated horizontal techniques, followed by a procedure called hydraulic fracture stimulation, or hydrofracturing, which is designed to get the gas flowing efficiently into the well. To allow gas to escape, engineers will force millions of gallons of water down the well and into the shale formation at high pressure. If all goes well, the natural gas will rush out of the shale and into the pipe after the water is pumped back out.

Renewed interest in the New Albany well began in the mid‐1990s and related drilling has accounted for nearly 500 wells since that time. Initially focused in Harrison County, where New Albany gas production was discovered in the late 1800s, successful exploration has more

32 Energy Information Administration, U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2007 Annual Report, p. 38. 33 David Rotman, MIT Technology Review, November/December 2009, “Natural Gas Changes the Energy Map,” data from John Curtis, professor of geology and geological engineering at the Colorado School of Mines and director of the Potential Gas Agency. 34For example see, IHS Cambridge Energy Research Associates, Fueling North America’s Energy Future: The Unconventional Natural Gas Revolution and the Carbon Agenda, IHSCERA.com, 2010.

Figure 2‐10 Shale Gas


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recently expanded to several other counties in southwest Indiana. Although wells with initial production test rates (IPs) typically range from 20‐400 MCFPD (thousand cubic feet gas per day), some wells in northern Daviess and in southern Sullivan Counties are rumored to have tested more than one MMCF (1 million cubic feet) of gas per day. Many of the New Albany wells are being drilled with one or more horizontal boreholes that extend outward from the surface drill‐site over a distance of one‐half mile to nearly a mile. In Harrison County, the New Albany occurs at depths ranging from 500‐1200 ft.; in some of the newly‐drilled areas the New Albany is encountered at greater depths, around 2,000 ft. ‐‐ Daviess County, for example.

Next Steps

Identify key stakeholders in SW Indiana, especially firms already exploiting SBM

Discuss with stakeholders the key issues supporting exploitation

Assess priority opportunities to expand SBM

Determine barriers and policy options to expand exploitation

2.3.3 Develop biomass and renewable microgrid technologies

2.3.3.1 A Perspective on incorporating biomass and renewable microgrid technologies into Indiana energy strategy

As stated earlier, Indiana, due to its climate and present power infrastructure, faces a unique set of challenges in continuing to provide economically attractive power under pending legislative initiatives such as renewable energy mandates, cap and trade, and CO2 sequestration. The State, with its proximity to the great lakes, has significant cloud cover during the colder months of the year, so the payback period for solar harvesting installations is lengthier than that of sunnier locals. The hilly terrain in the southern portion of the State greatly reduces low altitude wind speeds, which geographically restricts Indiana’s ability to harvest wind resources. The intermittent nature of both solar and wind based approaches to power generation can be offset by a variety of grid based storage elements such as batteries, compressed air, and pumped hydro; but these add further costs to generation approaches that, for Indiana, already have unacceptably long or negative return on investments.

The challenge of keeping Indiana’s energy costs competitive is further complicated by a power grid that is potentially vulnerable to both accidental and intentional disruption. The weak link is the infrastructure associated with transmitting and distributing power over large distances, which includes highly specialized components that commonly have lead‐times of years to replace. The threat to Indiana’s economy is multifaceted as military, manufacturing and agricultural sectors rely almost exclusively on the State grid for primary electrical power. In the past, Indiana’s small to medium scale coal plants have provided local power generation capabilities, thus enhancing the overall reliability of Indiana’s power grid. With new carbon related legislation, it is likely these smaller coal plants would cease to be economically viable. Closing them down will simultaneously reduce Indiana’s base‐load power generation capabilities and increased dependence on Indiana’s grid.

In addition Indiana is dealing with rising waste‐processing costs and environmental concerns due to the continued increase in waste produced by confined feeding operations (animal


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manure) and from municipal garbage collection facilities. Many landfills and confined feeding operations are at or exceeding their capacity for waste processing, and on the verge of closure due to environmental concerns. It is common for large municipalities to transport their waste considerable distances, or dump it offshore, as local landfills have become cost prohibitive. These practices only delay or transfer the environmental impact of the pollution to another locale. The majority of confined feeding operations dispose of animal manure through land application, which is strictly regulated by the EPA and can only occur when the ground is dry and there are no planted crops. Even when these conditions are met a sudden rainfall can wash the manure into the local water system, which then pollutes everything downstream. Most waste streams have significant energy content which could be converted into electricity, and in the process, change the waste from environmentally hazardous to environmentally inert or even beneficial.

2.3.3.2 Solution

Microgrid systems that employ waste‐to‐power technologies (similar to the example illustrated in Figure 2‐11) for converting carbon rich waste streams into useful power offer a means for maintaining the health and promoting the security of Indiana’s energy economy.

Examples of carbon rich waste streams include animal manure, industrial waste, solid municipal waste, municipal sewage, food processing and agricultural waste (this list is by no means comprehensive). Moisture content and uniformity of the waste stream dictate the type of conversion technique required to extract maximum power. Multi‐stage digesters are ideal for

Figure 2‐11. An Example of the SAIC Microgrid System in Mobile Configuration. The major components of the system include the pyrolysis unit (5), batteries (8), a methane‐gas compatible generator (6), and SAIC’s Microgrid Master Controller (11)


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high moisture content waste streams with uniform content. Pyrolysis based thermoconversion is ideal for low moisture and diverse or uniform content waste streams.

By combining the two, and in some cases incorporating a preliminary moisture extraction step, virtually any waste stream can be used as a fuel source for electrical power generation. The benefits of microgrid enabled digester and pyrolysis waste‐to‐power systems include:

Fixed or mobile applications

Distributed generation assets providing emergency and economically essential facilities with autonomy from the grid and grid‐based disruption.

Conversion of environmentally detrimental wastes into inert or beneficial byproducts.

Creation of new technology‐based jobs.

Reliable base‐load power generation that is commercially viable and environmentally benign without legislated incentives.

A mechanism for producing carbon credits to allow Indiana’s small scale coal plants to remain online, and to offset potential renewable mandates.

Networked AC‐DC converters, voltage step‐up and step‐down converters, and switching devices will act as junctions for bidirectional routing of power from distributed generation and storage assets to end users and enable emergency island operation of critical loads.

Control and monitoring hardware, firmware, and software are integrated to provide efficient, reliable, well regulated and secure power to the end user.

Power storage assets are critical to a microgrid’s enhanced efficiency, as they temporarily store excess power from both alternative and conventional generation assets and release the power in momentary lulls or provide coverage power while additional generation assets are brought online.

The definition of reliable is expanded to include a user knowing exactly what circumstances dictate their being without power or receiving the benefit of emergency power and for how long.

The power provided by the microgrid will be well regulated, which means consistent voltage and frequency behavior without noise and spikes.

Security systems, both cyber‐based and hard‐ware based, protect the microgrid from attacks and interference.

Scalable and flexible architecture and infrastructure, including the potential for mobile assets, maximize the networks ability to adapt to changing power requirements.

2.3.3.3 Indiana funded SAIC Microgrid Project details

In an effort to generate innovative energy solutions, the Indiana Office of Energy Development issued RFP 09‐SEP04‐1. SAIC, in response, submitted a proposal on August 28, 2009 for a new approach to generating and distributing power, based on local biomass and renewable sources of energy, called a distributed power microgrid. The State of Indiana, in September 2009, recommended to DOE the award of an economic development grant of $1.5M to SAIC as lead


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integrator. All DOE and state reviews have been completed and the team is currently awaiting a formal grant contract signing which will be followed by immediate initiation of the project. The project is to be completed by the end of the 2010 calendar year. The microgrid approach was chosen for approval and funding by Indiana since it satisfied major strategy and RFP goals of creating new jobs in Indiana, based on “green” energy. The SAIC proposed microgrid is based on distributed generation technology, and is designed to integrate locally available alternative and renewable sources of fuel, and generate electricity using the products of Indiana companies for commercial, homeland security, and military application. In developing this product, SAIC has leveraged previous work funded by the CCTR evaluating various energy technologies and applications.

The proposed microgrid is a fully integrated operational system, accepting inputs from alternative/renewable energy producing components, including solar and a biomass driven pyrolysis/generator set. Pyrolysis‐based thermal conversion systems can convert the diverse components found in municipal waste, for example, into electrical power, crude oil, and graphite.

The microgrid can be produced in a mobile configuration, and/or tailored to site‐specific requirements such as the availability of specific feed stocks and energy inputs. The microgrid will thus have the capability to serve multiple local, regional, national, and international markets to include: (a) a wide variety of commercial applications seeking a turn‐key solution to the alternative/renewable energy delivery of between one and five MW via a microgrid, (b) approximately 440 military installations in the continental US, (c) approximately 200 overseas installations and Forward Operating Bases, and (d) mobile military applications.

The microgrid product will be integrated and produced at an SAIC facility in Southwestern Indiana and installed for test at NSWC Crane. Proving the capabilities of the completed commercial product at NSWC Crane, which is the DoD Center for Power Systems and Electronics, will establish instant credibility in both the commercial and military market places and provide a common point in Indiana for military/commercial technology transfer. In addition, DoD and the Navy have made a conscious decision to become leaders in alternative energy and have set goals to meet the Energy Policy Act of 2005 and Executive Order 13423. As recently as April 2010, the DoD re‐emphasized their goal for purchasing or producing 25% of their electricity requirements from renewable resources by the year 202535

It is critical to note that the microgrid installed at NSWC Crane will be identical in function and technology to one which would be installed at any commercial site. After the initial Crane installation, SAIC plans continued tailoring the microgrid, to maximize commercial and military application.

The SAIC microgrid plan is included in this discussion since it would be an ideal adjunct to small and medium sized coal fired facilities and rural utilities, to assist in managing CO2 emission regulation, or meeting mandated renewable energy requirements.

35 DoD Facilities Energy, FY‐2009 Annual Energy Report: Overview and Status on NDAA 2010 Studies; FUPWG 14‐15 April 2010.


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In concert with MES, another Indiana company, SAIC is developing another “waste to power” system based on a second proven technology, anaerobic digestion. Multi‐stage digesters have the ability to convert high moisture content waste streams, such as animal manure from confined feeding operations or municipal sewage, into electrical power; organic fertilizer; organic animal feed; and nitrogen rich water.

Using one or both of the two waste‐to‐power technologies, an integrated system can process virtually any hydrocarbon‐rich waste stream in a manner that produces electricity, and, carbon credits. Since the byproducts from both of these techniques have commercial value, the waste streams with their associated environmental issues are eliminated as well. The carbon credits produced by microgrids could be used to offset carbon produced by Indiana’s coal plants and provide a cost effective means of keeping them online, in addition to producing significant distributed power, and meeting alternative energy mandates.

Pyrolysis

Pyrolysis is the thermoconversion of materials at high temperatures, and low pressure, in the absence of oxygen. For waste processing applications, it typically involves breaking long hydrocarbon chains into the constituent molecules. The pyrolysis process yields three byproducts: pyro‐gas, pyro‐oil, and char (Figure 2‐12). The exact chemical composition of these byproducts is dependent on the waste stream being used as a feedstock. In general, the pyro‐gas is primarily methane accompanied by smaller fractions of hydrogen and other light hydrocarbon based molecules. The pyro‐oil consists of heavier hydrocarbon molecules and the char is carbon plus trace amounts of whatever heavier elements were part of the original feedstock. The advantage of pyrolysis over gasification is the low pressure operation reduces fabrication costs, since it is not considered an ASME pressure vessel, and this also allows locating the facility in congested industrial and manufacturing locations which could not accommodate a gasification system due to safety concerns.

SAIC’s team member Organic Power Solutions has developed both mobile (250 lb/hr) and fixed‐installation (4,000 lb/hr) pyrolysis units. These systems operate at temperatures between 900°

Figure 2‐12. Schematic of Pyrolysis Process Showing the Three Byproducts: pyro‐gas, pyro‐oil, and char along with their potential uses. The Pyrogen system facilitates the thermoconversion of the wasteinto the constituent by products at temperature in excess of 900° F and pressures below 1 atmosphere.

Waste

Pyrogen System

Methane

Hydrogen

Crude Oil

JP8/JP5

Gas

Diesel

Solid Fuel

Fertilizer

Macadam

Pyro‐Gas

Pyro‐ Oil

Char


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and 1300° Fahrenheit and at slightly below atmospheric pressure. Continuous operation is enabled by means of an automated microbatch feeder mechanism. The pyro‐gas produced is fed into a generator and converted into electrical power. The pyro‐oil can be refined into fuel grade diesel and other high value petroleum products, or can be used as‐is in specialized engines. The char has value as fuel supplement for coal fired power plants, and can be used in water filtration applications, road building or for soil enrichment.

Multi‐Stage Digesters

Multi‐Stage Digesters use both naturally occurring and genetically enhanced bacteria to convert carbon‐rich waste with high moisture content into low‐sulfur biogas, fertilizer, and protein rich animal feed. The advantage of the multistage system over the single stage predecessors is that it more efficiently converts the waste into biogas, and the bacteria are selected to inhibit the production of gaseous sulfur compounds. These sulfur compounds, which are produced by single stage systems, are highly corrosive and drastically reduce the operating life of the generators used to convert the biogas into electricity. SAIC’s team member MES has developed a three stage system (Figure 2‐13), which consists of facultative, anaerobic, and aerobic stages.

The bacteria in the facultative stage make the waste acidic and traps all the free oxygen compounds, the anaerobic stage bacteria reduce the complex molecules into simpler forms with the end result being methane and hydrogen; the remaining material passes to the aerobic bacteria, which metabolize it and leave behind only nitrogen enriched water. The aerobic bacteria solid byproduct can be used as protein rich animal feed and the extracted liquid byproduct, nitrogen enriched water, as an organic liquid fertilizer.

SAIC’s team member MES has developed both mobile (250 lb/hr) and fixed installation (100 tons per day) multi‐stage digesters. These systems operate at temperatures between 85° and 100° Fahrenheit and at atmospheric pressure. The biogas produced is fed into a generator and converted into electrical power. The fertilizers and animal feed are commercially valuable

Figure 2‐13. Schematic of multistage digester process showing the outputs from each stage.

The byproducts consist of biogas that can be converted into electricity using a generator, organic solidfertilizer with an NPK content of 7:3:1, protein rich feed supplement, and organic liquid fertilizer.

Biogas

Protein Rich Feed

Supplement

Organic Solid

Fertilizer

Organic Liquid

Fertilizer

Waste

Aerobic

Facultative

Anaerobic


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byproducts, and the environmental impact of the precursor waste stream is entirely neutralized.

A preliminary business case analysis for a 2M pyrolysis‐based microgrid processing 4000 lb. of municipal waste per hour, with natural gas fuel supplement, a $0.07 per KWH revenue, is approximately five years. A 375KW multi‐stage digester system, with 50 tons of manure per day input, and $0.07 per KWH revenues, pays back in approximately 3 years.

Both pyrolysis and anaerobic digestion are popular because the use of a biomass waste contributes to the positive business case with the elimination or reduction in disposal costs. This can be a considerable benefit if it results in the elimination of environmental permits. It often allows the business to greatly increase capacity/output at the same location with minimal capital investment.

2.3.4 Develop commercial uses and technology solutions for C02

The current anti‐coal character of the national policy debate generally ignores the striking reality that coal will be a critical energy resource for decades to come, regardless of policy and technology scenario assumptions.36 Indiana policy makers clearly recognize this reality and have been pursuing a strategy to promote and adopt coal technologies that meet or exceed reasonable environmental standards. Recent environmental focus has been the potential controls of greenhouse gases, especially CO2. Indiana’s strategy to dealing with CO2 is analyzed below.

2.3.4.1 Monitor and support economically viable Pre and Post combustion CO2 capture technologies

As insurance, it is important for the State, in collaboration with its coal users, to be prepared to move quickly with the most economic solutions should policy force industry to capture and sequester CO2.

Pre and Post combustion CO2 capture technologies

A wide range of technologies are being explored to capture CO2 from various sources. What we know today is that current CO2 capture technologies are not cost‐effective for large power plants. The most recent economic studies sponsored by DOE indicate that carbon capture will add some 35% to the cost of electricity for new IGCC units and over 75% to the cost of electricity if retrofitted to a new pulverized coal (PC) unit. Costs are even higher for existing older coal units, ranging from 70%‐100% depending upon assumptions and type of plant.37 Indeed, CO2 capture and compression causes some 30% parasitic loss in net generating capacity (primarily for compression to a near liquid state for pipeline transport and injection). The overwhelming challenge is, of course, dealing with the existing fleet of power plants. The USDOE CCS research program has a strong focus on reducing these costs.

36 See U.S. Energy Information Administration, Annual Energy Outlook 2010 Reference Case, a presentation by Richard Newell, Administrator, December 14, 2009. 37 Data from http://fossil.energy.gov/sequestration/overview.html and http://www.netl.doe.gov/technologies/carbon_seq/FAQs/benefits.html. See also, “DOE/NETL’s Carbon Capture R&D Program for Existing Coal‐Fired Power Plants,” DOE/NETL‐ 2009/1356, February 2009.


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There are three technology routes to capturing CO2: pre‐combustion, post‐combustion and oxyfuel combustion. Pre‐combustion requires new gasification‐based power plants and does not help the existing fleet. It is of critical importance that the much greater efficiency of IGCC plants compared to PC plants represents a concomitant decrease in CO2 per MWH. This was one of the factors contributing to Indiana’s support for coal gasification technology. IGCC plants can also be designed so that most of the CO2 can be captured in relatively pure form at a single point in the process.

Current Federal research programs are focused primarily on post‐combustion and oxyfuel combustion technologies that can be retrofitted to today's coal plants.

CCTR is monitoring advances in all of these technologies and is partnering with state researchers and utilities on federally and privately funded projects to seek lower cost options for CO2 capture. At this point, major technology advances are required to reduce the costs of pre‐combustion CCS and to make any of the post‐combustion solutions economically viable. The main processes for CO2 capture are summarized in Figure 2‐14.

Source: Downloaded from http://www.purdue.edu/discoverypark/energy/pdfs/cctr/outreach/Basics4‐CO2Capture‐Mar08.pdf

Figure 2‐14. Main Processes for CO2 Capture


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2.3.4.3 Support characterization of CO2 sequestration potential in Indiana

The State is following a similar strategy regarding CO2 sequestration. CCTR is monitoring advances in all sequestration technologies and is partnering with and partially funding research on the Indiana’s geologic potential for CO2 sequestration. Further, as part of the agreement with the IURC, and funded in part by DOE, Duke Energy is drilling a test well.

The basic findings are that Southwest Indiana has geology with significant sequestration potential.38 However, validation of these findings will require concrete large volume tests. Even with substantial federal funding, it will be years before sequestration potential is validated, policies and regulations established, and investments executed to begin large scale operation.

2.3.4.4 Identify and support investigation of potential commercial uses of CO2

Obviously, large investments in CCS do not create the kind of direct economic value as like investments in productive capacity or efficiency. There are arguable environmental and long term economic benefits, but the negative short and medium term economic impacts are large and relatively visible. To the extent that productive investments can be made that also either reduce CO2 emissions or use CO2 in a commercially viable way, we can achieve both economic and environmental policy objectives. This is an important aspect of Indiana’s near‐term coal strategy.

CO2 pipeline for early capture for enhanced oil recovery (EOR)

The primary initiative is active exploration of and support for a proposed commercial pipeline to be built by Denbury Resources, Inc. from the Midwest to its CO2 infrastructure in Mississippi and Louisiana. Denbury is a large oil and gas operator, and owns the largest reserves of natural CO2 for tertiary oil recovery east of the Mississippi River. In order to meet expected growth in demand for tertiary recovery, Denbury is seeking to purchase industrial sources of CO2 to augment its current reserves.39

The current status is that a comprehensive feasibility study of the proposed pipeline has been completed looking at alternative routes, market conditions, estimated costs, financing options, and the regulatory, legal and permitting requirements.40 Two tentative base routes reaches from junctions with Denbury’s existing pipeline (one East and the other West of the Mississippi River) to a “Y” branching into Indiana and Illinois (see Figure 2‐15 for a conceptual national image.

38See "CO2 Sequestration and Indiana Site Selection," John A. Rupp, Indiana Geological Survey, Indiana University, presented at the CCTR Advisory Panel Meeting, Vincennes University, Vincennes IN, September 6, 2007; "Demonstrating Geological Carbon Sequestration in the Mt. Simon Sandstone of the Illinois Basin," Robert J. Finley, Illinois State Geological Survey, Champaign, IL, presented at the CCTR Advisory Panel Meeting, Indianapolis, IN, March 6, 2008; and "Assessing the Geological Sequestration Potential in the Illinois Basin: Successes and Challenges," John A. Rupp, Indiana Geological Survey, Bloomington, IN, presented at the CCTR Advisory Panel Meeting, Indianapolis, IN, March 6, 2008. 39 A good summary of the proposed project is provided in, "CO2 Pipelines: Infrastructure for CO2‐EOR & CCS," Sherry Tucker, Denbury Resources, presented at the CCTR Advisory Panel Meeting, Indianapolis, IN, March 5, 2009. 40 John Lewis and Lisa Bergeron, Economic Impacts of a Midwest CO2 Pipeline: Construction, Easement and Operational Impacts, October 30, 2009 (Regional Development Institute, Northern Illinois University), under agreement with Denbury

Resources.


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Preliminary cost estimates are $1.2 to $1.4 billion, depending upon the route selected. Construction, if started, is expected to take about four years. Denbury has purchase agreements with at least two proposed gasification projects (one in Indiana and one in Illinois) that have been selected to proceed in the term‐sheet negotiation phase of the U.S. Department of Energy Loan Guarantee Program.41

Figure 2‐16 displays the terminus routes in Illinois and Indiana used in the feasibility study).

41 Denbury Resources, Inc., News Release, “Denbury Undertakes Midwest CO2 Pipeline Feasibility Study,” July 13, 2009, www.denbury.com.

Source: "Reducing CO2 Emissions from Coal‐Fired Power Plants," John Wheeldon, EPRI, presented at the CCTR Advisory Panel Meeting, Vincennes University, Vincennes IN, September 10, 2009.

Figure 2‐15. Potential Denbury CO2 Pipeline Network


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The Denbury proposed pipeline is one part of more comprehensive discussions about the network of CO2 pipelines that will be required if legislation is passed.

42 The Denbury proposal, however, has strong potential for commercial viability even absent CO2 legislation.

Potential Coal‐Biomass Blending

Many analyses have addressed the potential for reducing the CO2 footprint of coal‐based energy systems afforded by combining coal and biomass, whether in combustion or gasification

42 "A Regional Concept for a CO2 Pipeline Network," Klaus Lambeck, Ohio Siting Authority, presented at the CCTR Advisory Panel Meeting, Bloomington IN, June 5, 2008.

Figure 2‐16 Denbury Proposed CO2 Pipeline: Illinois and Indiana Laterals


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solutions.43 This range of solutions is attractive for many reasons – not the least of which is that it is something that we can do in the near term without CCS. By creating an energy system – whether for production of electricity, heat, fuels or chemicals – that combines biomass and coal, it is possible to create net reduction of total CO2 emissions per unit of output compared to just using coal.

The challenge, of course, is in the details. One of the most significant problems is that blending coal and biomass, whether in a boiler or a gasifier, presents a wide range of technical challenges. Harvesting, processing, shipping, and storing biomass with very low energy density (compared to coal) has proven a major problem for large scale operations. Other key challenges have been feedstock consistency, emissions compliance concerns, combustion management, and detrimental impacts on commercial reuse of ash and slag.

Much work continues on blending solutions, but designs that manage coal and biomass as separate parallel processes appear to be the most viable, especially for gasification. For example, in a CCS mandated world with relatively high greenhouse gas emissions prices, coproduction of liquid fuels and electricity in a parallel gasification system becomes very attractive.44

Real, commercial‐scale projects have mostly focused upon simpler technologies, converting coal‐fired to biomass‐fired boilers, building new biomass combustion systems, and some co‐firing of very consistent biomass with coal (especially in Europe). For example, Springs Utilities in Colorado Springs recently announced that it was going to contract with a biomass management company to deliver woody biomass to its Martin Drake Power Plant with the goal of blending 15% biomass / 85% coal.45

With Indiana’s biomass potential, whether from waste streams or crop type production, a strategy to identify and maximize the potential of commercially viable projects using biomass energy production to offset the states CO2 footprint emerges as a key mitigation priority.

Potential Opportunity to sequester CO2 and generate Coal‐bed and Shale‐Bed Methane

A second area of some interest to Indiana is the potential to use CO2 and perhaps direct flue gas for enhanced coal‐bed and/or shale‐bed methane production. CCTR has supported geological survey analysis and the next step is to explore industry and federal interest in helping to support a more comprehensive feasibility analysis.

43 Examples addressing different technologies include: M. Sami, K. Annamalai, and M. Wooldridge., “Co‐firing of coal and biomass fuel blends,” Progress in Energy and Combustion Science 27 (2001) 171–214; H. B. Vuthaluru, “Thermal behavior of coal/biomass blends during co‐pyrolysis,” Fuel Processing Technology, Volume 85, Issues 2‐3, 15 February 2004, Pages 141‐155; and Larsen, et al, “Co‐production of decarbonized synfuels with electricity from coal + biomass with CO2 capture and storage: an Illinois case study,” 2010, 3, 28‐42. 44 Larson, ibid, and Robert H. Williams, “Coproduction of Liquid Fuels and Electricity from Coal + Biomass for an Energy‐Insecure and Carbon‐Constrained World,” Presented at Moving Ahead 2010, Ohio State University, 3 may 2010. 45 Lisa Gibson, “Colorado Springs plant will use coal‐biomass blend,” Biomass Magazine, Posted June 23, 2009, from the July 2009 issue.


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Enhanced Coal‐Bed Methane

Considerable attention is being given to CO2 injection as an alternative to dewatering in releasing methane from coal formations– so called enhanced coal bed methane (ECBM). CO2 displaces methane adsorbed onto coal’s organic molecules. This potentially lowers recovery cost, improves recovery of methane, and serves as a permanent CO2 sink for sequestration purposes.46 Coal beds are present globally, and are an option for sequestration on almost every continent.

Besides the fact that ECBM can serve a dual purpose ‐ recovering natural gas while sequestering a greenhouse gas ‐ there are other advantages to CO2 sequestration in coal beds. Methane recovery can generate a profit or can greatly reduce sequestration costs. Further, un‐mineable coal beds are often located near CO2 high emission locations, lowering transportation costs for early sequestration options. This is particularly true across Southwest Indiana.

Instead of injecting pure CO2, flue gas offers an attractive alternative. Flue gas is a mixture of CO2 and N2. It costs less to obtain and may enhance methane production better than pure CO2. The drawbacks are that less carbon dioxide will be sequestered and that an extra step of separating nitrogen from recovered methane will be required. Much research remains to be done on either option, but if viable, they offer very attractive alternatives to deep CO2 sequestration.

A third area of interest is microbial or biogenic coalbed methane. Biogenic methane is a term used to describe natural gas derived from the reduction of CO2 via biochemical processes. Although very site specific research needs to be conducted, work completed to date in many coal formations suggests that it is possible to accelerate these natural processes in ways that provide an opportunity to both generate commercially viable methane volumes and provide permanent CO2 storage in the process.

47 Some early investigations of the Illinois Coal Basin are promising.48

Several ECBM field test projects are underway in the United States, including The Allison Unit ECBM project in the San Juan Basin of New Mexico and the San Juan Tiffany Unit in Colorado. A full‐scale project is also underway at Fenn‐Big Valley, Canada. As far as we know, no test projects are underway in Indiana, although the Indiana Geological Survey has identified several promising areas.49

46 See the body of work associated with the Princeton CO2 Sequestration project, summarized at http://www.princeton.edu/~chm333/2002/fall/co_two/geo/coal_beds.htm and the sources cited therein. 47 See for example: David J. Beecy, Frank M. Ferrell, and James K. Carey, “Biogenic Methane: A long‐Term CO2 Recycle Concept,” U.S Department of Energy, Office of Environmental Systems. 48 M.E. Schlegel, B.L. Bates, and J.C. McIntosh, “Activity and Extent of Carbon Dioxide and Acetate Utilizing Methanogens in Deep Organic‐rich Aquifers Within the Illinois Basin,” American Geophysical Union, Fall Meeting, 2008; Strapoc, et al, “Microbial Coalbed Methane in the Illinois Basin: Substrate Competition among Genetic Pathways,” Indiana University, Department of Geological Sciences; and Strapoc, et al, “Methane‐Producing Microbial Community in a Coal Bed of the Illinois Basin,” Applied and Environmental Microbiology, April 2008, pp. 2424‐2432, Vol. 74, No. 8.. 49 See the list of reports and data sets available at http://igs.indiana.edu/geology/coalOilGas/CBM/index.cfm.


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Enhanced Shale‐Bed Methane

As with coal‐bed methane, considerable interest exists in injecting CO2 rather than water (enhanced shale‐bed methane or ESBM). CO2 binds more closely than does methane in the shale formation, displacing the methane. Research here is at a much earlier stage than for CO2 injection for ECBM, where several test projects are underway. Recently DOE announced funding for nine shale gas projects, none in Indiana.50 With the large potential in the New Albany Shale formation noted above, the potential economics for ESBM may be a significant commercial opportunity as well as a viable basis for CO2 sequestration.

Other Potential Commercial CO2 Applications

Many R&D and small scale prototyping and demonstration projects are underway looking at commercial CO2 applications. Most would represent relatively small demand for CO2 (relative to sequestration targets), but taken together could represent significant potential, and may be available well before sequestration on a large scale is possible. Some of the larger scale projects focus on accelerated algae growth for processing into liquid fuels and use of CO2 as a feedstock for chemical operations. DOE is not investing as heavily in use and reuse of CO2 as it is in CCS, but it is part of the department’s strategy. If successful, these could make a significant contribution to liquid fuel and chemical refinery feedstock diversification.51 The first round of ARPA‐e finalists and awards included a variety of interesting and potentially large commercial CO2 conversion projects.

52

2.4 Identify potential sites that meet primary selection criteria for select advanced coal technology projects

This report has noted some of the major options for implementing Indiana’s coal strategy. Each option generates specific characteristics for ideal site selection. Although many common elements emerge among the different options, ideal sites are far from identical. The following discussion summarizes some key location decision commonalities and differences for the various options. It is followed by a brief discussion of a small number of specific sites.

2.4.1 Key Site Criteria53

2.4.1.1 Proximity to Resource

Transportation costs are a significant share of delivered price of coal or petcoke, and are a far greater share of the potential delivered price of biomass in scenarios investigating various blending and co‐firing technologies. Proximity to supplies of feedstock is a key consideration for high volume operations. This is of particular importance to current power plant decisions and 50 Lab Manager Magazine®, Posted: 8/20/2009 51 The projects underway are too numerous to list. A discussion of DOE CO2 use and reuse priorities and funding can be found at http://www.netl.doe.gov/technologies/carbon_seq/core_rd/use‐reuse.html. 52 See http://arpa‐e.energy.gov/ for discussion. 53 The site selection discussion pulls from many sources cited throughout this report. Perhaps the most comprehensive source is Paul V. Preckel, Zuwei Yu, John A. Rupp, and Fritz H. Hieb, with others, Synfuel Park / Polygeneration Plant: Feasibility Study for Indiana, Prepared for the Center for Coal Technology Research (CCTR), State of Indiana, September 30, 2007, Revised June 26, 2008.


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for the location of coal gasification facilities. All recent major coal investments have been in the southwest Indiana coal region.

From another perspective, should petcoke from the expanded BP refinery prove potentially viable as a gasification resource, investigation of sites for any new facility would begin close to the refinery.

For UCG, and coal‐bed and shale‐methane co‐location with the resource base exists by definition.

2.4.1.2 Proximity to Customer

In some situations, the costs of delivery to the final consumer are very high, and must be counterbalanced against other elements. For example, a community or campus steam heat facility is not feasible from a long distance. Use or chemical conversion of syngas from a surface gasifier or UCG is most efficient if co‐located. The Crane‐proximate location discussed below is attractively close to a diesel fuel pipeline.

2.4.1.3 Proximity to Transportation Infrastructure

Transportation has three separate dimensions: 1) movement of large equipment and components to the construction site: 2) movement of raw materials to the facility; and 3) Movement of finished product to the customer. Southwestern Indiana has a good rail and road network and is accessible to the Ohio and Wabash Rivers, but each site has its own unique transportation characteristics. The existence of high quality transportation infrastructure may be the deciding factor in a final location decision.

For this industry cluster, transportation infrastructure must be viewed much broader than simply road, rail and water. It includes natural gas and liquid fuels pipelines and the electric grid. Coal to electricity requires access to the high‐tension distribution grid. Coal to SNG requires access to a natural gas pipeline. Coal to liquid fuels, depending upon scale, may be distributed by pipeline, truck or rail (maybe even water). If CO2 control legislation passes, an extensive new CO2 pipeline network will be required.

2.4.1.4 Water

For many coal technologies access to a high volume of water is critical. In the case of power plants and coal gasification facilities water is primarily for cooling and a significant percentage is consumed by evaporation. Technologies exist to significantly reduce water consumption, but at high cost. For larger operations, economies of scale might permit reduced water usage through increased recycling.

Current technologies for coal and shale bed methane extraction also require significant water management and present water disposal challenges.

Unfortunately, Indiana’s coal patch has limited groundwater availability (Figure 2‐17). The greatest groundwater availability is in the Northeast portion of the state. Selection of investment sites in Southwest Indiana will tend to require location near rivers or other bodies of water, especially for larger scale operations.


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Source: Indiana Department of Natural Resources, Division of Water, 2007).

Figure 2‐17. Indiana Underground Water Map


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2.4.1.5 Sequestration Potential

Sequestration potential is a relatively new, but increasingly important site selection criterion for any energy process that has significant CO2 output – especially coal. Though not required at this time, no prudent investor can ignore the potential extraordinary costs that CO2 control regulation/legislation could impose. Options for capture and sequestration are increasingly being incorporated into capacity planning analysis. Southwest Indiana appears to have significant sequestration potential, but substantial concrete testing will be required to validate the potential.

As stated above, access to a CO2 pipeline is of course an option to nearby sequestration potential. CCTR is working closely with a potential investor to bring a commercial CO2 pipeline to the southwestern corner of the state as a near term, commercially viable user for some of the State’s CO2 output.

2.4.1.6 Ease of Land Acquisition and Surrounding Community Acceptance

All of the geology, transportation and engineering criteria can line up for a stellar location, but if you cannot acquire and develop the site, it is not viable. A variety of criteria can be used to reduce, but not eliminate, these challenges. Some key selection criteria include:

Industry/Utility owned

Same or similar use.

Industrial brownfield or former mine site

Closed (closing) military facilities

Federal facilities (especially operational DoD)

State or community owned

States/communities that have welcomed/accommodated similar investments

2.4.2 Priority Sites

Using the general criteria discussed above and the various initiatives and priorities that are under active consideration by CCTR, we have identified a sample of sites and priority areas for coal‐related development. This list is not comprehensive, but serves to identify a short list for initial consideration for any interested commercial investors. For most of the identified coal‐related solutions, CCTR has funded the creation of a high level regional inventory for potential site investigation. The cited studies funded by CCTR provide high level area analysis for major technologies, and detailed analysis and maps for some. Each specific technical solution will have its own, much broader suite of location options. Each of these inventories is cited in this report.

We have selected a short list of eight sites for discussion below (illustrated on the map in Figure 2‐18). We list nine other potential sites that also may be of interest.


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Figure 2‐18. Sites Selected for Analysis


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We have organized the discussion around the following subset of selection criteria as relevant:

Resource availability

Transportation infrastructure/logistics

Transmission lines and power availability

Gas and oil pipelines

Water requirements and resources

Labor force/availability

Land, real estate requirements, waste disposal, and environmental issues

CO2 sequestration potential (including access to proposed CO2 pipelines)

The eight target sites are:

Northwest IN (east of Whiting Refinery)

Newport Chemical Depot ‐‐ Newport (closed under BRAC)

Near Fairbanks/Breed Site in Sullivan County (former power plant site west of Sullivan)

Underground coal gasification near Petersburg

NSA Crane proximate

Near Rockport Power Station ‐‐ Spencer County (Proposed Coal to SNG location)

Near Port of Indiana (or CountyMark Refinery) – Mount Vernon (on the Ohio River)

Indiana Arsenal – Jeffersonville (closed under BRAC, near Port of Indiana –Jeffersonville, on the Ohio River, across from Louisville, KY)

Other sites that deserve future consideration include:

Near the Francisco Mine in Gibson County;

Near the Minnehaha Mine in Sullivan County;

Near the Merom Power Station in Sullivan County;

At the NSA Crane Sullivan Site.

Near the Gibson Power Station in Gibson County;

Near the A.B. Brown Power Station in Posey County;

Near the F.B. Culley Power Station in Warrick County;

Near Tell City in Perry County;

Near Duke Energy’s Wabash Valley IGCC power plant west of Terre Haute.

2.4.2.1 Northwest IN (east of Whiting Refinery)

The Whiting BP refinery, once the expansion is complete, will be a major source of petcoke. Not only will this be the largest refinery in the Midwest, it is being designed to refine the heavy crude produced from Canadian tar sands, which will generate larger volumes of petcoke than other lighter crudes.

Resource availability BP will be examining the highest and best value for the large volume of petcoke generated by the expanded and modernized facility. There are alternative uses of petcoke, notably for asphalt.


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Transportation infrastructure/logistics The refinery sets on a major east/west railroad that will provide easily accessible bulk transport. It also sits near major interstate highway arteries and on Lake Michigan. The distances involved will depend upon how far east optimum sites are located.

Transmission lines and power availability Major power lines cross the region, and substantial electricity capacity is available that was sized for a much larger industrial base than exists today.

Gas and oil pipelines The refinery has major product lines and gas pipelines. The specific location on the east‐west corridor would determine access

Water requirements and resources Except for a lake Michigan‐proximate site, water access improves significantly as you move east from Northwest Indiana

Labor force/availability With an historic manufacturing history and high unemployment rates, the northern tier of the state has more than adequate capacity. Specialized training will, of course, be required.

Land, real estate requirements, waste disposal, and environmental issues Northwest Indiana is highly congested, and finding adequate space and compatible neighbors for a petcoke gasification facility may prove a challenge. Space availability improves further east (as does water access). Priority should be given to brownfield sites, for which permitting would be less complicated. Modern gasification facilities provide some environmental challenges. If there is no market for gasifier slag, it would have to be landfilled. Cooling towers are required. The region has only recently been released from non‐attainment status, so air pollution is of great concern.

Primary products Fertilizer, chemicals, and perhaps hydrogen rank high for the region. Electricity is probably not a priority, nor is SNG. Liquid fuels would depend upon the ability of BP to easily take the resulting products back into their refinery streams at limited cost.

CO2 sequestration potential (incl. access to proposed CO2 pipelines) This is an area of the state that has little sequestration potential and is not close to currently planned CO2 pipelines.

2.4.2.2 Newport Chemical Depot ‐‐ Newport (closed under BRAC)

This is a closed military site. Cleanup of the site in nearly finished and redevelopment efforts are getting underway. This site appears to be a very attractive location for virtually any surface large scale coal‐related energy project. Underground coal or shale resources are limited.

Resource availability Northern edge of Indiana’s coal patch – coal most likely shipped in by rail but truck is still viable.


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Transportation infrastructure/logistics Good rail or truck access. N/S CSX passes through the site

Transmission lines and power availability Onsite transmission and near the Cayuga power station.

Gas and oil pipelines Connected to the Panhandle east‐west gas pipeline via a 6” distribution pipe

Water requirements and resources On the Wabash River with substantial water availability.

Labor force/availability Near Terre Haute. Workforce has manufacturing history. Substantial number of dislocated workers. Specialized training will, of course, be required.

Land, real estate requirements, waste disposal, and environmental issues Lots of space onsite (7000 acres with easements in excess of another 1000 acres), looking for reuse candidates that will create jobs. No significant environmental concerns. Relatively isolated, rural location.

Primary products This is a good site for virtually any surface gasification product, depending upon market conditions. Its location and size would also permit biomass/coal facilities. Fertilizer or other chemicals may be a good option as well.

CO2 sequestration potential (including access to proposed CO2 pipelines) This is an area of the state that has limited direct sequestration potential, but is near the proposed east west CO2 pipeline. There is some sequestration in the potential for enhanced shale gas production, and injection in the deep saline aquifer. Newport is well north of the extreme northern reach of the proposed Denbury CO2 pipeline. It is much closer to the more speculative proposed East‐West CO2 pipeline.

2.4.2.3 Near Fairbanks/Breed Site in Sullivan County (former power plant site west of Sullivan)

The Fairbanks/Breed area is a few miles east of the Wabash River. It is the former location of the American Electric Power (AEP) Breed Power Station, which was demolished in 2007. The site consists of some 9,400 acres of unoccupied land. The company retains ownership, and has expressed no interest in selling, but also has adequate capacity to meet electricity demand without new construction on‐site. The Breed/Fairbanks site appears to be favorable for development of a wide range of alternatives. It has adequate land, water and infrastructure, either available or that could be developed at reasonable cost.

Resource availability No active mines in close proximity, but significant coal availability exists within 15‐40 miles by truck or rail


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Transportation infrastructure/logistics The rail lines that serviced the power plant at Breed are inactive, but could potentially be brought back into service at a reasonable cost. A very large scale operation may create rail congestion for coal deliveries.

Transmission lines and power availability A substation is maintained at the old Breed Power station, with transmission line connections. The substation is connected to the grid via 765 KV lines. Other lines are also available in the area.

Gas and oil pipelines The Midwestern Gas Transmission Corp natural gas pipeline is located 4‐5 miles to the east. A pipeline for refined products runs about two miles to the east. Depending upon product requirements, connecting pipelines of appropriate capacity may be needed to link to the major pipeline system.

Water requirements and resources The site is on the Wabash River with strong flow and good water availability.

Labor force/availability Rural area, reasonably close to Terre Haute, Sullivan and Vincennes. Workforce has coal, power and manufacturing history. Specialized training will, of course, be required.

Land, real estate requirements, waste disposal, and environmental issues Lots of space onsite (9400 acres), brownfield site; relatively isolated, rural location.

Primary products This is a good site for virtually any gasification product, depending upon market conditions. FT liquids, exported power, and SNG may be preferable. Because of the high potential for enhanced shale bed methane, this may also be a good site for shale exploitation.

CO2 sequestration potential (including access to proposed CO2 pipelines) There are several potential options for geological sequestration of CO2 from a facility at the Breed/Fairbanks site: enhanced coal bed methane production, enhanced oil recovery, enhanced shale gas production, and injection into deep saline water‐filled aquifers. There is also a plausible connection to the proposed Denbury pipeline (the plans in the recent feasibility study have a collector pipeline extending to the Duke Edwardsport facility.

2.4.2.4 Underground coal gasification near Petersburg

The CCTR supported analysis of the potential for UCG in Indiana offered up a variety of potential sites. The Petersburg area was selected here as a result of active investigation by commercial interests for a possible investment.

Resource availability Substantial coal resources exist across the entire area, both mineable and un‐mineable. The target here is un‐mineable coal at a depth and with a structure adequate to meet UCG requirements.


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Transportation infrastructure/logistics Good rail or truck access for construction phase. No need to transport coal. Finished product, if liquid fuels, fertilizer or chemicals, rail is likely the preferred option. Rail to the Ohio River for barge transport is also feasible.

Transmission lines and power availability Location is unspecified enough that precision is not possible. Sites further east will be closer to a 765KV line, further north will be closer to a 345KV line. If electricity is a target primary or secondary product, then careful selection of the site will be critical. Congestion may be an issue if power export is expected to be substantial.

Gas and oil pipelines Two gas pipelines run near the area, one owned by the Texas Gas Trans Corporation and another owned by the Texas Eastern Trans Corporation. A crude oil pipeline and a refined petroleum product pipeline also run through the area. As with the transmission lines the location is too fluid to be precise and choice of desired final product mix would be important in the final location decision.

Water requirements and resources Water use is likely to be a limiting factor for size of operation and for any water intensive product applications. Both wells and surface water sources have limited flow. This would work against SNG production.

Labor force/availability Limited local labor force. An operation would have to recruit from the surrounding communities of Princeton, Oakland, and Evansville.

Land, real estate requirements, waste disposal, and environmental issues Coal rights acquisition will be an issue, as will permitting. Space for surface plant smaller than other options, since no coal handling or storage is required. Significant safety/environmental concerns will have to overcome. Planners would have to concentrate on relatively isolated, rural locations. Depth of seams would be an issue regarding both subsidence and prevention of uncontrollable fires.

Primary products Good location for limited scale FT diesel, gasoline, military fuel(s), naphtha, with power as a byproduct. SNG and/or hydrogen would be limited by water availability.

CO2 sequestration potential (incl. access to proposed CO2 pipelines) Potential options for geological sequestration of CO2 from a UCG facility in this region include enhanced coal bed methane production, enhanced oil recovery, enhanced shale gas production and injection into deep saline water‐filled aquifers, and connection to the proposed Denbury CO2 pipeline.

2.4.2.5 NSA Crane proximate

An NSA Crane‐proximate site has several advantages. Land is relatively plentiful. Such a facility could support Crane Energy independence. Coal resources are reasonably close, and the infrastructure is generally good.


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Resource availability NSA Crane is about 12‐15 miles from two major mines in Daviess County. Mines in other adjacent counties to the west could also supply coal. Coal most likely shipped in by rail but truck is viable.

Transportation infrastructure/logistics Good rail. Truck access ok, but limited until completion of I‐69 between I‐64 and Crane. N/S CSX passes through the site. Some upgrading of the rail system may be needed to accommodate the flow of coal to the site.

Transmission lines and power availability Three 345 kilovolt transmission lines run close to Crane, and several lower kilovolt lines cross the base. Crane is connected to both the Duke Energy Indiana and Hoosier Energy transmission systems, with a peak demand around 26MW. The transmission system would allow some power to be exported without upgrades, but plans for substantial export would require a detailed connectivity and stability study.

Gas and oil pipelines A small gas pipeline connects Crane to the Texas Gas Trans Corporation pipeline. A refined petroleum pipeline runs about three miles from the base’s southwest corner. Potentially this might be usable for shipment of FT diesel or other liquids.

Water requirements and resources Water is limited at NSA Crane proper. However, the East Fork and West Fork of the White River offer substantial volumes. The East Fork alone is capable of providing enough water for a small to moderate sized coal‐based energy project.

Labor force/availability A project would be able to draw its workforce from Crane and the surrounding communities (a highly skilled pool). Further, much like Crane and its associated contractors, the project could draw upon workers in Bloomington and Bedford.

Land, real estate requirements, waste disposal, and environmental issues Land does not appear to be a constraint, especially off‐base. Environmental issues appear manageable.

Primary products This is a good site for virtually any gasification product, depending upon market conditions. However, the DoD mandate on bases become more energy self reliant (especially to develop the ability to become energy independent in an emergency) makes NSA Crane a potential customer for both electricity and SNG, if prices are reasonably competitive. In CCTR studies, specific attention has been paid to production of liquid fuels with a minimum electricity capacity, to take Crane off the grid in an emergency.

CO2 sequestration potential (including access to proposed CO2 pipelines) NSA Crane lies in an area abundant in New Albany shale, yielding good potential for ESG recovery and related CO2 sequestration. Small oil fields in the area could also be used for EOR. There is potential for ECBM to the west. Sequestration in aquifers appears to be a


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substantial possibility. Assuming the current I‐69 right of way could be utilized, the terminus of the in‐state portion of the Denbury CO2 pipeline could be extended to Crane along with the planned highway construction.

2.4.2.6 Near Rockport Power Station ‐‐ Spencer County (Proposed Coal to SNG location)

The Rockport site has some specific advantages, most notably access to potential barge transport on the Ohio River, no limits on water availability, and proximity to a major power station. Further, the site is already targeted for a proposed coal gasification to SNG facility and is under exploration for a coal to liquids facility.

Resource availability Coal can be supplied in a very large quantity by barge. Rail may require upgrade for large unit trains. Supply sources may be somewhat more distant by truck.

Transportation infrastructure/logistics Good barge access from Ohio River, also good rail and truck access.

Transmission lines and power availability Near Rockport Power Station, one of the larger stations in the state. Access to power during construction would not be a problem. If significant power is to be produced and exported, a more comprehensive capacity and stability analysis would be required.

Gas and oil pipelines Approximately six miles from MGT gas pipeline. Proposed site for the Rockport coal gasification to SNG facility.

Water requirements and resources On the Ohio River with lots of water availability.

Labor force/availability This is a rural area and workforce may need to draw from a larger surrounding region, including across the river to Owensboro KY. Workforce has a good manufacturing, farming history. Currently there is substantial unemployment. Specialized training will, of course, be required.

Land, real estate requirements, waste disposal, and environmental issues Considerable available land can be acquired. No significant environmental concerns exist. The relatively rural location provides options to buffer from encroachment.

Primary products This is a good site for virtually any gasification product, depending upon market conditions. SNG and liquid fuels are currently under active consideration.

CO2 sequestration potential (including access to proposed CO2 pipelines) The primary nearby sources of sequestration potential includes injection for enhanced shale gas production, and into the deep saline aquifer. Rockport is explicitly included as a connection point in the Denbury CO2 pipeline feasibility study.


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2.4.2.7 Near Port of Indiana (or CountryMark Refinery) – Mount Vernon (on the Ohio River)

The Mount Vernon area has several advantages as a location for an advanced coal‐based project. In particular, the Ohio River provides a ready source of water, as well as the prospect of water transportation for large equipment during the construction phase, and both coal and plant outputs during the operation phase. A coal handling facility exists at the Port of Indiana as well as a nearby refinery. Infrastructure is generally good.

Resource availability No active coal mines are located close by, but there are prospects both for shipping coal to the site by rail or barge or for opening a mine in the area. Rail may require upgrade for large unit trains. Coal can be supplied in very large quantity by barge.

Transportation infrastructure/logistics Good barge access from Ohio River, also good rail and truck access. High rail delivered coal volumes may cause rail congestion. A coal handling facility already exists (barge loading but not off‐loading). Truck access across the area is already facing seasonal congestion resulting from grain shipments to the port and may see significant growth in year‐round congestions once the ethanol plant under construction is completed.

Transmission lines and power availability Some upgrading of the connection to the electricity grid may be needed. Due to limitations on the grid connections, an output mix involving less power export may be advantageous. No large capacity power transmission lines connect to the Mt. Vernon area. The nearest significant power substation is the Vectren A.B. Brown Station, 10 miles to the east. To export large amounts of power to the grid, a new substation and HV transmission lines that can be connected to either the Gibson power station (about 30 miles) or the Brown power station (about 10 miles) would be required.

Gas and oil pipelines CountryMark owns oil and diesel pipelines in the Mount Vernon area that could potentially be used to export product. Small gas pipelines also exist in the area. Major gas pipelines run nearby, potentially enabling the production and sale of SNG.


Labor force/availability Any project in the Mount Vernon area could draw from the city itself, as well as from Evansville and other neighboring communities.

Land, real estate requirements, waste disposal, and environmental issues Considerable available farm land could be acquired to the east. Mount Vernon, west of the Port of Indiana and surrounding the CountryMark Refinery is development constrained.


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Primary products This is a good site for virtually any larger scale gasification product, depending upon market conditions and, with the ample water supply, inclusion of large scale FT‐liquids, SNG or hydrogen in the output mix may be desirable.

CO2 sequestration potential (incl. access to proposed CO2 pipelines) Four potential options for geological sequestration of CO2 exist in the Mt. Vernon area: enhanced coal bed methane production, enhanced oil recovery, enhanced shale gas production, and injection into deep saline water‐filled aquifers. Cost of a connection to the proposed Denbury pipeline has not been estimated. The recent feasibility study has the main lateral running south of the Ohio River in Kentucky crossing on the west side of Evansville, following I‐164 / I‐69 north.

2.4.2.8 Indiana Arsenal – Jeffersonville (closed under BRAC, near Port of Indiana –Jeffersonville, on the Ohio River, across from Louisville, KY)

The Closed Indiana Arsenal is not in Indiana’s coal patch, but does offer some attractive characteristics. It has large land area, a strong need for redevelopment, and good rail access on‐site connected to the CSX network. The Ohio River provides a ready source of water, as well as the prospect of water transportation for large equipment during the construction phase and both coal input and plant output during the operation phase via the Port of Indiana‐Jeffersonville.

Resource availability No active coal mines are located close by, but there are prospects both for shipping coal to the site by rail or possibly even barge. Rail may require upgrade for large unit trains.

Transportation infrastructure/logistics Good barge access from Ohio River, also good rail and truck access. No coal handling facilities exist and would have to be built. High rail delivered coal volumes may cause rail congestion.

Transmission lines and power availability A substation is nearby, but upgrading of the connection to the electricity grid may be needed if significant export is desired.

Gas and oil pipelines A major TGTC gas pipeline is about 6 miles to the east, as well as local distribution.


Labor force/availability Any project in the Jeffersonville area could draw from the entire greater Louisville metro area.

Land, real estate requirements, waste disposal, and environmental issues The closed base has extensive land development potential. It is a brownfield site and not likely to face any significant environmental challenges


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Primary products This is a good site for virtually any larger scale gasification product, depending upon market conditions, and with the ample water supply, inclusion of large scale FT‐liquids, SNG or hydrogen in the output mix may be desirable.

CO2 sequestration potential (incl. access to proposed CO2 pipelines) The options for local CO2 sequestration appear to be limited to enhanced shale gas production, and injection into deep saline water‐filled aquifers. This is too far east for the proposed Denbury pipeline under current plans. The recent feasibility study has the main lateral stopping at Rockport. The feasibility and cost of extending the line to the Louisville/Jeffersonville area is unknown.

2.5 Conclusions

Indiana has taken aggressive steps to maintain its competitive energy costs, and a clearer picture is evolving of both the threats and opportunities that the current environment affords. No “silver bullet” solution exists today to meet the energy challenges facing the state. However, a set of tailored solutions, driven by location, technology, economics and policy/legislation could result in minimizing the cost growth of energy in Indiana, maintaining coal as a viable energy and economic engine, while managing to national environmental standards:

Indiana has limited alternative energy or fossil fuel resources other than coal; the State’s alternative and nontraditional “natural gas” resources will be expensive (compared to coal) and slow to develop.

Significant cost increases in Indiana Energy may occur as a result of legislation and policy.

On‐going advanced coal strategies hold promise for significant medium‐term reward, e.g. coal gasification and the CO2 pipeline.

Biomass, renewable energy, and power management technologies are being matured by Indiana companies, and can be used in conjunction with small and medium sized coal plants and certain utilities, to help offset future mandates and regulations, and drive new jobs in manufacturing, agriculture and defense.

Indiana offers a unique set of sites with the necessary infrastructure to support major advanced coal facilities

2.6 Strategy Recommendations

It is recommended that biomass and alternative energy fueled distributed power systems be integrated into the Indiana Energy Strategy to minimize the loss of small and medium coal fired facilities, and impacts on rural utilities and communities, due to CO2 controls or alternative energy mandates. Specifically, the Indiana portfolio of coal fired facilities should be analyzed and priority candidates identified to be supplemented with a biomass‐powered microgrid. It is also recommended that a farm or municipal site be chosen with sufficient available waste to demonstrate the effectiveness of waste driven power generation, and to achieve the


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benefits described in this report of baseline power, environmental waste elimination, growth of Indiana agriculture, and the creation of new, green energy jobs.

Indiana’s clean coal strategy has resulted in the development of several initiatives that will positively impact Indiana’s energy future. As described in this report, these initiatives are in various stages of development, from early concept to near completion. It is recommended that a systematic process be applied to the defined initiatives to set priorities and develop the necessary industry and community partners, plans, and resources necessary to push through to completion.

It is also recommended, given the availability of sites in Indiana with the appropriate infrastructure for major energy projects, that a strategy be focused on publicizing and leveraging these sites, again with appropriate industry and community partnerships, to exploit the potential of each site for a major energy project.


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