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UNDERGROUND COAL GASIFICATION

HISTORY,ENVIRONMENTAL ISSUES,AND THE PROPOSED PROJECT AT BELUGA,ALASKA

Kendra L. Zamzow, Ph.D.

Center for Science in Public Participation

March 2010

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Table of Contents

CIRI's proposed project ................................................................................................................................. 4

Natural Gas and Coal Gas .............................................................................................................................. 5

How UCG works ............................................................................................................................................ 7

Getting coal to burn .................................................................................................................................. 7

Operational parameters............................................................................................................................ 9

Deep and Thick .................................................................................................................................... 10

Temperature ....................................................................................................................................... 11

Water .................................................................................................................................................. 11

Faults and fractures ............................................................................................................................ 11

Historical Perspective.................................................................................................................................. 12

Regional experiences .............................................................................................................................. 12

Former Soviet Union ........................................................................................................................... 12United States ....................................................................................................................................... 12

Europe ................................................................................................................................................. 13

Other countries ................................................................................................................................... 13

Key test sites ........................................................................................................................................... 14

Hoe Creek ............................................................................................................................................ 14

Centralia, WA ...................................................................................................................................... 15

Rocky Mountain I ................................................................................................................................ 15

El Tremedal ......................................................................................................................................... 16

Chinchilla ............................................................................................................................................. 16

Environmental Impacts ............................................................................................................................... 17Structural Integrity of Host Rock ............................................................................................................. 19

Formation of contaminants .................................................................................................................... 19

Migration of contaminants ..................................................................................................................... 20

CO2 .............................................................................................................................................................. 21

Life cycle greenhouse gas emissions ....................................................................................................... 21

Carbon capture ....................................................................................................................................... 24

Carbon sequestration ............................................................................................................................. 25

Summary ..................................................................................................................................................... 27

Bibliography ................................................................................................................................................ 29

Appendix A: UCG reactions and Syngas Reactions ..................................................................................... 31Appendix B: Natural Gas Processing ........................................................................................................... 32

Appendix C: UCG sites worldwide ............................................................................................................... 33

Appendix D: Water Analysis at Contaminated UCG Sites .......................................................................... 39

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Figures

Figure 1. Location of proposed UCG project, Beluga, AK.4

Figure 2. CRIP process of gasification.8

Figure 3. Depth and thickness of coal seams by global region..9

Figure 4. Faulted and dipping seams11Figure 5. UCG at Chinchilla, Australia...15

Figure 6. Comparison of life cycle greenhouse gas emissions by fuel type.22

Tables

Table 1. Composition of Natural Gas, Syngas, and UCG gas...5

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In November 2009, Cook Inlet Region, Inc. (CIRI), an Alaskan Native regional

corporation, filed for exploration permits to examine the potential to fuel a 100 MW power plant

using "underground coal gasification" (UCG) technology. This paper explores the history of

UCG technology globally, including environmental impacts during historical trials, how those

impacts might be mitigated, and risk of environmental impacts at the Beluga, Alaska project.

CIRI's proposed project

Information on CIRI's proposed project is limited since the project is only at the

conception and permitting states. The property is located in a remote location on the west side of

Cook Inlet, just north of the Beluga River, on CIRI lands (Figure 1). The site is 5-10 miles from

the current 385 MW Chugach Electric Plant, located at Beluga, which utilizes natural gas from

nearby offshore platforms to provide electricity. The CIRI project proposes a 100 MW

combined cycle power plant run on the syngas that would be the product of 'gasifying' coal in the

ground.1 Although no maps have been produced to indicate where the power plant would be

located, it would almost certainly be adjacent to the targeted coal fields.

1CIRI presentation to the Alaska State House Resources, Senate Resources, and Senate Energy committees,

October 9, 2009

Figure 1. Location of proposed UCG project, Beluga, AK.

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Natural Gas and Coal Gas

Natural gas, as extracted from production wells, is mostly methane (CH4) with a high

heating value (>1000 BTU/ft3). The composition depends on how the natural gas was formed. Ifit is biogenic (produced by living organisms) it is nearly pure methane. Thermogenic natural gas

(produced by the breakdown of organic matter) is methane with contaminants (small

hydrocarbons, water, sulfur, and CO2) and must be processed before it can be used (Table 1).2

The hydrocarbons can be separated and sold while the other constituents are corrosive.3,4Cook

Inlet gas is primarily biogenic, and North Slope natural gas is thermogenic.5 At the Beluga

Power Plant, seven gas turbines and one steam turbine together produce 385 MW of electricity,

the primary source of electricity to Anchorage. In the combustion process, methane is burned

and water, CO2, and oxidized sulfur and nitrogen products are the primary waste products.

"Syngas", or synthetic gas, is the term that refers to a carbon monoxide-hydrogen gas

mixture. It can be made from coal, natural gas, or biomass. "UCG gas" is used in this paper to

refer to gas produced from burning coal underground, although some literature also refers to this

as "syngas". Both are primarily carbon monoxide (CO) and hydrogen gas (H2), but the processes

of making them are different (Appendix A). To make coal-derived syngas above ground, coal is

put under heat (>700 oC) and pressure to make carbon monoxide and hydrogen gas. Hydrogen or

the building blocks for chemical products like methanol are the products. To make electricity,

the CO and H2are reacted with steam to form CO2and more hydrogen. Hydrogen is combusted

to produce power. Water, CO2, and oxidized sulfur and nitrogen products are the waste products.

Syngas plants are relatively common, with over 150 in operation.

6

The UCG process burns coal under heat (10001600 oC) and pressure with steam while

the coal is still underground. UCG gas as it comes out of the product well is carbon dioxide

(CO2) and hydrogen gas (H2), with more methane and less CO than syngas, and lower in sulfur,

tars, mercury, and other metals which are left underground in the residual ash after the burn.

The actual proportions of each component will vary depending on how the burn is operated:

Thickness of coal seam. Thin coal seams (< 2 m) produce a gas that is mostly CO2, with

little H2, CO, and methane. This is a low quality gas, and may not be economic. Thicker

2http://www.naturalgas.org/naturalgas/processing_ng.asp

3http://housemajority.org/coms/hres/gas_report_chapter1.pdf;

http://www.naturalgas.org/naturalgas/processing_ng.asp4

http://housemajority.org/coms/hres/gas_report_chapter1.pdf;

http://www.naturalgas.org/naturalgas/processing_ng.asp5

Clayton, G. 1980; Goldsmith and Szymoniak 2009; http://housemajority.org/coms/hres/gas_report_chapter1.pdf6

Simbeck, 2002, in Burton et al 2006.
http://www.naturalgas.org/naturalgas/processing_ng.asphttp://housemajority.org/coms/hres/gas_report_chapter1.pdfhttp://housemajority.org/coms/hres/gas_report_chapter1.pdfhttp://www.naturalgas.org/naturalgas/processing_ng.asphttp://housemajority.org/coms/hres/gas_report_chapter1.pdfhttp://housemajority.org/coms/hres/gas_report_chapter1.pdfhttp://www.naturalgas.org/naturalgas/processing_ng.asphttp://housemajority.org/coms/hres/gas_report_chapter1.pdfhttp://housemajority.org/coms/hres/gas_report_chapter1.pdfhttp://www.naturalgas.org/naturalgas/processing_ng.asphttp://housemajority.org/coms/hres/gas_report_chapter1.pdfhttp://www.naturalgas.org/naturalgas/processing_ng.asphttp://housemajority.org/coms/hres/gas_report_chapter1.pdfhttp://www.naturalgas.org/naturalgas/processing_ng.asp

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seams don't change the amount of CO2, CO or methane, but produce a lot more H2. This

is useful for generating hydrogen or a CO/H2syngas.

Depth of coal seam. Burning deep seams where the pressure is greater creates more

methane and less CO and H2, and therefore a higher quality gas.

Temperature. High temperature reactions produce more methane,, but temperatures that

are too high reduce the quality of the gas

Water. Changing the amount of water changes the amount of methane and hydrogen.

Oxygen. Injecting air to start the burn instead of oxygen increases the nitrogen content of

the gas, lowering the gas quality.

The product gas will also contain sulfur, nitrogen, and volatile trace metal species. Like

thermogenic natural gas, it needs to be 'cleaned' to remove hydrogen sulfide and other

contaminants (Appendix B). UCG produces either hydrogen or a methane-hydrogen mixture for

combustion after clean-up. If a methane-hydrogen mixture is combusted, CO2will be the

primary air emission. If hydrogen is combusted, water will be the primary emission, but CO2

will be produced as part of the process of making hydrogen. Hydrogen may also have other

industrial uses, or may be used for hydrogen fuel cells and other parts of the emerging hydrogen

economy. Similarly, chemical reactions can begin with UCG gas to make methane, methanol,

fertilizer, and other products.

Table 1. Composition of Natural Gas, Syngas, and UCG gas. Natural gas and UCG gas composition is as it occurs

at the well-head, not after cleanup. UCG gas composition will vary depending on the purpose the gas is to be used for.

and the conditions under which it is generated. The table is a compilation from the following sources: Shafirovich andVarma 2009, Goldsmith and Szymoniak 2009, Friedmann 2007, Bakker 2004, Claypool 1980, and the following

websites: http://www.naturalgas.org/naturalgas/processing_ng.asp,

http://www.naturalgas.org/overview/background.asp, http://www.uniongas.com/aboutus/aboutng/composition.asp,

http://www.fluent.com/about/news/newsletters/04v13i2/s8.htm

Natural Gas Syngas UCG gas

Methane (CH4) 70-90% 1-2% 5-14%

Hydrogen (H2) 24%-30% 25-40%

Carbon dioxide (CO2) 0-12% 4%-15% 25-40%

Carbon monoxide (CO) 35-65% 5-20%

Hydrogen Sulfide (H2S) 0-5% 1% 2-8%

Nitrogen (N2) 0-5% 1% ?
http://www.naturalgas.org/naturalgas/processing_ng.asphttp://www.naturalgas.org/naturalgas/processing_ng.asphttp://www.naturalgas.org/overview/background.asphttp://www.naturalgas.org/overview/background.asphttp://www.uniongas.com/aboutus/aboutng/composition.asphttp://www.uniongas.com/aboutus/aboutng/composition.asphttp://www.fluent.com/about/news/newsletters/04v13i2/s8.htmhttp://www.fluent.com/about/news/newsletters/04v13i2/s8.htmhttp://www.fluent.com/about/news/newsletters/04v13i2/s8.htmhttp://www.uniongas.com/aboutus/aboutng/composition.asphttp://www.naturalgas.org/overview/background.asphttp://www.naturalgas.org/naturalgas/processing_ng.asp

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Water (H2O) saturated 15-25% 33%

Producing electricity by burning these different gases will generate different

environmental footprints. For instance, syngas requires mining and transporting coal; natural gas

production requires deep, often offshore wells; while UCG gas may require deep wells but hasvery little above ground disturbance. Similarly each has a different potential to pollute water or

air, and different greenhouse gas types and amounts.

How UCG works

The basic concept is to drill two wells into a deep coal seam and burn out the coal

between them.

Compressed air or an oxygen/steam mixture is injected through one well, the coal burns

and releases gases, and the gases come out of the ground at the second well, called the

production well. The burn creates a cavity or "combustion chamber", and the process works best

with deep seams of low-quality coal, exactly the material that is difficult to traditionally mine

economically. Water flowing into the cavity is not pumped out, but is used as part of the burn

reaction. Because of the cost of transporting the gas, power plants would likely be sited adjacent

to the coal field.

Pilot projects have been conducted since the 1940's, and particularly in the 1970's and

1980's in the US and the 1990's in Europe and China. Trials focused on how to get the coal to

burn, how to control the burn, maximizing efficiency, and minimizing environmental

contamination.

Getting coal to burn

The first difficulty in the early trials was getting the coal to burn. Although there are

numerous instances of uncontrollable underground coal fires around the world, the fires are

dependent on oxygen reaching the coal. Deep coal seams several hundred feet underground are

saturated with water and isolated from oxygen, and attempts to simply set the seam on fire

fizzled. In researching science journals, federal documents, and company literature this author

was unable to find any instances of uncontrolled coal fires during UCG.

Eventually two techniques proved to be successful.

Inject air at the injection well. The ignition source is placed at the production

well to "draw" the fire towards the high oxygen area in a process called "reverse

combustion", burning a path through the seam.

Drill a simple vertical well as the production well. The injection well begins

vertical then bends to become a horizontal tunnel through the coal seam towards

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the production well. A "controlled retractable injection point" (CRIP) is a point

where coiled tubing burns through the horizontal tunnel borehole casing; oxygen

and steam are forced through the point to ignite the coal. This is initially placed

near the juncture of the injection and production wells. The coal burns for a

while, forming a cavity as hot gases move up and outward, but it eventually

fizzles. When the burn is done, the point is retracted and ignition is started again

at a point in the horizontal tunnel closer to the injection well. In this way the

burning coal front proceeds in a controlled manner (Figure 2). The CRIP

technique allows for several production wells for each injection well, reducing the

overall footprint.

A proprietary technology developed by Ergo Energy was successfully used in the

30-month long Chinchilla Australia project. However, the specifics of the

technology are not known.

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In general, the CRIP process and the Ergo technology have worked better than hydraulic

fracturing and reverse combustion in controlling the UCG process.7

Operational parameters

Constraints such as depth, thickness, dipping of the coal seam and temperature, pressure,

oxygen, and water in the burn cavity all play a role in gas quality, economics, and potential

environmental impacts.

7Hydraulic fracturing is a technique of fracturing the coal seam between the two wells to encourage gas flow; this

did not work, as gases spread out and did not flow consistently in the desired direction.

Overburde

Coa

Inject oxygen

and steamGas

Old burned out

cavity with

New injection

point, new burn

burned out injection well

heat and hot gases

pyrolyis products line

water influx

Figure 2. CRIP process of gasification. The movable injection point begins the burn near the production

well. When the first burn expires, a second burn is initiated closer to the injection well. This procedurecontinues until the seam is burned out. Adapted from Burton et al 2006.

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Deep and Thick

Trials have determined that UCG should be conducted on deep, thick coal beds. This

provides a better quality gas and reduces the risk of groundwater pollution or surface subsidence.

The pressure in the burn cavity affects how well the reaction will proceed, thecomposition of product gas, and how the surrounding rock will be altered. Burns conducted at

depth (200 m to over 1000 m) where the pressure is greater produce better quality gas with more

methane. This has been proven in the field: using oxygen injection, gas produced at 4 bars of

pressure contained 5%

methane (and 21% CO

and 38% hydrogen) while

gas produced at 5.3 bars

contained 13% methane

(and 13% CO and 25%

hydrogen.8

Theremainder of gases in both

cases was carbon dioxide

and hydrogen sulfide. The

difference affected the

heat content of the gas,

with 8.7 and 10.9 MJ/m3

produced respectively.

Deep seams also

cause the economics of airversus oxygen injection to

change. Injecting air

requires compressing nitrogen and injecting oxygen requires an oxygen separation plant both

are expensive. Oxygen injection becomes economically favorable for deeper coal seams as the

cost of making oxygen becomes less expensive than additional compressors for injecting air. 9

Thick seams allow gas production with fewer wells. Seams that are too thin (less than 2

m) allow heat to escape into surrounding rock too easily, and the resulting product gas is of poor

quality.10

Some UCG development companies suggest seams should be at least 10 m thick,11

while others believe seams as thin as 0.5 m can be used; this is likely biased by the depth ofavailable coal (Figure 3).

8Kreinin in Shafirovich et al 2008; Shafirovich and Varma 2009

9 Boysen et al 1998; Burton et al 2006

10 Bowen and Irwin 2008

11Shafirovich et al 2008

Figure 3. Depth and thickness of coal seams by global region. The US tends

to have thick seams of coal near the ground surface, while Europe tends to have

thin, deep seams of coal. Thick seams produce better quality gas, but deep seams

are more likely to isolate contaminants and reduce the risk of subsidence. FromBurton et al 2006.

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Figure 4. Faulted and dipping

seams. (Left) Drilling faulted

seams. (Below) Gasification of

steeply dipping seams.

Temperature

Temperatures that are too low allow tars to form and can cause the pathway between

wells to plug, but if too high reduce the efficiency of the gasification process and the heat value

of the final gas.

Water

Although coal contains water and combustion cavities are expected to have water flux

into them, too much water will reduce the methane content in the gas, reducing the heating value.

For this reason, if UCG is being used to provide electricity it is preferable to use coal with low

moisture with no overlying aquifer within 25 times the height of the seam.12 This also reduces

the risk of groundwater contamination, particularly groundwater that might reach surface water

or enter drinking water wells.

Faults and fractures

Coal seams may dip up and down, or a fault may cause the seam to be discontinuous,

suddenly stopping at one depth and starting again at another. To adjust for fault discontinuities,

drilling equipment has the capacity to contain "eyes" that "see" the geologic structure ahead of

the drill bit; the drill can then be adjusted as necessary (Figure 4).

To use the technology on steeply dipping coal seams, combustion occurs at the deep end

and the coal above "gravity feeds" down into the fire, with production gases working their way

upward (Figure 4) and coal tar flows down away from the burn. Testing on dipping seams has

been conducted at Rawlins, WY and in Russia (Juschno-Abinsk).

12Sury et al 2004, in Shafirovich et al 2008

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Historical Perspective

This section lays out some the general history of underground coal gasification in

different countries, and describes some key sites in detail. A list of all gasification sites is

available in Appendix C.

Regional exper iences

Former Soviet Union

The technology for burning coal into gas while it was still in the ground began in the

1930's in the USSR, and by the 1950's the USSR was producing about 300 MW of electricity

with this gas.13

About 200 pilots were conducted in the USSR and, after 1991, in Russia,

Ukraine, and Uzbekistan. One station (Yuzhno-Abinsk, Kuznetsk Basin, Russia) produced gas

for 14 boilers from 1955 1996, finally closing as equipment failed during the post-Soviet era.

Another plant built in the 1950's in Uzbekistan is still operating. Most closed as cheap natural

gas came on-line. During the trials in the former Soviet Union, it was learned that injecting

oxygen rather than air produced gas with higher heat value, that transporting the gas any distance

is often uneconomical, and that high temperatures (540-760 oC) cause rocks to swell.14

Environmental modeling was also developed.

United States

In the US, initial tests began in Alabama in the 1940's and 1950's. Testing was

revitalized during the years of high oil prices, with 31 tests conducted 1973-1989, mostly by the

Department of Energy (DOE). They were short-term projects, with a total of only 50,000 tons of

coal gasified. It was during this period that the CRIP technology was developed by Lawrence

Livermore National Labs (LLNL). Most trials attempted to answer specific questions about

managing the burn, shutdown and startup, gas consistency and quality, and groundwater impacts.

New projects are scheduled to begin in Wyoming: in July 2007, British Petroleum (BP), LLNL,

13Shafirovich et al 2008; Shafirovich and Varma 2009

14Den'gina et al 1994, in Shafirovich et al 2008

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and a UCG developer signed an agreement for a pilot in the Powder River Basin of Wyoming

that would incorporate carbon capture and sequestration (CCS) with UCG.15

Europe

In the European Union, a series of experiments was conducted 1982-1999, primarily inBelgium, France, and Spain. These trials tested methods to get coal to ignite, move gas to the

production well, and determined that coal burning could be conducted in deep coal seams.

Repeated testing of reverse combustion and hydraulic fracturing to direct gas to the production

wells failed. Not until directional drilling and oxygen injection were attempted at the El

Tremedal site in Spain were researches able to link wells productively.

All were short-term tests primarily designed to learn more about the technology. No

electricity is currently generated from UCG in Europe, although more trials are planned. A

consortium of countries led by Poland has started a pilot to test the feasibility of using UCG as a

cornerstone of developing a hydrogen economy and the feasibility of integrating it withgeothermal heat exchange and CCS.

16 The UK is examining the feasibility of conducting UCG

in a coal seam that lies under the Firth of Forth in Scotland; the gas would be used in conjunction

with fuel cells to make electricity. This would be the first UCG project beneath ocean water.

Other countries

In Australia, one of the most successful pilots was conducted. The Chinchilla project ran

from 1999-2003 and demonstrated that UCG could be controlled, including shutdown and re-

start. During the 4-year period, 35,000 tons of coal from a seam 140 m deep was gasified with

no environmental problems. Today two major pilot projects are in development, and severalother smaller projects. Pilots include a planned 400 MW combined cycle gas turbine (CCGT)

power plant and a 100-day pilot to test a module-based system to produce 20 MW per module,17

with the goal of developing a commercial CCGT plant. In October 2008, a coal gas-to-liquids

fuel production facility was started.18

Canada has not had any historical UCG projects, but two projects are moving forward in

Alberta to use UCG for power, fuel, and hydrogen and sequester CO2using enhanced oil

recovery (EOR).19

The steam from UCG may be used in tar sands oil recovery.20

The

proponents of these projects, Laurus Energy, may become a partner in the CIRI Beluga project.21

15Shafirovich and Varma 2009

16Rogut 2008

17Shafirovich et al 2008

18Friedmann et al 2009

19ibid

20Maev 2008; Shafirovich and Varma 2009

21Bluemink 2009

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A test project in New Zealand in 1994 only lasted 13 days. The information available

says the area was "tectonically active with coal deposits faulted and folded, providing a geologic

challenge" but does not explicitly detail the issues, except to say that they did not achieve good

gasification.22South Africa started a pilot UCG project in January 2007 with the intent to use it

for both power and coal gas-to-liquid fuel. The small amount of UCG gas would be used to co-

fire turbines at a large natural gas facility. The co-firing was successful 2007-2008, but it is

unclear if a scale-up occurred after that. China has had 16 UCG trials since the 1980's. One

project currently operating in XinWen uses six UCG reactors to provide gas for cooking and

heating, while one in Shanxi uses the gas to produce ammonia and hydrogen. A $100 million

pilot commercial project has started in Inner Mongolia next to a coal mine. Other plants are used

to produce fertilizer. More trials are planned, including feasibility of UCG for hydrogen and

methanol production.23

Key test sites24

Hoe Creek

The Hoe Creek site in Wyoming was operated from 1976-1979. The coal seam was 10 m

thick, lying 40-50 m below ground, with a shallow layer (5 m thick) of siltstone and clay

separating it from an upper coal seam; overburden above that was primarily silt, sand, and

sandstone. The sand and coal seams were the primary aquifers. Three experiments (Hoe Creek

I, II, and III) were conducted and heavily monitored to examine the burn process, gas

composition, cavity formation, and geotechnical data.

The primary research at this time was in getting gas to move to the production well. At

Hoe Creek I, explosives were used to fracture the coal bed and air was injected for 11 days. Thetest was not very successful, with about 7% of the gas lost to the overburden. At Hoe Creek II,

three separate trials of 2-43 days used reverse combustion with air or oxygen. Water entering the

burn cavity lowered gas quality, so the pressure was increased to keep water out. However, this

forced much of the gas out of the cavity away from the production well, and about 20% of the

gas was lost. Hoe Creek III used directional drilling and reverse combustion over a 47 day test.

Unfortunately the burn at the lower coal seam target moved into the upper coal seam, a mere 10

m above, and again nearly 20% of the gas was lost. Eventually subsidence occurred at both Hoe

Creek II and III.

Twelve monitoring wells were sampled before, during, and for up to two years aftergasification.

25Groundwater contamination occurred within seven days of the start of

gasification. The pressure used in the cavity to try to push water out also pushed out soluble

22Shafirovich and Varma 2009

23ibid

24These compilations are derived from Burton et al 2008, except where noted

25This section from Campbell et al 1979

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volatile organics (such as phenols) and other contaminants (like cyanide) into the aquifer above.

The problem was exacerbated by surface subsidence, which occurred due to the shallow depth of

the seam and the lack of structural integrity in overlying rock. Toxic organics in residual ash

dissolved in inflowing water and moved into all three aquifers. Due to the extensive monitoring

well system and groundwater analysis, the contamination was picked up and monitored.

Analysis was done for 250 different organic and inorganic compounds, and 70 were detected

(Appendix D). Testing up to two years after the burns found all contaminants were within 30 m

of the burn zone, and concentrations decreased very rapidly with distance; many probably sorbed

to overburden and residual coal layers.

However, by 1993, the DOE found that contaminants remained in an aquifer 55 m below

the surface, and had migrated off of the original BLM-owned property the testing was conducted

on. Contaminants included phenol and benzene (known carcinogens) and other organics known

to cause kidney and nerve damage; all were small, highly soluble molecules that do not sorb well

to soils. In 1998, DOE installed 64 air-sparging wells to remediate the site, and another 50 were

installed in 1999. A variety of remediation technologies were in use as of 2006.

Much of what we know now came out of this test, and later tests based on these findings.

This was the first successful use of oxygen/steam injection and a movable injection point. What

was learned from the subsidence and groundwater contamination became part of the basis for

site-based risk assessment by today's standards, the site would have been considered as having

high environmental risk due to the shallow depth of the coal and proximity to aquifers.

Centralia, WA

Between 1981 and 1982, the CRIP system was further tested at Centralia, WA for 4 andfor 30 day burns. Different oxygen/steam ratios as well as a propane-silane (SiO4) combination

were used to ignite the burns, and drilling configurations and slants were tried to examine

changes in syngas quality. The variations did not change gas quality much. This trial was the

first real test of the CRIP system, and also tested whether models could predict how cavities

would grow. Cavity shape and size models were validated by quarrying out the actual burn

cavities. Quarrying also allowed researchers to examine the products left in the cavitydried

coal, char, and ash. No subsidence was predicted, and none was observed.

Rocky Mountain I

The Rocky Mountain I test in Wyoming November 1987-February 1988 was considered

the most successful US test to date. The project focused on siting the project to prevent

groundwater contamination. Significant effort went into pre- and post-burn water, temperature,

and mineral analysis to determine how the burn changed the underground make-up of the rock

and water chemistry. The coal seam was 10 m thick and 130 m below ground. The successful

directional drilling and CRIP processes tested in Centralia were used continuously for several

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months.26 Negative pressure was used to ensure that water flowed into, not out of, the burn

cavity, and water that filled the cavity post-burn was pumped to the surface and treated to

remove underground contamination from dissolution of ash and pyrolysis products, both to

ensure that no contaminated water remained underground, and also to cool the cavity quickly to

reduce steam, which can crack the rock above and induce fractures, and reduce transfer of hot

gases to surrounding rock. No environmental contamination was found by the 19 groundwater

monitoring wells.

Research indicated that the heat in rocks surrounding the burn cavity does not dissipate

quickly, and rocks can still be 4-12oC hotter than normal two years after a burn. Similarly,

groundwater temperatures did not always rise until several months after gasification ended.27

The rise in temperature in wells was entered into models to calculate the temperature along

production lines. Within 1 m of the well, rocks could be 750-1000oC, nearly as high as

temperatures in the burn zone. This is potentially high enough to cause the rock around the gas

lines to change and affect the cement-rock seals and could lead to gas leaks. Temperatures

decreased rapidly with distance from the line: as modeled they would have been 100 oC four

meters away and within 16 m they were only 4.5 oC higher than background.

Although the testing was successful and the operators intended to go into commercial

production of ammonia, the Rocky Mountain UCG site was shut down when cheap oil became

available.

El Tremedal

The El Tremedal site was a joint project of Spain, the UK, and Belgium located in Spain

and operated 1992-1999. Directional drilling and oxygen injection were used. The tests wereconducted to determine if gasification could be done on deep seams (550 m) while maintaining

negative cavity pressure to prevent groundwater contamination. A methane explosion damaged

the injection well and stopped the project, but no environmental contamination was detected by

the several monitoring wells.28

Chinchilla29

The Chinchilla project emerged from testing in the 1980's at the University of

Newcastle, Australia. It was conducted over 30 months from December 26 1999-April 2003

using the proprietary Ergo technology and consisted of 9 injection/production wells surroundedby 19 monitoring wells (Figure 5). The coal was 140 m deep and 10 m thick. The test was

conducted under low temperatures (300 oC) and reverse combustion with air/water injection

26Clean Air Task Force 2009

27Gosnald 1998

28Friedmann et al 2009

29Information from Shafirovich et al 2008 and from Burton et al 2006

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(rather than the CRIP technology) was successfully used between vertical wells. Up to 675 tons

of coal per day was gasified, with 75% total energy recovery. No groundwater or surface water

contamination was detected, nor was there any subsidence. A gas-to-liquids plant was

constructed in 2008 at the site, with the intent of using UCG product gas.

What made this project important was that it validated the concept of keeping the cavityat a pressure less than the surrounding rock to allow groundwater to flow into the cavity and

keep volatiles from being pushed out; essentially a successful scale-up of the testing done at

Rocky Mountain.

Environmental Impacts

The primary concerns are the potential for uncontrollable fire, sinkholes (subsidence),

groundwater contamination, and air emissions, including increased greenhouse gases.

Essentially, the risks can be broken down into: will contaminants dissolve, how much CO2canbe captured and sequestered without leakage, and will any contaminants reach anything

important?

Although a literature review has not revealed any instances of uncontrolled fires,

most projects have been conducted for only a short period of time and little

information is available regarding the New Zealand pilot in a tectonically

Figure 5. UCG at Chinchilla, Australia. From Hattingh, L. 2008. Underground Coal Gasification.

Sasol.

http://www.sacea.org.za/SeminarsSymposium/Seminar22Aug2008/UNDERGROUND%20COAL%

20GASIFICATION%20%20-%20Lian%20Hattingh.pdf
http://www.sacea.org.za/SeminarsSymposium/Seminar22Aug2008/UNDERGROUND%20COAL%20GASIFICATION%20%20-%20Lian%20Hattingh.pdfhttp://www.sacea.org.za/SeminarsSymposium/Seminar22Aug2008/UNDERGROUND%20COAL%20GASIFICATION%20%20-%20Lian%20Hattingh.pdfhttp://www.sacea.org.za/SeminarsSymposium/Seminar22Aug2008/UNDERGROUND%20COAL%20GASIFICATION%20%20-%20Lian%20Hattingh.pdfhttp://www.sacea.org.za/SeminarsSymposium/Seminar22Aug2008/UNDERGROUND%20COAL%20GASIFICATION%20%20-%20Lian%20Hattingh.pdfhttp://www.sacea.org.za/SeminarsSymposium/Seminar22Aug2008/UNDERGROUND%20COAL%20GASIFICATION%20%20-%20Lian%20Hattingh.pdf

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complicated area. Current recommendations are that there should be no major

faulting within 45 m of the proposed gasifier.30 The potential for new faults to

develop and provide a route for air to reach the coal seam will need to be assessed in

Beluga.

Subsidence and groundwater contamination have been issues in past projects whereshallow coal seams were burned; the recommendation now is to use coal seams

greater than 200 m deep with an impermeable, structurally sound layer above the

seam and no potable aquifers nearby or within 25 times the height of the coal seam.

CIRI proposes to use a seam 198 m deep. If an impermeable overburden layer is

present it also helps prevents product gas from flowing into the surrounding rock,

improving the quantity of gas retrieved. However, it should be noted that a

structurally sound layer does not eliminate the risk of subsidence. Any rock

overlying a burned out cavity could develop fractures.

About half the mercury, arsenic, sulfur, tars, and particulates produced from burningcoal remain underground. While this reduces air emissions, it is a potential concern

for groundwater contamination.

Groundwater can become contaminated with volatile, soluble organics like benzene

and phenols.31

Site-specific geologic and hydrologic assessment will need to assess

whether the aquifers in the area are fresh or saltwater, the potential for connection

between the coal seam and aquifers, and the potential for the aquifers to reach surface

water. A connection to surface or tidal water is a serious risk, in that benzene at

levels safe for humans can cause genetic damage in salmon exposed to it

consistently.32

High temperatures in production wells could cause well casings to crack and release

hot gas;33

if the well passes through an aquifer this could be a route for

contamination.

To gasify coal above ground, the coal must be mined, transport, and put under great

pressure and heat before it can fuel turbines. The environmental impacts include all the impacts

of mining (water contamination, methane release, potential subsidence for underground mining,

human health impacts for miners) as well as air pollution from combustion (CO2, mercury, sulfur

and nitrogen oxides). By gasifying the coal below ground, many of the mining impacts areeliminated, and groundwater and air pollution become the primary risks.

30Surey et al 2004, in Burton et al 2006

31Campbell et al 1979

32Carls et al 2008

33Gosnald 1998

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Structural I ntegri ty of H ost Rock

Coal will be surrounded by "host rock". In the nearby Chuitna coal fields near the Chuit

River (less than 100 m deep), the host rock is primarily permeable sandstone saturated in water.

If the same geologic forces that created this set of conditions also created the coal and host rock

at the Beluga coal fields (200 m deep), they could also be overlain by a permeable sandstoneaquifer.34 This would increase the risk of a UCG burn contaminating an aquifer, and would be

important unless the aquifer were saline.

Tectonic activity can create faults and fractures that allow UCG gas to escape, allow

water to move in unexpected directions, and provide a route for contaminant transport.35 Not

only do any current faults need to be assessed, but the potential for high temperature activity to

cause stresses and fractures and provide new pathways, collapse of the burn cavity, or subsidence

needs to be assessed.

Subsidence occurs when coal is removed, leaving a void under the surface. Subsidencedoes not always occur; it was minimal in pilot tests in Centralia, WA and Chinchilla, Australia.

However, these were pilot projects, and it is not known what would happen in a commercial

situation where large quantities of coal are removed. Given the remote location, the primary risk

is the potential to create pathways for contaminants rather than direct risk to habitation.

Formation of contaminants

The high temperatures of the burn cause volatile hydrocarbons and some trace metals to

become gases and carbon in coal and carbonate rocks to release carbon dioxide. These generally

partition into either the production gas or end up in the residual ash that stays in the cavity after

the burn is complete. If there is a route to an aquifer, highly soluble off-gassed volatiles like

phenol can cause persistent water contamination, as can material in ash. Organic compounds

such as tars, benzene, toluene, phenols, and polycyclic aromatic hydrocarbons (PAH's) will be

created as heat dries and burns coal. The rocks themselves will change: carbonate rocks will

release calcium and CO2; mafic rocks will release iron and magnesium, and so forth. Metals

from rocks will volatilize and move out with production gas, remain in residual ash, and may

move into pore spaces of surrounding rock. A lining of burn products can be generated around

the burn cavity.

There are two periods to consider: during the burn and after the burn. During the burn,

contaminants are most likely to volatilize and move out with product gases. After the burn,

contaminants are most likely to become soluble in water and migrate out of the burn cavity as

normal hydrologic flow re-establishes.

34Burton et al 2006 Section 5.3.1.2

35Creedy and Garner 2004, in Burton et al 2006; Gregg 1977 in Burton et al 2006

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Migration of contaminants

Very high temperatures (greater than 1000 oC) cause rocks to crack and burn and solid

metals become gases; also water becomes less dense and less viscous so it moves more easily

allowing easier transport of contaminants. High temperatures in the production well, carrying the

gas product, may be high enough to crack the well casing and allow gases to escape

gases thatcan contain metals and toxic organics. The production of contaminants and their movement is

entirely different from any other industry, and prediction needs to rely strongly on results from

pilot tests. Whether contaminants become a risk depends on whether they are able to reach water

being used by aquatic life or people.

Just as steam and oxygen, temperature and pressure affect the quality of the UCG product

gas, they also affect what happens to the unintended byproducts. Burns will be operated at very

high temperatures in order to shift the reaction to produce methane, and the higher the

temperature the less byproduct. However, higher temperatures also increase the solubility of

organics, allowing them to move further in water. High temperatures can thermally drive waterup through the burn cavity roofing, cause cracks or collapse of the burn cavity that allow water to

migrate out, and cause organics to become soluble in water.36

Deep UCG projects will need to

be run at higher pressures to keep the burn going, risking outflow of water from the cavity, but

are more likely to be far from potable aquifers. High pressure and the buoyant gas forces can

combine to overcome the pressure surrounding the cavity, resulting in vaporized material

moving out of the cavity and condensing in the outer rock. If the burn is advancing in that

direction, the process may repeat.37

As material is pushed away from the hot cavity, it condenses, absorbs, adsorbs, or in

other ways reacts to precipitate away from the cavity. Organics and ammonia may sorb to coalor surrounding clay. This material may be encountered as groundwater re-establishes its natural

flow post-burn.

After the burn, the normal hydrologic flow will fill the underground chamber and

dissolve the ash left behind. When it encounters the precipitated or sorbed material outside the

burn cavity, different reactions may occur. Some material may dissolve; some will be detoxified

if the groundwater is high in oxygenfor instance, ammonia will become the non-toxic nitrate

and some may be broken down by aerobic bacteria. The migration of contaminants may be

irrelevant if the coal was capped by an impermeable layer or no potable aquifer is at risk.

However, some of the contaminants are toxic to fish, if they are able to reach fish-bearing

waters: ammonia, high concentrations of calcium or other cations, high concentrations of total

dissolved solids (TDS commonly mostly sulfate), and low but persistent concentrations of

36Under room temperature conditions, many organics are not soluble in water, which is why oil forms a sheen on

water instead of dissolving.37

Burton et al 2006

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PAH's. One method of mitigation to prevent harm to drinking water or aquatic life is to pump

and treat water as it enters the burn chamber until all toxic compounds are below safe levels, as

was done at Rocky Mountain I. One author has suggested that UCG sites should be at least 1.6

km from rivers and lakes, and 0.8 km from major faults to prevent groundwater contamination

conditions that may be difficult to meet at Beluga.38

CO2

Carbon dioxide is the defining pollutant of our age endangering entire populations of

people, plants, and animals through its role in global warming and ocean acidification. Models

developed by international consensus through the IPCC are proving to have underestimated the

rise in global temperatures. Feedbacks such as reduced ice cover at the poles (less reflection of

sunlight, more absorption), release of methane from warming Arctic tundra,39and positive

biological feedback mechanisms such as vast stretches of dying trees in the Pacific Northwest

(due to increases in beetle kills because winter temperatures no longer kill the beetles) and no

longer removing CO2may account for the unexpectedly rapid temperature increase. Ocean pH is

dropping, Arctic ice is melting, and permafrost is thawing at rates much faster than predicted,

and there has been increased drought in Australia, the US, Africa, and the Middle East; increased

flooding; eroding beaches in Hawaii and villages in Alaska; and more. The measured physical

observations indicating the fast rate of global warming, the human face of it, and the likely fiscal

impacts on individual gas emitters make it an imperative to consider greenhouse gas emissions in

any large scale project.

L ife cycle greenhouse gas emissions

Carbon dioxide will be produced from the UCG process as the raw gas exits the

production well and also when methane is combusted in the power plant if a methane/hydrogen

mixture is used. All carbon products become CO2during combustionif the product gas

entering the power plant contains CO2, CO, and methane, all of these will exit the stack as CO2.

If CO2and CO are removed during a "cleanup" or carbon capture process, only the methane will

be converted to CO2in the stack.

Although no studies could be found that analyzed the life cycle greenhouse gas emissions

of syngas made through the UCG process, analysis has been done comparing coal, syngas,

natural gas, and liquefied natural gas both with and without mitigation technologies (Figure 6).

40

The study notes that natural gas is one of the largest sources of greenhouse gas emissions in the

38Bowen, BH. A review and future of UCG. Powerpoint.

http://www.purdue.edu/discoverypark/energy/events/cctr_meetings_dec_2008/presentations/Bowen-12-11-

08.pdf39

Methane is a greenhouse gas more than 20 times as potent as CO240

Jaramillo et al 2007
http://www.purdue.edu/discoverypark/energy/events/cctr_meetings_dec_2008/presentations/Bowen-12-11-08.pdfhttp://www.purdue.edu/discoverypark/energy/events/cctr_meetings_dec_2008/presentations/Bowen-12-11-08.pdfhttp://www.purdue.edu/discoverypark/energy/events/cctr_meetings_dec_2008/presentations/Bowen-12-11-08.pdfhttp://www.purdue.edu/discoverypark/energy/events/cctr_meetings_dec_2008/presentations/Bowen-12-11-08.pdfhttp://www.purdue.edu/discoverypark/energy/events/cctr_meetings_dec_2008/presentations/Bowen-12-11-08.pdf

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US when processing, transmission, and combustion are included, producing about 800 lbs of

CO2-equivalents per MWh, or an estimated 250 lbs if CCS could be incorporated. But this is

less than traditional pulverized coal plants, which produce about 1800 lbs of CO 2-equivalents per

MWh, or an estimated 400 lbs if CCS could be utilized. UCG product gas is likely to be similar

to natural gas in the combustion, processing, and transmission components, although it will

require extra release of CO2for air compression or making oxygen; it will be significantly lower

than traditional above-ground gasification CO2releases in that no coal mining, processing, or

transportation are required, nor is energy required for the gasification process as in above-ground

facilities.

While UCG combined with carbon capture is likely to produce much lower greenhouse

gas emissions than a traditional natural gas plant, it is not a zero-emissions technology. In 2001,

the Beluga plant supplied 300,000 MWh of electricity.41 If UCG with CCS fueled a similar

amount of electricity, it would generate at least 375,000 tons of CO2-equivalent annually if the

estimates of about 250 lbs of CO2per MWh are correct.

41ISER 2003

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electricity is estimated to be 35-70% higher for a natural gas combined cycle plant, such as is

used at Beluga, if CO2capture is installed.43 Pre-combustion technology itself (Selexol) costs

about $25/ton CO2captured.44

Carbon sequestration

The locations where CO2is removed from natural gas are in the southern US, where

pipelines transport the CO2to declining oil fields. Geologic sequestration has been discussed

and theorized, but rarely implemented. The only commercial-sized long term sequestration of

CO2outside of enhanced oil recovery is at the Sleipner, Norway natural gas production platform,

where CO2has been injected into saline aquifers 1000 m beneath the ocean floor since 1996.

This project has been driven by Norway's high carbon tax, $55/ton CO2in 1991 (the equivalent

of over $100,000 per day for Sleipner). Drilling the injection well and installing a compressor

added $100 million to the project; adding scrubbers to remove CO2and monitoring equipment

were additional expenses.

While Sleipner has been successful, not all projects have gone smoothly.

Norway's Snohvit natural gas platform has had significant technological problems

with storing CO2. The CO2freezes at temperatures required to make LNG,

blocking the LNG transport pipe. The plant was shut down twice in 2008 and

again in 2009.45

Pilot projects that injected CO2into rock formations to make solid carbonate

rocks instead caused carbonic acid to form, and the acid dissolved the rock cavity

intended to contain it. The process stopped when neutralizing rock was

encountered.46

Injecting CO2into basalt rock to make mineral carbonates failed

when the rock swelled and plugged the underground pore spaces.47

CO2captured at a power plant in Wisconsin (as a demonstration project) did not

store the CO2because the geology under the plant was not favorable.48

Currently there has not been enough test-drilling to determine if the geology at the

Beluga coal fields would support sequestration. CIRI has suggested injecting the CO2into

declining natural gas or oil fields, but currently no producers have showed interest in the idea. A

report from the National Energy Technology Lab suggests that sequestration can only be done as

43Thambimuthu 2005 in Burton et al 2006

44Burton et al 2006

45Hurst 2008 andhttp://www.pr-inside.com/golar-lng-q2-2009-results-r1456514.htm

46Kharaka et al 2006

47Sturmer et al 2007

48http://www.scientificamerican.com/article.cfm?id=first-look-at-carbon-capture-and-storage
http://www.pr-inside.com/golar-lng-q2-2009-results-r1456514.htmhttp://www.pr-inside.com/golar-lng-q2-2009-results-r1456514.htmhttp://www.pr-inside.com/golar-lng-q2-2009-results-r1456514.htmhttp://www.scientificamerican.com/article.cfm?id=first-look-at-carbon-capture-and-storagehttp://www.scientificamerican.com/article.cfm?id=first-look-at-carbon-capture-and-storagehttp://www.scientificamerican.com/article.cfm?id=first-look-at-carbon-capture-and-storagehttp://www.pr-inside.com/golar-lng-q2-2009-results-r1456514.htm

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EOR or as saline aquifer injections in the Beluga area, and that both are likely to be cost-

prohibitive.49

CIRI has discussed geologic sequestration of CO2,50

although they have not shown how

this would be economically feasible. It is likely that storing the CO2in depleted underground

burn chambers will be considered; it is possible the capacity will be available, and injecting CO2

into residual coal causes swelling that would plug fractures and migrating CO2would tend to

adsorb to coal and not move far.

However, at Beluga the burn cavities are only expected to be 200 m below the surface,

and CO2storage should be at least 800-1000 m below the surface to maintain CO2in a dense

supercritical state. Nevertheless, the CO2is still likely to be less dense than water, and will be

"buoyed" up to the top of a caprock layer, making it important for the caprock to remain

impermeable in perpetuity.51 This may be particularly important in a seismically active area

such as Beluga.

The heat and steam may cause the rock around the cavity to be quite different

than pre-burn, potentially initiating cracks, fractures, and section collapses.

Volatile organics (benzene, etc) left behind in the cavity dissolve easily in CO2

and will be carried upwards by CO2if the rock above the cavity is permeable.

CO2forms carbonic acid as it dissolves in water and may form sulfuric acid on

contact with coal and ash. These acids lower the pH of groundwater and

potentially allow metals in surrounding rock to dissolve and migrate in a plume

along the groundwater pathway.

The act of injecting CO2will also create changes in temperature, pressure, pH, rock-water

chemistry, and gas-water chemistry. If injected too quickly after a burn, the CO2could boil,

increasing the pressure in the cavity. If injected with too much pressure, the water that has filled

the cavity and dissolved volatile organics and ash material could be flushed out or fractures

could be created. CO2that dissolves decreases water pH, and CO2that does not dissolve can

push up on the cavity, putting pressure on it.

Should CO2migrate up and out of the geologic storage location, it is likely to kill plants

and ground-dwelling animals at the discharge location. Slow, non-catastrophic natural leaks of

49Chaney and van Bibber 2006 Chapter 2

50CIRI's Coal Development plans presentation to the Alaska Bar Association Environmental Law/Natural Resource

Law Section Nov 9 200951

Keith et al 2005

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CO2continue to kill forests in the Sierra Mountains in California, and very large discharges from

natural sources have in the past asphyxiated plants, humans, and animals.52

This means that it is not feasible to safely remove product gas then use the same wells to

pump CO2back down into the burned out coal seams at the proposed Beluga project. At the very

least, injection wells will need to be drilled much further down, and the geology will need to be

favorable both for safe UCG reactions at the proposed 200 m coal seam level and the 800+ m

CO2storage level. The seismic analysis during the feasibility period of the project will be

critical to determine whether there is a risk of air entering the coal seam during the burn, and

further analysis post-burn may be required to determine the risk of CO2leaks from deep storage

locations if earthquakes open new faults.

In the feasibility studies for the UCG project, the true feasibility and costs of carbon

capture from both the product well gas and the power plant need to be presented, along with the

feasibility, costs, and risks of geologic storage.

Summary

The CIRI Beluga UCG project proposes to take components of two emerging

technologies and join them together. This will require scrutiny of both components. The UCG

component has been conducted successfully in pilot scale tests around the world; the one long-

term plant in existence (Angren, Uzbekistan) does not have environmental information readily

available. The operators will need to satisfy both the requirements of producing high quality gas

and the requirements of maintaining environmental integrity. Given the proximity of the

proposed project to the Beluga River, Cook Inlet tidelands, and the Castle Mountain Fault, it is

particularly important to examine the hydrogeologic and geophysical details to ensure

Geologic conditions that preventing subsidence

o At least 200 m below ground

o Structural integrity of host rock

o Geophysical modeling of temperature/pressure stresses on fractures

Siting to prevent contaminant migration

o Impermeable caprock

o a distance at least 25 times the depth of the coal seam between the seam and

aquifer

o a minimum of 1.6 km from rivers and lakes

o a minimum of 0.8 km from major faults

52Wilson et al 2003

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o seams should be thick and widely separatedto prevent burn-through between

seams

In addition to the conditions that must be satisfied for coal gasification, conditions also must

allow for carbon capture and sequestration. No UCG projects currently capture and sequester

carbon. Separating CO2and transporting it to an appropriate declining oil field will require extrafinancing and negotiations with Cook Inlet oil and gas companies. If the CO2is to be injected

back into the coal fields, injection wells at least 800 m deepfar deeper than the 200 m deep

target coal seamwill need to be drilled and the geologic conditions at that depth will need to be

sufficient to entrain the CO2for thousands of years.

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Nevada, Reno.

Thambimuthu, K et al. 2005.IPCC special report on carbon dioxide capture and storage, Chapter 3. International

Panel on Climate Change, 2005.

Walter, K. 2007. Fire in the Hole. Sci Tech Rev, pp. 12-18.

Wilson, EJ, TL Johnson, and DW Keith. 2003. Regulating the ultimate sink: managing the risks of geologic CO2storage. Env Sci Technol 37: 3476-3483.

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Appendix A: UCG reactions and Syngas Reactions

The table below lists the primary reactions found in producing syngas (SNG) or UCG product gas (UCG). The most important

reaction for both is Step 1, the actual transformation of coal into gases. Other reactions either provide the heat to drive the desired

reaction (burning coal) or are reactions to produce a desired product (methane, etc). Adapted from Burton et al 2006, Table 4-1.

Step Reaction Name Chemical reaction Chemical equation UCG SNG Notes

1

Gasification

reaction (Water-

Gas Shift reaction)

Carbon + waterhydrogen and carbon monoxide

C + H2OH2+ CO x x

main reaction; makeshydrogen for combustion

requires heat from steps

5,6

2 Shift conversionCarbon monoxide + waterhydrogen and carbon dioxide

CO + H2OH2+ CO2 x xreact CO to make more

hydrogen

3 MethanationCarbon monoxide and hydrogenmethane and water

CO + 3 H2CH4+ H2Oside

reaction

increase methane conten

of gas; to make hydrogen

from natural gas, reverse

the reactions

4Hydrogenating

gasification

Carbon + hydrogenmethane

C + 2H2CH4side

reaction

increase methane conten

of gas

5

Partial oxidation

(incomplete

combustion of coal)

Carbon + oxygen

carbon monoxide

C + O2CO xreleases heat to drive ste

1

6

Oxidation

(complete

combustion of coal)

Carbon + oxygencarbon dioxide

C + O2CO2 x xreleases heat to drive ste

1

7 Boudouard reactionCarbon + carbon dioxidecarbon monoxide

C + CO22COside

reaction

requires heat, provides CO

for steps 2,3

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Appendix B: Natural Gas Processing

fromhttp://www.eia.doe.gov/pub/oil_gas/natural_gas/feature_articles/2006/ngprocess/ngprocess.pdf
http://www.eia.doe.gov/pub/oil_gas/natural_gas/feature_articles/2006/ngprocess/ngprocess.pdfhttp://www.eia.doe.gov/pub/oil_gas/natural_gas/feature_articles/2006/ngprocess/ngprocess.pdfhttp://www.eia.doe.gov/pub/oil_gas/natural_gas/feature_articles/2006/ngprocess/ngprocess.pdfhttp://www.eia.doe.gov/pub/oil_gas/natural_gas/feature_articles/2006/ngprocess/ngprocess.pdf

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Appendix C: UCG sites worldwide

(all tables are from Burton et al 2006)

International experiments, not including the US or the Former Soviet Union

Dates

Place (Test

Name)

Dur -

ation

(days)

Coal

Gas-

ified

(tons)

Feed

gas

Coal

Seam

Depth

(m)

Auspices/

Comments Original Reference

1982-1985

Thulin,Belgium

12 4

air;mixof N2,O2,CO2

860

Institut pour leDevelopment dela GazeificationSouterraine,Belgium

Chandelle, V, 1986, OverviewAbout Thulin Field Test,Proceedings of the TwelfthAnnual Underground CoalGasification Symposium,DOE/FE/60922-H1.

1983-1984

Initially atBruay enArtois, andlater at LaHauteDeule,France

75

0.3 1stphase

1.5next

phase

N2,O2,CO2

880

Groupe d'Etudede laGazeificationSouterraine,France(Production wellplugged byparticulates andtar, terminatingthe tests)

Gadelle, C., et al., 1985, Statusof French UCG Field Test at LaHaute Deule, Proceedings ofthe Eleventh AnnualUnderground Coal GasificationSymposium, DOE/METC-85/6028 (DE85013720).

1992-1999

Province ofTeruel, NESpain (ElTremedal)

550

Spain, UK,

Belgium,Supported by theEuropeanCommission,used CRIP

www.coal-ucg.com/currentdevelopments2.html

1980-present

China, 16separatetrails *

UCG centre atChina Univ. ofMining andTechnology,Beijing.

1990 -present

Chinchilla,

Queensland,Australia

1994Huntley,NewZealand

with US technicalassistance

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Experiments in the Former Soviet Union

Dates

Place (Test

Name)

Dur -

ation

(days)

Coal Gas-

ified (tons)

Coal

seam

Thickness

(m)

Coal

Seam

Depth

(m)

Auspices/

Comments

Original

Reference

1959-1976Shatsk, MoscowBasin (ShatskayaUCG 1)

17 262,0302 to 4,

average1.9

30 to60,avg40

Flat bed

Olness,Dolores, "TheShatskaya UCGStation",UCRL-53229,1981

1941-1946

Tula, MoscowBasin(PodmoskovnayaUCG 1)

5

Phase 2 wassmall-scalecommercialoperation; flat bed

Olness,Dolores, "ThePodmoskovnayaUCG Station",UCRL-53144,1981

1946-1963

Tula, MoscowBasin(PodmoskovnayaUCG 2)

171,647,800

(from 1950to 1960)

1 to 5 50

Phase 1 R&D;110 boreholesdrilled, 61 links(1588 m) usingcounter-currentcombustion; flatbed; shut down1963, partly dueto coalexhaustion;production peaked

at 2 billion m3/yr(0.85 million tons)

Olness,Dolores, "ThePodmoskovnayaUCG Station",UCRL-53144,1981

productionstopped in1977

Donets coalbasin(Lisichansk)

831,604(from 1950to 1960)

Steeply dippingbeds; shut downin 1964, partiallydue to coal sourceexhaustion

Stephens et al.,"UndergroundCoal Gasification:Status andProposedProgram",UCRL-53572,1984; Olness, DUCRL-50026-80-1

Siberia (Yuzhno-Abinsk)

1,735,112

(sporadicdata oroperation,from 1955 to1977)

Steeply dippingbeds

Stephens et al.,"UndergroundCoal Gasification:

Status andProposedProgram",UCRL-53572,1984; Olness, DUCRL-50026-80-1

1955 topresent

Tashkent,Uzbekistan(Angren)

50 1,040,060 24 250Flat bed; stilloperating

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Experiments in the US

Dates

Place (Test

Name)

Dur-

ation

(days)

Coal

Gasi-

fied

(tons)

Feed

Gas

Coal

Seam

Depth

(m) Auspices Original Reference

1947 -1960

Gorgas,Alabama, US

US Bureau ofMines

Stephens, D.R., R. W.Hill, and I. Y. Borg,1985, Underground CoalGasificationReview. LawrenceLivermore NationalLaboratory, Livermore,CA UCRL-92068.

1976

Hoe Creek,Wyoming,USA (HoeCreek I)

11 123 air LLNL/USDOE

Stephens, D.R., R. W.Hill, and I. Y. Borg,

1985, Underground CoalGasificationReview. LawrenceLivermore NationalLaboratory, Livermore,CA UCRL-92068.

Wang, F.T., Mead, S.W.and Stuermer, D.H.,1982c, Mechanisms forgroundwatercontamination by UCGpreliminaryconclusions from the

Hoe Creek study,Proceedingsof the EighthUnderground CoalConversion Symposium.

1977

Hoe Creek,Wyoming,

USA (HoeCreek IIair-1)


1977

Hoe Creek,Wyoming,USA (HoeCreek II-O2)

2 47Oxy-gen

LLNL/USDOE

1977

Hoe Creek,Wyoming,USA (HoeCreek II-air -2)


1979Hoe Creek,Wyoming,USA (HoeCreek III-air)


1979

Hoe Creek,Wyoming,USA (HoeCreek III-O2)

47 3251Oxy-gen/

steamLLNL/USDOE

1981-1982

Centralia,Washington(Centralia-LBK-O2)

20 140Oxy-gen/

steam

LLNL/GasResearchInstitute/USDOE

Stephens, D.R., R. W.Hill, and I. Y. Borg,1985, Underground CoalGasificationReview. LawrenceLivermore NationalLaboratory, Livermore,CA UCRL-92068.

1981-1982

Centralia,Washington(CentraliaLBK-air)

Un-known

Un-known

airLLNL/GasResearchInstitute/USDOE

1983

Centralia,Washington(CentraliaCRIP-O2)

28 2000Oxy-gen/

steam

LLNL/GasResearcInstitute/USDOE

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Experiments in the US, continued

Dates

Place (Test

Name)

Dur-

ation

(days)

Coal

Gasified

(tons)

Feed

Gas

Coal

Seam

Depth

(m) Auspices

Original

Reference

1973-1974

Hanna, Wyoming(LETC-1)

168 2720 airLaramie EnergyTechnologyCenter/USDOE

Stephens, D.R., R.

W. Hill, and I. Y.Borg, 1985,Underground CoalGasificationReview. LawrenceLivermore

NationalLaboratory,Livermore, CAUCRL-92068.

1975Hanna, Wyoming(LETC-II-1A)

37 962Laramie EnergyTechnologyCenter/USDOE

1975Hanna, Wyoming(LETC-II-1B)


1976Hanna, Wyoming(LETC-II-II)


1976Hanna, Wyoming(LETC-II-III)


1977Hanna, Wyoming(LETC-III)


1978Hanna, Wyoming(LETC-IV-A(a))


1978Hanna, Wyoming

LETC-IV-A(b)48 3184

Laramie EnergyTechnologyCenter/USDOE

1977Hanna, Wyoming(LETC-III)


1978Hanna, Wyoming(LETC-IV-A(a))


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Dates

Place (Test

Name)

Dur-

ation

(days)

Coal

Gasified

(tons)

Feed

Gas

Coal

Seam

Depth

(m) Auspices

Original

Reference

1977Hanna,Wyoming(LETC-III)

38 2,663Laramie EnergyTechnologyCenter/USDOE

Stephens, D.R.,R. W. Hill, andI. Y. Borg,1985,UndergroundCoalGasificationReview.LawrenceLivermore


1978Hanna,Wyoming(LETC-IV-A(a))


1978Hanna,WyomingLETC-IV-A(b)

48 3,184Laramie EnergyTechnologyCenter/USDOE

1979Hanna,Wyoming

LETC-IV-B(a)

7 468Laramie EnergyTechnology

Center/USDOE

1979Hanna,Wyoming (LTC-IV-B(b))


1979Princetown, W.Virginia(METC-1)

17 234Morgantown EnergyTechnologyCenter/USDOE

1979

Rawlins, CarbonCounty,Wyoming(GRD-I-air)

30 1,207 airGulf Research andDevelopmentCompany/USDOE

1979

Rawlins, CarbonCounty,Wyoming(GRD-I-O2)

5 125Oxy-gen

Gulf Research andDevelopmentCompany/USDOE

1979

Rawlins, CarbonCounty,Wyoming(GRD-I-O2)

5 125Oxy-gen


1981

Rawlins, CarbonCounty,Wyoming(GRD-II-O2)

66 8,550Oxy-gen


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Dates

Place (Test

Name)

Duration

(days)

Coal

Gasified

(tons) Feed Gas

Coal

Seam

Depth

(m) Auspices

Original

Reference

1976Fairfield,Texas (BRI-I)

26Basic Resources,Inc. (privatelyfunded)

Stephens, D.R.,R. W. Hill, and I.Y. Borg, 1985,Underground

Coal GasificationReview.LawrenceLivermore


1978-1979

TennesseeColony, Texas(BRI-IIa)

197 4500 airBasic Resources,Inc. (privatelyfunded)

1978-1979

TennesseeColony, Texas(BRI-IIb)

10 212 OxygenBasic Resources,Inc. (privatelyfunded)

1978

RenoJunction,Wyoming

(ARCO-I)

60 3600Atlantic RichfieldCompany

(privately funded)

1977CollegeStation, Texas(TAM-I)

1 2

Texas A&MUniversityIndustrialConsortium(privately funded)

1979BastropCounty, Texas(TAM-II)

2 Unknown

Texas A&MUniversityIndustrialConsortium(privately funded)

1980

Bastrop

County, Texas(TAM-III)

Un-known Unknown

Texas A&MUniversity

IndustrialConsortium(privately funded)

1987-1988

Hanna,Wyoming(Rocky Mt.)(RM1-ELW)(extended linkwell)

40 4,100 Oxygen/steam 10Gas ResearchInstitute andMETC (USDOE)

GRI ReportGRI-90/008;Thorsness, C.B.,and Britten, J.A.,1989, LawrenceLivermore

NationalLaboratoryUndergroundCoal GasificationProject: Final

Report.LawrenceLivermore

NationalLaboratory,Livermore, CA.UCRL-21853.

1987-1988

Hanna,

Wyoming(Rocky Mt.)(CRIP-ELW)

93 11,400 Oxygen/steam 10Gas ResearchInstitute andMETC (USDOE)

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Appendix D: Water Analysis at Contaminated UCG Sites

Groundwater Quality UCG Hoe Creek I, from Campbell et al 1979

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Water analysis in the burn cavity before and after a UCG burn at a small Texas site, from

Humenick, MJ and CF Mattox. 1977. Groundwater pollutants from underground coal

gasification. Wat Research 12: 463-469

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