Eastern Kentucky Coal Field



Final Report

Exploring for Economic Coal Bed Methane in the Eastern Kentucky Coal Field

Final Report for Project M-06227538

Kentucky Department for Energy Development and Independence

by

Cortland Eble

Stephen Greb

Michael Solis

Kathryn Takacs

Kentucky Geological Survey

University of Kentucky

Lexington, Kentucky

40506-0107

Executive Summary

Seven samples of coal (5) and shale (2) of below drainage coal were collected from a core hole in Floyd County, Kentucky and tested for coal bed methane content and coal composition. Analyses included coal gas desorption, gas composition, proximate analysis, total sulfur content, major element oxide content, and coal petrographic composition. The coal beds and shales that were sampled, in stratigraphically descending order, were the Whitesburg coal, Kendrick Shale, Williamson coal, Dwale Shale, Van Lear coal, Alma coal and Lower Elkhorn coal; the sampling interval was from 618.80 ft to 944.70 feet from the surface. Unfortunately gas contents were low in terms of gas volume, with total gas contents ranging from 2 SCF/ton to 56 SCF/ton on a raw basis. These values are somewhat higher when calculated to a dry ash-free basis (19.17 SCF/ton to 67.01 SCF/ton). There are several reasons for this and include thin coal thicknesses, low permeability, and relatively low levels of coal maturation (rank); these factors are explained in the report. Gas composition results were more positive showing the desorbed gas to be dominantly methane (> 95 %), with relatively minor amounts of heavier gas species (e.g., ethane, propane, butane).

Other important observations include the following: 1) gas contents did not vary with depth. In fact the shallowest (Whitesburg coal) and deepest (Lower Elkhorn coal) samples had nearly identical gas yields, 2) rank was essentially the same for all of the coal samples (i.e., did not increase with depth), 3) gas content was found to be inversely proportional with ash yield (e.g., lower ash = higher gas content), and 4) gas content was found to vary proportionally with sample thickness (e.g., thicker coal = higher gas content).

Although the results of this study were less than encouraging in terms of gas content the results of this study have provided a great deal of insight into the most favorable areas of the Eastern Kentucky Coal Field to drill for economic coal bed methane. These areas are principally located to the southeast, along the trend of the Eastern Kentucky Syncline, where thicker coal occurs. It is hoped that future exploration efforts will benefit from the geologic framework that was developed during the course of the present work.

Table of Contents

Content Page Number

Executive Summary 2

Table of Contents 4

Introduction 6

Coal Bed Methane as an Energy Resource 6

Environmental Aspects of Coal Bed Methane 7

Methane in Eastern Kentucky Coal – How Much? 8

Implementation 9

Geology 9

Background 10

Sample Acquisition 11

Desorption 12

Stages of Gas Measurement 12

Lost Gas 12

Measured Gas 13

Residual Gas 13

Gas Collection 14

Sample Sizing 14

Geochemical Analyses 14

Proximate Analysis 14

Total Sulfur Content 15

Calorific Value 15

Major and Minor Elements 16

Coal Petrology 16

Results 17

Discussion 19

Conclusions 20

Acknowledgements 21

References 22

Figure Captions 25

Figures (1 – 20) 28 - 47

Appendix 1 – Core Description

Appendix 2 – Analytical Summary

Introduction

Kentucky has two geographically distinct coal fields, the Eastern Kentucky Coal Field, and the Western Kentucky Coal Field. The purpose of this study was to evaluate the coal bed methane gas potential of the eastern Kentucky Coal Field (EKCF), which occurs along the western margin of the Central Appalachian Basin (Figure 1). Kentucky is the third largest coal-producing state in the U.S. with 115.3 million short tons of coal being produced in 2007 (87.1 million tons from eastern Kentucky and 28.2 million tons from western Kentucky), down 5.6 million tons from the previous year (-4.6 %).

Coal resource estimates by the Kentucky Geological Survey indicate that the Commonwealth has approximately 88 billion tons of remaining coal resources, some of which is unmineable using present extraction technologies. For example, of the 52 billion tons of remaining resources in eastern Kentucky 52 % is between 14 and 28 inches thick, too thin to underground mine by conventional methods (Figure 2). And although the EKCF is generally regarded as a low sulfur resource, nearly a quarter of the resource (22 %) has sulfur dioxide emission values of 1.68 to 2.5 lbs SO2 / MMBTU, which is too much to be burned without SO2 control technology (Energy Information Administration data) (Figure 3). Both factors (thickness and sulfur content) have been, and will continue to be, limitations to production.

Coal Bed Methane as an Energy Resource

The extraction of coal bed methane (CBM) in the EKCF may be one way to make further use of this extensive energy resource, especially in areas where the coal cannot be mined economically. Methane, which is the dominant gas species in natural gas, is a much cleaner-burning fuel from an emissions standpoint (it produces approximately 1.4 pounds of CO2/ MM BTU versus approximately 2.2 pounds CO2 for bituminous coal, U.S. DOE data), and the production of CBM has a negligible effect on the local environment compared to conventional coal mining, especially surface mining. CBM could also play a major role in providing the hydrogen needed to power fuel cells and coal-to-liquids technologies that may be important for future electric power generation, the transportation sector, and the military.

Environmental Aspects of Coal Bed Methane

Methane is a greenhouse gas, meaning that its presence in the atmosphere affects the Earth’s temperature and climate system. Due to its relatively short life time in the atmosphere (9-15 years) and its global warming potency — 20 times more effective than carbon dioxide (CO2) in trapping heat in the atmosphere — reducing methane emissions should be an effective means to reduce climate warming on a relatively short timescale. Anthropogenic (human-influenced) sources of methane include landfills, natural gas and petroleum production and distribution systems, agricultural activities, coal mining, stationary and mobile combustion, wastewater treatment, and certain industrial processes. About 60% of global methane emissions come from these sources and the rest are from natural sources. Natural sources include wetlands, termites, oceans, and hydrates. Hydrates consist of methane molecules each surrounded by a cage of water molecules and are present in seafloor deposits around the world (ICCP, 2001).

The historical record, based on analysis of air bubbles trapped in ice sheets, indicates that methane is more abundant in the Earth’s atmosphere now than at any time during the past 400,000 years (ICCP, 2005). Over the last two centuries, methane concentrations in the atmosphere have more than doubled. However, in the past decade, while methane concentrations have continued to increase, the overall rate of methane growth has slowed (Dlugokencky et al., 2003). Given our incomplete understanding of the global methane budget, it is not clear if this slow down is temporary or permanent. Once emitted, methane is removed from the atmosphere by a variety of processes, frequently called “sinks.” The balance between methane emissions and methane removal processes ultimately determines atmospheric methane concentrations, and how long methane emissions remain in the atmosphere. The dominant sink is oxidation by chemical reaction with hydroxyl radicals (OH).

Methane in Eastern Kentucky coal – How Much?

CBM presently contributes about 10 % of the total natural gas that is produced in the U.S., and this is predicted to increase. Although CBM has seen an expansion in production in neighboring Virginia and West Virginia, CBM production in the EKCF has remained largely dormant. This is mainly due to historical gas content data that shows coals in the EKCF to have low methane contents (Diamond et al., 1986) (Figures 4, 5). However, other data suggest the presence of potentially economic CBM. Federal Mine Safety and Health Administration ventilation experts in eastern Kentucky indicate that where the Pond Creek coal (a major economic coal bed in eastern Kentucky, (Figure 6) is mined below drainage, 500,000 to 1,000,000 cubic feet of methane are commonly liberated daily. Indeed, one of the worst mine explosions (Figure 6) in the history of the EKCF occurred at the Scotia mine where the Imboden coal (a Pond Creek equivalent) was being mined below drainage (Diamond, 1994). Likewise, the application of the Kim Formula (Kim, 1977), a widely used method of indirectly estimating gas contents from coal analytical data indicated that significant gas contents might be present in Kentucky coal beds The Kim formula is as follows:

Gdaf = (0.75)(1-a-m) * [Ko(0.095d)N – 0.14(1.8d/100 + 11)]

Ko = 0.8(Xfc/Xvm) + 5.6 and

No = 0.315 – 0.01 * (Xfc/Xvm)

where: Gdaf = dry, ash free storage capacity in cm3/g; a = ash content, weight percent; d = sample depth in meters; Xfc = fixed carbon, weight percent; Xvm = volatile matter, weight percent.

The Kim formula was applied to 704 coal analysis records from the Kentucky Geological Survey data base. Results indicate a median value of 324 cubic feet of CBM per short ton of coal for below drainage coal beds in the EKCF (Figure 7). Collectively, we believe that these data, along with the increased demand for natural gas, and higher gas prices, justifies the need for increased research and exploration for economic CBM in the EKCF.

Implementation

Geology

The EKCF consists mainly of sandstone, and siltstone, with minor amounts of impure limestone and coal. In order to identify areas that have the potential for economic CBM, it is important to analyze all available data from subsurface coals to determine the most promising areas that will have sufficient coal thickness for economic CBM. To accomplish this, data from the KGS borehole data base, results of regional coal bed mapping, and analysis of oil and gas well logs that had density signatures were all evaluated. From these data, it was decided that the best part of the EKCF to evaluate deep strata for economic CBM is in an area where the Eastern Kentucky syncline transects the coal field (Figure 8). In this area, coal-bearing rocks assigned to the Grundy, Pikeville and Hyden Formations (Figure 9) occur below the level of regional stream drainage, and exist at sufficient depth for methane retention (> 500 ft, i.e., in all likelihood the CBM has not “leaked” to the atmosphere). Rocks below the base of the Grundy Formation are largely dominated by thick orthoquartzitic (almost pure quartz) sandstones with only a few thin, discontinuous coal beds. This is unfortunate as these thick sandstones are the lateral equivalents of the coal-rich Pocahontas and New River Formations of SW Virginia and southern West Virginia, areas with substantial CBM production (Figure 9). Indeed, CBM Operations in SW Virginia primarily target two adjacent fields known as the Oakwood Field and the Middle Ridge Field. These fields, along with the nearby Nora Field, contain some of the gassiest coal in the Western Hemisphere, with gas content of between 400-600 cubic feet per ton. If these three fields were listed as one field by the U.S. Department of Energy, it would rank near or in the top 10 of all gas fields in the U.S.

Figure 10 is a cross section (Chesnut, 1992) across part of the EKCF that illustrates the stacking and dip characteristics of the rock units referred to in Figure 9. The area that has the thickest accumulation of below drainage coal-bearing strata occurs in the center/right center of the diagram. This became the target area for potentially economic CBM production. Maps were constructed using the data sources described above, one showing the cumulative coal thickness of coals > 1 foot thick below 500 feet of cover (Figure 11), and another for coals > 1 foot thick below 1000 feet of cover (Figure 12). These two maps were ultimately used as guides to select the most promising area for drill core testing.

Background

The accumulation of methane in underground coal mines continues to be a safety problem in the United States and around the world. Concern regarding fugitive methane from coal is so great that it has led the U.S. Environmental Protection Agency to develop a program called CMOP. CMOP stands for Coalbed Methane Outreach Program (CMOP), which is a voluntary program with a goal of reducing methane emissions from coal mining activities. CMOP's mission is to promote the profitable recovery and utilization of coal bed (CBM) and coal mine methane (CMM).

Measuring the quantity of methane contained within a coalbed can be an important step in evaluating the potential severity of gas problems in new mines or in unmined areas of existing mines. Gas content testing can be included in the exploratory core drilling program usually conducted during the planning phase of mine development (Diamond, 1979). An early assessment of the potential for methane emission problems provides the greatest amount of lead time to incorporate longer term gas drainage techniques into the mine development plan (Diamond, 1994; Diamond and Schatzel, 1998). However, whereas mine safety was initially the primary purpose for measuring the gas content of coal beds, the potential for commercial coal bed methane production has resulted in an major interest in this technology.

The coal bed gas content testing procedure used in the present study was developed by Dr. Charles Barker of the U.S. Geological Survey (retired). It is essentially an improvement on the technique commonly referred to as the USBM direct method (Kissell et al., 1973). As mentioned previously, the original USBM method was an adaptation and simplification of the method developed by Bertard et al. (1970).

Sample Acquisition

Initially, we had hoped to have access to samples from two to three drill holes. However, two of the companies that had originally agreed to provide access to drill core were unable to honor their commitment, mainly because of a general lack of interest in CBM in eastern Kentucky. As such, we were only able to obtain one drill core, which unfortunately, was outside of the area determined to have optimal conditions for encountering cumulatively thick coal. Nonetheless, we are especially grateful to Beech Fork Coal Company for providing the core samples. A geologic log of the drill hole is shown in Appendix 1, and a location map of the site, which is very close to the confluence of the Martin, Johnson and Floyd county lines, is illustrated in Figure 13. A picture of the drill site is shown in figure 14. As the drilling took place on top of a ridge top that had previously (mid 1970’s) been mountain top (surface) mined, only coals and shales that occurred at, or below, drainage were sampled. At this location, the Fire Clay coal was determined to be at local drainage level (582.00 feet), based on its mapped position on the Offutt geologic quadrangle map (Outerbridge, 1964) relative to adjacent stream elevation. The coals and shales that were sampled, and their respective canister numbers, are highlighted on the drill log. The names assigned to the sample units are based on the analysis of surrounding drill cores on the company property, and KGS geologic quadrangle information.

Desorption

The nature of CBM is different from that of conventional natural gas. Rather than existing as a “pool” at depth, the methane molecules are adhered to the surface of the coal and held in place by geologic and hydrostatic pressures (Yee et al., 1993). As methane has an affinity for coal, as well as most other organic matter, Van der Waal bonding is also a factor (Figure 15). Desorption measurements are summarized in Appendix 2.

Stages of gas measurement

Lost Gas – timing is critical in the collection of samples for CBM analysis, and as such, we register the time the coal is “cut” by the drill bit, the time it arrives at the surface, and the time it is placed and sealed in specialized desorption canisters (Figure 16). Collectively this is recorded as “lost gas” and is estimated by taking a series of closely-spaced (time-wise) measurements through which a regression curve can be drawn through the X-axis, which in part represents lost gas time. Lost gas regression lines can be observed in Appendix 3. A specialized instrument keeps record of time, temperature, and barometric pressure.

Measured gas – as the coal liberates gas, it is incrementally measured and recorded. The sampling intervals depend on the amount of gas being given off. Gas measurements are taken with a device called a manometer, which essentially measures how much water is displaced when the CBM canister valve is opened Figure 17).

Residual gas – The volume of gas desorbing from a coal sample gradually declines with time. Desorption measurements for the extended desorption techniques are terminated at some point when an arbitrary low desorption rate is reached. This rate may be reached in a matter of days for very friable samples or can take months for some blocky coals. When gas liberation has become minimal the coal is taken out of the canisters and run through a “hammermill crusher”, a device that reduces the solid core to a size of approximately 10 mesh (top size 2 mm), and then returned to the canister and resealed. Special attention is placed on making certain the canister cap has a clean, firm seal. Closely-spaced measurements are again taken to record any gas that was lost during the crushing/transfer process, followed by a series of gas measurements until no further gas is liberated.

Analysis of the gas content component parts for 1,500 coal samples from 250 coal beds in the United States (Diamond et al., 1986), shows that residual gas can comprise 40 to 50% of the total gas content, in particular for relatively low-rank (high volatile-A bituminous) blocky coal beds. In contrast, friable, high rank (medium to low volatile) bituminous coal beds typically had less than 10% residual gas. As such, caution must be used in evaluating the resource recovery potential of coal beds with high residual gas contents, since they may represent methane that will not readily flow to a methane drainage borehole under field conditions. Residual gas may also represent a portion of the total gas content that will not be admitted into a mine atmosphere either from migration to the mine openings from the surrounding coal or from the mining of the coal at the face.

Gas collection – after approximately one week, gas samples were drawn into vaccutainers (the same types of vials used to collect blood) using a specialized device for gas species analysis. All gas analyses were performed on a gas chromatograph that records methane and higher carbon species. One sample was drawn for conventional desorption, and another for residual gas. Results are shown in Appendix 2.

Sample sizing – once all gas had been liberated, all samples were further crushed using a sample pulverizer to 60 mesh (top particle size 250 microns). The 18 mesh size fraction from the hammermill was used to construct petrographic pellets; the 60 mesh pulverized fraction was used for geochemical and gas composition analysis.

Geochemical Analyses

All geochemical analyses were performed by geologists and geochemists at the Kentucky Geological Survey (KGS). The analyses that were performed were:

Proximate analysis – a proximate analysis records the amount of moisture, volatile matter, ash and fixed carbon. All proximate analyses were performed on a Leco TGA 701. All samples were run in duplicate to check for errors. The instrument consists of a chamber with a rotating plate with 12 perforations that hold high temperature porcelain crucibles. Crucibles are filled with 1 gram of coal, weighed, and placed in a perforation on the disk wheel. Following this step, the chamber is sealed with an airtight lid and the internal temperature is ramped up to 105o C. The wheel holding the crucibles automatically rotates to a position above a special heat-tolerant scale. Each crucible is continuously weighed in this manner until negligible weight loss is observed. The difference between the initial and final weights is termed “as-determined moisture”. The lid then opens, porcelain covers are placed on the crucibles and the lid closes again. The chamber is flooded with nitrogen gas and the internal temperature is brought up to 950o F. The same “turn and weigh” procedure, as was used for moisture determination, is used during this phase to measure volatile matter content. The initial versus final weights provides the percentage of volatile matter in the sample. Following this step, the furnace cools down to 650o and the lid re-opens. The crucible covers are removed, the lid closes and the chamber is flooded with pure oxygen. The internal temperature ramps back up to 750o C and the remaining sample is burned. The same “turn and weigh” concept that was used for moisture and volatile matter determination remains the same. After no weight loss is detected during this final step the lid opens and the crucibles are allowed to cool. The weight of the original empty crucible compared to the crucible with the residue is a measurement of the percent ash in the sample. All three parameters are added together and subtracted from 100. The resulting value, which is a calculated and not measured value, is termed “fixed carbon”. All proximate analysis results are shown in Appendix 2.

Total Sulfur Content - Total sulfur contents were determined with a Leco® SC 144DR sulfur analyzer. All samples were run in duplicate to check for unacceptable analytical deviation. In practice, ¼ g of sample is placed in a porcelain carrier that is boat-shaped. The sample is fed into a furnace at a temperature of 1350o C where it combusts. The resulting gases are channeled through tubes filled with magnesium perchlorate (MgClO4) to remove any fugitive moisture. The “dried” gases are then fed into an infrared analyzer which measures the amount of sulfur dioxide (SO2) and sulfur trioxide (SO3).

Calorific Value - Calorific values were measured using a Leco® AC500 bomb calorimeter. One-half gram of sample is placed in a specialized holder, to which a specialized ignition wire was attached. The holder was then placed in a stainless steel vessel, closed tightly with a threaded cover and pressurized with 400 pounds of pure oxygen. The vessel was then placed in a water bath of known temperature and the material inside the container was ignited by electric arc. The resulting change in temperature records the calorific value of the material in question, which usually is presented as “BTU / pound (joules / gram is the metric equivalent).

Major and minor elements - Thirteen major and minor elements were measured by a Haskey® X-Ray Fluorescence unit. In practice, the ash residue from the proximate analyses are placed in a highly specialized instrument. Ash was combined with lithium tetraborate (Li2B4O7) and then heated to 950o C to produce a fused disk that helps disperse the ash, which in turn produces more accurate results. All XRF data are shown in Appendix 2.

Coal petrography - Approximately 2 to 3 g of 18 mesh coal were mixed with petrographic epoxy and placed in 2.5 cm round molds called “pellets”. These were allowed to cure overnight, or until completely hard. The pellets were then placed in a special holder and ground and polished. This was accomplished with grit paper (400 and 600), alumina slurry (1 and 0.5 micron), and finally 0.05 micron colloidal silica. The result is an almost scratch-free polish. Coal is composed of “macerals”, which are analogous to minerals in rocks (i.e., the building blocks). All analyses were performed on a Zeiss® USMP microscope under incident (reflected) light. The following macerals were identified using both white (regular tungsten) and blue (fluorescent) lighting:

Vitrinite

Telinite

Telocollinite

Desmocollinite

Vitrodetrinite

Liptinite

Sporinite

Cutinite

Resinite

Liptodetrinite

Inertinite

Fusinite

Semifusinite

Macrinite

Micrinite

Inertodetrinite

Vitrinite macerals are derived from the wood and bark of ancient plants. Liptinite macerals are volatile material such as spores and pollen, cuticles and resins. Inertinite macerals represent vitrinite precursors that have become oxidized by fire or microbial degradation (Figure 18). Five of the seven collected samples were analyzed petrographically; samples with more than 50 % ash (e.g., canisters 31 and 32) are difficult to analyze and, more often than not, produce inaccurate results, and as such were not analyzed. In practice, maceral percentages were determined by point-counting 250 points per sample. Vitrinite reflectance was recorded using a glass standard of known reflectance as a standard reference. All reflectance measurements were recorded after standardization at 0.96 % Ro (percent reflectance using an oil immersion objective). Fifty points were counted for each sample on pieces of telocollinite to insure that all measurements were being made on the same material. Petrographic data is listed in Appendix 2. Although the thermal maturity of coals can be estimated from geochemical data (ASTM, 1992), vitrinite reflectance was used as it is commonly believed to be more accurate

Results

Overall, the collected samples had very low total gas contents, ranging from a low of 2.1 SCF/ton to a high of 56.41 SCF/ton on a raw basis (Appendix 2). On a dry, ash-free basis (DAF) the range is from 19.17 SCF/ton to 67.01 SCF/ton. By comparison, coals producing CBM in SW Virginia (Pocahontas Field), and the Black Warrior Basin in Alabama commonly have gas contents of 200 to 600 SCF/ton (e.g., Diamond et al., 1976). The reason for this disparity is most likely due to the Pocahontas and Black Warrior Basin coals being of higher rank (higher level of metamorphism). The vitrinite reflectance values observed in the present work ranged from 0.69 % Ro to 0.75 % Ro, placing them in the high volatile bituminous rank category (Figure 19). Pocahontas and Black Warrior Basin coals, in contrast, are low volatile bituminous in rank and typically have reflectance values of 1.3 to 1.6 (C.F. Eble, unpublished data). In addition, the coals from these two producing areas are also, in general, much thicker (typically < 5 feet). The thickest coal in the present study was only 2.9 feet thick (3.1 ft if you add in a 0.2 ft bone coal parting).

In western Kentucky, a prior CBM study in the Eastern Interior Basin by Eble et al. (1995) indicated that Carbondale Formation coal bed gas contents ranged from 45 scf /ton to 111 scf/ton (raw basis). Parallel testing in Indiana and Illinois and Indiana showed similar gas contents, though in at least one case a gas content of 149 scf/ton was recorded from the Seeleyville coal in southern Indiana (Drobniak et al., 2004).

Two other important observations arose from this study. First, no lost gas was observed. This could partially be explained by the coring method being wireline, which brings the coal/shale to the surface much more quickly than a conventional core rig. However, the low gas contents need to be considered as a contributing factor as well (i.e., fast core extraction + low gas contents = no lost gas). Second, examination of the desorption data from Appendix 2 indicates that the residual gas contents (after the coal had been crushed) are approximately twice that of the desorbed gas. For example, the average measured raw gas value for the seven samples is 8.29 SCF/ton, whereas the average residual gas value for the seven samples is 17.45 SCF/ton. Although actual permeability testing was not done, the disparity between the volumes of desorbed gas versus residual gas are indicative of very low permeability’s. A good example of this is the Kendrick Shale sample (canister 32 in Appendix 2), which showed no desorbed gas, but liberated a small amount once it was crushed. Examination of the data showed no correlations between analytical parameter and gas content, with one exception – coal thickness. Future work should examine this further, but in any case it appears likely that well stimulation of some type will be necessary for economic production.

One very promising finding of this study was the relative purity of the gas. Methane contents were in the 95 to 96 % range for all samples, save one (canister 27), which could not be tested due to analytical difficulties. Ethane is the next common gas species, ranging from 0.49 % to just under 4 % (3.97 %), with heavier hydrocarbons (i.e., propane, butane, pentane and hexane being minor components). These findings are consistent with the pioneering work of Kim (1973), as well as with a more comprehensive data set developed by Rice (1993).

Discussion

Gas contents were disappointing in terms of gas volume (Appendix 2). There are many reasons for this. First, we were not able to drill in an area that we would have preferred. The drilling site that was provided through industry support was close to the juncture of the Floyd/Martin/Johnson County lines. This area is outside of the eastern Kentucky syncline where coals are relatively shallow, thin and are high volatile bituminous in rank (i.e., compared to Pocahontas and Black Warrior Basin coals, they are more thermally immature). Examination of the drillers log (Appendix 1) shows some thick coal present near the top of the hole, but coal thickness falls off rather dramatically down hole. All of these factors were likely contributors to the low gas contents that were observed.

Although it is difficult to draw any correlation between the tested parameters because of the small number of samples, a few things are apparent. First, there doesn’t appear to be any relationship between gas content and depth. For example, the shallowest sample, the Whitesburg coal (total raw gas = 32.53 scf/ton), produced essentially the same amount of total gas as did the deepest sample, the Lower Elkhorn coal (total raw gas = 31.92 scf/ton). Second, gas contents are higher in samples that are lower in ash yield. Put another way, the four coal samples that produced the most gas (Whitesburg, Van Lear, Alma and Lower Elkhorn) were lower in ash (average 13.9 %, dry basis) than the Kendrick and Dwale Shales (average 87.4 %, dry basis), and the Williamson coal (42.3 % ash, dry basis). This is not too surprising as methane preferentially adheres to the organic part of coal, rather than the inorganic (mineral matter) fraction. A similar trend has been noted for coals and organic-rich shales in SW Indiana (Mastalerz and Kvale, 2000). Third, there doesn’t appear to be any correlation between total vitrinite content and gas content. Two of the highest yielding gas samples, the Whitesburg (total gas content = 32.53 scf/ton; total vitrinite content = 74.8 %, mineral matter free basis) and the Van Lear (total gas content = 42.38 scf/ton; total vitrinite content = 80.0 %, mineral matter free basis), are high in vitrinite, while two others, the Alma (total gas content = 56.41 scf/ton; total vitrinite content = 68.4 %, mineral matter free basis) and the Lower Elkhorn (total gas content = 31.92 scf/ton; total vitrinite content = 68.0 %, mineral matter free basis). Fourth, of the four coals that were low to moderate in ash, the thicker coals yielded more gas. The two thickest coals (Van Lear, 2.10 feet thick and Alma, 3.10 feet thick) produced more gas than the two thinner coals that were sampled (Whitesburg, 1.50 feet thick and Lower Elkhorn, 1.20 feet thick). Clearly though, additional data from other areas in the EKCF is needed to help clarify these brief observations.

Conclusions

Although the results of this study were less than encouraging, areas to the southeast where thicker coal occurs may produce more positive results. Further exploration, especially in areas of the EKCF that have thicker coal accumulations (e.g., the Eastern Kentucky Syncline), would verify this. The low gas contents and low permeability’s are definitely obstacles to future production. As such, well stimulation, by fracturing or horizontal drilling (or a combination of both), will most probably be necessary to produce economic CBM. Indeed, horizontal drilling is currently being employed for CBM production in other parts of the Central and Northern Appalachian Basin. One bright spot is that the gas that was collected and analyzed was almost pure methane with minimal contamination of heavier gases. This is encouraging, especially if future drilling shows this trend to extend into deeper parts of the coal field, as it is of “pipeline” quality as is. It wouldn’t have to be blended in with gas from other sources.

Ultimately, it seems likely that gas prices, which are extremely difficult to predict, will dictate whether or not CBM in eastern Kentucky will be an economically viable energy resource. Virtually every long range forecast for energy consumption shows the demand for natural gas to continue to rise through 2025 (U.S. Department of Energy). Gas prices are likely to increase as well. If natural gas doubles, or even triples in price, then more interest may be placed on the CBM potential of eastern Kentucky coals.

Acknowledgements

The authors wish to thank the Kentucky Department for Energy Development and Independence (formerly the Governer’s Office for Energy Policy) for funding this study. Ms. Talina Mathews and Mr. Brad Stone are especially thanked for their encouragement and timeless patience throughout the extended timeframe of this investigation. Mr. Ted McGinnis, president of the Beech Fork coal company is thanked for providing us access to drill core samples, and accessory drill core information. Mr. Henry Francis, Mr. Jason Backus, Ms. Andrea Mitchell and Mr. Steven Mock, all members of the Kentucky Geological Survey’s Laboratory section, are thanked for their careful analyses of the collected samples. Finally, Dr. James Cobb, Director and State Geologist, and Mr. David Harris, head of the Energy and Minerals section, are thanked for their support of this, and other, research projects.

References

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Figure Captions

1. Map showing the position of the Eastern Kentucky Coal Field (EKCF), which is part of the Central Appalachian Basin (see inset map).

2. Pie chart showing that of the 52 BT of remaining coal resources 52 % of coal reserves in eastern Kentucky are in the 28 to 32 inch category.

3. Pie chart showing that although the EKCF is generally regarded as the “low sulfur field”, nearly half (47 %)of the resource is of medium (1.68 to 2.5 lbs SO2/MM BTU) to high sulfur content (< 2.5 lbs SO2/MM BTU). Sulfur categories are from the U.S. DOE Energy Information Administration.

4. Estimated in-place CBM resources for both the Eastern and Western Kentucky coalfields.

5. Summary of available desorption data from the (now defunct) U.S. Bureau of mines for eastern Kentucky coals.

6. Historical summary of mine explosions in Kentucky. This diagram clearly illustrates that, in places, coal bed gas exists in significant volumes to trigger ignitions.

7. Calculated values for potential CBM using the Kim method. All data used in the formula are from the Kentucky Geological Survey Coal Quality data base. As can be seen, the calculated values overestimate the measured data rather significantly.

8. Map showing the position of the east Kentucky syncline, which is a major structural feature in the EKCF. This structural feature was a significant guide for identification of potential CBM source areas.

9. Stratigraphic chart showing the position of major coal beds and marine zones. Coals in the Pikeville and Grundy Formations are highlighted as they represent the greatest number of beds that exist below drainage across most of the coal field. This was the target interval for the study. Also note that eastern Kentucky does not have any of the high gas content Pocahontas coals that are currently being exploited in adjacent SW Virginia. The lateral equivalent of the Pocahontas Formation of SW Virginia and SE West Virginia is a massive sandstone unit called the Warren Point Sandstone Member.

10. Pineville strike section from Chesnut, 1992 (see Figure 9 for the position of this section). Sea level is the datum for this section. Note that strata of the Pikeville and Grundy Formations are the most consistent Formations that exist below drainage, and therefore have the best potential for economic CBM.

11. Cumulative thickness map for below drainage coals at least 1 foot thick and 500 feet deep.

12. Cumulative thickness map for below drainage coals at least 1 foot thick and 1000 feet deep.

13. Well location map showing the position of the drill hole that was sampled. The core sight is in Floyd County very close to the triple juncture of the Floyd, Martin and Johnson County lines. Detailed location information is included with the core description in Appendix 1.

14. Photograph of the coring rig with above drainage core laid out for inspection, description and sampling.

15. Diagram showing the nature of CBM. CBM is an “unconventional” gas resource in that it adheres to the surface of the coal, rather than occurring in discreet pore spaces between mineral grains of certain rock types (e.g. sandstone).

16. CBM canisters used to measure gas contents. The canisters shown in this photograph are constructed of an aluminum alloy. The KGS also uses canisters made with PVC (polyvinyl chloride). Regardless of the canister composition, each has a valve at the top to release gas for measurement and sampling.

17. Gas measurement using a monometer. A manometer is simply a device (there are several varieties) that measures gas volume by the displacement of water. The manometer in this photograph is designed for field testing, and as such, is constructed of high density plastic for durability.

18. Photomicrograph of a polished coal sample from canister 30 in reflected light. Magnification is 640X. The gray material is vitrinite, the white material is inertinite, and the black material is liptinite. See Appendix 1 for a more critical breakdown of maceral components in the examined samples.

19. Thermal maturation comparison diagram.

20. Diagram showing past, present, and projected use of different energy sources in the U.S. (source: Energy Information Administration, U.S. DOE).

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