Reservoir Modeling for the Design of the

RECOPOL CO2 Sequestration Project, Poland

Topical Report

January 1, 2002 – June 30, 2002

Scott Reeves and Anne Taillefert

Advanced Resources International 9801 Westheimer, Suite 805

Houston, TX 77042

U.S. Department of Energy Award Number DE-FC26-00NT40924

July, 2002

1

Disclaimers

U.S. Department of Energy This report was prepared as an account of work sponsored by an agency of the United States Government. Neither the United Sates Government nor any agency thereof, nor any of their employees, makes any warranty, express or implied, or assumes any legal liability or responsibility for the accuracy, completeness, or usefulness of any information, apparatus, product, or process disclosed, or represents that its use would not infringe privately owned rights. Reference herein to any specific commercial product, process, or service by trade name, trademark, manufacturer, or otherwise does not necessarily constitute or imply its endorsement, recommendation, or favoring by the United States Government or any agency thereof. The views and opinions of authors expressed herein do not necessarily state or reflect those of the United Sates Government or any agency thereof.

Advanced Resources International The material in this Report is intended for general information only. Any use of this material in relation to any specific application should be based on independent examination and verification of its unrestricted applicability for such use and on a determination of suitability for the application by professionally qualified personnel. No license under any Advanced Resources International, Inc., patents or other proprietary interest is implied by the publication of this Report. Those making use of or relying upon the material assume all risks and liability arising from such use or reliance.

i

Executive Summary

In late 2001, the European Union (EU) funded RECOPOL project was launched. The project, the acronym for which stands for “Reduction of CO2 Emissions by Means of CO2 Storage in Coal Seams in the Silesian Coal Basin of Poland”, is a combined research and demonstration project to investigate the possibility of permanent subsurface storage of CO2 in coal. The field demonstration experiment is the first of it's kind outside of North America.

In 2000, the U.S. Department of Energy (DOE), through contractor Advanced Resources

International (ARI), launched the Coal-Seq project. The Coal-Seq project has the objective of demonstrating CO2 sequestration in coal seams using enhanced coalbed methane (ECBM) recovery technology. The primary demonstration sites are in the San Juan Basin, the leading coalbed methane basin (CBM) in the U.S. The specific sites are the Allison Unit, operated by Burlington Resources, and the Tiffany Unit, operated by BP America. The purposes of the field studies are to understand the reservoir mechanisms of CO2 injection into coalseams, demonstrate the practical effectiveness of the ECBM and sequestration processes (and an engineering capability to simulate them), evaluate sequestration economics, and document field procedures.

To maximize mutual learning of this emerging ECBM/carbon-sequestration technology,

and to foster cooperation between the EU and DOE, the two projects are now being coordinated. Benefits of this cooperation for the RECOPOL project include insights into field operational and reservoir performance issues gained through years of experience by San Juan Basin operators and documented by the Coal-Seq project. Benefits to the Coal-Seq project include having a field test site analogous to Appalachian basin coals such that better knowledge of the potential of this important U.S. basin for CO2 sequestration can be understood.

As originally envisioned, the RECOPOL demonstration project will involve the injection

of CO2 into a newly drilled injection well for a period of 1-2 years, with methane production from two existing and offsetting coalbed methane production wells. The purpose of this modeling study was to assist in the design of the pilot with respect to issues such as:

o Injection horizons. o Injection well placement. o Injection timing and rates.

It should be noted that an important objective of the RECOPOL project, similar to that of

the Coal-Seq project, is to be able to replicate the field results with a numerical reservoir simulator. Achieving this objective is viewed critical to enable future predictive and process optimization studies. To this end, it was viewed imperative for model validation and verification purposes that significant breakthrough of CO2 at the production wells be achieved during the field experiment. This observation would create an important performance benchmark for model calibration. Therefore, achieving this outcome was a key objective in pilot design.

ii

Based on the results from the modeling runs presented herein, the following conclusions and recommendations were made:

o Assuming CO2 availability is limited to 10,000 m3/day and for 12 months only, the location of IN-1 should be less than 100 meters from MS-4, and roughly downdip from it, to observe both significant gas production response and increase in CO2 content within 18 months after the start of injection.

o It is recommended that only the uppermost three coal layers be used for injection; the lower coals should be isolated in the production wells with a bridge plug or similar device.

o The production wells should be produced for six months prior to initiating injection to ensure that the increase in production caused by CO2 injection can be differentiated from primary production response.

o The above conclusions and recommendations are based on the input data (both for the reservoir and operationally) used for the model. Changes in those parameters would change the results and potentially these conclusions and recommendations.

iii

Table of Contents

Page 2.0 Site Description................................................................................................................... 3

3.0 Model Input......................................................................................................................... 6

4.0 Results and Sensitivities ................................................................................................... 10

5.0 Conclusions and Recommendations ................................................................................. 17

6.0 References......................................................................................................................... 17

iv

List of Tables

Page Table 1: Well Completion Information.......................................................................................... 6

Table 2: Gas and Water Production ............................................................................................... 6

Table 3: Coal Depth and Thickness Data ...................................................................................... 7

Table 4: Model Input Data............................................................................................................. 8

Table 5: Gas Content/Sorption Properties ..................................................................................... 9

v

List of Figures Page

Figure 1: RECOPOL Experimental Concept.................................................................................. 2

Figure 2: Concession Location ....................................................................................................... 3

Figure 3: Geologic Cross-Section................................................................................................... 3

Figure 4: Map of Project Area ........................................................................................................ 4

Figure 5: Cross-Section Through MS-1 and MS-4......................................................................... 4

Figure 6: Coal Occurrence Between MS-1 and MS-4 .................................................................... 5

Figure 7: Model Grid ...................................................................................................................... 7

Figure 8: Model Cross Section ....................................................................................................... 8

Figure 9: Isotherms and Initial Gas Content ................................................................................... 9

Figure 10: Relative Permeability Curves...................................................................................... 10

Figure 11: Production Response at MS-1 due to Continuous Injection of CO2 at 60 ton/day into Original Proposed IN-1 Location.......................................................................... 11

Figure 12: Production Response at MS-4 due to Continuous Injection of CO2 at 60 ton/day into Original Proposed IN-1 Location.......................................................................... 11

Figure 13: Gas Production Response at MS-1 due to Injection of CO2 at 20 ton/day for 12 Months into Original Proposed IN-1 Location ..................................................... 12

Figure 14: Gas Composition Response at MS-1 due to Injection of CO2 at 20 ton/day for 12 Months into Original Proposed IN-1 Location ..................................................... 13

Figure 15: Gas Production Response at MS-4 due to Injection of CO2 at 20 ton/day for 12 Months into Original Proposed IN-1 Location ..................................................... 13

Figure 16: Gas Composition Response at MS-4 due to Injection of CO2 at 20 ton/day for 12 Months into Original Proposed IN-1 Location ..................................................... 14

Figure 17: Gas Production Response at MS-1 due to Injection of CO2 at 20 ton/day for 12 Months into New IN-1 Location........................................................................... 14

Figure 18: Gas Composition Response at MS-1 due to Injection of CO2 at 20 ton/day for 12 Months into New IN-1 Location........................................................................... 15

Figure 19: Gas Production Response at MS-4 due to Injection of CO2 at 20 ton/day for 12 Months into New IN-1 Location........................................................................... 15

Figure 20: Gas Composition Response at MS-4 due to Injection of CO2 at 20 ton/day for 12 Months into New IN-1 Location........................................................................... 16

Figure 21: Map of CO2 Migration, Time = 2,830 days after Injection......................................... 16

vi

I.0 Introduction

In November 2001, the European Union (EU) funded RECOPOL project was launched. The project, the acronym for which stands for “Reduction of CO2 Emissions by Means of CO2 Storage in Coal Seams in the Silesian Coal Basin of Poland”, is a combined research and demonstration project to investigate the possibility of permanent subsurface storage of CO2 in coal. An international consortium was formed to execute the research, design, construction and operation within the RECOPOL project. This consortium is formed by research institutes, universities and companies from the Netherlands (TNO-NIITG and Delft University of Technology), Poland (Central Minig Institute), Germany (DBI-GUT and Aachen University of Technology), France (IFP, Gaz de France and GAZONOR), Australia (CSIRO), U.S.A. (Advanced Resources International) and by the IEA Greenhouse Gas R&D Programme. The field demonstration experiment is the first of it's kind outside of North America.

In 2000, the U.S. Department of Energy (DOE), through R&D contractor

Advanced Resources International (ARI), launched the Coal-Seq project. The Coal-Seq project has the objective of demonstrating CO2 sequestration in coal seams using enhanced coalbed methane (ECBM) recovery technology. The primary demonstration sites are in the San Juan Basin, the leading coalbed methane basin (CBM) in the U.S. The specific sites are the Allison Unit, operated by Burlington Resources, and the Tiffany Unit, operated by BP America. The purposes of the field studies are to understand the reservoir mechanisms of CO2 injection into coalseams, demonstrate the practical effectiveness of the ECBM and sequestration processes (and an engineering capability to simulate them), evaluate sequestration economics, and document field procedures.

To maximize mutual learning of this emerging ECBM/carbon-sequestration

technology, and to foster cooperation between the EU and DOE, the two projects are now being coordinated. Benefits of this cooperation for the RECOPOL project include insights into field operational and reservoir performance issues gained through years of experience by San Juan Basin operators and documented by the Coal-Seq project. Benefits to the Coal-Seq project include having a field test site analogous to Appalachian basin coals such that better knowledge of the potential of this important U.S. basin for CO2 sequestration can be understood.

As originally envisioned, the RECOPOL demonstration project will involve the

injection of CO2 into a newly drilled injection well for a period of 1-2 years, with methane production from two existing and offsetting coalbed methane production wells (Figure 1). The purpose of this reservoir modeling study was to assist in the design of the pilot with respect to issues such as:

o Injection horizons. o Injection well placement. o Injection timing and rates.

1

It should be noted that an important objective of the RECOPOL project, similar to that of the Coal-Seq project, is to be able to replicate the field results with a numerical reservoir simulator. Achieving this objective is viewed critical to enable future predictive and process optimization studies. To this end, it was viewed imperative for model validation and verification purposes that significant breakthrough of CO2 at the production wells be achieved during the field experiment. This observation would create an important performance benchmark for model calibration. Therefore, achieving this outcome was a key objective in pilot design.

Figure 1: RECOPOL Experimental Concept

2

2.0 Site Description

The Metanel concession area, on which the site exists, is located in the west-central Upper Silesian Coal basin (Figure 2). Compared with commercial CBM basins in the U.S., the Upper Silesian coal basin is structurally complex. Major east-west trending normal faults exist, some with throws approaching 1 km (Figure 3). The principal CBM targets are thin multiple coal seams of Carboniferous age.

RECOPOL ProjectRECOPOL Project

Figure 2: Concession Location

Figure 3: Geologic Cross-Section

3

A more detailed map of the project area is provided in Figure 4. Note that the X and Y scales are in meters, and north is toward the top of the figure. The two existing CBM production wells, labeled MS-1 and MS-4, are located in the center of the figure, and between two major normal faults that intersect to the south of the wells. The distance between the two wells is approximately 375 meters, with the preliminary location of the injection well closer and to the northeast of MS-4. The preliminary location of the injection well, IN-1, was based on a desire to be located between MS-1 and MS-4, as well as surface access considerations.

butt

face

butt

face

Figure 4: Map of Project Area

A north-south cross-section that passes through MS-1 and MS-4 is illustrated in Figure 5. A more detailed illustration of coal occurrence between MS-1 and MS-4 is illustrated in Figure 6. There are six coal seams completed in the production wells, and hence are the de-facto possible targets for CO2 injection. The coals dip gently at an angle of about 12 degrees from south to north, from MS-4 to MS-1.

The RECOPOL project 16t

Cross-section North-SouthS N

SHALE

SAND

COAL

Decre asing thickness variation in time indicates decre asing fault movement

Sand bodies along faults

Sand body along fault cutt ing in to coal seam 501

Si-7 Si-16 MS-4 MS-1 Si-18Si-15

501510

405

501510

405

401364357401364357

354354

Figure 5: Cross-Section Through MS-1 and MS-4

4

North South

357

401

405

501510

304

North South

357

401

405

501510

304

Figure 6: Coal Occurrence Between MS-1 and MS-4 The two existing production wells were drilled and completed by a Polish company, Metanel, and began production in September 1996. As mentioned previously, both wells were completed in all six coals, but not all zones were fracture stimulated (Table 1). The fracture stimulation procedures for all treatments are unknown, but in the case of the 501 and 510 seams in well MS-1, apparently the first treatment of the project, 14,000 lbs of 20/40 mesh sand proppant was placed with 28,000 gals of linear gel before the treatment screened out. No further information is available on the stimulation treatments. Prior to the treatments, injection/falloff and stress tests were performed in the 510 seam in well MS-1. Analyses of these data indicated a coal permeability of about 1.5 md, and an in-situ stress level of slightly over 0.8 psi/ft. The wells were produced, apparently intermittently, for between two and six months each, with disappointing results (Table 2). Hence, little depletion of the reservoir is surmised to have occurred prior to the RECOPOL project.

5

Table 1: Well Completion Information

Coal MS-4 MS-1 357 Perf Frac 364 Frac Frac 401 Perf Perf 405 Frac Frac 501 Perf Frac 510 Frac Frac

Table 2: Gas and Water Production

Gas Water Maximum Rate Cumulative Initial Rate Final Rate

MS-1 600 m3/d 9,000 m3 22 m3/d 14 m3/d MS-2 400 m3/d 3,000 m3 15 m3/d 7-8 m3/d

3.0 Model Input The reservoir simulator used for this effort was ARI’s COMET2 model. The input data for the model was (where possible) taken directly from the information available for the site, as described above. As a secondary source of information, data available for the five-well Texaco pilot CBM project, performed in 1996-98 and approximately 15-20 km to the northwest, was used1. The model grid was aligned with the face and butt cleat directions, approximately 15 degrees east of north (Figure 4). Without any data to indicate permeability anisotropy, isotropic permeability was assumed. The major faults were assumed to be sealing, and hence no-flow barriers (Figure 7). The injection well was located at the same position as that in Figure 4, approximately 175 meters from MS-4.

6

N

Figure 7: Model Grid A six-layer, 2,904 grid-block (22 x 22 x 6) model was constructed, dipping to the north at an angle of 12 degrees (Figure 8). The depths and thicknesses assigned to each layer are presented in Table 3. Note that average coal thickness values were used throughout the model, and the dip was uniform. Skin factors (completion efficiency) for each completed coal in each well was assigned a value of –3 if it was fracture stimulated, and +3 if it was not, based on Table 1. The injection well was assumed to have a skin of zero.

Table 3: Coal Depth and Thickness Data

3.21229.3-1232.52.81145.7-1148.5510

1.81221.7-1223.51.71141.1-1142.8501

3.11152.0-1155.13.11057.6-1060.7405

3.01084.0-1087.03.31004.4-1007.7401

2.01075.5-1077.52.9991.5-994.4364

1.61068.9-1070.51.3988.6-989.9357

Thickness (m)Depth (m)Thickness (m)Depth (m)Coal Seam

Well MS-1Well MS-4

3.21229.3-1232.52.81145.7-1148.5510

1.81221.7-1223.51.71141.1-1142.8501

3.11152.0-1155.13.11057.6-1060.7405

3.01084.0-1087.03.31004.4-1007.7401

2.01075.5-1077.52.9991.5-994.4364

1.61068.9-1070.51.3988.6-989.9357

Thickness (m)Depth (m)Thickness (m)Depth (m)Coal Seam

Well MS-1Well MS-4

7

NS NS

Figure 8: Model Cross Section Additional reservoir data used for the model, and their sources, are listed in Table 4. Table 5 provides the gas content and isotherm information, which are also illustrated in Figure 9. This data was provided by the RECOPOL project. Note that the Langmuir volume and methane content figures were not corrected for ash and moisture content, which were 5% each. Figure 10 provides the relative permeability curves used for the model, which are based on the modeling study of the Texaco pilot project1.

Table 4: Model Input Data

Parameter Value Source Initial Pressure

10,532 kPa @ 988.6m reference depth, pressure gradient based on

water density of 1140 kg/m3

Provided by RECOPOL

Temperature 39°C Provided by RECOPOL Porosity 0.5% Assumed Initial Water Saturation 100% Assumed Permeability 1.5 md MS-1 Well Test, 501/510 seams Pore-Volume Compressibility 200 x 10-6 psi-1 Assumed Matrix Compressibility 1 x 10-6 psi-1 Assumed Differential Swelling Factor 1.0 Assumed Permeability Exponent 3.0 Assumed Gas Composition 95% CH4, 5% CO2 Reference 1

8

Table 5: Gas Content/Sorption Properties

–4,000Desorption Pressure (kPa)

–10.0Initial Gas Content, daf(m3/metric ton)

32.020.5Langmuir Volume, daf(m3/metric ton)

1,9034,200Langmuir Pressure (kPa)

Carbon DioxideMethane

–4,000Desorption Pressure (kPa)

–10.0Initial Gas Content, daf(m3/metric ton)

32.020.5Langmuir Volume, daf(m3/metric ton)

1,9034,200Langmuir Pressure (kPa)

Carbon DioxideMethane

CO2

CH4

Initial Conditions

4000 kPa desorption pressure

CO2

CH4

Initial Conditions

4000 kPa desorption pressure

CO2

CH4

Initial Conditions

CO2

CH4

Initial Conditions

4000 kPa desorption pressure

Figure 9: Isotherms and Initial Gas Content

9

Relative Permeability Estimated for Texaco's WP-TXA CBM Pilot AreaHistory Match-Derived Curves from Run WPTXA17

0.0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1.0

0.00 0.20 0.40 0.60 0.80 1.00

Water Saturation (fraction)

Rel

ativ

e Pe

rmea

bilit

y to

Gas

(krg

)

0.0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1.0

Relative Perm

eability to Water (krw

)

krg assigned to all wells

krw assigned to all wells

Figure 10: Relative Permeability Curves Operationally, in the model the two production wells were produced for a period of six months at a bottomhole pressure of 40 psi beginning October 1, 2002, after which CO2 was injected into IN-1 continuously at a rate of 60 tons/day (32,000 m3/day). 4.0 Results and Sensitivities The results of the initial model run, comparing a case with injection to a case without any injection, are presented in Figures 11 and 12 for MS-1 and MS-4 respectively.

10

No CO2 InjectionCO2 Injection

Gas Rate

Gas Composition

Beginning of

Injection

No CO2 InjectionCO2 Injection

Gas Rate

Gas Composition

Beginning of

Injection

Breakthrough

No CO2 InjectionCO2 Injection

Gas Rate

Gas Composition

Beginning of

Injection

No CO2 InjectionCO2 Injection

Gas Rate

Gas Composition

Beginning of

Injection

Breakthrough

Figure 11: Production Response at MS-1 due to Continuous Injection of CO2 at 60 ton/day into Original Proposed IN-1 Location

No CO2 Injection CO2 Injection

Gas Composition

Beginning of

Injection

Gas Rate

Breakthrough

No CO2 Injection CO2 Injection

Gas Composition

Beginning of

Injection

Gas Rate

No CO2 Injection CO2 Injection

Gas Composition

Beginning of

Injection

No CO2 Injection CO2 Injection

Gas Composition

Beginning of

Injection

Gas Rate

Breakthrough

Figure 12: Production Response at MS-4 due to Continuous Injection of CO2 at 60 ton/day into Original Proposed IN-1 Location

11

It is clear from these results that, based on the assumptions made, a response would be observed both in terms of gas producing rate and gas composition at both MS-1 and MS-4. In both cases, a noticeable production response would be observed within 12 months. Significant gas composition responses would take longer however, with MS-4 CO2 content reaching 20% in mid-2005, +/- 27 months after injection started. The CO2 content of MS-1, however, is not predicted to reach 10% by the end of 2005. The project objective is to achieve CO2 breakthrough in at least one well within 18 months of injection; an outcome not quite achieved based on this model run. To complicate matters, the volumes of CO2 practically and economically available for injection were learned to be more on the order of 20 ton/day (10,000 m3/day) and limited to 12 months. This would render the current configuration non-compliant with the project objectives. Therefore, a decision was made to limit injection to the uppermost three coal seams only. These coals were in relatively close (vertical) proximity to each other, and were surrounded by shales that would (hopefully) prevent upward or downward migration of injected CO2. This would improve the chances for observing a response in the production wells with the limited CO2 volumes available. In addition, this would eliminate the need to deepen the production wells for effective dewatering pump installation, a need strongly recommended by the concession operator, Metanel. In addition, to better replicate the likely operational conditions, it was decided to model injection at a constant pressure, not a constant rate. However, the injection pressure was selected such that the injection rate approximated the 10,000 m3/day target rate. The results of that run, again comparing injection vs. no-injection cases, are presented in Figures 13 through 16. Note that the predicted bottomhole pressure at IN-1 required to achieve the target injection rate was just under 10,000 kPa.

No Injection

Injection for 365 days

No Injection

Injection for 365 days

No Injection

Injection for 365 days

Figure 13: Gas Production Response at MS-1 due to Injection of CO2 at 20 ton/day for 12 Months into Original Proposed IN-1 Location

12

Injection for 365 days

No Injection

Injection for 365 days

No Injection

Figure 14: Gas Composition Response at MS-1 due to Injection of CO2 at 20 ton/day for 12 Months into Original Proposed IN-1 Location

No Injection

Injection for 365 days

No Injection

Injection for 365 days

Figure 15: Gas Production Response at MS-4 due to Injection of CO2 at 20 ton/day for 12 Months into Original Proposed IN-1 Location

13

Injection for 365 days

No Injection

Injection for 365 days

No Injection

Figure 16: Gas Composition Response at MS-4 due to Injection of CO2 at 20 ton/day for 12 Months into Original Proposed IN-1 Location

As these results indicate, while a gas production response is clearly observed in both wells within 12 months of injection, no meaningful change in CO2 content of the produced gas is observed in either well. This again suggests that this pilot configuration would not satisfy the project objectives. Therefore, a further model run was made to examine whether locating the injector well closer to one of the producer wells, specifically the updip MS-4 well, would achieve breakthrough within the desired time frame. In that run, IN-1 was positioned at a distance of about 80 meters downdip of MS-4, and closer in-line with between MS-1 and MS-4. The results of that run are presented in Figures 17 through 20.

No Injection

Injection for 365 days

Injection for 365 days

New Location

No Injection

Injection for 365 days

Injection for 365 days

New Location

Figure 17: Gas Production Response at MS-1 due to Injection of CO2 at 20 ton/day for 12 Months into New IN-1 Location

14

Figure 18: Gas Composition Response at MS-1 due to Injection of CO2 at 20 ton/day for 12

Months into New IN-1 Location

Injection for 365 days

Injection for 365 days

New Location

No Injection

Injection for 365 days

Injection for 365 days

New Location

No Injection

Injection for 365 days

Injection for 365 days

New Location

No Injection

Figure 19: Gas Production Response at MS-4 due to Injection of CO2 at 20 ton/day for 12

Months into New IN-1 Location

15

Injection for 365 days

New LocationBreakthroughInjection for 365 days

New LocationBreakthrough

Figure 20: Gas Composition Response at MS-4 due to Injection of CO2 at 20 ton/day for 12 Months into New IN-1 Location

These results seem to indicate that by positioning the new injection well at a distance of 80 meters downdip from MS-4, both a significant production response and increase in CO2 content (to 20%) are achieved within about 12 months after the start of injection. This can also be observed in the map view of CO2 migration shown in Figure 21. The production response at MS-1 is much less (since the injection well is further away from and updip from it), but still observed within the project timeframe. However, an increase in CO2 content in the produced gas should not be expected at MS-1.

New LocationNew Location

Breakthrough

@ MS-4

Breakthrough

@ MS-4

Figure 21: Map of CO2 Migration, Time = 2,830 days after Injection

16

17

5.0 Conclusions and Recommendations Based on the results from the modeling runs presented herein, the following conclusions and recommendations were made:

o Assuming CO2 availability is limited to 10,000 m3/day and for 12 months only, the location of IN-1 should be less than 100 meters from MS-4, and roughly downdip from it, to observe both significant gas production response and increase in CO2 content within 18 months after the start of injection.

o It is recommended that only the uppermost three coal layers be used for injection; the lower coals should be isolated in the production wells with a bridge plug or similar device.

o The production wells should be produced for six months prior to initiating injection to ensure that the increase in production caused by CO2 injection can be differentiated from primary production response.

o The above conclusions and recommendations are based on the input data (both for the reservoir and operationally) used for the model. Changes in those parameters would change the results and potentially these conclusions and recommendations.

6.0 References

1. McCants, C.Y., Spafford, S., Stevens, S.H., “Five-Spot Production Pilot on Tight Spacing: Rapid Evaluation of a Coalbed Methane Block in the Upper Silesian Coal Basin, Poland” presented at The 2001 International Coalbed Methane Symposium University of Alabama, Tuscaloosa, May 2001, p. 193-204, Paper # 0124.