1. New Albany Shale Gas Project Project Review Presented at RPSEA Unconventional Gas Conference 2010 Golden, CO. April 6, 2010 Iraj Salehi Gas Technology Institute

2. 2 New Albany Shale An Industry-RPSEA Cooperative R&D Project Illinois Basin 86 to 160 Tcf New Albany Shale ( Gas-in-Place) 86 to 160 Tcf New Albany Shale ( Gas-in-Place) Large Geographic Area Multiple States Complex Geology Low Permeability Large Geographic Area Multiple States Complex Geology Low Permeability Large GIP with Limited Production (.3 Bcf/y) + Technically Complex = R&D Target Large GIP with Limited Production (.3 Bcf/y) + Technically Complex = R&D Target

3. 3 New Albany Shale A Fully Integrated Project Reservoir Engineering Formation Evaluation Geochemistry Hydraulic Fracturing Geology Production Data Research Quality Field Data  9 Industry participants providing data and wells of opportunity for field data acquisition and testing  9 Research organizations and 2 service companies performing the research together with engineers and geologists from the host companies

4. 44 Project Structure and Tasks  Field Data Acquisition, GTI  Geology, BEG  Geochemistry, Amherst  Formation Evaluation, ResTech  Fracture Modeling, A&M  Fracture Diagnostics Pinnacle  Reservoir Engineering,  A&M, WVU  Technology Transfer, GTI

5. 55 >360 feet of cores and complete suit of logs were taken for geological, geochemical, formation evaluation, reservoir engineering, and rock mechanics studies. >45 water samples for study of methanogenic bacterial population were taken. >Production data from over 250 wells obtained. >Several cores from public repositories studied. >One geologic field trip carried out >Surveyed a Reversed Vertical Seismic Profile (RVSP) for determination of the dominant natural fractures from velocity anisotropy New Albany Shale Field Data Acquisition RVSP

6. 6 Field Data Acquisition >Coop work with CNX; Evaluation of Zipper Frac in NAS ─Received log and core data ─Cored and logged a pilot hole ─CNX shall drill two parallel horizontal wells ─Project will use fracture modeling and microseismic imaging ─CNX shall provide production data Coring & Logging in CNX well SA-005

7. 7 Field Data Acquisition >Coop work with NGAS ─NGAS provides production data used for Reservoir Engineering studies ─Cored and logged a pilot hole ─Geochemical and petrophysical analysis of cores ─Microseismic imaging of hydraulic fractures completed ─Production from the coop well awaits installation of nitrogen rejection unit

8. 88 >Two cores from Noble Energy were studied. The project, in cooperation and cost sharing of Daugherty Petroleum (NGAS) and CNX Gas cut a total of 360 feet of cores that are being studied by BEG and other researchers. > One geologic field trip carried out. >Natural fractures in the NAS are common and have diverse origins. >Steep, partly or completely sealed fractures are likely most important for completions in NAS. >Calcite-sealed fractures form weak planes. >More complex fracture fill gives stronger planes. New Albany Shale Geology Location Of Cooperative Wells

9. 99 >45 water samples were. >Extracted DNA from samples of microbial population. >Analyzed 12 NAS samples from 12 cores. >Performed geochemical analysis on gas samples from 10 NAS wells. >Currently completing bacteria and archaea 16S clone libraries >High alkalinity and enriched residual 13 C from dissolved inorganic carbon that correlate with biogenic gas formation in previous studies have been observed. >Analysis of Antrim samples indicates that bacterial methane generation continues and may have noticeable slowed the down production decline rate. New Albany Shale Geochemistry Wells sampled, summer 2008 & summer 2009

10. 10 >41 sets of logs and core data received from producing companies. >Developed the cost matrix for various logging, coring, and core analyses for the project. >Data from several geochemical analyses were aggregated to arrive at an average desorption isotherm. >Investigated the effects of adsorbed gas on density and porosity calculation from logs and verified that the adsorbed gas has a 0.37 g/cc. New Albany Shale Formation Evaluation

11. 11 >Determine effectiveness of the horizontal open-hole packer completion process in New Albany Shale and determine azimuth and extent of hydraulic fractures. >Designed 3 microseismic and one tiltmeter fracture diagnostic surveys and performed a microseismic imaging in well DPI- 2485. >A second microseismic fracture imaging survey on well SA-005 is scheduled for April, 2010. New Albany Shale Fracture Diagnostic

12. 12 Microseismic Mapping in the Western Kentucky Low-Pressure NAS Designed 3 microseismic and one tiltmeter fracture diagnostic surveys and performed a microseismic imaging in well DPI-2485 Low-μ fluid (± 1MMSCF N 2 ) created adequate length (1,000 – 1,600 ft) & high degree of far-field complexity, but may require minimal propping excessive height growth during the last 3 stages indicates the presence of fault Primary induced azimuth of N85°E suggests optimal area lateral azimuth of N15°W Horizontal stresses  min and  max were lower in the NAS than in bounding layers, suggesting that (in absence of geological features) vertical confinement may be generally expected.

13. 13 Reservoir Engineering >Reservoir engineering studies have been challenging due to extremely low permeability and data scarcity. The project has adopted a two-pronged approach >Texas A&M is using various analytic and numerical techniques and West Virginia University is developing a top- down AI-geostatistical approach for field–level reservoir evaluation. Pressure profile after 1 and 5 years of production

14. 14 Reservoir Engineering 30 Year Production: Arps exponential.14 BSCF Arps Hyperbolic.74 BSCF Modified Hyperbolic.26 BSCF

15. 15 >Parallel to the A&M studies, West Virginia University is taking a field- level approach using the FRACGEN and NFFLOW simulation packages. >Using production data from over 250 wells obtained from Kentucky Geological Survey, WVU is developing an AI-based reservoir engineering technique for field study. >Combination of the two approaches will be a valuable tool for reserve estimate and production forecasting. Reservoir Engineering / Best Practice Analysis

16. 16 Fracture Modeling -Parametric simulation nearing completion -Modeling of NGAS well fracturing suggests that pore pressure distribution resulting from nitrogen injection has increased the virgin pore pressure by as much as 4 MPa in a large zone around the fracture. Although the calculated stress state does not show intact rock failure, the increased pore pressure is likely to trigger slip on pre- exiting cracks and induce micro-seismicity as in observed in the field. Interaction between natural and hydraulic fractures Minimum principle stress after 10 minutes of injection in NGAS well

17. 17 Environmental Considerations >States of Emphasis: Kentucky and Indiana >Primary Regulatory Agencies Contacted ─Kentucky: Department of Natural Resources (DNR) ─Indiana: Indiana Dept of Environ Mgt and the DNR >Responses from Regulatory Agencies ─Minimal Environmental Impact ─No or Minimal Flowback Water ─Low Flow Produced Water -- stored in 50 bbl tanks, then transported to permitted Class II injection wells. ─No Air Issues have surfaced (e.g. VOC’s) ─Minimal Solid Waste Issues. >Conclusion: NAS Enjoys Minimal Environmental Barriers.

18. 18 Technology Transfer

19. 19 Conclusions & Discussions  Project has developed knowledge and information for removing uncertainties regarding economics of New Albany Shale Gas, e.g.; reserve assessment, well performance; and development of efficient completion techniques  There are no environmental or regulatory obstacles at this time  Major Results:  Gas content  Gas type thermo vs bio result  Fracture Stimulation  The NAS Resource:  Is not a Barnett or Marcellus, but a truly a nanodarcy resource for the most parts  Requires gas price support  While D&C cost improvements have been significant; still requires a D&C cost breakthrough  Approach to NAS will require economy of scale  Nanodarcy technology is not yet developed  NAS is a Barnett of the future with ongoing development.  Technologies developed will be transferable to other shale gas basins that are presently considered marginal