1. Coal Bed Methane (CBM) Permeability Testing WTN Network Meeting April 28 - 29, 2011 ExxonMobil Exploration / Well Testing Team

2. ExxonMobil use only2 CBM Flow Characteristics Producing Time (yr) Gas Rate Water Rate Flow mechanism Gas desorbs when pressure drops below critical pressure After gas desorbs, it diffuses through the matrix Gas migrates into the cleats and fractures Factors that affect system permeability Cleat system, stress, diffusion, relative permeability, natural fractures other than cleats, heterogeneity Coal bed methane production Production involves dewatering the formation to lower the pressure to the critical gas-desorption pressure After first gas to surface, slow initial desorption and relative permeability create a increase in gas rate Cumulate gas production increases for a period of months/years while coal is being dewatered

3. ExxonMobil use only3 Types of CBM Permeability Testing Drill Stem Test (DST) Can be performed in both open-hole or cased-hole environment DST may be performed with high reservoir pressure, high deliverability, and reservoirs with free gas Advantages oCoals may have less near-wellbore damage oEase of readily obtaining water and gas samples oConfirm gas production early in the program Disadvantages oRelatively high cost compared to other permeability testing methods Slug Test Inject volume of water into wellbore and measure pressure response as the fluid level returns to equilibrium Advantages oLow cost, Simple to design and perform Disadvantages oDuration of the test may be long, especially if kh < 10 md-ft coal seams oMinimal radius of investigation oIt is limited to under-pressured reservoirs

4. ExxonMobil use only4 Types of CBM Permeability Testing Advantages oShort-duration test; economical for operator oResults can be used to optimize stimulation treatments Disadvantages oPseudo-radial flow signature must be observed to estimate kh Diagnostic Fracture Injection Test (DFIT) Inject fluid above the fracture gradient to estimate the reservoir breakdown and closure pressure To derive kh, after-closure analysis appears to be the preferred technique Injection Fall-off Test (IFT) Can be performed in open- or cased-hole environment It is critical to inject below fracture gradient Advantages oInjection rate is controlled. Hence, it may cover a wider range of permeability values than other methods Disadvantages oThe injection pressure must be maintained below fracture gradient, which is usually not known in an exploration setting

5. ExxonMobil use only5 Equipment Requirements for IFT Injection pump that provides constant rate (0.05 GPM to 10 GPM) Low- and high-rate flow meters connected to the data acquisition system for real-time reading Minimize pump pulsation while maintaining constant injection rate Water Filters & Assembly used to avoid plugging cleats Inflatable straddle packer assembly to isolate IFT zone with injection capability from surface Surface read-out or Redundant gauges run in memory mode Option for bottom-hole shut-in for zones with permeability < 1 md High shot density with dynamic under-balance perforation for clean perforation tunnels and to ensure good communication with the coal cleat system

6. ExxonMobil use only6 Operationally the system with straddle packers worked well Surface readout was crucial to optimize program during operations Measurement devices and pumps at limits in thin coal beds (< 0.5 m) In general it seems that injection permeability > falloff permeability Could be partly due to stress Could also be attributed to fracture/cleat opening CBM IFT - General Observations Example Log-Log Derivative Plot Wellbore Storage Extremely small due to a stiff system Does not appear to mask any other flow regime Skin Most cases show a stimulated reservoir (negative skin) Dynamic under-balance perforation system seems to have worked successfully

7. ExxonMobil use only7 Log-log Plot History Plot Pressure Analysis Example SPE paper 133356

8. ExxonMobil use only8 CBM Permeability Test Design Consideration Testing objectives Cleat system permeability to water Initial reservoir pressure Skin Relative permeability (only DST) Formation water fluid samples (only DST) Breakdown & closure pressure (only DFIT) Reservoir conditions and ranges Initial reservoir pressure Effective permeability Breakdown pressure Seam thickness and shale boundary Formation fluid composition Saturated vs under-saturated Wellbore conditions Stable Drilling conditions (wash-outs) Cementing conditions Susceptible to near wellbore damage Cost Value of information Quality of data Type of permeability test DST vs. IFT vs. DFIT (or Slug or Tank tests) Open vs. Cased hole Operations Tubing vs. wireline vs. Coil-Tubing Conventional vs. slim-hole design Rig vs. Rigless operations Larger diameter perfs vs. deeper perf tunnel (with Dynamic-Underbalance perforations) vs TCP vs. under-ream Surface read-out vs. memory gauges Stimulation: Under-ream and water flush, Slick water frac, Gel type frac with proppant, acid wash Production (DST) vs. Injection (Fresh water, inhibitive brine, weighted brine) Surface discharge vs sub-surface injection Cementing and Mud weight Design Basis Permeability Test Design