Appendix D Evaluation of Coalbed Methane Well Types in the San Juan Basin (November 2005 and March 2004)

Transcription

1 Appendix D Evaluation of Coalbed Methane Well Types in the San Juan Basin (November 2005 and March 2004)

2 EVALUATION OF COALBED METHANE WELL TYPES IN THE SAN JUAN BASIN DRAFT REPORT Prepared for Bureau of Land Management November 2005 MHA Petroleum Consultants, Inc.

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4 DRAFT EVALUATION OF COALBED METHANE WELL TYPES IN THE SAN JUAN BASIN Table of Contents Introduction...1 Summary...1 Selected Responses to DEIS...3 Responses by Entity...4 Operator One...4 Citizen Contributor...4 La Plata Energy Council...5 Operator Two...5 Public Lands Advocacy...5 Operator Three...6 Comparison to Other CBM Plays...6 San Juan Basin CBM Wellbore Stability Modeling...7 Background...7 Application to NSJB Project Area...8 Wellbore Stability Model Findings: Uncemented Horizontal Wells...10 Scoping Economics for San Juan Basin CBM...12 Economic Input...12 Economic Results...13 San Juan Basin Performance Analysis...13 Performance Comparison of Horizontal & Offsetting Vertical Wells...13 Industry Drilling Practices...16 CBM Literature Review...18 References...20 List of Tables...21 List Of Figures...21 Appendices...22 MHA Petroleum Consultants, Inc. i

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6 DRAFT EVALUATION OF COALBED METHANE WELL TYPES IN THE SAN JUAN BASIN Introduction At the request of the San Juan Basin Public Lands Center, MHA Petroleum Consultants, Inc. (MHA) has updated its report, Evaluation of Coalbed Methane Well Types in the San Juan Basin, prepared for The Bureau of Land Management in March This report compared the performance of San Juan Basin (SJB) horizontal and highly deviated wells with offsetting vertical wells, provided a comprehensive literature review concerning the application of horizontal wells in coalbed methane (CBM) reservoirs, and recorded input from SJB operators employing horizontal well technology. MHA s March 2004 report was included in the San Juan Basin Public Land Center s Draft Environmental Impact Statement that was issued in June The following report updates the previous comparative analysis of horizontal and vertical well performance and provides some additional information from industry literature and basin operators. In addition, MHA was asked to provide comments regarding the public and industry responses to the DEIS pertaining to the SJB CBM resource and its exploitation using horizontal wells. In order to address these DEIS responses MHA has included information that compares the SJB Fruitland Coal with CBM resources in other geographic areas and basins. MHA has also included the results of wellbore stability modeling in an attempt to provide additional quantitative guidance concerning the suitability of horizontal wells in the Northern San Juan Basin study area. Finally, MHA has performed economic analysis of typical horizontal and vertical SJB wells in order to provide some context to the conditions under which each well type would be economically attractive. Summary Since March 2004 CBM development using horizontal wells has accelerated in the Arkoma and Appalachian basins because these areas contain thin, low permeability, high strength coals that are excellent candidates for horizontal wells. Furthermore, drilling costs in these areas are lower than the SJB and gas prices are higher due to proximity to substantial markets. Since March 2004 only a handful of horizontal CBM wells have been drilled in the SJB and it may be too early to tell if they will be economic successes. In the near term, wellbore stability issues (hole collapse and coal fines production) continue to be problems that SJB operators must address when drilling horizontal wells. In the longer term, there remain questions about 1) the effectiveness of horizontal wells in draining the coal(s) in which the horizontal well is completed and, 2) the feasibility of re-entering horizontal wells upon depletion of the first coal seam(s) in which they are drilled and drilling additional laterals to produce undepleted coals. It is believed there are presently 19 horizontal CBM wells producing in the SJB (although public records are sometimes inconsistent and some operators seem reluctant to acknowledge horizontal wells and discuss their performance). Compare to vertical well offsets these horizontal wells have exhibited maximum sustained rates of between zero and 12 times those of the offset vertical wells; the average horizontal well produced at a sustained rate of 2.08 times that of the nearby vertical wells. Estimates of ultimate gas recovery are inherently more MHA Petroleum Consultants, Inc. 1

7 DRAFT uncertain but it appears that the horizontal wells will recover just under twice as much gas (1.85 times) that of the offset vertical wells. Five of the horizontal wells, or just over 25 percent, may produce more than three times as much gas as the average offset vertical well. The performance of 16 highly deviated wells was examined in this study. These wells did not exhibit a wide variation in performance with their offsetting vertical wells and on average there was little difference between the highly deviated wells and their vertical offsets when considering maximum sustained rates and EURs. Review of selected well files obtained from the Colorado or New Mexico oil and gas commissions indicated that the category highly deviated well is difficult to generalize since well trajectories, particularly through the coal beds, may reflect dramatically different wellbore and completions conditions. Three recent horizontal wells drilled by BP will contribute significantly to the knowledge base concerning the application of horizontal wells in the NSJB. These wells were drilled in areas having different coal characteristics, each of the wells used a different mud system but were drilled over-balanced, and each well used different motherbore and lateral configurations. Two of the three appear to be very successful wells based on initial completion rates. However, there remain significant questions concerning the performance of the horizontal wells in the longer term. For example, while the horizontal wells exhibited significant multiples of rate improvement over nearby vertical wells, it is not known whether multiples of EUR will be achieved. Several years of pressure and production monitoring will be required in order determine the degree of gas recovery enhancement. In addition, there are multiple coal seams comprising the net coal thickness within the Fruitland; while the horizontal wells may effectively drain larger areas of particular coals it will leave other coals undepleted, so the mechanical considerations and economics of redrilling these wells in other coal seams upon depletion of the initially completed seams remain to be addressed. Finally, closer examination of core data and FMI (formation micro imager) logs shows that some of the coal fractures do not cross the shales within the thicker coals. This adds additional uncertainty to whether a particular coal seam may effectively be drained by a horizontal well. Related to this are questions about the lateral continuity of the coals and shales that can only be answered with well control; in other words, there is a high degree of risk in drilling horizontal wells in areas that have not been partially developed using vertical wells. In response to comments on the NSJB Draft Environmental Impact Statement and issues raised by operators MHA has investigated the wellbore stability of Fruitland coal wells. This work, performed by Higgs Technologies and PCM Technical, provides quantitative guidance as to the conditions under which horizontal wells in the NSJB area might fail during drilling operations. This work also shows how producing conditions (drawdown) and reservoir depletion may influence wellbore failure resulting in hole collapse or the production of coal fines. Based on published information concerning the depths and types of coals present in the NSJB, these drilling and production wellbore stability (WBS) issues are not expected to be uniform across the project area. This work emphasizes that the specific failure conditions described in this report are illustrative only. In order to improve these predictive models specific data must be acquired and analyses performed in order to understand the stresses and strengths associated with the Fruitland coals in the NSJB project area. The economics of drilling CBM wells were examined using drilling and operating costs and initial rates and ultimate gas recoveries believed to be representative of the NSJB area. While drilling costs are closely held by area operators, a vertical well stimulated by hydraulic fracturing is believed to cost approximately $750,000, while horizontal wells are estimated to cost at least twice as much, or $1,500,000, and there is anecdotal information that horizontal wells with multiple laterals have cost as much as $3,000,000 in part due to remediation activities MHA Petroleum Consultants, Inc. 2

8 DRAFT associated with getting the wells on production. Using a gas price based on current NYMEX forecasts, vertical wells are economically attractive with initial rates of 300 MCFD and EURs of one (1) BCF. Vertical wells become very attractive with higher initial rates and larger EURs, which are not unusual for existing wells in the NSJB project area. The economics of horizontal wells require initial rates in excess of 300 MCFD even if drilling costs are only $1,500,000. If drilling costs are as high as $3,000,000, then initial rates of more than 1000 MCFD are required with a minimum EUR of between one and two BCF. These scoping economics generally indicate that if drilling costs can be limited to about two million dollars and stable initial production rates of 1000 MCFD achieved, horizontal wells may be economically attractive in the NSJB area. Selected Responses to DEIS MHA was asked to review selected responses to the DEIS and provide information to address or elaborate on the technical evidence or assertions concerning the use of horizontal wells in the NSJB project area. Excerpts from this review are provided below; they fall generally into one of three categories: 1. Other basins in which CBM development is occurring should be examined as analogs to the SJB. This is always a good idea but in this instance the horizontal well activity in other basis does not provide general support for horizontal wells in the NSJB. Most of the operators holding leases in the NSJB project area are also involved in developing CBM assets in other basins; therefore, they are aware of the variety of horizontal well drilling and completions that may be employed. Examination of other basins shows that the CBM plays being aggressively developed with horizontal wells have different coal properties than those of NSJB Fruitland. 2. The wellbore stability of horizontal and highly deviated wells in the SJB is a major concern to operators and will require further coalbed characterization and analysis in order to understand where horizontal wells may or may not be suitable. This assertion is supported by SJB experience, wellbore stability modeling, and CBM literature that highlights the variability of the Fruitland coals. One of the major conclusions upon consideration of these issues is that reservoir characterization is very important to determining the manner in which various CBM areas with the NSJB should be developed. 3. The economics of horizontal wells in the NSJB should be considered. This is a valid response to the DEIS. This study examines the economics of CBM development in the SJB to demonstrate the gas rates and recoveries that appear to be required to support economic development. Consistent with coal properties and geologic characterization, the economics associated with SJB CBM wells are different than the economic of other plays. MHA Petroleum Consultants, Inc. 3

9 DRAFT Responses by Entity Operator One This company is actively engaged in many areas of the SJB and has specific experience drilling horizontal wells in the NSJB project area. Its comments included the following: such technology has not matured enough for it to be required as is stated in the draft EIS engineering assessment. While current spacing orders allow for two wells per 320 acre spacing (160 acre infill) and drilling is continuing under this order...[the company] is evaluating potential 80 acre infill areas in La Plata County... The single biggest unknown is question of long term wellbore stability. Of six horizontal wells drilled into the coal in the last two years, half... have experienced wellbore failures. From [this operator s] perspective... summarize some of the challenges alternative technologies present in thee San Juan Basin: 1. wells... deviated to an average of 35 degrees or less from the vertical... is a proven technology, but is usually applied only to access gas resources otherwise unobtainable due to surface constraints, because of its high cost and incompatibility with standard fluid lift equipment. 2. Drilling and producing horizontal wells is a developing technology, with the problem of wellbore stability added to the challenges of cost and artificial lift The use of these technologies may ultimately improved well productivity, but it is unlikely to result in greatly reduced ecological impact, because of... the need to drill additional wells to access vertically separated coal seams The western portion of the EIS Study Area appears less amenable... than the eastern portion because of greater water production, natural permeability and vertical isolation of the coal seams. Citizen Contributor [DEIS]... does not adequately address the use of horizontal technology nor has it utilized all readily available information. DEIS failed to consider, 1. Hartshorne Coal, Oklahoma; what is required is an in-depth analysis of the geology, vertical and horizontal well performance, costs and economics. 2. Analysis of a similar fracture play, the Austin Chalk MHA Petroleum Consultants, Inc. 4

10 DRAFT 3. Economic data of horizontal versus vertical well development Compares SJB coal that is 70 feet thick, to the Oklahoma Hartshorne coal that is four (4) feet thick. La Plata Energy Council there are a number of technical challenges that exist with these unproven technologies, especially in regard to completing and maintaining wellbore integrity for horizontal wells. Half of all horizontal wells drilled in the last two years in the San Juan Basin have experienced wellbore failures. Per the Colorado Oil and Gas Commissioner Griebling (April 15, 2004), Directional wells... technically feasible... in particular geologic formations of certain areas around Colorado. They haven t been shown as such in the Fruitland Formation in the San Juan Basin. Operator Two The horizontal well will require casing at the heel and minimum of slotted liner set through the coal. Only one horizontal well is therefore technically feasible, not multiples. Thus natural gas resources will be left untapped in the remaining seams. Extensive geologic control... is required to properly design... horizontal technology in this basin. Reservoirs are not homogenous... density of four (wells) per section is needed... (to plan) horizontal drilling. Horizontal technology in CBM reservoirs is still investigational in all areas but the mature dry coals in West Virginia. Public Lands Advocacy... it is unreasonable to impose across the region a requirement that could render a well uneconomic or infeasible, particularly when existing leases do not require the use of alternative drilling techniques.... it does not make sense for the federal agencies to attempt to force companies to use unproven technology when it has been demonstrated over the past 20 years that vertical drilling has been successful.... the technology required by this alternative has yet to be scientifically validated as feasible in this area. In fact, the successful use of directional/horizontal drilling is in doubt due to the geological features throughout the project area. MHA Petroleum Consultants, Inc. 5

11 DRAFT Operator Three... opposed to any Record of Decision, which incorporates phases or stages for development.... further believes that the alternatives that employ thee use of horizontal drilling techniques... cannot be successfully implemented at this time or in the foreseeable future. The coal reservoir in this area is not one homogenous reservoir. Existing well data shows that there exist two and sometimes three or more separate coal zones... We believe we have reduced thee impacts of our proposed action through the use of directionally drilled wells in the high elevation areas where it is possible to attain a useful horizontal offset (horizontal distance from a well surface location to the location of the bottom of the well). Comparison to Other CBM Plays CBM plays in the United States are notably different from one another. These differences relate to characteristics such as coal rank, gas content, depth and permeability, as well as geographic conditions that contribute to drilling and development costs. While the technology and development activities associated with a particular CBM play may be of interest and application to another, the characteristics of CBM development in each basin are sufficiently different that direct analogs are usually inadequate. In fact, differences within each CBM play or basin usually preclude the successful application of uniform development practices within a basin. FIGURE 1 shows that the CBM gas reserves of the SJB are significant but that there are many established and emerging basins in the United States. TABLE 1 is a tabulation of some these CBM plays and indicates the degree of activity as reflected by current rates and number of wells. TABLE 2 provides a summary of coal characteristics in a number of the important CBM basins. While TABLE 2 illustrates that the coal characteristics are much different from basin to basin, it does not capture the significant variations within most of the basins. Coupled with the geographic and economic conditions associated with each basin, and with each coal within a basin, development practices and the maturity of CBM development are not uniform. One of the characteristics that not summarized in TABLE 2 is coal strength, which is an important to maintaining a stable wellbore particularly when drilling high angle and horizontal wells. The coal rank is of particular importance as it reflects the relative gas content of the coals, in other words, the higher or more mature the rank, the higher the gas content. In addition, as will be described below, the rank also is an indicator of the coal strength, which is important to wellbore stability considerations. TABLE 3 shows the industry designation for coal rank. The SJB CBM is characterized by relatively high gas content, moderate permeabilities, and thick coals, although the coal thicknesses are not usually associated with a single seam. When compared to other basins in which horizontal drilling is widely used the SJB coals are decidedly different than the coals in which horizontal drilling is more universally applicable. For example, the Hartshorne coal of the Arkoma Basin has become almost synonymous with horizontal CBM development, but it has decidedly different coal characteristics, land ownership, geography and market proximity. MHA Petroleum Consultants, Inc. 6

12 DRAFT The Hartshorne coal play located in eastern Oklahoma and western Arkansas was producing approximately 50 MMcfd in 2003 from about 750 vertical wells and 250 horizontal wells. As of early 2004 there were at least 10 horizontal drilling rigs active and over 300 horizontal wells had been completed. Among the operators developing Hartshorne CBM are El Paso, Chesapeake, Williams, Devon, Questar and Klabzabh; in the aggregate these companies were planning to drill about 225 horizontal wells in Among the technology advances that were spurring this more aggressive development were; 1) improvements to the oriented gamma tool locating it 19 feet rather than 40 feet behind the bit, 2) improved lateral length and efficiency, increasing lateral lengths from 1000 feet with 65 percent of the lateral in the coal, to over 4000 feet with 95 percent of the lateral in the coal, 3) recognition that wells drilled with water produce fewer coal fines and, 4) increased use of slotted liners to prevent lateral collapses. The Hartshorne coal consists of one or at most two coal seams, with the thickest seam ranging from three (3) to five (5) feet in thickness. It is also a mature coal being composed of hvbb to sa coals, most of which are relatively strong coals and conducive to wellbore stability in horizontal wells. At the end of 2003, 739 vertical wells had been drilled in the Hartshorne coal, only 10 percent of which exhibited daily rates greater than 136 MCFD; however, of nearly 250 horizontal wells drilled by year end 2003, 25 percent exhibited daily rates greater than 500 MCFD. Clearly, the Hartshorne is an attractive candidate for horizontal well development, being a thin, mostly singular coal having relatively low permeability and generally favorable wellbore stability characteristics. The economics of the Hartshorne play are also very different from the SJB (the SJB economics are discussed in a later section). Hartshorne horizontal wells cost less $500,000 and estimated ultimate gas recoveries (EURs) are between 0.5 and 1.0 BCF. Payouts are reported to occur within six to 12 months with internal rates of return of between 45 and 90 percent. Contributing to these favorable economics are the land ownership, which is mostly fee lands, and the proximity to multiple gas markets, resulting in gas prices that reflect very small discounts to NYMEX. Some of the coals in the Appalachian areas have also been attractive targets for horizontal well development. For example, Penn Virginia Corporation plans to spend 20 million dollars in horizontal drilling for CBM (Williams, 2004) on 620,000 acres that it controls in West Virginia, Virginia and Kentucky. It reportedly has an area of mutual interest with CDX Gas, which has some proprietary horizontal drilling technology that works well in the hard (high rank and high strength) coals that are prevalent in the central Appalachians. San Juan Basin CBM Wellbore Stability Modeling Background As indicated in MHA s March 2004 report and in the responses to the DEIS, the wellbore stability (WBS) of horizontal wells is a major concern in the SJB. For this reason MHA has investigated the mechanics of WBS using leading edge modeling of CBM reservoirs. This modeling was performed by investigators from Higgs Technologies, LLC and PCM Technical, Inc. The technology of WBS modeling is well established in conventional clastic reservoirs and is used to predict wellbore instability while drilling and under producing conditions when sanding or formation collapse might occur. However, the use of WBS modeling in CBM reservoirs has not been widely employed because it usually does not represent a critical element in the drilling and completion of vertical wells: coals may washout, but that does not stop drilling, and vertical MHA Petroleum Consultants, Inc. 7

13 DRAFT wells are cased which prevents wellbore collapse; the worst that can happen is fines production, and this is mitigated by the presence of the hydraulic fracture. With horizontal wells, we have another animal: the wells are mostly uncemented (although they may have a liner), and this means a well may collapse, and cause more serious drilling difficulties. A well may collapse when it produces, as depletion ensues, and cause a loss of effective length (if openhole) or a loss of perm and inflow (if has a liner). Furthermore, fines production may be greatly increased.the methodology of WBS modeling is described in SPE 96872, Coal Failure and Consequences for Coalbed Methane Wells, by Palmer, Moschovidis & Cameron (2005), and in Paper 0517, Methodology and Examples of Wellbore Stability in Coalbed Methane Wells, by Moschovidis, Cameron & Palmer (2005 International Coalbed Methane Symposium, Tuscaloosa, May 17, 2005). Application to NSJB Project Area These WBS methods were applied to the Northern SJB Project area as follows: 1. Six hypothetical well locations were selected to evaluate the range of parameters in the NSJB project area that may affect WBS and fines production. The WBS study predicts the safe mud weight window to avoid formation shear-failure within a horizontal well. The production stability study predicts when an openhole horizontal well will collapse or fines will be produced. Openhole refers to a truly openhole well, or one with an uncemented liner. The six hypothetical wells are designated HW1 through HW6 and their locations are shown in FIGURE 2. FIGURE 2 also shows the Fruitland Formation coal rank in terms of vitrinite reflectance. The 6 wells sample the three different coal ranks in the NSJB project area(bituminous LV, MV or HVA). 2. In situ stress data were estimated as follows for these six well locations. The coal depths were derived from FIGURE 3, by subtracting 100 ft from the depth to the Pictured Cliffs sand, and the overburden stress was considered to be 1.0 psi per foot.the minimum horizontal stress was varied from 0.72 to 0.90 psi per foot of depth based on experience in the SJB to reflect the variability that can occur with coals from well to well. The pore (initial reservoir) pressure was derived from FIGURE 4 and varied from 0.48 to 0.52 psi per foot of depth. 3. The range of safe mud weights that could be used and maintain wellbore stability requires a knowledge of coal strength as well as in situ stresses. The compressive strength of different coals was based on thousands of Hardgrove Grindability Index (HGI) lab tests, which have been correlated to UCS tests for different ranks of coal (FIGURE 5). Higgs Technologies and PCM have found that the UCS of coals is a function of rank (TABLE 1), and cannot be predicted from logs. The minimum UCS for each rank in FIGURE 5 has been used in TABLE 4, because we assume each coal seam is very heterogeneous. Higgs and PCM have also developed a generalized failure envelope base on published data for different coal ranks (FIGURE 6). Once UCS is chosen for a particular rank of coal, a specific failure envelope is defined. Imposing the wellbore stresses (mininum horizontal insitu stress (Sh), maximum horizontal insitu stress (SH), vertical insitu stress (Sv), pore pressure (Po), and wellbore pressure (P)) on this specific failure envelope allows the determination of the minimum and maximum mud weights to maintain wellbore stability (FIGURE 7). Using muds having less than the minimum weight exposes the wellbore to shear failure or wellbore collapse; using mud weights greater than the maximum mud weight exposes the wellbore to shear or tensile MHA Petroleum Consultants, Inc. 8

14 DRAFT failure associated with an induced fracture. TABLE 5 summarizes the stress and pressure parameters for the six well locations used in the WBS analysis. 4. The WBS modeling incorporated a filter cake parameter, b, that accounts for whether the drilling conditions will result in the formation of a borehole mud cake, and the effectiveness of this mud cake in preventing conduct of the wellbore pressure to the formation. As indicated in FIGURE 8, a filter cake parameter of one (1) considers that scenario of underbalanced drilling with water such that no filter cake is formed. Under this condition the wellbore pressure is fully transmitted to the wellbore vicinity. At the other end of the spectrum is a filter cake parameter of zero (0), which is expected to be realized if drilling in an overbalanced condition with mud or with water (in the latter case the presence of coal fines can lead to plugging of cleats or plastering the wellbore), and the development of a perfectly isolating filter cake. Under this condition the wellbore pressure is not transmitted to the vicinity of the wellbore. 5. The results of the WBS modeling were expanded to include the impact of horizontal drilling in a depleted reservoir. To do this, we program the far-field stresses Sh = SH as they change with depletion, and this is shown in FIGURE 9. The figure also shows the minimum and maximum safe mud weights from the WBS modeling for the hypothetical well location (HW1). If the reservoir pressure remains above approximately 520 psi, the wellbore is stable under conditions of overbalanced or underbalanced drilling. Below a reservoir pressure of 520 psi, however, a well would have to be drilled overbalanced in order to maintain wellbore stability. 6. TABLE 6 presents the mud-weight window results of the WBS modeling at initial reservoir pressure for all 6 hypothetical well locations in FIGURE 2, and for a range of filter cake effectiveness. Two wells with b=1, shown shaded, have no safe mud window and are predicted to be unstable: these are MV coals at intermediate depths. The deepest well, HW5, is in a HVA coal, which is stronger, and so is more stable. The pattern of results indicate that (1) small UCS, and (2) large stress difference (Sv-Sh) increase instability (ie, reduce safe mud-window). 7. TABLE 7 summarizes WBS results for drilling horizontals into depleted reservoirs. Two of the hypothetical wells are stable for any degree of depletion, two are unstable for all degrees of depletion, and two are in between. Clearly, there is a lot of variability in this one small area of the San Juan basin. 8. As well as drilling stability, it is important to be able to predict production stability, ie, whether an uncemented horizontal will collapse and/or produce fines at some combination of drawdown and depletion during its production life. The criterion used in the model for predicting the onset of collapse/fines is shear failure (collapse) of a cylinder (wellbore) subject to hoop stresses. This approach predicts the maximum allowable drawdown before collapse/fines may be problematic both under initial reservoir conditions or following reservoir depletion. 9. This method of predicting collapse/fines is based on sophisticated methods that are used for predicting sand production in clastic reservoirs. Its application to coals has only recently been described in the literature (see SPE referenced above). The prediction equation that is used in this analysis is shown in FIGURE 10. In this figure the Tronvoll equation is used to derive TWC from UCS, with a = 37.5 and b = An additional a is used as a sensitivity factor to account for the uncertainty of this MHA Petroleum Consultants, Inc. 9

15 DRAFT relationship until laboratory TWC tests can validate the appropriate value of the constant to be used in coals. 10. FIGURE 11 illustrates the diagnostic value of a triangular plot that comes out of the prediction. As indicated, FIGURE 11 shows the drawdown that may be imposed on a well at the initial reservoir pressure and at pressures representing some degree of depletion. FIGURE 12 shows a triangular plot for the HW4 well in the NSJB project area, which indicates that this well could be produced under open flow or very large drawdown conditions at initial reservoir pressure, without collapse/fines. With reservoir pressure at 1000 psi or about 70 percent of initial reservoir pressure, the CDP is approximately 720 psi (1000 psi 280 psi). Finally, at a reservoir pressure of 552 psi (38 percent of initial pressure), collapse/fines production will occur under any drawdown condition. This is called the Critical Reservoir Pressure. The results of this modeling are summarized in TABLE 8 for a Tronvoll constant of 1.0. The modeling results using a constant of 0.6 are shown in TABLE 9. A coefficient less than 1.0 results in critical reservoir pressures that are higher than if a value of 1.0 is used. Wellbore Stability Model Findings: Uncemented Horizontal Wells Examination of WBS in the NSJB project area was informative for a number of reasons. But there is an important caveat: all the predictions (drilling and production stability) in this part of the report have been based upon UCS values that are chosen at the minimum of a range of labderived values, for each rank of coal. The results presented here are illustrative only, because a proper wellbore stability prediction requires core to be tested in the lab (both UCS and triaxial tests to determine a failure envelope, and TWC to determine collapse of a cylinder). 1. Based on available information the Fruitland coals exhibit a significant amount of variability within the project area. Coal depths range from about 1800 feet to 4500 feet, with most of the area having coal depths of between 1300 and 2900 feet. The coal rank varies from Bituminous LV to HV-B and these coal ranks translate into coal strengths of 490 to 4800 psi UCS. Finally, the uncertainty in the minimum horizontal stress is reflected in the range of between 0.74 and 0.92 psi per foot assigned to the well locations. These coal property variations emphasize the need to properly characterize the coals at multiple locations within the project area, including securing core material that can undergo laboratory strength testing, and conducting leakoff tests to determine formation stresses. 2. The safe mud weight window becomes larger with increasing UCS (stronger coals). 3. The safe mud weight window for WBS becomes smaller, in other words the well becomes less stable, for larger stress differences between vertical and horizontal stress. This effectively means that instability increases as the term (Sv Sh), which is equal to [(1.0 psi/foot frac gradient) x depth], becomes larger. 4. The stability triangle for collapse/fines production becomes larger (the horizontal well is more stable) for larger UCS and smaller stress difference (Sv-Sh), but other factors are involved 5. The chances for wellbore instability during drilling or production generally increase with depth, since (Sv-Sh) increases with depth. MHA Petroleum Consultants, Inc. 10

16 DRAFT 6. FIGURE 13 summarizes the findings of the WBS (drilling) modeling in the context of the hypothetical well locations used in this analysis. As indicated, WBS cannot be conveniently related to geography within the project area. Rather WBS will be a strong function of coal strength (ie, rank) and whether the reservoir has been depleted before drilling, and specifically; a. If drilling in an overbalanced condition results in a filtercake, there is a stable mud weight for all coal ranks under any condition of reservoir depletion; however, b. If drilling in an underbalanced condition with water at locations HW1 and HW5 (in the northwest and southeast of the project area, respectively) there is a stable mud weight window prior to any significant depletion, but there is no mud-window (ie, unconditional instability) after SOME reservoir depletion. c. If drilling underbalanced at locations HW4 and HW6 (in the central project area), there is no safe mud weight window if the conditions at the upper depth (lower range of minimum horizontal stress) are applicable. d. If drilling underbalanced at location HW2 and HW3 (in the western and northern project areas) there is a stable mud weight window that exists for any condition of reservoir depletion. TABLE 6 summarizes the detailed results of the mud weights that can be used for wellbore stability. 7. TABLE 7 summarizes WBS results for drilling horizontals into depleted reservoirs. Two of the hypothetical wells are stable for any degree of depletion, two are unstable for all degrees of depletion, and two are in between. Clearly, there is a lot of variability in this one small area of the San Juan basin. 8. FIGURE 14 summarizes the findings of the collapse/fines production of WBS modeling, again in the context of the hypothetical well locations. Again, the characterization of potential problems associated with coal fines production cannot be generalized by geographic area, rather; a. Locations HW4 and HW5 are not expected to collapse/produce fines until the reservoir pressure reaches about 80 percent of initial pressure, which represents only a small amount of reservoir depletion. b. Locations HW6 and HW2 may begin to experience collapse/coal fines production when the reservoir pressure reaches about 60 percent and 40 percent of initial reservoir pressure, respectively. c. Locations HW3 and HW1 should not collapse/produce fines until reaching a very advanced state of reservoir depletion, when reservoir pressures are less than 20 percent of initial pressure. TABLES 8 and 9 summarize the detailed results of the critical reservoir pressures that are predicted by the modeling. MHA Petroleum Consultants, Inc. 11

17 DRAFT Scoping Economics for San Juan Basin CBM MHA examined the economics of CBM development in the NSJB project in order to put into context 1) performance differences that might be realized between horizontal and vertical wells, and 2) risks that are inherent in drilling and producing coals that may be susceptible to wellbore instability. The following analysis presents the economic analysis in terms of the net present value (NPV) of a successful-efforts well. This analysis also presents a range of possible outcomes and capital investment requirements that are expected to cover the reserve expectations and drilling costs within the NSJB project area. Economic Input The economic analysis of CBM development in the NSJB project area used the following input: Initial rate and expected ultimate recovery: The range of possible initial rates and EURs was derived by inspection of the performance statistics of 307 wells that have produced in the NSJB project area. The average volume of gas produced during the first 12 months of production for these wells was 118,000 MCF (an average daily rate of 323 MCFD), while the median volume was 67,000 MCF per year (184 MCFD). The best wells, representing a 10 percent probability of occurrence, produced approximately 350,000 MCF (960 MCFD) during the first 12 months of production. Looking at the cumulative gas production for these wells in the project area, the average well has produced about 1.77 BCF and is expected to ultimately recover about 2.64 BCF, while the median well has produced about 1.38 BCF and is expected to ultimately recover about 2.1 BCF. Approximately 10 percent of the wells have produced four (4) BCF of gas. These statistics were only used to frame the range of economic cases for analysis. They are not intended to imply specific outcomes or expectations for specific areas of the NSJB. However, using these statistics as a guide and assuming that successful horizontal wells may be able to produce at an initial rate twice that of a vertical well and may ultimately produce twice as much gas as a vertical well, MHA ran economic cases for initial rates (starting rates) of 300 MCFD, 1000 MCFD and 2000 MCFD, and EURs of one (1), two (2), four (4) and eight (8) BCF. Drilling Costs: MHA indicated in its 2004 report that one of the area operators represented that it could drill a horizontal well with one lateral for between $600,000 and $800,000. This same operator also indicated that this range of costs was consistent with those of a cavitated vertical well. However, this operator did not otherwise provide direct input to the 2004 report and its horizontal drilling results had been disappointing as of the March 2004 reporting date. Given the escalation of industry drilling costs since early 2004 it is likely that a hydraulically fractured vertical well in the SJB now costs approximately $750,000 (hydraulically fractured vertical wells usually cost less than cavitated vertical wells). BP indicated when contacted about input for this report that as a rule of thumb horizontal wells having two laterals cost approximately twice that of vertical well. Anecdotal evidence concerning the costs of successful horizontal wells in the SJB indicate that they cost between $2,000,000 and $3,000,000. This significant range of costs reflects 1) the length and number of lateral sections, and 2) the costs that have been associated with remedying initial production problems associated with one or more of the lateral sections. With this guidance, MHA use capital expenditures (CAPEX) reflecting drilling costs of $750,000 ($750K), $1500K, and $3000K. Operating Costs and Taxes: MHA used constant operating costs for each of its economic cases of $0.60 per MCF, and gathering and compression charges of $0.15 per MCF. In addition it was assumed that there would be a five (5) percent reduction in gross wellhead MHA Petroleum Consultants, Inc. 12

18 DRAFT volumes attributable to shrinkage and system losses. These estimated costs are based on MHA experience in other Colorado basins that produce CBM and tight gas. This economic analysis also included severance and advalorem taxes of five (5) percent and seven (7) percent, respectively. Gas Price: A NYMEX strip gas price with a $2.00 price differential was used in this economic analysis. The NYMEX strip was as of November 16, 2005 and provided a monthly price forecast for a five year period beginning in January 2006 (the effective date of the economics) and going through December Gas price was held constant thereafter. A price differential of $2.00 per MMBTU was deducted from the NYMEX strip based on the average difference in 2005 between the Henry Hub gas price and the El Paso Blanco Hub price, which is believed to be the price that is received for the gas in the SJB. This resulted in a gas price for this economic analysis of $10.35 per MMBTU in January 2006, with this gas priced declining to $4.98 per MMBTU in November 2010 (with seasonable variations). FIGURE 15 shows the monthly gas prices used in this analysis. Economic Results The scoping economics for SJB CBM development are summarized in FIGURE 16, which presents the NPV for each economic case discounted at 30 percent. The 30 percent discount factor reflects the mechanical risk, gas price risk, and environmental compliance risks that may be appropriate to consider for CBM development in the NSJB project area. As indicated in FIGURE 16 vertical wells (costing approximately $750,000) are economically attractive with initial rates of 300 MCFD and EURs of one (1) BCF. Vertical wells become very attractive with higher initial rates and larger EURs, which are not unusual for existing wells in the NSJB project area. The economics of horizontal wells require initial rates in excess of 300 MCFD even if drilling costs are only $1500K. If drilling costs are as high as $3000K, then initial rates of more than 1000 MCFD are required with a minimum EUR of between one and two BCF. These scoping economics generally indicate that if drilling costs can be limited to about two million dollars and stable initial production rates of 1000 MCFD achieved, horizontal wells may be economically attractive in the NSJB area. San Juan Basin Performance Analysis Performance Comparison of Horizontal & Offsetting Vertical Wells In its March 2004 report MHA compared the performance of horizontal and highly deviated wells with offsetting vertical wells. The basis for this comparison was as follows: Horizontal Wells the IHS Energy database (PI/Dwights Plus CD) was queried to identify under the well tab (and hole direction indicator), horizontal wells in the Fruitland Coal of New Mexico and Colorado. Seventeen wells were identified from the database that included production through November Of these 17 wells, seven were drilled as new wells and ten were described as horizontal laterals drilled from preexisting vertical producers. MHA Petroleum Consultants, Inc. 13

19 DRAFT Highly Deviated Wells the IHS Energy database was also used to identify directional wells completed in the Fruitland Coal of the San Juan Basin. In this manner 174 deviated wells were identified; however only 46 of these wells contained information on both measured depth (MD) and true vertical depth (TVD) which allowed the degree of deviation to be inferred. For the March 2004 study highly deviated wells were identified as those directional wells in which the MD was greater than the TVD by more than 300 feet. This resulted in the identification of 13 highly deviated wells. Offsetting Vertical Wells the wells used as a basis for comparison with the horizontal or highly deviated wells were the vertical wells drilled in the same section of land as the horizontal or highly deviated wells. In the event there were no vertical wells within the same section, wells in adjacent sections were selected. Performance Metric MHA used two indicators of well performance. Firstly, MHA identified the maximum sustained annual producing rate, which was represented as a monthly volume (the maximum annual production volume was divided by 12). Secondly, MHA performed decline curve analysis to determine the estimated ultimate recovery (EUR), which was derived by adding the cumulative gas production to the gas that will be recovered under the decline curve forecast on a plot of the logarithm of the producing rate versus time. Finally, MHA combined the maximum sustained monthly producing rate and the EUR into a performance index defined as the weighted average of the horizontal well EUR divided by the EUR of average offset vertical well and the maximum annual rate of the horizontal well divided by the average maximum annual rate of the offsetting vertical wells (see equation in TABLE 14). As part of the update of these performance comparisons MHA again queried the IHS Energy database, resulting in the identification of 20 horizontal wells and 246 directional wells. However, closer examination of the respective horizontal wells indicated that some of the wells in the 2004 report are not identified as horizontal wells in the current IHS Energy database and, conversely, some additional wells that predated the 2004 report are now identified as horizontal wells (but previously they were not identified as horizontal wells). As a result of these inconsistencies, MHA reviewed well files from the digital databases of the Colorado and New Mexico oil and gas commission web sites for approximately half of the so-called horizontal wells; this review confirmed that some of the wells in question were indeed horizontal wells, others were simply highly deviated wells, and some were vertical wells. Finally, three additional horizontal wells were identified as a result of discussions with BP. TABLE 10 is the resulting list of 19 horizontal wells identified for this study. Considering the database inconsistencies experienced with the horizontal wells MHA did not do any further queries on the directional well database. Instead, the highly deviated wells from the March 2004 report were retained and only those wells that were identified as highly deviated from the horizontal well review described above were added to the data set. During review of the (digital) oil and gas commission well files it was noted that some of the highly deviated wells represent wellbores completed in the Fruitland coals with inclinations as much as 40 degrees from vertical, while other highly deviated wells may have significant bottomhole displacement from the surface location, but otherwise go through the Fruitland as a vertical wellbore. Since the highly deviated wells being used in this comparison set appear to exhibit significantly different conditions of inclination and completion within the coals, the aggregate comparison of their performance with the vertical offset wells is not considered to be as diagnostic as the horizontal well comparison. TABLE 11 is the resulting list of 16 highly deviated wells used in this study. MHA Petroleum Consultants, Inc. 14

20 DRAFT Using the updated lists of horizontal and highly deviated wells and the offsetting vertical wells MHA determined the maximum sustained annual production rate and the estimated ultimate gas recovery for each of the wells. The maximum production rate was derived from the production database; for those wells having less than one year of production the present cumulative production was divided by the number of months the well has been producing to arrive at the maximum sustained monthly rate. For the three new horizontal wells that have been drilled by BP, the unofficial initial producing rates are used for the maximum sustained rates. (Obviously, these anecdotal rates may be larger than the stabilized rates following one year of production; on the other hand, it is not known whether these new wells have restricted drawdowns in order to avoid production problems and, therefore, the rates may remain relatively constant during the first year of production.) Decline curve analysis was performed on semilog plots of rate versus time to determine the EUR for each well. APPENDIX A contains the decline curve plots showing historical production through June, July or in some cases August of Also shown on these plots is the forecast of future performance to an economic limit of 300 MCF per month. Production was forecast based on historical trends. In the event that production has been erratic, relatively constant, or even inclining, future production was forecast using a constant exponential decline consistent with nearby producing wells. In many cases a constant effective decline rate of 10 percent (for vertical wells) or about 15% (for horizontal wells) was used. For new wells having less than about one year of production history and exhibiting relatively steep declines, hyperbolic declines with a hyberbolic exponent ( b ) of 0.5 were sometimes used to forecast performance (in these instances a terminal or minimum decline of 10 percent was imposed). TABLES 12 and 13 summarizes the results of this performance analysis for the horizontal and highly deviated wells and associated vertical offset, respectively. These tables show for each well the maximum sustained rate and EUR as well as providing other summary statistics. This performance analysis does not constitute a formal reserve evaluation; in other words, the resulting EURs have not been reconciled with volumetric estimates of original-gas-in-place, operator intention has not been surveyed for wells having erratic or no production decline, and analogous well performance outside the immediate vicinity of these well groups has not be examined to corroborate the forecasts. However, this analysis is believed to be reliable for understanding the relative performance of the subject horizontal and highly deviated wells with the offsetting vertical wells. APPENDIX B provides semilog production plots for each of the well groups, each group being composed of a horizontal or highly deviated well and is offsetting vertical wells considered in this analysis. TABLES 14 and 15 show the ratios of the EURs and maximum annual rates as well as the performance indices for the horizontal and highly deviated wells, respectively. TABLE 14 shows that the horizontal wells exhibit EURs that average 1.85 times those of offsetting vertical wells, and maximum rates that average 2.08 times those of offsetting vertical wells. The average performance indicator for the horizontal wells is Therefore, in the aggregate the horizontal wells appear to perform about twice as well as offsetting vertical wells. It should be noted that the three recent wells drilled by BP (Brown Gas Unit #2, Knight Gas Unit E #2, and Gallegos-Bonifacio Gas Unit A #2 described below) represent wells that have little or no production performance with which to compare to offset vertical wells. Initial production rates or even reported test rates have been used as the basis for these horizontal wells performance; therefore, their maximum sustained rates and EURs have a greater than normal degree of uncertainty. TABLE 15 indicates that on average the highly deviated wells do not provide a performance improvement over the offsetting vertical wells (average performance indicator is 0.94). MHA Petroleum Consultants, Inc. 15

21 DRAFT Industry Drilling Practices MHA received input from two operators who have utilized horizontal wells in SJB CBM development. CDX Gas provided some general information but would not provide details due to the proprietary nature of its horizontal drilling technology and its competitive position in the SJB as both a leaseholder and a horizontal drilling contractor. BP was very forthcoming in describing its recent horizontal wells and it was also quite open in discussing its concerns regarding the longer term performance of the SJB horizontal CBM wells. CDX s proprietary technology for drilling horizontal wells is discussed in the literature review below. CDX was not able to provide much specific information concerning its efforts in the SJB (it is believed that CDX has drilled four horizontal wells but this was not confirmed by CDX). While CDX did indicate that it believes its technology is applicable to the SJB, it indicated that the keys to any economic advantages over vertical wells were drilling costs, coal permeability, wellbore stability, and gas content. One of the reasons CDX believes its technology will be successful is because the number, length, and system of multilaterals it employs should effect a much more pronounced drainage of the coal gas. While CDX will not discuss its horizontal well completions directly, it is believed that one of the lessons learned from its two initial wells (Penrose and Anderson) was that surges, or pressure drawdowns, (differences between the reservoir pressure and the wellbore pressure) associated with drilling and completion activities cannot exceed certain levels or WBS problems will be encountered. In commenting on the results of other horizontal wells that have been drilled in the SJB, CDX believes that horizontal wells relying on a single lateral have not and will not be economically successful. MHA s March 2004 report provides some additional information on the Anderson and Penrose wells, the first and second horizontal wells drilled by CDX. The configuration of the laterals drilled in these two wells is not known with certainty and both wells apparently experienced production problems associated with coal fines following completion. While CDX indicated that it runs liners in some of its laterals it is not known whether that is the case with one or both of these wells, nor is it understood whether the effectiveness of each of the laterals in these two wells is quantifiable. CDX also indicated that it is on a learning curve in the SJB regarding accessing more than one coal layer and that it may be necessary to attempt re-entering wells at later dates to recover gas from other coal layers. BP has drilled three horizontal SJB CBM wells since the March 2004 report. One of these wells, the Brown Gas Unit #2 was completed in March 2005 and was brought on production at about 300 MCFD. It was producing about 435 MCFD in August BP indicated that this initial rate was only a two-fold rate improvement compared to offset vertical wells. The Brown Gas Unit #2 has two lateral wellbores, one of which has a production liner. The laterals are reportedly drilled so as to access about 40 feet of net coal over a 150 foot gross interval by drilling from the lower coals in the gross interval to the upper coals as the lateral traverses about 1700 feet of length. The second horizontal well drilled by BP in this recent three-well program was the Knight Gas Unit E #2, which reached TD in June 2005 and was recently completed with an initial rate of about 2500 MCFD. According to BP this represents a five fold increase compared to offset vertical wells that are currently making about 500 MCFD. (Note that comparing the initial horizontal well rate with the current offsetting vertical well rates is not the same comparison made in TABLE 14, which compares the maximum annual rates exhibited by the horizontal and average offset vertical well.) The Knight Gas Unit E #2 incorporates three laterals with two of the laterals accessing one coal bed and the third lateral accessing a second coal bed. Lateral MHA Petroleum Consultants, Inc. 16

22 DRAFT lengths were not reported but are believed to be less than 2000 feet in length. The third and most recent horizontal well is the Gallegos-Bonifacio Gas Unit A #2, drilled in September 2005 and just completed for a reported rate of about 2000 MCFD. This rate is nearly seven times larger than offsetting vertical wells that are making about 300 MCFD. BP indicated that this third well is located in a poorer quality Fruitland coal section than the location of the Knight Gas Unit E #2, which may contribute to the performance advantage of a horizontal well compared to a vertical well. This third well also has three laterals reportedly drilled so as to access three of four coal beds over the gross Fruitland coal interval. Again, the lateral lengths are unknown but believed to be less than 2000 feet. The three recent horizontal wells drilled by BP will obviously contribute to the knowledge base concerning the application of horizontal wells in the NSJB. The wells were drilled in areas having different coal characteristics, each of the wells used a different mud system but were drilled over-balanced, and each well used different motherbore and lateral configurations. However, BP indicated that there remain significant questions concerning the performance of horizontal wells in the NSJB: While the horizontal wells exhibited significant multiples of rate improvement over nearby vertical wells, it is not known whether multiples of EUR will be achieved. Several years of pressure and production monitoring will be required in order determine the degree of gas recovery enhancement. There are multiple coal seams over the net coal thickness within the Fruitland; for example there may be seven or eight seams representing a total of 40 feet of net coal within a 150 foot gross interval. Horizontal drilling technology allows a lateral to be placed within a five foot coal seam; however, unlike a vertical well that can complete and drain the multiple coal seams a horizontal well will effectively drain only the coal(s) which it traverses. Therefore, while the horizontal well may effectively drain larger areas of particular coals it will leave other coals undepleted. Obviously, the mechanical considerations and economics of redrilling these wells in other coal seams upon depletion of the initially completed seams remain to be addressed. Closer examination of core data and FMI (formation micro imager) logs shows that some of the coal fractures do not cross the shales within the thicker coals. This adds additional uncertainty to whether a particular coal seam may effectively be drained by a horizontal well. In the future it is possible that frac ing horizontal wells may be attempted in order to insure vertical communication within some of the thicker coals; however, this technology is evolving in conventional reservoirs and would at this time be expensive and risky in CBM wells. Related to this are questions about the lateral continuity of the coals and shales that can only be answered with well control; in other words, there is a high degree of risk in drilling horizontal wells in areas that have not been partially developed using vertical wells. Consistent with the information reported in the March 2004 study, BP is continuing to investigate wellbore configurations, downhole equipment and pumps that can facilitate the removal of water, both in horizontal wells and in highly deviated wells. It reiterated that fracture treatements in wellbores having more than 30 degrees of inclination are seldom successful; as a result, directional wells are planned so as to penetrate the Fruitland coal at angles of less than 20 degrees. MHA Petroleum Consultants, Inc. 17

23 DRAFT CBM Literature Review MHA s March 2004 report included a literature review that focused on the historical development of horizontal drilling in coal. This report extends that review by including information published since about mid-2003, the cutoff date for consideration of materials for the prior report. The following articles and professional publications are not represented as an exhaustive list of available information on the application of horizontal wells in coals; however, they are relevant to CBM development in the NSJB project area and they capture some of the current industry thinking. The References following this report provide the source of the following literature. Hower (2003) provides a concise review of CBM simulation practices and models. In particular he reviews the challenges facing simulation of horizontal and multilateral wells. The case of a multilateral CBM well in Queensland, Australia is shown where shortly after completion a portion of one of the laterals collapsed. Following a history match of the well performance, the simulation grid was extended to include the collapsed portion of the lateral so that the benefits of re-entering the well and extending the lateral can be simulated and evaluated. Hower describes how simulation technology is advancing to the point that construction of complicated grids to describe horizontal and multilateral well configurations can be performed in minutes and embedded into standard Cartesian grid (reservoir) systems. Simulation of NSJB horizontal well development may be a useful way to evaluate continued development with horizontal rather than vertical well development. However, characterization of coal geology, flow properties and formation strengths will be critical to credible simulation results. Maricic, Mohaghegh and Artun (2005) performed a parametric study of the benefits of drilling horizontal and multilateral wells in CBM reservoirs. The metric used for comparing the benefits of different drilling configurations was NPV. The wellbore configurations considered were dual-, tri-, and quad-laterals and a fishbone (representing the pinnate ) geometries. The parametric study was divided into three parts; 1) the influence of well configuration and spacing between laterals, 2) the influence of reservoir coal properties including permeability, time constant ( timeto-peak-gas ), gas content, and desorption characteristics, and 3) evaluation of the influence of coal thickness. These authors showed that using the reservoir coal properties and economic assumptions of their investigation that the optimum configuration was a quad-lateral well with spacing between laterals of 680 feet and total horizontal length of around 3100 feet. These specific results are not represented as being applicable to the NSJB project area; rather, the paper demonstrates an analysis approach that might have merit in the NSJB, particularly if factors influencing WBS are included. Smith (2003) presents the application and possible advantages of CDX s Pinnate wellbore configuration. The author notes that this drilling method has been touted by conservationists and citizen s groups concerned about CBM development in Colorado s HD Mountains, part of the NSJB project area. This article illustrates the configuration of multiple pinnate wells and how they can replace as many as 16 vertical wells that otherwise might be required to drain 1280 acres. One of the advantages of CDX s technology is the ability to drill underbalanced and thereby avoid damaging the coal with drilling fluids. This technology is very attractive and has reportedly been successful in a number of CBM plays, notably in the Appalachian area. While it remains a viable consideration for the SJB, among the issues that will have to be addressed, and which apparently have affected the CDX wells in the SJB, is the issue of WBS. While the pinnate pattern is theoretically attractive for achieving high recoveries with fewer wells, the MHA Petroleum Consultants, Inc. 18

24 DRAFT wellbore have to be stable as openhole completions since production liners cannot be run into the multiple laterals used in this technology. Williams (2004) presents a summary of CBM development in several major basins and discusses some key challenges to current and future development. The SJB is described as the granddaddy of all CBM basins, having some 4000 wells that have produced more than 10 trillion cubic feet of gas. Discussion of the application of horizontal wells in the SJB is restricted to the Menafee coals in the southern part of the SJB. Among the other CBM plays described is the Ferron play in Utah s Uinta Basin, the numerous fields in Alabama s Black Warrior Basin, the Powder River Basin in Wyoming and Montana, and the Raton Basin of Colorado and New Mexico. In addition, there are discussions concerning CBM development in the Cherokee Basin of Kansas and Oklahoma and the Washakie Basin in Wyoming. The benefits of horizontal drilling are touted in descriptions of CBM development in numerous Appalachian areas and in the Hartshorne coal of the Arkoma Basin, where the coals are thin and of low permeability. Palmer, Moschovidis and Cameron (2005) provide an analysis of how coals suffer formation failure during drilling, hydraulic fracturing and production. Among the conclusions reached by the authors are that WBS depends on the insitu stresses, coal strength and wellbore deviation (these dependencies are elaborated in the section of this report that discusses WBS). The paper illustrates calculation of the safe mud-weight window (drilling outside this window may result in fracturing if the mud weight is too high, or shear failure (wellbore breakout) if the mud weight it too low) for coals having properties similar to those of the Black Warrior, Cherokee, San Juan, and Piceance basins. Similarly, the authors discuss how wellbore failure during production can occur as a result of excessive drawdowns or as a result of reservoir pressure depletion. This type of failure can result in the collapse of a horizontal wellbore and the enhanced production of coal solids and fines. Moschovidis, Cameron and Palmer (2005) present the same concepts concerning WBS; however, this paper provides some additional equations and illustrations that help the reader understand the WBS modeling and prediction methods. Ramurthy et. al. (2003) present a case history of the Tiffany Area of the SJB, which is just south of the NSJB project area but north of the Fruitland fairway coals. In particular these investigators examined the performance of selected wells in the area to assess the efficiency of the initial hydraulic fracture treatments applied to these wells. In the Tiffany Area the Fruitland contains between three (3) and seven (7) coal seams; the coal rank tend to be high volatile bituminous (hvbb), and the coals are described as being laterally discontinuous and fluctuate sharply in thickness. This characterization of the coals is not dissimilar from the NSJB project area and it highlights the importance of characterizing the coal prior to attempting development with horizontal wells. Many of the wells in this area were originally completed in multiple coals over the Fruitland section using a single stage high rate fracture stimulation. Reservoir simulation of individual wells was used to evaluate the respective efficiencies with which the upper and lower Fruitland coals were completed. The completion optimization work that resulted from this analysis is described as being generally successful. In addition, the study significantly improved the understanding of which coals appeared to be effectively treated and were thus contributing to production. The final recommendation of the study was to extend this work to a full-field (area) model in order to improve the understanding of reservoir depletion and optimum well spacing. Weida, Lambert and Boyer (2005) present some information and ideas relative to statistically evaluating production distributions in a proven CBM production basin area, and then using this type of analysis to improve exploration program requirements. Although the NSJB project area MHA Petroleum Consultants, Inc. 19

25 DRAFT is not an exploration area per se, it is relatively undeveloped and the statistical methods described in this paper may be helpful in understanding the validity of the current well sampling in generalizing the area s potential. The paper also describes some work that was performed in the Black Warrior Basin to develop statistical methods that can be used to understand the driving characteristics of successful CBM development; this particular work illustrated the permeability variation that can occur with a CBM reservoir developed with spacing of about 23 acres per well. Young and Prat (2005) present a detailed review of coal characteristics in the Western Interior Coal (WIC) Region. This work provides some useful information concerning how coals are characterized; the data that are provided facilitate an understanding of why there are variable drilling and development practices not only within the WIC region, but between CBM basins. With this particular article the authors indicated that they have concluded a study of domestic unconventional gas reservoirs titled, Frontier Plays Coalbed and Shale Gas Resource and Production Assessment. References Hower, October 2003, Coalbed Methane Reservoir Simulation: An Evolving Science, SPE Maricic, Mohaghegh, and Artun, October 2005, A Parametric Study on the Benefits of Drilling Horizontal and Multilateral Wells in Coalbed Methane Reservoirs, SPE Smith, October 2003, Chasing Unconventional Gas Unconventionally, New Technology Magazine, October/November 2003 Williams, June 2004, Coalbed Methane, Oil and Gas Investor, June 2004 Palmer, Moschovidis, and Cameron, October 2005, Coal Failure and Consequences for Coalbed Methane Wells, SPE Moschovidis, Cameron, and Palmer, May 2005, Methodology and Examples of Wellbore Stability in Coalbed Methane Wells, Paper 0517, 2005 International Coalbed Methane Symposium, Tuscaloosa, May 17, 2005 Ramurthy, Young, Daves and Witsell, October 2003, Case History: Reservoir Analysis of the Fruitland Coals Results in Optimizing Coalbed Methane Completions in the Tiffany Area of the San Juan Basin, SPE Weida, Lambert and Boyer, September 2005, Challenging the Traditional Coalbed Methane Exploration and Evaluation Model, SPE Young and Pratt, September 2005, Coal Gas Reservoir Assessment Western Interior Coal (WIC) Region, Winter 2005, Gas TIPS (GTI/US DOE) MHA Petroleum Consultants, Inc. 20

26 DRAFT List of Tables 1. Major U. S. Coal Basins 2. Coal Properties in Major U. S. CBM Plays 3. ASTM Coal Rank 4. Likely Minimum UCS of Coals Based on Rank 5. In Situ Stress Data 6. Safe Mud Weight Window for 6 Horizontal Wells at Initial Reservoir Pressure 7. WBS versus Reservoir Depletion, No Filter Cake 8. Production Stability for Horizontal Open Hole (Tronvoll with a=1) 9. Production Stability for Horizontal Open Hole (Tronvoll with a=0.6) 10. List of Horizontal Wells Used in SJB Performance Comparison 11. List of Highly Deviated Wells Used in SJB Performance Comparison 12. Performance Analysis Summary Horizontal Wells and Vertical Offsets 13. Performance Analysis Summary Highly Deviated Wells and Vertical Offsets 14. Performance Indicators Horizontal Wells 15. Performance Indicators Highly Deviated Wells List Of Figures 1. CBM Plays in the United States 2. NSJB Fruitland Coal Rank and Six Hypothetical Well Locations 3. Fruitland Coal Overburden Map 4. Fruitland Formation Pressure Gradient in NSJB 5. UCS from Core Tests versus Rank 6. General Coal Failure Envelope as Function of UCS 7. Coal Failure Envelope and Safe Mud Weight Range 8. Pressure Distributions Around Wellbore as Function of Filter Cake Effectiveness 9. Minimum and Maximum Wellbore Pressure vs. Reservoir Depletion for Wellbore Stability 10. Fines Prediction Equation MHA Petroleum Consultants, Inc. 21

27 DRAFT 11. Fines Prediction for Vertical Well 12. SJB Horizontal Open Hole Completion Sanding (Fines) Potential 13. Drilling Stability Summary 14. Collapse/Fines Production Summary 15. Forecast Gas Price for Northern SJB CBM Development 16. Scoping Economics, NSJB CBM Development Wells Appendices A. Production Plots and Performance Forecasts B. Semilog Production Plots Comparing Horizontal and Highly Deviated Wells with Vertical Offsets MHA Petroleum Consultants, Inc. 22

28 Tables

29

30 Table 1 MAJOR U.S. COAL BASINS Basin San Juan Black Warrior Raton Mesa Greater Green River Powder River Northern Appalachian Central Appalachian (Pacific Coal Region) Western Washington Wind River Illinois Arkoma Uinta Cherokee Location Colorado, New Mexico Alabama, Mississippi Colorado, New Mexico Wyoming, Colorado Montana, Wyoming West Virginia, Pennsylvania, Ohio, Kentucky, Maryland West Virginia, Virginia, Kentucky, Tennessee Washington, Oregon Wyoming Illinois, Indiana, Kentucky Oklahoma, Arkansas Utah, Colorado Kansas, Oklahoma, Missouri

31 Table 2 COAL PROPERTIES IN MAJOR U.S. CBM PLAYS Coal Basin Play Coal Depth (ft.) Maximum Net Coal Thickness (ft.) Individual Coal Seam Maximum Average Gas Content (scf/ton) Coal Rank Permeability (md) San Juan Fruitland Outcrop to hvbb - lvb Black Warrior hvab - mvb Raton Vermejo Raton hvcb - lvb 10 Piceance Outcrop to 12, hvcb (NE) sa (SE, Interior) Greater Green River SubC, hvcb - hvab Powder River Outcrop lig - subb Central Appalachian (max) hvab - lvb 5-27 Illinoi Outcrop hvcb - hvab Arkoma (NW) hvbb - sa (central) Uintah hvbb - hvab Note: Information from various sources

32 Table 3 ASTM COAL RANK CLASS GROUP ABBREVIATION Meta-Antracite ma Antracitic Antracite an Semianthracite sa Low Volatile lvb Medium Volatile mvb Bituminous High Volatile A hvab High Volatile B hvbb High Volatile C hvcb Subbituminous A suba Subbituminous Subbituminous B subb Subbituminous C subc Lignite Lignite A liga Lignite B ligb

33 Likely Minimum UCS of Coals Based on Rank Rank high low Coal Rank (decreasing order) VM-daf% Likely min UCS (psi) Based on literature data Anthracite Less than LV 14 to MV 22 to HVA 31 to HVB 39 to HVC 42 to Lignite Greater than Low UCS of 200 to 300 psi have been measured also! Table 4

34 In Situ Stress Data Well designation HW1 HW2 HW3 HW4 HW5 HW6 Depth to Top of Pictured Cliffs Sandstone (ft) Estimated Dept to Fruitland coals (ft) Bottom of coals Rank (VR) 1.1 to 1.3 > to to to 1.4 Rank (ASTM) MV-bit. LV - bit. HV-B&C bit. MV-bit. HV-A bit. MV-bit. Min Exp UCS (psi) Shmin (psi/ft) Shmin (psi/ft) Sh_min (psi) Sh_min (psi) Pr (psi/ft) Computed BHP (psi) Computed BHP (psi) Table 5

35 Well TVD (ft) Safe Mud-weight Window for 6 Horizontal Wells at Initial Reservoir Pressure UCS (psi) Sob (ppg) Res.Pr (ppg) Sh=SH (ppg) (Sv-Sh) (psi) b = 1 b = 0 b = 0.5 minmw (ppg) maxmw (ppg) minmw (ppg) maxmw (ppg) minmw (ppg) maxmw (ppg) HW3U HW3D HW1U HW1D HW2U HW2D HW6U HW6D HW4U HW4D HW5U HW5D nu = 0.35 E = psi Large stress difference (Sv-Sh) and small UCS increase instability (reduce safe mud-window) Unstable No safe mud-window Table 6

36 WBS vs. Reservoir Depletion no filter cake: b=1 HW1 stable for Pr > 520 psi (Po = 864 psi) HW2 stable for any Pr (Po = 1144 psi) HW3 stable for any Pr (Po = 637 psi) HW4 unstable for any Pr (Po = 1450 psi) HW5 stable for Pr > 880 psi (Po = 1890 psi) HW6 unstable for any Pr (Po = 1248 psi) Table 7

37 Production Stability: Horizontal Open Hole (Tronvoll with a = 1) Critical Reservoir Pressure (psi) No fines for any Pr Res. Pressure (psi) CBHFP (psi) No TWC degradation ( a = 1) No fines for Pr > 0.2*Po UCS (psi) fines for Pr > 0.2*Po TWC (psi) Sv (psi) Sh (psi) SH (psi) Depth (ft) Well HW1U HW1D HW2U HW2D HW3U HW3D HW4U HW4D HW5U HW5D HW6U HW6D Table 8

38 Production Stability: Horizontal Open Hole (Tronvoll with a = 0.6) Critical Reservoir Pressure (psi) No fines for any Pr Res. Pressure (psi) CBHFP (psi) UCS (psi) No fines for Pr > 0.2*Po fines for Pr > 0.2*Po TWC (psi) Sv (psi) Sh (psi) SH (psi) Depth (ft) Well TWC degradation coefficient a = HW1U HW1D HW2U HW2D HW3U HW3D HW4U HW4D HW5U HW5D HW6U HW6D Table 9

39 Table 10 Horizontal Wells Used in Performance Comparison San Juan Basin, Fruitland Coal API LEASE Well No Operator Location State County Completion Date Vertical Well Vertical Well Cum (MMCF) Completion Date Horizontal Well HUGHES B 18R CONOCOPHILLIPS COMPANY 21 29N 8W SW NE NE NM SAN JUAN 9/1/ SUNRAY H 201 BURLINGTON RESOURCES O&G 11 30N 10W W2 SW SW NM SAN JUAN 3/1/ SAN JUAN 30 6 UNIT 477 BURLINGTON RESOURCES O&G 28 30N 6W NE SW SW NM RIO ARRIBA 7/1/ , /1/ SAN JUAN 30 6 UNIT 479 BURLINGTON RESOURCES O&G 29 30N 6W SW NE SW NM RIO ARRIBA 6/1/ , /1/ ROSA UNIT 310 WILLIAMS PRODUCTION COMP 26 31N 4W NW SE SW NM RIO ARRIBA 1/1/ ROSA UNIT 371 WILLIAMS PRODUCTION COMP 13 31N 5W NW SE SW NM RIO ARRIBA 9/1/ PAYNE 11 BURLINGTON RESOURCES O&G 27 32N 10W NW NE NE NM SAN JUAN 9/1/ FC FEDERAL COM 8 CONOCOPHILLIPS COMPANY 18 32N 11W SW NE SW NM SAN JUAN 2/1/ /1/ UTE #402H 402H BURLINGTON RESOURCES O&G 4 32N 11W NW SE NE CO LA PLATA 6/1/1993 4, /1/ SAN JUAN 32 5 UNIT NP 100 ENERGEN RESOURCES CORPOR 23 32N 6W SW NE SW NM RIO ARRIBA 9/1/ ANDERSON 1R CDX GAS LLC 5 32N 6W NE SW SW CO LA PLATA 11/1/ PENROSE 1R CDX GAS LLC 8 32N 6W NE SW SW CO LA PLATA 5/1/ SO UTE H BP AMERICA PRODUCTION CO 12 32N 9W SW NE SW CO LA PLATA 2/1/ /1/ SO UTE J-26 #1 1 BP AMERICA PRODUCTION CO 26 33N 11W SE NW SE CO LA PLATA 8/1/1988 2, /1/ SHORT ALVA GU A 1 BP AMERICA PRODUCTION CO 7 33N 9W NW SE SE CO LA PLATA 3/1/1991 2, /1/ ROSA UNIT 273A WILLIAMS PRODUCTION COMP 8 31N 6W NE NE SW NM SAN JUAN 12/1/ GALLEGOS-BONIFACIO GAS UNIT A 2 BP AMERICA PRODUCTION CO 2 33N 8W NW SW SE CO LA PLATA 10/1/ KNIGHT GAS UNIT E 2 BP AMERICA PRODUCTION CO 9 34N 7W NE SW SE CO LA PLATA 6/1/ BROWN BP AMERICA PRODUCTION CO 10 32N 6W NE CO LA PLATA 10/1/2004

40 Table 11 Highly Deviated Wells Used in Performance Comparison San Juan Basin, Fruitland Coal API LEASE Well No Operator Location State County Completion Date Deviated Well BLACK RIDGE SU CHEVRON U S A INCORPORAT 17 33N 10W NE SE NW CO LA PLATA 8/1/ BLACK RIDGE SU# CHEVRON U S A INCORPORAT 17 33N 10W NE SE NW CO LA PLATA 2/1/ CARRACAS UNIT 25 B 13 ENERGEN RESOURCES CORPOR 25 32N 4W NW SW SW NM RIO ARRIBA 1/1/ CARRACAS UNIT 34 B 9 ENERGEN RESOURCES CORPOR 34 32N 4W SW NE SE NM RIO ARRIBA 12/1/ DAVE A 1 RED WILLOW PRODUCTION CO 7 33N 10W NW SE SE CO LA PLATA 4/1/ GRASSY CANYON 4 DOMINION EXPLORATION & P 31 32N 7W SW NW NE NM SAN JUAN 8/1/ NORTHEAST BLANCO UNIT 461 DEVON ENERGY CORPORATION 12 30N 8W SW NE SE NM SAN JUAN 11/1/ NORTHEAST BLANCO UNIT 404R DEVON ENERGY CORPORATION 34 31N 7W NW SW NW NM SAN JUAN 4/1/ NORTHEAST BLANCO UNIT 423R DEVON ENERGY CORPORATION 8 30N 7W NE NW SE NM RIO ARRIBA 2/1/ NORTHEAST BLANCO UNIT 479R DEVON ENERGY CORPORATION 20 30N 7W SE NE NW NM RIO ARRIBA 11/1/ SAN JUAN 30 6 UNIT NP 498R BURLINGTON RESOURCES O&G 30 30N 7W SW SW NE NM RIO ARRIBA 1/1/ SIMON L&C 15U2R 2 BP AMERICA PRODUCTION CO 15 34N 9W NW NW SW CO LA PLATA 7/1/ SO UTE # BP AMERICA PRODUCTION CO 15 32N 10W SW NW NE CO LA PLATA 1/1/ SO UTE BP AMERICA PRODUCTION CO 29 33N 9W SE SW NW CO LA PLATA 4/1/ SO UTE FC RED WILLOW PRODUCTION CO 7 33N 10W NE SE NW CO LA PLATA 3/1/ WEST ANIMAS UNIVERSITY 9-3 CHEVRON U S A INCORPORAT 9 34N 9W NE SE SW CO LA PLATA 10/1/2002

41 Table 12 Maximum Annual Rates and Estimated Ultimate Recovery for Comparison Horizontal Wells Location (Twp-Rng- Sec) Ultimate Gas (MMCF) Qmax Year Monthly Average Cum Gas Remaining Group # Lease Well No API Life (MMCF) Gas (MMCF) 1 HUGHES B 18R N-8W ,661 1 HUGHES B N-8W ,098 1 HUGHES B N-8W ,120 2 SUNRAY H N-10W ,371 2 SUNRAY H COM N-10W ,169 3 SAN JUAN 30 6 UNIT N-6W , , , ,555 3 SAN JUAN 30 6 UNIT 477S N-6W , , ,859 3 SAN JUAN 30 6 UNIT 476S N-6W ,178 3 SAN JUAN 30 6 UNIT N-6W , , , ,023 4 SAN JUAN 30 6 UNIT N-6W , , , ,445 4 SAN JUAN 30 6 UNIT 478S N-6W ,857 4 SAN JUAN 30 6 UNIT N-6W , , , ,440 9 ROSA UNIT N-4W ROSA UNIT N-4W ,016 9 ROSA UNIT N-4W , ROSA UNIT N-5W , ROSA UNIT N-5W , ROSA UNIT N-4W , ROSA UNIT N-5W , , ROSA UNIT N-5W , PAYNE N-10W , , , KEYS GAS COM E N-10W , KEYS GAS COM F N-10W KEYS GAS COM G 1R N-10W , , , KEYS GAS COM G 1PI N-10W , PAYNE 11S N-10W , , , FC FEDERAL COM N-11W , FC FEDERAL COM N-11W , SO UTE # N-11W , , , SO UTE # N-11W , , , UTE #402H 402H N-11W , , , , UTE # N-11W , , , SAN JUAN 32 5 UNIT NP N-6W , , , CHAPIN N-6W DUFOUR N-6W , SAN JUAN 32 5 UNIT 100S N-6W , , , SAN JUAN 32 5 UNIT 101S N-6W , SAN JUAN 32 5 UNIT NP N-6W ,111 Table 12, page 1 of 3

42 Table 12 Maximum Annual Rates and Estimated Ultimate Recovery for Comparison Horizontal Wells Location (Twp-Rng- Sec) Ultimate Gas (MMCF) Qmax Year Monthly Average Cum Gas Remaining Group # Lease Well No API Life (MMCF) Gas (MMCF) 18 ANDERSON 1R N-6W , , , DUELL N-6W , ANDERSON 32-6 # N-6W DUELL N-6W , , , PENROSE 1R N-6W , , , , ALLISON UNIT N-6W , , , ALLISON UNIT COM N-6W PAYNE # N-6W , SO UTE H N-9W , , , SAN JUAN 32 FEDERAL N-9W , , SAN JUAN 32 FEDERAL 12 1A N-9W , , , SO UTE N-9W , , , , SO UTE N-9W , , , , SO UTE N-9W , , , , SO UTE J-26 # N-11W , , , , SOUTHE N-11W , , , , SOUTHE N-11W , , , SHORT ALVA GU A N-9W , , , , LYLE S N-9W-7 0 1, , , LYLE S N-9W , , , , SHORT ALVA GU A N-9W , , , , SHORT LYLE GU A # N-9W , , , , ROSA UNIT 273A N-6W ROSA UNIT 224A N-6W , ROSA UNIT N-6W , , , , ROSA UNIT N-6W , , , , GALLEGOS-BONIFACIO GAS UNIT A N-8W , , BRADFIELD GU CH N-8W , BRADFIELD GU CH N-8W , GALLEGOS B GU A N-8W , , IGNACIO N-8W , , , IGNACIO N-8W , KNIGHT GAS UNIT E N-9W , , , FRENCH #1-9U N-7W , , , , FRENCH GAS UNIT 1-9U 2R N-7W KNIGHT GAS UNIT N-7W , , , , LEPLATT GU A N-7W , , , , LEPLATT GU A A N-7W , , , ,932 Table 12, page 2 of 3

43 Table 12 Maximum Annual Rates and Estimated Ultimate Recovery for Comparison Horizontal Wells Location (Twp-Rng- Sec) Ultimate Gas (MMCF) Qmax Year Monthly Average Cum Gas Remaining Group # Lease Well No API Life (MMCF) Gas (MMCF) 35 THACKER GAS UNIT N-7W , , , , THACKER GU N-7W , , , , BROWN N-6W , , , BAKER # N-6W , BLOOMFIELD N-6W BROWN N-6W , , , MILLER N-6W , ,896 Table 12, page 3 of 3

44 Table 13 Maximum Annual Rates and Estimated Ultimate Recovery for Comparison Highly Deviated Wells Location (Twp-Rng- Sec) Ultimate Gas (MMCF) Qmax Year Monthly Average Cum Gas Remaining Group # Lease Well No API Life (MMCF) Gas (MMCF) 5 NORTHEAST BLANCO UNIT 479R N-7W , , , ,696 5 NORTHEAST BLANCO UNIT N-7W NORTHEAST BLANCO UNIT 413R N-7W , , , ,370 5 NORTHEAST BLANCO UNIT N-7W , , ,688 5 NORTHEAST BLANCO UNIT 413A N-7W ,502 6 SAN JUAN 30 6 UNIT NP 498R N-7W ,030 6 SAN JUAN 30 6 UNIT N-7W ,010 6 SAN JUAN 30 6 UNIT N-7W ,630 7 NORTHEAST BLANCO UNIT N-8W , , , ,258 7 NORTHEAST BLANCO UNIT 437A N-8W , , ,411 7 NORTHEAST BLANCO UNIT N-8W , , ,961 7 NORTHEAST BLANCO UNIT N-8W , , , , NORTHEAST BLANCO UNIT 404R N-7W , , , , NORTHEAST BLANCO UNIT N-7W , , , , SO UTE # N-10W , , , BONDS COM N-10W , , , , HEIZER N-10W , , , , SO UTE # N-10W , , , , CARRACAS UNIT 34 B N-4W , CARRACAS UNIT FR N-4W , , GRASSY CANYON N-7W , , , , GRASSY CANYON N-7W , , , , BLACK RIDGE SU N-10W , , , , BLACK RIDGE SU# N-10W , , , BLACK RIDGE SU# N-10W , , , , BLACK RIDGE SU# N-10W , , , , DAVE A N-10W , , , , SO UTE FC N-10W , , , , ALLISON DAVE # N-10W , SO UTE FC N-10W SOUTE FC # N-10W , , , , SOUTE FC # N-10W , , , SO UTE N-9W , , , , SO UTE N-9W , , , SO UTE N-9W , , , , SO UTE TRIBAL GU JJ N-9W , , , ,719 Table 13, page 1 of 2

45 Table 13 Maximum Annual Rates and Estimated Ultimate Recovery for Comparison Highly Deviated Wells Location (Twp-Rng- Sec) Ultimate Gas (MMCF) Qmax Year Monthly Average Cum Gas Remaining Group # Lease Well No API Life (MMCF) Gas (MMCF) 27 SIMON L&C 15U2R N-9W , , , , LINDNER GAS UNIT A N-9W , LINDNER GU A N-9W , , , , SIMON L&C 15U-2R UT 2R N-9W , , , , SIMON LAND & CATTLE N-9W , WEST ANIMAS UNIVERSITY N-9W , , , , CRAIG HELEN GU N-9W , , , , DUSTIN GU N-9W , , , , DUSTIN GU N-9W , , , , W ANIMAS-UNIVERSITY N-9W , , , , W ANIMAS-UNIVERSITY N-9W , , , CARRACAS UNIT 25 B N-4W , CARRACAS UNIT FR N-4W , , , NORTHEAST BLANCO UNIT 423R N-7W , , , , NORTHEAST BLANCO UNIT 425R N-7W , , , ,876 Table 13, page 2 of 2

46 Table 14 PERFORMANCE ANALYSIS SUMMARY HORIZONTAL WELLS IN SAN JUAN BASIN FRUITLAND CBM EUR, MMCF Maximum Annual Rate as MCF/Mo. Performance API Number Lease Well Number Horizontal Well Offset Verticals EUR Horiz / EUR Vert Horizontal Well Offset Verticals Rate Horiz / Rate Vert Index HUGHES B 18R ,661 3, SUNRAY H ,371 3, SAN JUAN 30 6 UNIT 477 9,721 6, ,555 50, SAN JUAN 30 6 UNIT 479 6,961 11, ,445 90, ROSA UNIT , ROSA UNIT ,619 7, PAYNE 11 5,068 2, ,864 18, FC FEDERAL COM , ,825 60, UTE #402H 402H 9,714 5, , , SAN JUAN 32 5 UNIT NP 100 3, ,894 7, ANDERSON 1R 1, ,938 6, PENROSE 1R 6, ,315 4, SO UTE H 3,420 4, ,470 37, SO UTE J-26 #1 1 4,748 9, , , SHORT ALVA GU A 1 4,295 4, ,218 41, ROSA UNIT 273A 33 5, , GALLEGOS-BONIFACIO GAS UNIT A 2 4,408 1, , KNIGHT GAS UNIT E 2 5,516 2, ,000 15, BROWN , ,308 3, AVERAGES Note:

47 Table 15 PERFORMANCE ANALSYSI SUMMARY HIGHLY DEVIATED WELLS IN SAN JUAN BASIN FRUITLAND CBM EUR, MMCF Maximum Annual Rate as MCF/Mo. API Number Lease Well Number Deviated Well Offset Verticals EUR Horiz / EUR Vert Deviated Well Offset Verticals Rate Horiz / Rate Vert Performance Index NORTHEAST BLANCO UNIT 479R 8,558 5, ,696 50, SAN JUAN 30 6 UNIT NP 498R ,030 6, NORTHEAST BLANCO UNIT 461 5,663 4, ,258 33, NORTHEAST BLANCO UNIT 404R 14,816 14, , , SO UTE # ,883 24, , , CARRACAS UNIT 34 B , ,452 11, GRASSY CANYON 4 3,624 9, ,638 75, BLACK RIDGE SU ,709 7, ,392 71, BLACK RIDGE SU# ,633 7, ,967 71, DAVE A 1 9,398 2, ,743 35, SO UTE FC ,255 2, ,715 35, SO UTE ,817 5, ,408 43, SIMON L&C 15U2R 2 4,519 3, ,904 23, WEST ANIMAS UNIVERSITY 9-3 2,771 6, ,178 35, CARRACAS UNIT 25 B , ,982 17, NORTHEAST BLANCO UNIT 423R 20,103 18, , , AVERAGES Note:

48 Figures

49

50 THE POTENTIAL ROCKIES BUSINESS FOR TECHNICALLY UNIT - RECOVERABLE CBM IS SIGNIFICANT W. WASH 0.7 TCF FOREST CITY/CHEROKEE 2.4 TCF ILLINOIS 1.6 TCF POWDER RIVER 25 TCF WIND RIVER 0.4 TCF CENTRAL APPAL. 3 TCF N. APPAL TCF GRN. RIVER 3.9 TCF PICEANCE 7.5 TCF GRI UINTA 3.2 TCF SAN JUAN 7.5 TCF RATON 1.8 TCF From Lamarre, 10/28/04 IPAA Emerging Technology Conference ARKOMA 2.6 TCF BLACK WARRIOR PRODUCING EMERGING PLAYS IDENTIFIED POTENTIAL Figure 1: CBM Plays in the United States

51 GRI94/0307 Fig. 5: Fruitland Formation coal-rank map in the northern San Juan basin (modified from Scott and others, 1991) HW2 HW1 HW6 HW3 HW4 HW5 Wells sample whole range of coal ranks in study area Figure 2: NSJB Fruitland Coal Rank and Six Hypothetical Well Locations

52 GRI 90/ Fig. 24: Coal overburden map defined as the depth to the top of the Pictured Cliffs Sandstone or the uppermost Pictured Cliffs tongue. Figure 3: Fruitland Coal Overburden Map

53 GRI94/0307 Fig. 6: Fruitland Formation pressure gradient in the northern San Juan basin (after Kaiser and others, 1991) HW2 HW1 HW6 HW3 HW4 HW5 Figure 4: Fruitland Formation Pressure Gradient in NSJB