I H ' HHH * /. A* ° • * * .0 ^ .» J *bK : *W* ** ° > • j§^^^a - A 0^ »VUL% "> v # i * • ,% -£ 0^ o^»^ ^*0 1* f ^vT/AiP * r <^«. A ^l • * s \ ' <\» ° • » «G o '^ °- -.*S»: „*°-v "-3 ^ .-iaSfe*. V./ /jfite\ wV ^ °J5i' ***** &$ 4 : /**> '-•' A ' V'^'V^ °°^ V'^'V V^V v*?^/ '■' VV ,* ♦ o A v » . <*>. 1C 9080 Bureau of Mines Information Circular/1986 Economic Evaluation of Horizontal Borehole Drilling for Methane Drainage From Coalbeds By Eugene C. Baker, Roy H. Grau III, and Gerald L. Finfinger UNITED STATES DEPARTMENT OF THE INTERIOR Information Circular 9080 Economic Evaluation of Horizontal Borehole Drilling for Methane Drainage From Coalbeds By Eugene C. Baker, Roy H. Grau III, and Gerald L. Finfinger UNITED STATES DEPARTMENT OF THE INTERIOR Donald Paul Hodel, Secretary BUREAU OF MINES Robert C. Horton, Director r>o< tfW Library of Congress Cataloging in Publication Data: Baker, E. C. (Eugene C.) Economic evaluation of horizontal borehole drilling for methane drainage from coalbeds. (Bureau of Mines Information circular; 9080) Bibliography: p. 10. Supt. of Docs, no.: I 28.27:9080. 1. Methane industry -Alabama -Cost effectiveness. 2. Gas well drilling -Alabama -Cost effectiveness. 3. Coal mines and mining-Alabama-Safety measures. I. Grau, Roy H. II. Finfinger, Gerald L. III. Title. IV. Series: Information circular (United States. Bureau of Mines); 9080 TN295.U4 [HD9579.M43U6] 622 s [338.2'3] 86-600068 CONTENTS Page Abstract 1 Introduction 2 General mining plan 2 Horizontal drilling plan 2 Gas drainage plan 3 Borehole locations and production 3 Gas collection and transmission system 5 Methane gas sensing system 5 Surface equipment 8 Basis for economic evaluation 8 Assumptions 8 Estimated capital investment. 8 Depreciated and expensed items 9 Estimated annual operating cost. 9 Cash flow analysis 9 Summary of discounted cash flow 10 Conclusions 10 References 10 Appendix. — Cost and analysis tables.. 11 ILLUSTRATIONS 1 . Mine plan and borehole location 6 2. Gas transmission pipeline and borehole location 7 3. Gas production decline curves 8 TABLES 1. Annual gas recovery, 1985-90 3 2. Annual gas recovery, 1986-90 4 3. Annual gas recovery, 1987-90 4 4. Annual gas recovery, 1988-90 5 5. Annual gas recovery, 1989-90 5 A-l. Estimated initial capital investment 11 A-2. Estimated deferred capital investment 11 A-3. Drill string 12 A-4. Methane gas collection system 12 A-5. Methane gas transmission system 13 A-6. Methane gas sensing system 14 A-7. Estimated capital investment summary 14 A-8. Depreciation schedule 14 A-9. Estimated annual operating cost 15 A-10. Cash flow analysis 17 A-ll. Summary of discounted cash flow 18 UNIT OF MEASURE ABBREVIATIONS USED IN THIS REPORT d/yr day per year kW/h kilowatt per hour ft foot Mft 3 thousand cubic feet ft2 square foot Mft 3 /d thousand cubic feet per day ft3 cubic foot MMft 3 /d million cubic feet per day h hour pet percent hp horsepower pct/yr percent per year h/shift hour per shift psig pound per square inch, gauge h/yr hour per year shifts/d shifts per day in inch yr year kW'h kilowatt hour ECONOMIC EVALUATION OF HORIZONTAL BOREHOLE DRILLING FOR METHANE DRAINAGE FROM COALBEDS By Eugene C. Baker, 1 Roy H. Grau III, 2 and Gerald L. Finfinger 3 ABSTRACT The potential profitability of a horizontal borehole drilling program for recovering methane gas in an Alabama coalbed for 6 yr in advance of mining is estimated in this Bureau of Mines report. A cash flow analysis based on estimated capital investments, annual operating costs, and the selling price of methane gas was used to deter- mine the net income and net cash flows for each year of operation. Sub- sequently, the annual net cash flows were capitalized to determine the discounted cash flow rate of return. Findings indicate that a 25.08-pct interest rate of return on invest- ment could be realized from the sale of methane gas in excess of 3 bil- lion ft 3 during the years 1985 through 1990 at a mine site price of $2.25/Mft 3 . 'Physical scientist. ^Mining engineer. •^Supervisory geologist. Pittsburgh Research Center, Bureau of Mines, Pittsburgh, PA. INTRODUCTION Release of methane gas from coalbeds is a serious safety hazard in underground coal mining. The Bureau of Mines has pi- oneered the development of drilling hori- zontal boreholes for draining methane gas from coalbeds in advance of mining O -4). 4 Industry has shown increasing interest in methane drainage since 1977, primarily because of the decreasing supply and in- creasing price of methane gas. The de- velopment of horizontal borehole drilling technology, improved drilling equipment, computerized methane sensing and control, systems, and definitive guidelines for installing and maintaining underground gas transmission pipelines has provided added incentive for coal producing com- panies to invest capital in methane drainage systems (5-7). Underground horizontal boreholes in coal seams have great potential for producing large-volume flows of methane. Every foot drilled in the coalbed from underground locations is productive, and gas flows increase as hole length in- creases. In using horizontal boreholes, dewatering pumps are not necessary be- cause gas pressure forces water out of the hole so that methane can be recovered through the use of simple and inexpensive gas-water separators. The quantity of available gas and po- tential drainage rates used in this re- port were based on recent tests performed at an underground mine in Alabama. The number of horizontal boreholes that could be drilled each year was based on the company's current and future coal produc- tion rate. To current knowledge, this report is the first to examine the economic feasi- bility of recovering and selling methane to gas transmission companies. GENERAL MINING PLAN The operating underground mine used in this study is located in Tuscaloosa Coun- ty, AL, and is producing coal from the Mary Lee group of coalbeds in the Warrior Basin. Overburden thickness at this lo- cation is approximately 2,000 ft; coal seam thicknesses are about 6 ft for the Blue Creek and 1.5 ft for the Mary Lee (8). The coal mine is developed primarily for longwall mining using continuous miners to drive four entry sections for longwall development. The four entries are mined on 120-ft centers and are ap- proximately 20 ft wide. The continuous mining sections employ split ventilation by using the outside two entries as re- turn airways and the middle two entries as belt and intake track airways. The longwall panels vary in length and are generally 600 ft wide. HORIZONTAL DRILLING PLAN One drilling unit would be operated two shifts a day for 240 days. Maintenance of the equipment would be done concur- rently with drilling. Twenty-three bore- holes would be drilled the first year, ^Underlined numbers in parentheses re- fer to items in the list of references at the end of this report. and 22, 19, 13, and 12 boreholes, respec- tively, would be drilled in the next 4 yr, based on the mine development plan. Drilling would be accomplished by normal rotary drilling techniques as described in previous Bureau publications (_3, 9- 10). Cost of the drilling equipment is $207,950 as shown in appendix tables A-l and A- 2. GAS DRAINAGE PLAN BOREHOLE LOCATIONS AND PRODUCTION The horizontal boreholes used for methane drainage are drilled with an underground electrohydraulic drill unit as described in a previous Bureau publi- cation (2^). The 3-1/2-in-diam boreholes are approximately 1,000 ft long. All boreholes are drilled from return airways and are started in approximately the mid- dle of the coalbed. Boreholes drilled from active continuous mining sections generally are located as close to the face as possible without causing inter- ference with production. The drilling of boreholes for this program is started at an approximate angle of 15° from the di- rection of mining advance. This reduces the probability of borehole interception of areas being mined by the continu- ous miners. The remaining boreholes are located in inactive areas of the mine and are spaced throughout the mine perimeter. The horizontal borehole locations are shown in figures 1 and 2. Figure 1 rep- resents the mine plan and additional hor- izontal boreholes on an annual basis. The gas produced from the horizontal boreholes was estimated from actual data collected from methane drainage studies of the Mary Lee Group. By averaging data from previously drilled horizontal bore- holes, estimated gas production decline curves shown in figure 3 were prepared. Two production decline curves were used, depending on the orientation of the bore- holes with respect to the highly perme- able face cleat direction. Subsequently, the production decline curves were used for determining annual gas drainage for each of the horizontal boreholes (tables 1-5). TABLE 1. - Annual gas recovery, 1985-90, thousand cubic feet 1985 boreholes 1985 1986 1987 1988 1989 1990 3 4 6 7 8 9 11 13 14 15 16 17 18 19 20 21 23 21, 21, 21, 21, 21, 21, 21, 21, 21, 21, 21. 21 21 21 21 21 21 21 21 21 21 21 21 000 600 600 600 000 000 000 000 000 000 000 000 000 ,000 ,000 000 ,000 ,000 ,000 000 ,600 ,000 ,000 11,700 5,800 5,800 5,800 11,700 11,700 11,700 11,700 11,700 11,700 11,700 11,700 11,700 NAp 11,700 11,700 11,700 11,700 11,700 11,700 NAp 11,700 11,700 8,500 4,400 4,400 4,400 8,500 NAp 8,500 8,500 NAp NAp NAp 8,500 8,500 NAp 8,500 8,500 NAp NAp NAp 8,500 NAp 8,500 8,500 6,000 3,300 3,300 3,300 6,000 NAp NAp NAp NAp NAp NAp 6,000 6,000 NAp 6,000 NAp NAp NAp NAp NAp NAp 6,000 6,000 3,400 1,700 1,700 1,700 3,400 NAp NAp NAp NAp NAp NAp 3,400 3,400 NAp NAp NAp NAp NAp NAp NAp NAp 3,400 3,400 1,000 500 500 500 1,000 NAp NAp NAp NAp NAp NAp 1,000 NAp NAp NAp NAp NAp NAp NAp NAp NAp 1,000 1,000 Total. 485 ,400 228,000 106,700 51,900 25,500 6,500 NAp Not applicable. TABLE 2. - Annual gas recovery, 1986-90, thousand cubic feet 1986 boreholes 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 Subto Carryove Total tal r. . 1986 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 464 228 692 000 000 000 000 600 600 000 000 000 000 000 000 000 000 000 000 000 000 000 600 600 ooo 400 000 400 1987 11 11 11 11 5 5 11 11 11 11 11 11 11 11 11 11 11 11 11 5 5 11 233 106 340 700 700 700 700 800 800 700 700 700 700 700 700 700 700 700 700 700 700 700 800 800 700 800 700 500 1988 NAp NAp NAp NAp 4,400 4,400 NAp NAp NAp NAp 8,500 8,500 8,500 NAp 8,500 8,500 8,500 NAp NAp 4,400 4,400 8,500 77,100 51,900 129,000 1989 NAp NAp NAp NAp 3,300 3,300 NAp NAp NAp NAp NAp 6,000 6,000 NAp NAp NAp NAp NAp NAp NAp NAp 6,000 24,600 25,500 50,100 1990 NAp NAp NAp NAp 1,700 1,700 NAp NAp NAp NAp NAp NAp NAp NAp NAp NAp NAp NAp NAp NAp NAp 3,400 6,800 6,500 13,300 NAp Not applicable. TABLE 3. - Annual gas recovery, 1987-90, thousand cubic feet 1987 boreholes 1987 1988 1989 1990 1987 boreholes 1987 1988 1989 1990 3 6 8 21,000 21,000 21,000 21,000 21,000 21,000 21,000 21,000 21,000 21,000 21,000 11,700 11,700 11,700 11,700 11,700 11,700 11,700 11,700 11,700 11,700 11,700 NAp 8,500 8,500 NAp 8,500 8,500 8,500 NAp NAp NAp NAp NAp NAp NAp NAp 6,000 6,000 6,000 NAp NAp NAp NAp 13 14 Subtotal Carryover. Total. .. 21,000 21,000 21,000 21,000 21,000 21,000 21,000 21,000 11,700 11,700 11,700 11,700 11,700 11,700 11,700 11,700 8,500 8,500 8,500 8,500 8,500 8,500 8,500 8,500 6,000 6,000 NAp NAp 6,000 NAp NAp NAp 10 399,000 340,500 222,300 129,000 110,500 50,100 36,000 13,300 739,500 351,300 160,600 49,300 NAp Not applicable. TABLE 4. - Annual gas recovery, 1988-90, thousand cubic feet 1988 boreholes 1 2 3 4 5 6 7 8 9 10 11 12 13 Subtotal. . . Carryover Total 1988 21 21 21 21 21 21 21 21 21 21 21 21 21 273 351 624 000 000 000 000 000 000 000 000 000 600 000 000 000 600 300 900 1989 11,700 11,700 11,700 11,700 11,700 11,700 11,700 11,700 11,700 5,800 11,700 11,700 11,700 146,200 160,600 306,800 1990 8,500 NAp 8,500 8,500 8,500 8,500 8,500 8,500 NAp 4,400 NAp 8,500 8,500 80,900 49,300 130,200 NAp Not applicable TABLE 5. - Annual gas recovery, 1989-90, thousand cubic feet 1989 boreholes 1 2 3 4 5 6 7 8 9 10 11 12 Subtotal Carryover Total 1989 21,000 21,000 21,000 21,000 21,000 21,000 21,000 21,000 21,000 21,000 21,000 21,000 252,000 306,800 558,800 1990 11,700 11,700 11,700 11,700 11,700 11,700 11,700 11,700 11,700 11,700 11,700 11,700 140,400 130,200 270,600 GAS COLLECTION AND TRANSMISSION SYSTEM The gas collection system gathers the methane from the coal face, separates gas from water prior to its entering the transmission system, and measures the gas production. The gas collection system for each borehole comprises a stand- pipe, a water trap, a venturi meter, and assorted valves, fittings, and pipes (2). The total costs of the gas collection and transmission systems are $132,910 and $584,700, respectively, as shown in ta- bles A-4 and A-5. The underground gas transmission system is constructed of 6- and 8-in-diam poly- ethylene pipe and 10-in-diam steel pipe. The 6-in-diam polyethylene pipe would be used for transporting the gas from each mining section, and the 8-in-diam polyethylene pipe would serve as the main line of the system. Each year addi- tional polyethylene pipe would be added as needed to connect with newly drilled boreholes. The 8-in-diam polyethylene pipe would connect with the 10-in-diam steel pipe, the mine's porting the which would be anchored to return air shaft for trans- collected gas to the sur- face. For emergency shutdown and mainte- nance, all underground gas lines would be equipped with manual shutoff valves. The pipeline sizes were selected to minimize pressure losses based on expected gas flows and pipeline lengths. METHANE GAS SENSING SYSTEM The underground gas collection and transmission system is continuously moni- tored for leaks by methane sensors in- stalled at strategic locations through- out the mine. The sensors are connected through a series of control devices to pneumatically activated valves at each horizontal borehole. The valves pneumat- ically close if unsafe conditions occur, thereby automatically stopping the gas flow from each borehole. The safety sys- tem requires the installation of methane sensors, a microprocessor, a data sta- tion, and a 3/4-in-diam polyvinyl chlo- ride (PVC) pipeline which delivers LEGEND Panel Borehole and Mine boundary Lj ^ -r r FIGURE 1.— Mine plan and borehole location. LEGEND Borehole and number Year 3 1985 3) 1986 Manual valve /^"8-in main line E\ © S/ ©/ A7 ■ 2,000 1 1 1 Scale, ft 4' 3 2 FIGURE 2.— Gas transmission pipeline and borehole location. "I 1 1 1 1 — KEY Hole parallel to face cleat Hole perpendicular to face cleat 2.0 2.5 3.0 TIME, yr FIGURE 3.— Gas production decline curves. compressed air to the pneumatic valve. The system is described in detail in a previous publication (9). The total cost of the pipeline sensing system is $455,910 as shown in table A-6. SURFACE EQUIPMENT The main function of the surface equip- ment is to assure continuous quality con- trol of the recovered gas and to provide sufficient gas pressure to access a natu- ral gas transmission system. Basic sur- face equipment includes a 168-hp com- pressor capable of handling 2 MMft 3 /d at 30-psig discharge, a gas analyzer, a flowmeter, a temperature monitor, and three flame arrestors installed for fire safety control. The surface equipment would be continuously operated and would require daily inspection and periodic maintenance. Cost of the surface items is $209,350 as shown in table A-l. BASIS FOR ECONOMIC EVALUATION ASSUMPTIONS 1. Project development and the pur- chase of initial property were completed in 1984 by company personnel. The pur- chase price of surface building equipment and drilling equipment includes installa- tion and setup by the vendor. 2. The horizontal drilling program will be conducted for 5 yr, and methane gas will be recovered and marketed for 6 yr. The producing company owns the gas rights. 3. Costs of initial and deferred capi- tal equipment, operating materials, sup- plies, and electric power were obtained from suppliers. 4. Tangible assets were depreciated over 5 yr using the accelerated cost recovery system rates, and salvage val- ue is recovered on deferred capital investments. 5. Labor wages are escalated from third-quarter rates quoted in the Bitumi- nous Coal Wage Agreement of 1981; salar- ies of supervisors and technicians are escalated on the basis of estimates ob- tained from industry. 6. Working capital is based on the cost of operations for 3 months. The value of working capital at the end of the gas drainage program will be equal to its initial value. 7. Equity capital will be used to fi- nance the project. ESTIMATED CAPITAL INVESTMENT The estimated capital investment in- cludes initial expenditures in 1984 and deferred capital costs in 1985 through 1988. The items included in the total capital investment are detailed in table A-l and summarized in table A-7. Project development is an intangible cost that is not depreciable. In the cash flow analysis (table A-10) develop- ment costs are expensed in 1984 and car- ried forward to 1985, which is the first year of operation and revenue. The surface building and equipment and drilling equipment detailed in table A-l were purchased in 1984. They are to be placed in service in 1985 and be fully depreciated by the end of the borehole drilling phase of the project in 1989. The quantity and cost per year of ini- tial and deferred items included in the methane gas collection system, trans- mission system, and sensing system are detailed in tables A-4, A-5, and A-6. These items would be purchased during the year prior to the start of borehole drilling and gas drainage. The intangi- ble indirect capital costs are shown in the year incurred. Based on the mine development plan, the number of boreholes to be drilled each year from 1985 through 1989 is 23, 22, 19, 13, and 12 respectively, as shown in tables 1-5. The boreholes that show no drainage are either depleted of gas or mined through. As a result, the equip- ment and materials of the gas collection system, transmission system, and sensing system that were used on these boreholes will be dismantled, moved, and installed for use on boreholes that will be drilled in subsequent years. The capital cost of the initial and deferred systems includes the purchase price and installation of new items added each year and the disas- sembly, moving, and installation costs of the items recovered each year from non- producing holes previously drilled. DEPRECIATED AND EXPENSED ITEMS Initial and deferred direct capital in- vestment items shown in table A-l are de- preciated in table A-8 using accelerated cost recovery rates of 15, 22, 21, 21, and 21 pet for 1986-90, respectively. Initial and deferred indirect capital investment items including administra- tion, overhead, and contingency are ex- pensed as intangible costs in the cash flow analysis (table A-10). The systems used for gas collection, transmission, and sensing will be placed in service in 1985 and 1986 and are as- sumed to be fully depreciated in 5 yr. Additional items will be placed in ser- vice in these systems in the following 3 yr but will not be fully depreciated. Salvage value equal to book value is taken on the systems because they will be used in subsequent gas drainage projects. ESTIMATED ANNUAL OPERATING COST Horizontal drilling of boreholes into an underground coalbed for the drainage of methane gas will continue for 240 d/yr for 5 yr. Methane gas will drain from the boreholes for 6 yr, during which time the surface, drilling, and gas sensing equipment will be monitored and main- tained. The estimated annual operating costs are detailed in table A-9. The pay for wage and salaried personnel is escalated 8 pct/yr for the first 3 yr of operation and 10 pct/yr for the last 3 yr. Shift differential pay of $0.30/h and $0.40/h for the second and third shift is included in total wages for op- erating and maintenance labor. The initial and escalated costs of sup- plies and parts are based on estimates provided by suppliers, and electric power is escalated 5 pet from its base price in 1984. Payroll overhead is based on 57 pet and 30 pet of the cost of labor and super- vision, respectively. It includes all benefits except workman's compensation and black lung benefits, which are cov- ered by company insurance. CASH FLOW ANALYSIS The cash flow analysis shown in table A-10 lists the accounting entries and how they were used to arrive at annual net cash flows. The annual cubic feet of gas available for sale is the difference between total gas recovered and that consumed by the compressor. Revenue is the product of gas sales and price per thousand cubic feet. Operating costs, which include depre- ciation, are described in the previous section. Development and indirect capital costs are intangible costs that are not depre- ciable; they are carried forward as nega- tive income and deducted against revenue until they are expended. Depletion is based on the allowable rate of 15 pct/yr on revenue with a limit of 50 pet of gross income. Investment tax credit of 10 pet was taken on the direct cost tangible items shown in table A-l. The first credit was taken in 1986 on direct capital costs in- curred in 1984. The credit in 1987 is the sum of the credit carried forward from the 3 previous years and the credit allowed on direct capital for 1987. Net income is the sum of after-tax rev- enue and investment tax credit. Depreciation and depletion are non- cash deductions for tax purposes. 10 Subsequently, depreciation, depletion, and losses carried forward were added to net income to determine operating cash flow. SUMMARY OF DISCOUNTED CASH FLOW The summary of discounted cash flow shown in table A-ll shows how the net present value and discounted cash flow rate of return were determined. The net cash flows from table A- 10 were discounted by using continuous interest factors of 25 and 30 pet. Subsequently, the discounted cash flow rate of return was calculated by interpolating between 25 and 30 pet. CONCLUSIONS Results from the economic evaluation of drilling horizontal boreholes in an un- derground coalbed in Alabama for the re- covery and sale of methane gas indicate that an investment rate of return of 25.08 pet could be achieved by selling the gas at a relatively low constant price of $2.25/Mft 3 for the 6-yr period 1985-90. Based on projections from the American Gas Association TERA-Fall 1983 Base Case of average wellhead nominal prices in- cluding severance and gathering taxes, the price of natural gas per thousand cubic feet will be $3.96 in 1985, falling to $3.60 in 1987 and increasing to $4.28 in 1990 (11). REFERENCES 1. Brezovec, D. Mine Fans Deliver High Pressures. Coal Age, June 1980, pp. 84-97. 2. Campoli, A. A., J. Cervik, and S. J. Schatzel. Control of Longwall Gob Gas With Cross-Measure Boreholes (Upper Kit tanning Coalbed). BuMines RI 8841, 1983, 17 pp. 3. Cervik, J., H. H. Fields, and G. N. Aul. Rotary Drilling Holes in Coalbeds for Degasif ication. BuMines RI 8097, 1975, 21 pp. 4. Diamond, W. P. , and J. R. Levine. Direct Method Determination of the Gas Content of Coal: Procedures and Results. BuMines RI 8515, 1981, 36 pp. 5. Fields, H. H. , J. Cervik, and T. W. Goodman. Degasif ication and Production of Natural Gas From an Air Shaft in the Pittsburgh Coalbed. BuMines RI 8173, 1976, 23 pp. 6. Fields, H. H. , J. H. Perry, and M. Deul. Commercial-Quality Gas From a Multipurpose Borehole Located in the Pittsburgh Coalbed. BuMines RI 8025, 1975, 14 pp. 7. Finf inger, G. L. , and J. Cervik. Review of Horizontal Drilling Technology for Methane Drainage From U.S. Coalbeds. BuMines IC 8829, 1980, 20 pp. 8. Harris, G. J., R. W. Dalzell, and J. W. Stevenson. Mine Ventilation Prin- ciples. Sec. in SME Mining Engineering Handbook, v. 1, ed. by A. B. Cummins and I. A. Given. Soc. Min. Eng. AIME, 1973, pp. 16-22. 9. Perry, J. H. , L. J. Prosser, Jr., and J. Cervik. Degasif ication of the Mary Lee Coalbed, Brookwood, Ala. Bu- Mines RI 8669, 1982, 13 pp. 10. Prosser, L. J. , Jr. , G. L. Finfin- ger, and J. Cervik. Methane Drainage Study Using an Underground Pipeline, Marianna Mine 58. BuMines RI 8577, 1981, 29 pp. 11. American Gas Association. AGA- TERA Fall 1983 Base Case Analysis, Sup- plement C. Arlington, VA, Nov. 1983, p. 5. 11 APPENDIX. —COST AND ANALYSIS TABLES TABLE A-l. - Estimated initial capital investment Item Development: Preparation of drilling plan and procedure Training of personnel in drilling and maintenance techniques Site preparation for surface building and equipment Supervision, office, and general overhead associated with development Subtotal Direct cost: Surface building and equipment: Building - 400-f t 2 , metal, insulated, complete with utilities Gas analyzer and recorder Gas flow meter Temperature meter Flame arrestors - 1 horizontal, 1 vertical Compressor - 168-hp, 2-MMf t 3 /d-capacity , 30-psig-discharge Check valve - 10-in Steel pipe - 2,000-ft, 10-in-OD, installed in shaft Fence - 8-ft chain link, 800-ft-long, 12-ft gate Miscellaneous pipe and fittings Subtotal Drilling equipment: Electrohydraulic drill and power unit Pump - water-recirculating, 30-hp Pump - grout Mixer - grout Pipe fusion machine Drill string - see table A- 3 Subtotal Gas collection system - see table A-4 Gas transmission system - see table A-5 Gas sensing system - see table A-6 Total direct cost Indirect cost: Administration and overhead (except development) Contingency Total indirect cost Net initial investment Working capital Total initial investment Cost, 1984 $20,000 3,750 2,000 2,580 28,330 26,000 3,900 2,000 580 4,570 93,200 630 72,840 3,160 2,470 209,350 91,580 6,870 3,200 4,410 11,730 69,000 186,790 38,000 295,090 276,930 1,006,160 100,620 170,270 270,890 1,305,380 193,260 1,498,640 TABLE A-2. - Estimated deferred capital investment Item Cost 1985 1986 1987 1988 Direct cost: Drilling equipment, drill string bit inserts only, table A-3 $6,550 38,540 113,250 73,210 $6,000 28,390 114,080 68,030 $4,350 21,640 50,440 26,460 $4,260 6,340 11,840 11,280 231,550 216,500 102,890 33,720 Indirect cost: 23,160 38,210 21,650 35,720 10,290 16,980 3,370 5,560 61,370 57,370 27,270 8,930 292,920 273,870 130,160 42,650 12 bo c w CO < co 4_> *J CO o o H o o o o o CMn oo c 1/1 iD 1/1 \C ON — 1 CM ■C0- O — I o f- o CO m o ft ft a no < < <; cm z z z < z en a a a cn CJ co qj co n a) • iH O" CD 4J • HH z • CO CO CQ co m • M CO -orH CD OJ rH CO QJ U N r-t 13 QJ O t-l O O *J 4j i— i o u co CJ CO cj CD CO N QJ •H CO J-J 0) QJ N N iH •H CD CO o-o CO o- PQ o- PQ C_) CJ) Q Q -O QJ O 4H P CD rH CO rH CD •H QJ r4 rH a QJ QJ > > rH H tH CO CO 3 4H > CO O J* M CJ QJ OJ 4J J= co CJ 3 E QJ 4-1 CD S^ CD b o o cj co CO bO QJ B CO .c 4H QJ g Ed rJ PQ < ft O o o O O O o o o o o O rH vO co r^ CM r» cm rH 00 in no in r-H CO 4-1 co . in co On 4H CO * — ^ *• «> ^ r ^ •* •> n O O vD — i co . — i O 00 #-H CM rH . 1 CM H o - — i <- cn — h CM CO o o o O o o o o o c o o 4-1 co 00 no oo JJ 4-1 " H •H 4-J 14H c CM o o O o o o o o ft ft ft CO i — 1 CM < < < 3 rH z z Z O" o o o o o o o o o c o o 4-1 co o o 00 r* - ^ CM >i On 4-1 4-J — ' ■H 4-J •4-1 B ro o o o o o o o O ft ft ft CO i — i ^-H i—4 cn -H CM ^^ r- H CO < 00 CM NO in r^ cn cn vO NO 00 N on 4H 4-1 ^ •H 4H 14H c CM CM CM O cm . rH ^ •* *■ r •* CJ cn •co- CM CM On CM co • • O U rH TJ CM •• 4H • CU . . 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