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HomeMy WebLinkAboutWestern Arctic Coal Development Project Phase lll Final 1988Alaska Energy Authority COA LIBRARY COPY Departme Affairs _ 949 E. 36th Avenue, Suite 400, Anchorage, Alaska 99508 — 1D Alaska Native Foundation Wd 4101 University Drive, Anchorage, Alaska 99508 __ Western Arctic _ Coal Development Project PHASE Ill FINAL REPORT | arctic slope consulting engineers April, 1988 Department of Community and Regional Affairs 949 E. 36th Avenue, Suite 400, Anchorage, Alaska 99508 Alaska Native Foundation 4101 University Drive, Anchorage, Alaska 99508 Western Arctic | Coal Development Project PHASE Ill FINAL REPORT B_» arctic slope consulting engineers April, 1988 < a w < CoA osl Prepared for STATE OF ALASKA DEPARTMENT OF COMMUNITY AND REGIONAL AFFAIRS 949 E. 36th Suite 400 Anchorage, Alaska 99508 and se ALASKA NATIVE FOUNDATION A. nr 4101 UNIVERSITY DRIVE Wap ANCHORAGE, ALASKA 99508 State Contract No. LG2172117 Western Arctic Coal Development Project PHASE Ill FINAL REPORT APRIL, 1988 Prepared by 6700 Arctic Spur Road Anchorage, Alaska 99518 (907) 349-5148 2. engineers A SUBSIDIARY OF ARCTIC SLOPE REGIONAL CORPORATION WESTERN ARCTIC COAL DEVELOPMENT PROJECT June 30, 1988 P.O. Box 129, Barrow, Alaska 99723 a Telephone: (907) 852-4556 or Jane Angvik, Contract Administrator (907) 852-8633, Ext. 235 Alaska Native Foundation Telecopier: (907) 852-5733 4101 University Drive Anchorage, Alaska 99508 Subject: WESTERN ARCTIC COAL DEVELOPMENT PROJECT, PHASE III - FINAL REPORT Dear Ms. Angvik, Arctic Slope Consulting Engineers (ASCE) is pleased to submit herein the Western Arctic Coal Development Project (WACDP), Phase III - Final Report. This report marks the completion of an in-depth feasibility study that began in July 1984. The purpose of this assessment was to investigate the feasibility of developing a local coal industry in the Western Arctic to supply an energy alternative to fuel oil for those communities, military installations, and jndustries lying along the northern and western coasts of Alaska. The Phase III report presents a _ near term development strategy that if implemented will provide many long term social and economic benefits to the state and study region. Some of those benefits are: 1) provide an abundant, economic, and stable price energy resource to a region that traditionally pays some of the highest cost for energy in the nation; 2) provide long term permanent employment in an area of high unemployment; 3) stimulate and diversify the state and regional economy; 4) and reduce the states participation in energy assistance programs in the region. The Phase III report in combination with the WACDP Phase II Final Report provide documents whereby future decisions concerning project development can be made. Further, if it is determined to proceed with development, these reports can be used as a control document during future WACDP activities including project permitting, final design, and construction. The ASCE project team wishes to express its appreciation for the opportunity to have worked with you and thank you for your cooperation and assistance through all phases of this project. In addition, we wish to thank the many people contacted in the study region whom unselfishly gave of their time to provide valuable input and assistance throughout this assessment. Yours Truly, Arctic Slope Consulting Engineers Western Apetic Coal Deveropment Project Kent Grinag Project Manager Total cost for coal use are less than oi] over the 20 year time period, however the large capital investments, for coal conversions, required in the initial years of the project affect the operational savings. If generation equipment capital costs are excluded from the analysis savings over the 20 year time frame exceed $26 million. Without state assistance in the area of power plant capital costs the project would still achieve positive benefits at a higher production level during initial development and/or higher oil prices. Results of Phase III produced lower overall capital costs and production costs than those previously reported in Phase II. In addition the report presents a near term development strategy that indicates two stages of development to be the preferred approach to project. development. This approach takes advantage of increasing annual coal volumes while decreasing production costs. With state assistance in the area of power generation facilities, the WACDP project can be developed in the near term and at the lower tonnages while placing the WACDP in a position to penetrate the market further, again increasing the annual production rate while reducing the unit cost of coal. With the project in full production many long term benefits to the state and region can be realized, such as: providing an abundant stable price energy source; providing long term permanent employment in an area of high unemployment; reducing the states participation in energy assistance in the region; and stimulating and diversifying the regional and state economy. viii Alternatives to a berthing facility were examined such as lighterage of coal to line haul barges and use of slurry pipelines or conveyor systems. The analysis showed lighterage of coal to be the most attractive option, especially at the lower tonnages. Camp facilities and associated costs were examined in considerable detail. Revised cost estimates are presented for the road, airstrip, camp, and port facilities. Under the 50,000 tpy scenario, the revised Phase III infrastructure capital cost requirements were estimated to be $6,230,000; under the 20,000 tpy scenario, the capital cost is estimated at $4,730,000. The revised Phase III infrastructure operating, maintenance, and fuel costs are estimated at $505,000 annually under the 50,000 tpy scenario, and $203,000 per year under the 20,000 tpy scenario. Significant savings were realized through size reduction of the camp facility and in the use of lightering in lieu of a dredged marine berthing facility within Omalik Lagoon. Financial and Economic Analysis The financial and economic analyses focused on changes due to project design and scale modifications. The staged development assumes an initial production rate of 30,600 tpy (stage 1) increasing to 47,590 tpy (stage II) over a five year period. These production levels are achieved with essentially the same fixed capital outlay as the 20,000 tpy base case. Fixed costs represented by the initial capital cost were held constant with the exception of the bulk fuel storage costs, and stockpile loading costs. By holding capital cost relatively constant while substantially increasing production rates it provides corresponding economies of scale. As a result the cost per ton drops from $106.72 for the 20,000 tpy base case to $82.81 for stage I and to $67.57 for stage II. This represents a price reduction of $23.91 and $39.15. vii Mine Engineering New geologic information and the new topography data dictated that certain revisions should be made to the base case preliminary mining plan. Information regarding the spoil characteristics suggest that the top 5 feet of the spoil can _ be successfully ripped without blasting. This results in an estimated savings in mining cost of about $0.48 per ton. The cost for a steady state production level of 20,000 tpy was investigated. It was found that adequate reserves of coal could be uncovered with hydraulic excavator, without the need for spoil hauling equipment. The 20,000 tons could be produced in the fall of the year, taking advantage of maximum thaw depth in early fall and frozen surface conditions in the late fall. The coal could be mined in about three months with a maximum crew of 9 persons and stockpiled at the port, for shipment to markets the following year. The estimated mining cost for the 20,000 tpy production rate is $42.00 to $46.00 per ton for mining and delivery of uncrushed coal to the port stockpile. Infrastructure Development In response to permitting agency comments, the relocation of the proposed marine berthing facility (described in the Phase II report) to the northeast corner of Omalik Lagoon, was estimated instead of to the northwest corner as was initially proposed. The analysis determined that this option would decrease mining haul road construction costs by about $85,000 but that it would necessitate an increase in initial dredge excavation costs by about $186,000. Thus, the capital expense of this project would increase by about $100,000. Further, permitting the new option may be more difficult to do than the northwest corner option. vi expansions to an annual tonnage rate of about 47,590 tpy, the additional tonnage consisting of the Bethel Utility demand as wel] as various institutional demands in Kotzebue, Nome and Bethel. Staged development will allow time for the mining and shipping operations to gain experience and improve upon performance prior “to the operations reaching full capacity. Once the market has reached the second stage of development the project will begin to make additional inroads into the total potential market, first in the villages surrounding the major communities, as well as the coastal villages convenient to shipping. With the continued development of the mine, both hardrock mining interests and military installations in the region could be developed to use Western Arctic coal. Coal Field Geology The purpose of the Coal Field Geology Program was to expand on the coal geologic database within the selected Mormon Block West Mining Unit of the Deadfall Syncline. Several geologic factors brought to light by the bulk sampling programs and additional exploration drilling indicated that the reserve estimate for the Mormon West mining unit should be revised. The two factors that have the greatest impact on the reserve estimates are, the coal dips appear to be significantly greater than what was assumed originally and that the recovery of coal from DFS 4 Seam will likely be greater than had originally been assumed. To assess the overall effect of all the new geologic information on the reserve base, new cross sections of the mine area were taken and analyzed for coal reserves at various stripping ratios. The net effect of the analysis is that the estimated reserve base for the base case stripping ratio of 4:1 is reduced to approximately 1,050,000 tons, down from the Phase II estimate of 1,170,000 tons. This amount of coal is still adequate to cover the first ten years of mine production. Major findings reported from the field studies were: Beluhka arrived at Omalik Lagoon on June 27. They receded north and were absent from the area by July 13; Brown bear sitings occurred mostly during July and August, with several incidents of bears present in the Deadfall Syncline camp. No salmonoid fisheries were captured or observed in Kuchiak Creek during brief fishing efforts, suggesting that fish use of the creek is limited. Coal Demonstration Program The Mineral Industry Research Laboratory conducted a _ coal combustion test of Deadfall Syncline coal in selected residential coal combustion heating units. Combustion testing was performed on a Chippewa Trader Mountain Man 85 furnace and a Harmon Mark III stove. The mechanical performance of the furnace system was acceptable. Furnace efficiency was no. more than 40%, apparently due to low feed rate into the furnace. The stove performed well achieving an efficiency of 64%. Analyses of the furnace and stove stack gases indicate that pollutant concentrations are reasonably low for the observed burn rates. Sulfur emissions from the stove were found to be substantially lower than that produced by oi] heating. Oi] was estimated to produce 76.7 1b of SOz per year. Coal was estimated at only 6.9 1b of SOz per year. Market Evaluation The basic findings of the Phase III marketing effort indicate the development of the WACDP should be viewed in stages with the start up production rate of 30,600 tpy based on the coal demands from three North Slope villages and the power utilities of Kotzebue and Nome. These communities and organizations have shown the highest interest in the project and are logical choices based on their close proximity to the mine site and high energy costs associated with their areas. Over a five year period the market will see iv EXECUTIVE SUMMARY The Western Arctic Coal Development Project (WACDP) was established to determine the feasibility of developing a coal industry in the Western Arctic providing an abundant, economic, stable priced energy alternative to fuel oi] to communities, military installations, and industries along the northern and western coasts of Alaska. The WACDP assessment was divided into 3 phases. Phases I and II provided the information necessary to evaluate the economic, technical, and environmental feasibility of the selected mining site. The WACDP Phase III was initiated to augment ‘the efforts of Phases I and II by providing special studies identified in the Phase II report as being necessary prior to a development decision being made on the project. Phase III initiated: the process of gathering baseline physical data for the Mormon West Block mining unit for mine engineering; the performance of the first extensive and continuous environmental observation of the WACDP environs; a marketing effort establishing the start up and near term development of the mine; and a domestic stove and furnace combustion test and analysis using Deadfal] Syncline coal. The remainder of this section will present a summary of the major findings of this report based on each major task of the project. Environmental Assessment Results of the Phase III Environmental Assessment Appendix D, indicates that there are no major environmental constraints to further consideration of the project. Continuous ecological studies of the WACDP environs were conducted during June 20, to October 5, 1987. Information and reports were gathered on belukha, caribou, waterfowl and shorebirds, brown bears, furbearers, and incidental animal populations. Input from Point Lay residents, resource agencies, and fisheries and archaeological consultants were integrated into the report. ne TABLE OF CONTENTS Cover (Coal Mining Near Wainwright, Alaska 1921) Cover Letter . Executive Summary. Section 1.0 2.0 3.0 4.0 5.0 INTRODUCTION. . . 1.1 Background. ‘ 1.2 Western Arctic Coal Devel opment Project ‘ 1.3. Project Organization. . . 1.4 Organization of the Phase Ill Final Report. MARKETING EVALUATION . . 2.1 Introduction. . . 2.2 Market Area and Demand. 2.3 Conclusions . 2.4 References. . eo So > - DEMONSTRATION PROGRAM . Introduction. . . Bulk Sample Analysis. cei : Briquetting of DFS Coal Fines : Combustion Efficiency Testing . Conclusions . References. . . WWWWWW AnPwWwWNr oO Ce Oe ee ee FIELD GEOLOGY PROGRAMS. Introduction. . Geology .... Bulk Sampling . : Definition Drilling. . Rippability Study . . . Cratering Test. Magnetometer Survey . Conclusions . . Definitions .. References. . . PPHPHP PP PHF HHO Oo MINE ENGINEERING ANALYSIS. 5.1 Introduction. 5.2 Site Survey . 5.3 Phase II Mine Plan Revisions. Bier ‘i 5.4 20,000 Ton Per Year Production Rate : 5.5 Conclusions ‘ LL ix e MMP 1 NM ' WWWW 1 oo Pwr PPpPppHL 1 i PpPPPHPHL NPR 1 rowo 1 aan Pee i ca I PRP Re be i owmwrfrnNnr t mn I ' Orawr 1 1 1 1 ' OWDOUWUWWPE 9 WOWDHWUOWMHPWNH i i ' ONOUWr 6.0 7.0 8.0 RECOMMENDATIONS Introduction .. San or 8.2 Project Development wee 8.3 Summary 8. ADAAA+ aPWwNnre aan 6 7 8 ECON ied ie ics 7.4 NFRASTRUCTURE EVALUATION 1 OMIC ANALYSIS. Introduction. ....... Marine Berthing Facility Location Option. : : : : : Camp Utility Systems (50,000 tpy Scenario). .... . Camp Facility Requirements (20,000 tpy Scenario). ... Road, Airport, and Staging/Stockpile Area Requirements. . . . Revised Marine Transportation Facility. Conclusions =<; «a. 4-5 a6 s=5 096 4 : % References: 26. 4 66 we es ss Introduction ... ; : : i Financial Evaluation. Coe at ene ae mS - : : : Economic Evaluation . . us @ Conclusions ...... et oe ee APPENDICES A xronmoow Institutional Coal Boiler Conversion Schematics and Cost Estimates Test Results Sample Calculations Coal Field Geology Data Characteristics of Thermex T-100 Surface Topography, Mormon West Block Dredged Spoils Analysis Sediment Transport Survey Hydrology Survey 1.0 INTRODUCTION Index g Paragraph Pp 1.1 Background. ...... ne ee ee 1.1.1 Problem Statement ....... SSS 1.1.2 Western Arctic Coal... ........... a 1.2 Western Arctic Coal Development Project ———— 1.2.1 Phase —I-Studiies 6s, 35 9 ee 1.2.2 Phase II Studies ........... foe 1.2.3 Phase III Program. . eee Te 3 PVhOjseCt_ONGaMnil Zac lOM tems ter ote otros 1 PRP PRP PRP RR ' PrP Ono WNP 1.4 Organization of the Phase III Final “Report eee eee = Table Number Page i=1—Project—leat\—.—.— 3. — ae no 2 ee 1-9 Attachments Figure 1-1 Location Map 1.1 Background 1.1.1 Problem Statement The Western Arctic Coal Development Project (WACDP) Phases I through III was conducted from July 1984 through March 1988. It assessed the potential of developing a coal industry in the western Arctic to supply an energy alternative to communities, industries, and military installations along the northern and western coasts of Alaska. In this region fuel oil is the predominant energy source and its costs have remained very high despite the fluctuations in crude oil prices. This situation has created hardships, altered lifestyles of rural residents, and suppressed economic development throughout the area. In addition, the rural energy problem has been impacted directly, by reductions in federal and state energy assistance programs, and indirectly, by the substantial decreases in state, federal and _ local expenditures in capital projects which in the past have provided cash income opportunities to many rural Alaskans. The energy problem that persists in rural Alaska is complex and solving the problem will require consideration of many important issues. However, to meet the needs of rural residents, solutions to the problem must focus on two critical concerns; 1) development of a dependable and economical source of energy, and 2) development of additional employment opportunities within the region. State and local agencies have investigated many potential energy alternatives for rural Alaska over the years. Results of the WACDP and other studies conducted by the Alaska Power Authority, State Division of Legislative Finance, and North Slope Borough indicate that the resources of the western Arctic shows real promise as a viable substitute for fuel oil in northern and western regions of the state. These coal resources could provide T= 2 an abundant and economically competitive source of energy for communities and industries within the region while increasing employment opportunities. Further, the State of Alaska would realize additional benefits such as: reduction in the cost of economic development in western Alaska; diversification of the state economy; and reduction in state energy and power subsidy programs. This concept of addressing the rural energy problem through development of a coal industry that would have a significant impact on the regional economy was presented in House Research Agency Report 85-C entitled, Rural Energy - An overview of Programs and Policy. 1.1.2 Western Arctic Coal The coal bearing lands of the western Arctic lie along the Chukchi “Sea coast from Cape Beaufort northeast to the Village of Point Lay (see Figure 1-1). They represent the western tip of what may be the largest coal province in the world, extending for more than 300 miles from the Chukchi Sea east through the National Petroleum Reserve Alaska (NPRA) into the Arctic National Wildlife Refuge, and ending south of Camden Bay. These coal deposits underlie approximately 30,000 square miles of the North Slope area and may contain up to one-half of the state's total coal resources. Ross Schaff, State Geologist (1980) estimated the northern coal fields to contain 402 billion to 4.0 trillion tons of hypothetical coal resources. The Arctic Slope Regional Corporation selected the western Arctic coal bearing lands as part of the Alaska Native Claims Settlement Act of 1971 and holds title to the coal resources. Preliminary geologic work on the western Arctic coal resource began in the 1920's when the U.S. Geological Survey (USGS) investigated the western Arctic in conjunction with evaluating the Naval Petroleum Reserve No. 4 (now NPRA). In the 1940's and 1950's, the entire area was mapped and from the late 1940's to the 1 = 13 present, the USGS and the Bureau of Mines have intermittentily mapped, sampled, and drilled various potential coal resource locations. In the early 1980's the State of Alaska, Division of Geological and Geophysical Survey investigated the area for the Northwest Alaska Coal Program and the USGS National Coal Resource Evaluation Program. Other recent investigations included a reconnaissance survey and drilling program performed under WACDP Phase I in 1984 and a geophysical and drilling program conducted by the Arctic Slope Regional Corporation in 1985. Even though less than 30 percent of the coal resource in the western Arctic has been adequately explored, results of the field investigations show that the western Arctic coal resource is vast in quantity. Geologic studies of the western Arctic coal deposits indicate that the coals are bituminous in rank and are of a generally high quality, and include some of the best coals’ in Alaska. The coal has an ASTM classification of high volatile bitumuous B to A. Heating values of the coal average in excess of 12,000 btu/1lb (on an as received basis) with a moisture content of about 5 percent and a sulfur content ranging between 0.1 and 0.3 percent. 1.2 Western Arctic Coal Development Project Based on the results of the past studies and geologic investigations described above, the Alaska Native Foundation (ANF) decided to further evaluate the potential of western Arctic coal as a fuel source for the region. The interest of the ANF in conducting the project was to conduct research that may result in a long-term solution to the rising costs of maintaining rural lifestyles in western Alaska. In that context, the ANF submitted a proposal to the 1984 Alaska State Legislature to fund an in-depth study of western Arctic coal. The WACDP was authorized in June 1984 by appropriation of funds to the State of Alaska Department of Community and Regional Affairs (ADCRA). ANF was retained by ADCRA to administer grant funds. 1-4 WACDP was divided into three (3) phases. Phase I being a reconnaissance and preliminary economic evaluation, Phase II provided an in-depth analysis of the project, and Phase III provided specific baseline, geologic and engineering data. Descriptions of each phase follows. 1.2.1 Phase I Studies Phase I, which began in July 1984, was designed to evaluate the coal resources of the area, identify a potential mine site, and evaluate the overall economic viability of the project. The following major tasks were conducted during this Phase. - Geologic Reconnaissance - Drilling Program - Coal Sample Analysis - Preliminary Environmental Analysis - Permitting Requirements - Preliminary Market Evaluation - Preliminary Economic Evaluation Phase I studies were completed in November 1984. The findings of Phase I. indicated that: 1) the western Arctic coal resource was vast in quantity, high in quality, and had favorable mining parameters, 2) the energy requirements for the regional communities could be met by coal from the Deadfall Syncline area of the western Arctic coal fields; and 3) there were no major technical or environmental obstacles to proceeding with the WACDP. 1.2.2 Phase II Studies As a result of the promising findings of Phase I, the second phase of the project was initiated in December 1984. The primary objective of Phase II was to perform an in-depth analysis of the planned components of the WACDP to determine whether or not the a5 project was feasible in terms of the technical, social, environmental, and economic considerations of the selected mining site. Phase II studies were conducted at a level of detail that provided the prospective mine developer with a reasonable level of confidence in the economic and technical feasibility of extracting and delivering coal. Phase II included the following major tasks: - Market Evaluation - Village End Use Assessment - Mine Planning and Design - Infrastructure Development - Marine Transportation Evaluation - Environmental Assessment - Economic/Financial Analysis - Component Impact Evaluation - Permitting Plan - Pre-Development Drilling Program Phase II was completed in June 1986. It established the Mormon West Block Mining Unit of the Deadfall Syncline as the initial mining unit for the project, identified Omalik Lagoon as the preferred port site, and provided conceptual plans for a marine berthing facility, road, airstrip, coal stockpile, fuel storage, camp, and vehicle maintenance/warm storage facilities. The major findings of Phase II were: 1) the base case production level of the mining operation was established at 50,000 tons per year (tpy); 2) the capital requirements for the development of the mine at the Deadfall Syncline prospect site, was approximately 16 million dollars; 3) development of the mine at the base case production rate would provide substantial savings in the areas of domestic heating for consumers and the operations of power generation facilities; 4) the cost of coal was highly dependant on the level of production at the mine. Economics could be achieved in both coal production and transportation as the level of production increased; and 5) from the economic analysis, at the AD hanO base case production level, coal is competitive with oil ata price per barrel of crude oi] of $15/bb1. 1.2.3 Phase III Program WACDP Phases I & II provided the information necessary to evaluate the economic, technical, and environmental feasibility of the project. It was shown that coal produced from the deposit could be delivered to the market area at a significant cost savings, in terms of raw energy unit costs, compared to present energy sources. The market analysis performed in the Phase II study indicated that production levels less than 50,000 tpy might be attainable for the project. Further, the study identified specific studies of environmental resources in the area that would be required prior to permitting and that additional engineering and geologic data acquisition in key areas would be prudent prior to making a development decision on the project. Therefore, Phase III of the WACDP was initiated to expand the geologic, environmental and engineering database for the selected mining area and to investigate the effects on cost of alternate mining scenarios. Phase III began July 1986 and was completed March 1988. Phase III included the following major tasks: - Camp Utility Systems Selection and Evaluation - Marine Berthing Facility Development and Alternatives - Demonstration of Deadfall Syncline Coal for Domestic Space Heating - Expansion of the Environmental Baseline Data - Evaluation of a 20,000 tpy Mining Operation Scenario Completion of Phase III activities have provided specific data to address key assumptions and conditions used to arrive at the Phase II conclusions and addressed the environmental items raised by the various federal, state, and local agencies whom reviewed the efforts of WACDP Phase I & II. Further, the Phase III report, in combination with the Phase II Final Report, provide a control document that can assist in permitting, design, and construction of the project. 1.3 Project Organization Arctic Slope Consulting Engineers (ASCE) managed the WACDP and was directly responsible to the ANF for overall project performance. Due to the multi-disciplinary nature of the project, it was necessary for ASCE to assemble a project team that included specialists from many different firms. These firms contracted with and worked under the direction of ASCE. The selected project team members ffor Phase III and their responsibilities are listed in Table 1-1. Team Member Kent Grinage Patrick Gillen Janie Campbell John McClellan Steve Denton Dr. Wayne Hanson Stephen Grabacki Patrick Burden Howard Grey Dr. Pemmasani Rao Ogden Beeman Edwin Hall James Wise Jack Heesch (ANF) The project team recognized that TABLE 1-1 Project Team Firm Arctic Slope Consulting Engineers Arctic Slope Consulting Engineers Arctic Slope Consulting Engineers Arctic Slope Consulting Engineers Denton Civil & Mineral Hanson Environmental Research Services Graystar Technical Svc. Northern Economics Howard Grey & Assoc. Mineral Industry Research Laboratory Ogden Beeman & Assoc. Edwin Hall & Associates Arctic Environmental Project Role Project Manager Project Control Project Secretary Infrastructure Design Mine Engineering Environmental Assessment Fisheries Study Economic Analysis Geology Coal Analysis . Transportation Evaluation Archeaological Survey Climate Survey Information & Data Center The J.R. Heesch Company interest Marketing Location Barrow, AK Anchorage, AK Barrow, AK Anchorage, AK Ketchikan, AK Bellingham, WA Anchorage, AK Anchorage, AK Anchorage, AK Fairbanks, AK Portland, OR Brockport, NY Anchorage, AK Anchorage, AK rates, labor costs, and other economic variables could change repeatedly during the progress of the Phase III analyses. Rather than continuously modify the analytical ~ findings as these variables changed, all appropriate modifications were made during preparation of the final report. “Thus, some of the capital on) and operating costs in this final report are different from those presented in preliminary reports. 1.4 Organization of the Phase III Final Report The methods and results of Phase III studies are presented in two (2) documents: 1) Western Arctic Coal Development Project - Phase III Final Report 2) A supplemental report issued March 1988, entitled, Western Arctic Coal Development Project, Environmental Assessment - Appendix D, 1987 Field Program. This document was prepared as a supplement to the WACDP Phase II Environmental Assessment. It presents the results of the 1987 environmental field data gathering programs. This Phase III Final Report consists of the following sections: Section 1.0, Introduction Section 2.0, Marketing Section 3.0, Coal Demonstration Program Section 4.0, Coal Field Geology Program Section 5.0, Mine Engineering Analysis Section 6.0, Infrastructure Evaluation Section 7.0, Economic Analysis Section 8.0, Recommendations The final report contains a table of contents at the beginning of the document that outlines key sections and appendices. Each section isa discrete subject of the project and begins with an index which lists major paragraphs, tables, and attachments of that section. Tables are presented in the sections after the point at which they are first referenced. All. attachments appear together at the end of the appropriate section referencing them. All pertinent technical terms appear in a definition sub-section at the end of the appropriate section. 1 - 10 BARROW, 72 & WAINWRIGHT Li WESTERN ARCTIC ronal COAL DEVELOPMENT ~ | PROJECT j POINT | HOPE = Wad ka e ie Uke crn ” RED-peGe_?./ /~Noatak Tee | L 0 25 Scale in Miles WESTERN ARCTIC @ ___..cCOAL DEVELOPMENT Arctic Slope Regional Corporation consulting. PROJECT Surface & Subsurface Lands LEGEND LOCATION MAP Northern Alaska Coal Field Prepared by: Date: arctic'slope | April, 1988 consulting engineers | Figure 1-1 2.0 MARKET EVALUATION Index Paragraph eal ae 253 2.4 Introduction. .... J+ 22 ial — General —s—.—s-2— 3-6) se 2.1.2 Assumptions ........ 2.1.3 Approach..... ——— : : : : j : : : : : : Market Area and Demand. ....... 2.2.1 Area Demand 2.0.2 Cetra. sss ke ee ee 2.2.2.1 Kotzebue Electric Association ..... 2.2 Northwest Arctic School District... 2.3 Kotzebue Technical Center ....... 2.4 2.5 National Guard Armory ........ a a a Zales | em el ee Nome School District. ...... 8 Norton Sound Health Corporation... Anvil Mountain Correctional Facility. OCHOVS ee peter aoe eee eee OmPWNrH Oieibroit 1 @ a sles « NMNNMNMNetNONNMNMNMNMZ NNN PD Bethel Public Works Department. . . . NNMNNDWNNNNNNZNNNND APWNrR 5 1 -1 General ..... sss ea 2 2.3.2.1 First Stage of Market Development . 2.3.2.2 Second Stage of Market Development 2.3.2.3 Near Term Summary ....... 5 3 Mid to Long Term Market Potential -4 Mining and Military ....... 2.3.4.1 Red Dog Mine .. 2.3.4.2 Military Installations. 2.3.5 Summary ..... ae References ....... Nome Joint Utility ..... : : : : : . Bethel Utility Corporation. ... : : : . Lower Kuskokwim School District... . SUMAN Y <5 —.—. 3 — lope Communities. ............ Near Term Market Potential CC ee ee : Tables Number WACDP Phase I Total Community Demand. . . . WACDP Phase III Potential Community Demand. Kotzebue Near Term Coal Requirements. Nome Near Term Coal Requirements. Bethel Near Term Coal Requirements. First Stage Market Penetration. . . Second Stage Market Penetration . . NMNMNMN PP t NOAOPWNME uv Q oO MMM NM MH PP PP NNMNR RON PWONN 2.1 Introduction 2.1.1 General Reports of the Western Arctic Coal Development Project (WACDP) have included extensive analyses of the market potential for WACDP coal. The Phase I WACDP Final Report (ASCE,1984) identified the potential market area for WACDP coal as an area including the geographic region stretching from Wainwright on the northern coast of the Chukchi Sea south to Kodiak Island and including the Aleutian Chain. The Phase II Final Report (ASCE,1986a) refined the potential area to some 130 communities, 5 military bases, and 2 major mineral industry installations in the region and further identified that total market penetration of coal, i.e. conversion to the exclusive use of coal throughout the market area for space heating and power generation would require over 500,000 tons per year of coal. This is equivalent to about 80 million gallons of fuel oi] annually. The Phase II report established the "base case" production rate at 50,000 tons per year (tpy) and demonstrated that the economics of mining and transporting western arctic coal to market is highly dependent on the scale of operation. Therefore, as both market demand and production level increases the unit cost of energy will decrease for all consumers. For instance, at the 50,000 tpy production level, the price of crude 01] would have to be around $20.20 per barrel to establish sufficient demand. At 100,000 tpy of production, the price of crude oil would have to _ be about $15.00 per barrel. Further, with government assistance for either coal-fired power plants, or mine infrastructure, the break even point for 50,000 tpy is about $16.00 per barrel of crude oi] and at 100,000 tpy is less than $10.00 per barrel. The Phase II report reviewed each energy-user group and evaluated the potential for conversion to coal. These groups included residential users (primarily home heating), institutional users, electric utilities, and industrial demand, including fish processing, mining, and military. Of the various user groups, the electric utilities were seen as having the highest potential demand for coal conversion, based on total regional power generation. Institutional usage ranked as second, while residential users were third. Industrial, mining, and military were all considered to have long term conversion potential, but not near term. 2.1.2 Assumptions The WACDP Phase II Final Report identified that the institutional users provided the preferred market for WACDP coal during initial development stages. The major reasons cited were: 1) Large single users would provide the highest return on investment; 2) Minimum amount of energy distribution installations; 3) Least impacted by state and federal subsidies, there- fore have more incentive to convert; 4) Provide entire community with the opportunity to observe the requirements of using coal; 5) Historically in Alaska, community-wide energy conversions have been initiated by the largest institution(s) in the community or surrounding area; 6) Large institutional users are currently totally dependent on oi], and therefore more sensitive to high fuel oil costs (it is not uncommon for smaller institutions and residents to burn an alternative fuel such as wood or coal as a replacement or supplement to oi] in order to reduce their heating bill); 7) Large single demands using bulk delivery of coal optimize on coal transportation and distribution systems, thereby decreasing the cost of coal delivered to the consumer; and, 8) The time of conversion is relatively short and easy due to the well-known, easy to use, off the shelf coal technologies available to the institutional user. The Phase II report also identified a number of constraints or factors which would affect the early phases of the development of Western Arctic Coal's market area. Converting from existing heating and power generation equipment would not occur immediately, but would be influenced by the cost of conversion, the price differential between coal and diesel fuel, household incomes, availability of capital, and the availability of alternative technologies and fuels. Some communities would not be appropriate for conversion as a result of location, size and other similar factors. Also, the present suppliers of fuel would restructure their pricing as a result of the coal availability, thereby increasing the competitiveness of the market. Finally, the development of a distribution system for coal within the market area may in some cases require modification of the existing supply network or establishment of new ones. This would take time to develop. The WACDP Phase II Preliminary Institutional Market Assessment (ASCE, 1986b) estimated the institutional market demand for start up at 20,000 tons per year. That demand would be met by large institutions within the market area that are: willing to utilize coal delivered in bulk form, in close proximity to the mine, have a higher price differential between coal and fuel oil, are captive to oi] technologies, do not benefit from existing state energy subsidy program, have in place maintenance capabilities, and have the resources or ability to obtain funding needed to finance conversion costs. The Preliminary Institutional Market Assessment further identified that the large power utilities, the North Slope Borough, and the North Slope Borough School District are the institutions most likely to make up the initial demand. For start up to occur, a demand of between 20,000 and 50,000 tpy is required. An initial start up of 20,000 tpy, growing over a number of years to 50,000 tpy would allow for the development of a distribution net that would eventually see the cost of coal decreasing as the demand increased due to greater market penetration. Based on the information and direction provided by the Phase II Final Report and the Preliminary Institutional Market Assessment, a review was conducted to identify those communities most likely to generally fit the developed criteria and provide a sufficiently large demand to justify mine opening. Table 2-1 lists the demand for coal for the west coast North Slope Borough communities, in addition to Kotzebue, Nome, and Bethel as provided in the Phase I Final Report. These communities were deemed to hold the best potential for providing the initial market for WACDP coal. : TABLE 2-1 WACDP Phase I Total Community Demand (tpy) Community Res/Inst Elec Total North Slope Borough 4928 2332 7260 Kotzebue 9157 8239 17396 Nome 7301 9467 16768 Bethe] 38144 12503 50647 Total 59,530 32,541 92,071 note: source, WACDP Phase I Final Report 2.1.3 Approach Having selected the communities of Kotzebue, Nome, and, Bethel, as well as the North Slope Borough, as having the best potential for providing the initial market for WACDP coal, it was decided to visit the three major communities to verify the information in hand and to determine the acceptability of coal in these communities. It should be noted that the North Slope communities of Wainwright, Point Lay, and Point Hope were already subject to an on-going coal demonstration project (Western Arctic Coal Demonstration Project, ASCE, 1986c) under the auspices of the North Slope Borough and it was therefore not necessary to visit those communities for this purpose. Each of the three communities was visited two times. The initial visit familiarized individuals at the utilities and major institutions in each community with the WACDP. Concurrently, fuel oi] usage was verified at each site. Sites were inspected to ascertain their appropriateness for and ability to accommodate conversion from fuel oi] to coal. 2.2 The WACDP Village End Use Technology Assessment (ASCE,1986d) had provided a thorough review of the available technology for conversions of various types and sizes of heating and power generating systems. That report provided the basis upon which to base the assessments. The community visits also allowed an assessment of the availability of infrastructure capable of accommodating major coal transportation, storage, and handling. Market Area and Demand 2.2.1 Area Demand The WACDP Phase I Final Report had estimated that the combined electrical generation demands of Kotzebue, Nome, and Bethel would be 30,209 tons of WACDP coal per year after conversion from diesel fuel (see Table 2-1). Further, the North Slope communities would provide a demand of some 4,928 tons per year for residential and institutional uses. This combination would provide demand sufficient to support the initial stages of development of the mine. The visits to the communities of Kotzebue, Nome, and Bethel during Phase II showed a general increase in demand of about 10% over the Phase I estimates (1983). The Phase I estimates for residential and institutional use assumed a total market penetration in each community. The community visits in Phase III allowed for an assessment of the institutions most likely to convert in the early stages of the mine development. Table 2-2 provides the estimates for each community based on these community visits. Generally, these are the larger community institutions for whom the early savings would justify the costs of conversion. A more complete discussion of each community follows. TABLE 2-2 WACDP Phase III Potential Community Demand tpy Community Res/Inst Power Total Kotzebue 900 10,000 10,900 Nome 1,960 15,400 (2) 17,360 Bethel 115130 13,300 14,430 North Slope Borough 5,200 -0- 5,200 Total 9,190 38,700 47,890 Note: 1) source, WACDP Phase III on-site investigations 2) includes 5,000 tpy for providing power to Alaska Gold Co. beginning in 1989. Once the utilities and some of the major institutions within each community have converted, and as coal becomes both available and more widely accepted, the market for WACDP coal will expand. The three major communities will see a greater market penetration over time, as smaller institutions begin to convert to coal for space heating. Further, as the price of coal becomes more competitive with fuel oil for the home heating market, coal conversions will become more prevalent throughout the area. This same phenomena will likely repeat itself, first to the nearby communities and, ultimately, to rest of the regions. As coal is being barged along the coast of western Alaska, its availability and competitiveness with fuel oi] will increase its use throughout western Alaska. While it will take some time to make serious inroads into the use of fuel oil, the market will continue to grow as the cost of fuel oil continues to consume such a disproportionate share of income in western Alaska. 2.2.2 Kotzebue Kotzebue is the largest rural community closest to the WACDP mine site at the Deadfall Syncline. The WACDP Phase I Final Report estimated that Kotzebue's total consumption of coal, assuming a 100% conversion, including all residential, institutional, and electrical power generation, would total 17,396 tons per year. 2.2.2.1 Kotzebue Electric Association The Kotzebue Electric Association (KEA) is the supplier of electrical power to the community. This REA co-op has an installed capacity of 6,425 kW consisting of seven diesel fired generators. They consume approximately 1.5 million gallons of fuel oil per year. It is estimated that the current generation system will have to be replaced by 1998. KEA is working on the development of a district heating system utilizing waste heat from power generation. The system being considered would include the city offices complex, public works complex, the new hospital, the senior center, and day care center. Although the loop would be close enough to tie into the new National Guard Armory, the school district complex, the new borough offices, and the community college, there is not enough waste heat to do so. KEA is seriously considering a conversion to a coal fired power plant. Given the life expectancy of the existing plant (1998) or sooner, the community is beginning to make plans for the eventual replacement of the plant. The KEA Board voted in August 1987 to begin investigations for conversion to a coal fired plant by 1998 (Kotzebue Electric Association, 1987). A site south of town has_ been tentatively identified as appropriate for siting a new, coal-fired plant. The site, which is on city owned property, 2 = 10 is close to some reasonably deep water for coal delivery, and is near existing transmission lines. In the event of such a relocation of the power generation facility, the current facility could continue to serve the district heating loop, either through the continued use of diesel fuel or as converted to coal fired. A coal fired plant could be developed with additional thermal capacity to include those facilities which had been initially excluded in a district heating loop. 2.2.2.2 Northwest Arctic School District The second largest user of fuel oi] in Kotzebue is the Northwest Arctic School District (NWASD). The district complex, which consists of the high school, the middle school, the elementary school, and administrative buildings, is heated by a series of unconnected boilers. Currently, the school district uses 130,000 gallons of fuel oi] per year. Conversion to a coal-fired system for the school district would most likely include the development of a self-contained heating system within the district complex itself. 2.2.2.3 Kotzebue Technical Center The Kotzebue Technical Center (KTC), which is administered by the NWASD, is located some distance from the school district itself, as well as away from the proposed district heating system. KTC burns some 24,000 gallons of fuel oi] per year. Each of the two buildings, the dormitory and the main classroom building, are heated by a boiler. The systems are not connected. The Center itself was completed in 1981, while the dormitory was completed in 1986. A coal-fired system would likely continue to heat each Zia oe building separately, as, currently, the distance between the two would preclude a single boiler system. See Appendix A for amore detailed discussion of a proposed coal fired boiler for KTC. 2.2.2.4 National Guard Armory The National Guard Armory was completed in February, 1987. It is heated by a three boiler system, which could be converted to coal. However, the Armory is located on the proposed route of the district heating system, and an expanded system could easily tie into the Armory. 2.2.2.5 Summary KEA is the likely candidate. for conversion to coal in Kotzebue. The utility is already exploring the feasibility of converting to coal. An expanded, coal fired district heating system will also increase the demand for coal. In addition to the utility, only the Northwest Arctic School District complex and the Kotzebue Technical Center are likely candidates for early conversion from fuel oil to coal. Table 2-3 summarizes the near term potential for coal in Kotzebue. TABLE 2-3 Kotzebue Near Term Coal Requirements (tpy) Candidates Demand Kotzebue Electric Association 10,000 Kotzebue Technical Center 100 Northwest Arctic School District 800 Total 10,900 Note: source, WACDP Phase III on-site investigations 2 - 12 2.2.3 Nome The WACDP Phase I Final Report considered Nome as the most likely candidate for an initial start up market. The utility was thought to be the most favorably disposed towards conversion to coal. The community also has a number of institutions which are good candidates for conversion. Nome, which is located somewhat further south of the Deadfall Syncline than is Kotzebue, has a new port facility capable of handling delivery barges as well as a large storage area belonging to the city. Phase I, based on 1983 data, estimated Nome's total demand for coal at 17,396 tons per year. 2.2.3.1 Nome Joint Utility The Nome Joint Utility is owned and operated by the City of Nome. The utility has three power plants. The main plant which is located at the Snake River, has an installed capacity of 4,368 kW. consisting of six diesel generators. A remote diesel unit at Belmont Point generates 2,600 kW. A third unit, a joint venture with the school district, has a 600 kW unit at the Beltz High School complex, providing both power and cogenerating heat for the school complex. The utility consumes over 1.6 million gallons of diesel per year. The main power plant is located on the Snake River flood plain. Estimates are that there are some 10-18 years left on the plant. A new plant would most likely be located off the flood plain in a less vulnerable location. The city has recently completed construction of a tank farm at the new port area, consisting of four 800,000 gallon tanks. This addition has allowed the city utility, along with the school district, to bulk buy fuel thereby reducing their costs for fuel. 2) 13 The utility has demonstrated considerable interest in the potential for a district heating system. The location of any new power plant would greatly influence the development of a district heating system, however. A complete discussion of the Nome Joint Utility and its potential for conversion, including a thorough discussion of the available technologies appropriate for conversion to a coal fired power generation system may be found in the WACDP Village End Use Technology Assessment (VEUTA) (ASCE, 1986d). As in the case of Kotzebue the Nome Joint Utility desires to evaluate further the use of coal for power generation and district heating in their community. 2.2.3.2 Nome School District The Nome School District's Beltz High School complex is the second largest user of fuel in the community. The school and housing complex are heated by a fuel oil fired three boiler system. In 1987, a 600 kW Mitsubushi generator, a joint venture with the utility, was installed. The waste heat from the generator is used to heat the school complex, while the power generated is put into the utility's distribution system. The generator is expected to have a useful life of approximately five years. The three boilers are actually suitable for coal firing, though coal has never been used. However, a boiler could be easily retrofitted into a fully coal fired system through the addition of stoker bases. A complete discussion of the Beltz system, and its conversion potential may also be found jin the VEUTA (ASCE, 1986d). 2- 14 2.2.3.3 Norton Sound Health Corporation The Nome Hospital jis run by the Norton Sound Health Corporation. The hospital and the out-patient facility located across the street, are heated by a four boiler fuel oil fired system. The system consumes some 80-90,000 gallons of fuel per year. A 6,000 square foot addition to the hospital includes a new boiler room. 2.2.3.4 Anvil Mountain Correctional Facility The Anvil Mountain Correctional Facility, run by the state Department of Corrections, serves the northwest region of the state. The facility, which was completed in 1986 is heated by two fuel oil fired boilers. Fuel consumption had originally been estimated at 90,000 gallons per year, but the actual consumption for the first year was under 40,000 gallons. See Appendix A for a more detailed discussion of a coal fired boiler for Anvil Mountain. 2.2.3.5 Others A number of other smaller institutions in Nome could benefit from conversion to coal, if it were available in the community at competitive prices. A number of larger buildings could consider conversion as a_ cost saving mechanism. The Polaris Hotel, The Old Federal Building, and the AC store are all potential conversions once coal begins moving into the community. Another potential is the Alaska Gold Company. Currently, Alaska Gold operates its dredge utilizing two older and three new 1,000 kW fuel oi] fired generators. Alaska Gold operates only 6-7 months per year, yet generated some ten million kW of power during 1987. Their equipment will not =D) be in need of replacement for some time. Their power generation facility supplies their dredges, which have extreme power surges when encountering frozen ground. Recent discussions between the Nome Joint Utility and Alaska Gold indicate that the utility may take over operation of Alaska Gold's power generation and supply power to Alaska Gold. The tentative schedule has the Utility taking over for Alaska Gold by 1990. This would boost Nome's conversion requirements by an additional 5,000 tpy of coal. 2.2.3.6 Summary Nome is well equipped and in a prime position to convert its utility and a number of its institutions to coal. The utility, which is faced with replacement over the next 10-18 years, and which is likely to begin providing power to the Alaska Gold Company, is beginning to evaluate conversion to coal. In conjunction with the new port’ facilities, the utility could locate on a site which would make materials handling convenient and cost effective. With the utility burning coal, a number of other institutions could easily find themselves also burning coal or be included ina district heating system, currently under investigation by the Utility. Table 2-4 summarizes the near term potential for coal conversion in Nome. 2 > 16 TABLE 2-4 Nome Near Term Coal Requirements (tpy) Candidate Demand Nome Joint Utility (2) 15,400 Beltz High School Complex 1,160 Nome Hospital 550 Anvil Mountain Correctional Facility 250 Total 17,360 Note: 1) source: WACDP Phase III on-site investigations 2) includes 5,000 tpy for providing power to Alaska Gold Co. 2.2.4 Bethel Bethel, located on the Kuskokwim River, is the community furthest from the Deadfall Syncline, yet included in the market area. The Bethel utility consumes the highest amount of fuel oil of the three major communities reviewed. Additionally, as the shipping hub for the Lower Kuskokwim, Bethel provides an excellent beginning for gaining a major market. The WACDP Final Report estimated that Bethel could require some 50,647 tons of coal per year. (It should be noted that this figure is inflated as the estimates may have failed to account for the transshipment of fuel to the region or the use of fuel for aircraft.) 2.2.4.1 Bethel Utility Corporation The Bethel Utility Corporation is a privately owned utility. The utility currently provides electrical power to all of Bethel, in addition to Napakiak. The utility will soon be tied in to Oscarville. Plans are also underway to tie the utility in to Nunapitchuk, Kasigluk, and Atmautluak. Zooey, The plant, which was. constructed in 1976, consists of four 2,160 kW and one 1,000 kW diesel generators. The expected plant life is approximately 20 years. Waste heat from the utility is being used to provide heat to a major portion of the community's institutions. Receiving waste heat from the utility are: the Public Health Service Hospital, the Yukon-Kuskokwim Correctional Facility, the police department, the Youth Facility, Phillips Alcoholism Treatment Facility, fire station, City complex, including the Troopers and Courthouse, the Calista Apartments, Library, and yet to be connected, Community College and the hospital apartments. The power plant is located on the west side of town, away from the river and the tank farm. Fuel is delivered daily to the utility. The site for the utility was selected based on the availability of land in the community. The current owners of the utility have expressed interest in selling it. The City of Bethel has considered purchasing the utility. Another likely operator of the utility would be the Bethel Native Corporation. The availability of land adjacent to the river poses some problems for conversion of the utility. Conversion at the current location would require handling the coal twice, as is currently done with the fuel. There is some land available adjacent to the river, which jis situated ina locale that would allow the continued operation of the district heating system. The land is owned by either the City of Bethel, the Bethel Native Corporation, or the Public Health Service. 2 - 18 2.2.4.2 Lower Kuskokwim School District The Lower Kuskokwim School District's Bethel High School complex is heated with a system that includes three fuel oi] fired boilers. These boilers are such that they could be converted to coal fired. The High School complex is currently consuming 140,000 gallons of fuel oil per year. See Appendix A for a more detailed discussion of the conversion of the Bethel High School complex to a coal fired system. 2.2.4.3 Bethel Public Works Department The Bethel Public Works Department is housed in a warehouse in which the city's vehicles are parked and maintained. The warehouse, which was completed in 1983, is heated by a two boiler, fuel oil fired system. The fuel oi] consumption of the building is estimated at 60,000 gallons per year. The heating system of the building lends itself to conversion to coal. See Appendix A for a more detailed discussion of the conversion of the Public Works facility to a coal fired system. 2.2.4.4 Summary The balance of the major institutions are already included in the district heating system and are not candidates for conversion to coal. However, the large population of Bethel itself, combined with its position as the shipping hub to a large number of nearby communities makes the potential for residential space heating fairly good. Table 2-5 summarizes the near term potential for conversion to coal in Bethel. The addition of the surrounding communities to Bethel's power grid would increase Bethel's conversion demand by an additional 600 tpy of coal. 2 = 19 TABLE 2-5 Bethel Near Term Coal Requirements (tpy) Candidate Demand Bethel Utility 13,300 Bethel High School Complex 850 Bethel Public Works Facility 280 Total 14,430 Note: source, WACDP Phase III on-site investigations 2.2.5 North Slope Communities The North Slope Communities of Pt. Lay, Pt. Hope, and Wainwright are the closest communities to the WACDP mine site with Pt. Lay located just 40 miles northeast of the coal project. The WACDP Phase I Final Report estimated that the three North Slope communities total consumption of coal, assuming a 100% conversion, would total 7,260 tons per year. From recent 1987 energy data there has been a 15% increase in energy demand over the 1983 data due to both an _ increase in population and construction of several major new public facilities. The current total potential consumption of coal in these communities jis about 8,349 tons per year. The residential and institutional markets of the North Slope communities are likely candidates for conversion to coal. In the past 2 years the same three communities have participated in the North Slope Borough sponsored Western Arctic Coal Demonstration Program. This project involved; test mining at the Deadfall Syncline Coal prospect; packaging and distribution of the coal to the communities; installation of coal burning units in selected homes in each community; and utilization of the coal in each participant's home. 2 - 20 2.3 In 1987 100 tons of coal was mined and used for the demonstration. In 1988 the program was expanded to 250 tons of coal. To date 29 coal burning units have been installed in the 3 North Slope communities. It is not anticipated there will be any conversions to coal fired power generation in these communities in the near term due to the Jack of appropriate small scale (1-500kw) coal fired power generation technologies. This was discussed in detail in the VEUTA (ASCE, 1986d). Therefore, the near term coal requirements for the North Slope communities will consist of the residential and institutional demand only and is estimated at 5,180 tons per year. Conclusions 2.3.1 General The full market potential for WACDP coal has been identified as 500,000 tpy, given total market penetration. That estimate may be reachable, but must be viewed as the long-range potential for in-state consumption of Western Arctic coal. The WACDP must be viewed along a time continuum, spanning many years. Generally, the market penetration will begin with those few North Slope communities currently using WACDP- coal, the utilities of the major communities in the immediate market area, the institutions within those same communities, and some residential usage in the major communities and the surrounding villages. Even these inroads into the market will be phased over a number of years. Adding to the market over time is the potential for both the mining industry and for the military. The mining industry, particularly the Red Dog mine, could became a major user of 2/5 21 western arctic coal. The military bases at both Adak and Shemya could likewise serve as major potential users. 2.3.2 Near Term Market Potential The near term potential for WACDP coal spans a period of some five to ten years. That market penetration itself is seen as divided into at least two phases. Further estimates for coal demand presented in this report are based on 1987 data gathered during visits during Phase III and there jis no attempt to adjust those estimates based on projected increase in demand overtime. 2.3.2.1 First Stage of Market Development The first stage of the jnitial market development includes the communities of the North Slope Borough which are currently involved in an on-going demonstration coal project. The coal usage in these communities is limited to space heating. It is expected that over the next several years, the use of coal for residential and institutional heating will become more accepted within these communities and the demand will increase to some 5,200 tpy. Along with the North Slope communities, it is expected that the utilities in both Kotzebue and Nome will convert to coal at approximately the same time. Both communities are currently beginning to investigate conversion to coal. With the availability of state assistance, each of these communities will likely be converting to coal within the next five to ten years for their power generation. air 22 Just these three user groups provide demand sufficient to begin the mining of Western Arctic coal. Table 2-6 summarizes the demand of these three initial user groups. TABLE 2-6 First Stage Market Penetration (tpy) Candidate Demand North Slope Communities 5,200 Nome Joint Utility (2) 15,400 Kotzebue Electric Association 10,000 Total Demand 30,600 Note: 1) source, WACDP Phase III on-site investigations 2) includes 5,000 tpy for providing power to Alaska Gold Co. 2.3.2.2 Second Stage of Market Development The second stage of the near term market penetration expands the market further south to Bethel. The Bethel Utility is the next likely candidate for conversion to coal. The Bethel Utility is the largest power producer of the utilities in the three major communities. It is also growing, as several near-by communities may be added to the Bethel power grid, boosting demand for coal by an additional 600 tpy. The time frame for this market expansion is some five years after the conversion of the Kotzebue and Nome utilities. Within that same approximate time frame, it can be expected that the major institutions within the three communities 2 = 23 will convert, as a result of competitively priced coal in the market place. These institutions will consume close to 4,000 tpy. See Table 2-7 for a detailing of the second stage market penetration demand. TABLE 2-7 Second Stage Market Penetration (tpy) Candidate Demand Bethel Utility 13,000 Kotzebue Institutions 900 Nome Institutions 1,960 Bethel Institutions 15130 Total 16,990 Note: source, WACDP Phase III on-site investigations 2.3.2.3 Near Term Summary Over a period of five to ten years, the near term market demand grows from 30,600 tpy in the North Slope communities combined with the Kotzebue and Nome utilities, to a total of 47,590 tpy with the addition of the Bethel utility and the major institutions in Kotzebue, Nome, and Bethel. This increasing demand proves to be sufficient to begin mine operations. It also provides the basis upon which a mid term market may be developed. 2.3.3 Mid to Long Term Market Potential The mid term market potential consists primarily of the space heating requirements of the villages throughout the market area. 2- 24 It is assumed that those villages nearest the communities of Kotzebue, Nome, and Bethel will be among the first to begin converting to coal. Coastal villages also provide likely candidates as barges moving coal along the coastline may be able to easily call on those villages with small, yet cost effective shipments of coal. Here again, the institutions are the likely leaders in the conversion process. The village schools provide likely candidates for conversion, as the technology for small institutional use is readily available. This mid to long term potential is a function of the price of the delivered coal to the price of delivered fuel oil. As the coal becomes more competitive with oil as a space heating fuel, its acceptability will increase. A market which begins at approximately 20,000 to 50,000 tpy can expand considerably. See Section 7.0 Economic Analysis for a detailed discussion of the expansion of the market, particularly for space heating, in relationship to the delivered cost of coal in the market area. 2.3.4 Mining and Military The mining industry and the military provide two potentially very large markets for WACDP coal. These are, however, long term potential, as for various reasons, neither is in a position to convert during the early phases of mine development. The biggest potential lies with the Red Dog mine and with the military bases at Shemya and Adak. 2.3.4.1 Red Dog Mine Located in the DeLong Mountains, the Red Dog mine, at full production will be the largest zinc, lead, and silver mine in the world. The Red Dog mine site is located some 70 air 2) =) 25 miles south from the area of development of the Western Arctic Coal Project. Red Dog is expected to begin production in the early 1990s. At full production, Red Dog has a potential mine life of fifty years. At production, Red Dog will have an installed capacity of 18 mw with an expected average load of 12 mw and peak demands of 15 mw. During the early phases of mine development, it has been considered neither practical nor economically attractive for Red Dog to utilize coal for power production. Further as long as the Western Arctic coal is in a non-production phase large potential users such as Red Dog will] have real concern over the coals long term availability and pricing which are critically important due to the large financial and long term commitment necessary to convert to coal. However, as the Western Arctic Coal fields are developed, thereby reducing the cost of delivered coal and concerns of potential major users, and as Red Dog goes in to full production, conversion of Red Dog to coal could become very attractive. At full production, Red Dog would require between 80,000 and 100,000 tpy of Western Arctic coal. 2.3.4.2 Military Installations The western Alaska, and Aleutian Islands market area contains numerous military installations. These are, for the most part, small, remote sites. Each generates its own power, but for the most part, are not large enough to consider conversion to coal-fired technology based on today's technology. The exception to this, are the two major installations in the Aleutians, the Air Force Base, Shemya and the Naval 2 - 26 Station, Adak. These two installations generate sufficient power to justify conversion to coal. Converted to coal, Shemya would have an estimated demand of 41,029 tpy of WACDP coal. Adak's estimated demand is 46,943 tpy. (ASCE, 1986e.) These potential markets are considered to have long term potential for conversion. The military will have to be kept informed of the development of the project in order to be persuaded to convert these installations to coal. Like Red Dog, without Western Arctic coal in a production mode, commitment to its long term use by the military will not be forthcoming. 2.3.5 Summary The development of the WACDP must be viewed in stages, spread over many years. With a beginning of some 30,000 tpy based on the North Slope villages and the utilities at Kotzebue and Nome and growing to include the Bethel utility as well as the institutions in Kotzebue, Nome, and Bethel, the project will begin to make additional inroads into the total market. Once the project is mining some 50,000 tpy, the market will see expansion into first, the villages surrounding the major communities, as well as the coastal villages convenient for shipping. With the continued development of the mine, both mining interests, particularly the Red Dog mine, and the military, primarily at Shemya and Adak, can be developed as WACDP coal users. Ultimately, the penetration of the market as envisaged in the WACDP Phase I report may become possible and the goal of reducing and stabilizing the cost of power and heating in western Alaska will be realized. cue] 2.4 References Arctic Slope Consulting Engineers (ASCE). 1984. Western Arctic Coal Development Project (WACDP) Phase I _ Final Report, Market Assessment. Report prepared for Alaska Native Foundation. ASCE. Anchorage, Alaska. . 1986a. WACDP Phase II Final Report, Market Evaluation. Report prepared for Alaska Native Foundation. ASCE. Anchorage, AK. 1986b. WACDP Preliminary Institutional Market Assessment. Report prepared for Alaska Native Foundation. ASCE. Anchorage, AK. : 1986c. Western Arctic Coal Demonstration Project. Project using coal for residential space heating. Conducted by ASCE for North Slope Borough. . 1986d. WACDP Village End Use Technology Assessment. Report prepared for Alaska Native Foundation. ASCE. Anchorage, AK. Bivin, William. 1987, 1988. Bethel Native Corp. Personal Communication. Borrego, Harold. 1987, 1988. Bethel Utility Corp. Personal Communication. Butcher, Gary. 1987. Alaska Gold Co. Personal Communication. Chin, Lanston. 1987, 1988. City of Bethel. Personal Communication. Coffee, Dan. 1988. NW Arctic School Dist. Personal Communication. Colby, Neil. 1987. Nome AC Store. Personal Communication. Connick, Sarge. 1987. Bethel Port Facility. Personal Communication. Conti, Richard. 1987. Norton Sound Health Corp. Personal Communication. Erlich, Richard. 1987, 1988. Personal Communication. Fuller, Gary. 1988. Kotzebue Technical Center. Personal Communication. Geigerich, Hank. 1987. Cominco Alaska. Personal Communication. 2 = 28 Greene, Marie. 1987. Maniilag Association. Personal Communication. Handeland, John. 1987. City of Nome. Personal Communication. Handschke, Arnie. 1987. Kotzebue Technical Center. Personal Communication. Herring, John. 1987. Kotzebue Electric Association. Personal Communication. Kass, Jim. 1987. Lower Kuskokwim School District. Personal Communication. Kotzebue Electric Association. 1987. Board Resolution #637. Kristie, Kathie. 1987. Alaska Dept. of Corrections. Personal Communication. LaBolle, Larry. 1987. Nome School District. Personal Communication. Malone, John. 1987. Bethel Seawall Committee. Personal Communication. McA. Campion, Denis. 1987. Port of Nome. Personal Communication. Merkouris, Paul. 1988. Nome Joint Utility. Personal Communication. Michel, Myron. 1987. Anvil Mtn. Correctional Facility. Personal Communication. Mittino, John A. Deputy Assistant Secretary of Defense (Logistics). 1987. Letter to Sen Ted Stevens re: WACDP. Murphy, Joe. 1988. Nome Joint Utility. Personal Communication. Olson, Steve. 1987. Alaska Commercial Co. Personal Communication. Parker, Lisa. 1987, 1988. Cominco Alaska. Personal Communication. Porter, Rosie. 1987, 1988. Tundra Drum. Personal Communication. Poulsen, Mary. 1987. Y-K Delta Regional Hospital. Personal Communication. Prchal, Polli. 1988. City of Nome. Personal Communication. Reeve, Brad. 1988. Kotzebue Electric Association. Personal Communication. 25729 Scott, Mike. 1987. City of Kotzebue. Personal Communication. Sheldon, Frank. 1987. Kotzebue Electric Association. Personal Communication. Smith, Jeff. 1987 , 1988. Northwest Arctic Borough. Personal Communication. Stiles, Norm. 1987. Nome Polaris Hotel. Personal Communication. Stock, Raymond. 1987, 1988. Bethel Public Works Dept. Personal Communication. Vowel, Chuck. 1987. Alaska Commercial Co. Personal Communication. West, Mike. 1987. Norton Sound Health Corp. Personal Communication. Whitelock, Steve. 1987. NW Arctic Borough School Dist. Personal Communication. Wipperman, Capt. 1987. Army National Guard,Kotzebue. Personal Communication. Zurawski, Alan. 1987. Arctic Literage Co. Personal Communication. 2 |=| 30 2.0 COAL DEMONSTRATION PROGRAM Index Paragraph Sak 3.2 3.4 a5) Introduction .. Bulk Sample Analysis : 3.2.1 Description of Coal “Samples | and Location a 3.2.2 Proximate and Ultimate Analysis of DFS Coal 3.2.3 Characteristics of Ash from DFS Coal 3.2.4 Combustion Product Analysis qi Briquetting of DFS Coal Fines. . 3.3.1 Coal Briquetting Process... 3.3.2 Product Testing Observations . Combustion Efficiency Testing . 3.4.1 Methodology a 3.4.2 Mountain Man 85 Furnace. es - 3.4.2.1. Description of Heating “Unit fs =’ 2 Description of Test and Sensor Locations. 3 Data Analysis... : -4 Combustion Product Analysis : -5 Discussion of Results . n Mark III Stove ... Fs Description of Heating “Unit : ; Description of Test and Sensor Locations. Data Analysis . . = Combustion Product Analysis : Discussion of Results . : zi Fuel Equivalency Calculations ‘ Comparison of Sulfur Emissions ray PPHPPHPH HH HS on ae ae 4 WWWWWWWWd NNN OIYODNPWNH 3453 m WWWWWWWWTWWWW Emission Factors . ar Ash Residues Conclusions . w wo 3.6 References Comparison of Stove Stack Emissions t to “EPA. uv E © ' WWW WWW WW WWW WWW WWW WWW LD WWW Ww ' WWWNHNMNNNNNMRP RPP Err OW WNP WWW RO UILLE Le NADDONPHPHNMEHFAPRPRrROOCO Number Figure Figure Figure Figure Figure Figure Figure Figure Figure Figure Figure Tables Sizing of DFS-2 Bulk Sample i Proximate and Ultimate Analyses for. Deadfall Syncline coal Concentration of Major Elements in the Deadfall Syncline Coals, Ashed at 750°C... : Ash Fusibility for the Deadfall Syncline Coals in Oxidizing and Reducing Atmospheres Critical Data for March 7, 1987 Tests . Critical Data for March 22, 1987 Tests . Results for March 7, 1987 Tests . Results for March 22, 1987 Tests ....... Critical Data for Stove Test (April 19, 1987) Results of April 19, 1987 Stove Test... Stack Loss Due to: Time Period, Radiation and Convection .. Furnace Stack Emission Measurement Data Stove Stack Emission Measurement Data Quantities of Pollutants Produced WWWWWWW 1 NNR Rr CO WWW W OnMWOnN WwWWwr MWwow Attachments 3-1 House located 0.75 mile Rosie Creek Road, used for coal testing 3-2 Stack Gas Measuring Tube and Gas Suction Devices 3-3 Tube Coloration Showing Level of NO, Concentration in Stack Gas 3-4 Data Logger Used for Recording Temperatures, for Furnace and Stove Testing Mountain Man 85 Furnace through Various Louvers an] Dr. Bandopadhyay Measuring Furnace Stack Gas Composition 3-8 Energy Balance Using the Mountain Man 85 3-9 Thermocouple Placement on the Mountain Man 85 3-10 Locations Where Temperature Measured for Harmon Mark III Stove 3-11 Dr. Bandopadhyay Measuring Stove Stack Gas Composition 3-5 3-6 Clarke Pelz and Dr. Johnson Measuring Velocities of Air 3.1 Introduction The coal demonstration program included the performance of a coal combustion test of Deadfall Syncline (DFS) coal in selected residential coal combustion heating units. The purpose of the program was to: demonstrate the applicability of the technology; verify the combustion characteristics of the coal; and make available this information to potential customers. DFS coal was provided to the program as part of the North Slope Borough's Western Arctic Coal Demonstration Project conducted during the fall and early winter of 1986. Under the State funded Western Arctic Coal Development Project (WACDP) Phase II, a sample of this coal was shipped to the Mineral Industry Research Laboratory (MIRL) for testing in an automatic residential coal fired furnace and a stove provided by Arctic Slope Regional Corporation to study combustion efficiencies and the production of pollutants. Combustion testing was performed on a Chippewa Trader Mountain Man 85 furnace and a Harmon Mark III stove, a space heater. The Mountain Man Furnace is an automatic stoker fired unit that produces up to 100,000 btu/hr. The furnace was tested using 1" x 10 mesh coal while +1" coal and briquetted coal fines were burned in the Harmon stove tests. The furnace and the stove were installed and tested in a house located at 0.75 mile Rosie Creek Road, Fairbanks (Figure 3-1). 3.2 Bulk Sample Analysis 3.2.1 Description of Coal Samples and Location A one ton coal sample, taken from the DFS prospect, was received at MIRL in bags. The sample was first screened ona double deck vibrating screen with 1" opening top deck and 10 mesh opening bottom deck, both of woven wire. The top size of the coal received was approximately 5". The coal pieces were quite friable and broke readily. The weight distribution of the sized product is shown in Table 3-1. TABLE 3-1 Sizing of DFS-2 Bulk Sample Size Weight Pounds Weight % Plus 1" 316.0 14.8 1" x 10 mesh 1460.5 68.7 Minus 10 mesh 350.5 16.5 Total 2127.0 100.0 The three size fractions of coal were sampled and analyzed. In addition, two samples with designations DFS-2, test pit #2 (17 lbs) and DFS-1, test pit #3 (28 lbs) were received for analysis. Sample designation DFS-2, test pit #2 specifics include: Location - lat. 69°10' 26" long. 163°25' 29" Seam - DFS-2 Depth interval - 11.5 ft to 18.6 ft Date of sampling - December 19, 1986 Sample designation DFS-1, test pit #3 specifics include: Location - lat. 69°10' 10", long. 163°25' 45" Seam - DFS-1 Depth interval - 4 ft to 6ft Date of sampling - December 15, 1986 3.2.2 Proximate and Ultimate Analysis of DFS Coal Table 3-2 shows proximate and ultimate analysis for the three size fractions from the bulk sample as well as for the two test pit samples. The screened coal shows an increase in ash content with “a increasing size. This is attributable to the presence of coarse rock pieces, which are more stable than the readily fractured coal. The as received heating value of the 1" x 10 mesh coal is 10,804 btu/1b, which is equivalent to 12,987 btu/1b on a dry; ash free basis. By comparison, the core coal sample obtained from the 1984 Field Program from drill hole DF-84-115, which intercepted the bed at 40-48', analyzed 14,500 btu/lb on a dry, ashifree basis. The lower heating value of the bulk sample coal is apparently due to weathering. The coal seam mined was only 12' below ground level. Further, the bulk sample had a Free Swekling Index (FSI) of '0' whereas the 1984 core sample had a FSI of 3, indicating that weathering has destroyed the coking quality of this coal. Sulfur content of the coal is very low, averaging 0.27%. 3.2.3 Characteristics of Ash from DFS Coal 8 Table 3-3 shows the concentration of major elements >in the Deadfall Syncline coals used in and ashes produced from the stove and furnace tests. The composition of the stove ash resembles ash of +1" coal and furnace ash compares well with DFS 1" x 10+mesh ash as expected. Table 3-4 shows ash fusibility temperatures for various coals. Differences in ash fusibility between the three size fractions of the bulk sample are not very significant... DFS Test Pit #3 ash gave a softening temperature in excess of 2800°F due to high Si02 concentration. TABLE 3-2 Proximate and Ultimate Analyses for Deadfall Syncline Coal Sample Basis* Moisture Ash Volatile Fixed Heating Hydrogen Carbon’ Nitrogen Oxygen Sulfur % % Matter Carbon Value % % % % % % % Btu/1b. DFS +1" i 7.26 12.12 30.02 50.60 10,366 3.99 63.24 1.14 19.23 0.28 2 10.71 11.67 28.90 48.72 9,980 4.26 60.89 1.10 21.81 0.27 *XDFS 1"x10m = 1 8.06 8.75 30.56 52.63 10,804 4.48 66.28 1.18 19.03 0.28 . 2 10.55 8.51 29.73 $1.21 10,511 4.66 64.48 1.15 20.93 0.27 DFS - 10m 1 9.46 6.77 30.34 53.43 10,801 4.36 66.44 1.18 20.94 0.27 2 10.96 6.66 29.84 52.54 10,622 4.47 65.34 1.20 22.06 0.27 DFS Test #2 1 Vxde 9.51 30.42 Sf. ad 10,538 4.25 65.20 0.94 19.84 0.26 2 10.05 9.27 29.65 51.03 10,272 4.43 63.55 0.92 21.58 0.25 DFS Test #3 1 1.43 17.98 28.41 52.18 10,185 3.66 61.31 1.09 15.69 0.27 2 10.72 16.29 25.73 47.26 9,225 4.37 55.53) 0.99 22.58 0.24 Stove Ash 0.21 50.92 9.75 39.12 6,260 1.07 Furnace Ash 1.52 48.82 5.51 44.15 6,872 0.86 Coal Briquette 6.29 7.66 33.40 52.65 10,604 0.24 * 1 - As Received Moisture Basis 2 - Equilibrium Bed Moisture Basis ** Stoker Coal b a , _ =z = a =e TABLE 3-3 0 Concentration of Major Elements in the Deadfall Syncline Coals, Ashed at 750 C (percent) Sample Si0 Al 0 Fe 0 MgO Cad Na 0 K 0 TiO MnO So Total 2 23 23 z c 2 a DFS +1" 26.9 18.6 19.4 8.39 15.7 3.10 1.32 . 0.95 0.18 3.35 97.89 DFS 1"x 10m 34.8 24.8 11.9 6.22 12.4 4.16 1.68 1.26 0.08 4.43 101.73 DFS -10m 19.4 21.7 10.8 9.18 25.2 5.09 0.84 1.18 0.06 4.81 98.26 DFS Test #2 20.6 18.6 18.0 9.31 17.4 4.72 0.52 1.14 0.18 4.45 94.92 DFS Test #3 52.6 33.4 3.36 1.62 3.92 1.64 1.46 1.37 0.03 0.85 100.25 Stove Ash 24.0 18.8 16.9 8.68 18.0 3.48 1.84 0.97 0.20 3.56 96.43 (reashed) Furnace Ash 34.3 23.4 11.5 6.28 11.9 3.86 1.67 1.10 0.07 3.61 97.69 (reashed) Sample Initial Deformation Temperature DFS +1" 2070 DFS 1"x 10m 2075 DFS -10m 2150 DFS Test #2 2155 DFS Test #3 1850 DFS +1" 2045 DFS 1"x 10m 2040 DFS -10m 2140 DFS Test #2 2140 DFS Test #3 1875 TABLE 3-4 Ash Fusibility for the Deadfall Syncline Coals in Oxidizing and Reducing Atmospheres Temperatures (°F) Softening Temperature Hemispherical Temperature Oxidizing Atmosphere 2270 2225 2375 2425 2800+ 2305 2270 2395 2435 2800+ Reducing Atmosphere 2235 2210 2360 2415 2800+ 3.2.4 Combustion Product Analysis 2300 2260 2370 2425 2800+ Stack emissions were analyzed for CO, C02, NO, "Dragertube" measurement system. a sample port. The gases were Stack gases were first cooled through a tube containing reagents that discolored Fluid Temperature 2500 2505 2460 2510 2800+ 2450 2510 2425 2510 2800+ and SO, using a sampled through and then passed or colored upon =~ 3.3 reacting with the specific gas being measured (Figures 3-2 and 3- 3). The length of coloration or discoloration is calculated taking into account the total gas sucked through the tube. Emissions are expressed in parts per million or percent by volume. Ashes from the furnace and stove still contained about 50% combustible matter. One interesting observation is that the stove ash retained more sulfur than the furnace ash, indicating that there would be less SO, pollution with the stove than the furnace. Stove ash retained 91% of the sulfur contained in the coal, allowing only 9% to go up the stack whereas furnace ash retained 59% of the sulfur. A furnace smoke tester type device was used to determine particulates. The device was found to be ineffective in sucking particulates from the stack. Briquetting of DFS Coal Fines 3.3.1 Coal Briquetting Process 120 lbs of minus 10 mesh coal was shipped to K.R. Komarek Inc., Anniston, Alabama for briquetting. Initial briquetting trials utilizing 6% granulated petroleum asphalt as a binder yielded briquettes that did not have the desired strength. Another procedure using pregelatinized corn starch as a binder produced excellent briquettes. Briquettes were made using a Model B-220A Briquetter with a capacity of 500 to 2000 lb/hr. This press was equipped with B-2095- 1 rolls, which have 28 pockets spaced around the 2-inch wide working face. The feed auger used to feed the rolls is 2-13/16 inches in diameter and displaces 6.7 cubic inches of material per revolution. The rolls were operated at 13 RPM and produced 1.2 1b briquettes per revolution for a capacity of 936 lb/hr. 3.4 A 31 ton roll compression force was used during the trial, yielding green briquettes that would not fail in a 16' drop onto a concrete floor. The crushing strengths of the green briquettes averaged 45.2 + 6.1 pounds. After drying, the crushing strength of these briquettes increased. However, drop height to produce failure decreased. The briquettes were made from minus 10 mesh coal to which 3% water and 3% Hamaco 267 corn starch (45 cents/1b of starch) were added. The starch is a modified pregelatinized corn starch made by the A.E. Staley Company. Precooked starches are useful for small quantity briquetting, but larger operations generally cook their own raw starch (8 cents/lb of starch).The cooked raw starches are not highly modified like the Hamaco 267, but they cost less and still make an acceptable binder. 3.3.2 Product Testing Observations The briquettes have the appearance of charcoal briquettes. They handled well without breaking and did not’ produce dust. They burned quite uniformly in the Harmon Mark III space heater. The briquettes remained coherent during the entire combustion process. Briquettes are considered to have the most desirable characteristics for domestic use in stoves and are superior to Jump coal in terms of size stability. Combustion Efficiency Testing 3.4.1 Methodology There are three principal components in combustion efficiency calculations: 1) The amount of heat (btu) produced in the unit by burning coal (1b of coal burned x heating value of coal, btu/1b). 3 - 10 { vm 2) The heat lost through stack gases. The heat needed to raise the temperature of the stack gases from room temperature to exit gas temperature. 3) The useful heat delivered to the room: a) Forced convection - a circulation fan forces room air to contact a heat exchanger. b) Free convection - the heat delivered by the warm vertical and horizontal furnace surfaces. c) Radiation - the heat radiated by the furnace surface. Calculated using an estimated emissivity value. The heating value of the coal less the heating value of the ashes should theoretically equal heat lost through stack gases plus heat delivered to the room. Furnace efficiency is the ratio of the heat delivered to the room to the heat contained in the burned coal. Principal data needed for calculating unit efficiencies are the temperature difference between room temperature and temperature of hot air and the volume of stack air. Temperatures were measured with a Fluke Datalogger 2240C coupled to type K and T thermocouples (Figure 3-4). This is a fully integrated data logger with multiplexer, digitizer and printer output. Its capable of 1 mv resolution at 4 1/2 digits. The volume of stack air is calculated knowing the stack cross sectional area and the velocity of the stack gases, which was measured with a pitot probe. 3.4.2 Mountain Man 85 Furnace 3.4.2.1 Description of Heating Unit The Mountain Man-85 (Figure 3-5) is designed to be used as a free standing space heater for burning a_ broad range of 3 1d fuels, including hard and soft coal, coal pellets, and wood pellets. More specifically, the unit will burn most bituminous and sub-bituminous forms of coal in a size range of 1/4 to 3/4 inches (stoker coal). Coals often exhibit widely differing burning characteristics, and therefore some coals will not perform as well as others. Adjustments in air and feed rate will be required to match the coal to the capabilities of the unit. The unit is designed to deliver up to 12 lbs. of fuel per hour to the fire, to produce 80,000 to 100,000 btu/hr of heat output. The forced air output is circulated across the stainless steel finned fire box (heat exchanger), and is controlled from a room thermostat. Important features include: 5 Thermostatic control : Forced air circulation - Two speed fan c 240 1b self-contained fuel hopper = Safe surface temperatures - Temperature limit switches to prevent over-firing - "Hold-fire timer" that operates like a pilot light = Forced under-fire and over-fire air for clean combustion = Built-in ash bucket - 24-48 hours of burn time per hopper The unit may operate up to 48 hours on a single hopper of stoker fuel depending upon heat demand, and will require ash removal at least once per day. Under-fire and over-fire air are each adjustable in order to match combustion air flow to the burning rate, thus maximizing cleanliness and efficiency. These units should be tended at least once per day during the heating season. The Mountain Man-85 is designed to 3 = 12 ~~ automatically stoker fuel from the hopper to the burner by means of a "feed screw" (auger). The auger normally turns at approximately one rpm, but adjustments to higher or lower rpm can be made by changing motor gearbox pulleys. Since the turning rate for any given auger controls the feed rate, adjustments in auger speed may be needed to tailor the feed rate to the specific fuel being used. The feed rate of the fuel will depend upon the auger speed as well as the size of the fuel particles. Small size fuel will feed at a higher rate than larger fuel. Fuel is augered into the “retort bowl" which forms the base of the burner head. The segmented "tuyere ring" is mounted on top of the retort bow] to direct combustion air into the fire. The retort bowl is mounted on the “air chamber" which serves to distribute both the under-fire air through the tuyeres, and the over-fire air through the over-fire air tube. The volume of air is adjustable through individual air gates for under-fire and over-fire air at the output of the squirrel cage "combustion fan". The combustion air volume must be adjusted to produce a "clear flame" and minimum smoke from the flue. As the heat exchanger increases in temperature, the "120 degree thermo disk" mounted on the cabinet divider panel will be actuated (switch closure). This completes the electrical circuit with the circulation fan. The fan is connected in series with a "Carson Reactor" having three terminals. The fan will initially come on at a reduced speed because of the Carson Reactor. The circulation fan will operate as long as the 120 degree thermo disk is actuated. As the heat exchanger temperature continues to increase, the "140 degree thermo disk" will close its contact. This closure puts full power on the fan so it will run in the "high speed" mode. The heat exchanger design contains several important features. Sails Although the 18 gauge stainless steel heat exchanger is relatively thin, the fins welded to it provide a large area for heat transfer via air blown over it by the "circulation fan". The bottom of the heat exchanger is lined with a high temperature refractory cement for insulation. A flue baffle is mounted to the top of the heat exchanger in front of the flue opening to maximize the combustion of volatiles. The baffle is mounted in front of the opening rather than across the opening to avoid blocking the flue with fly ash buildup. The stoker control electronics include a “relay timer" (j.e., “hold fire timer"). The hold-fire timer operates like a pilot light when the thermostat is not calling for heat. After a preset period when heat is not demanded, the timer turns on the stoker and combustion fan for a period of time that is also adjustable. 3.4.2.2 Description of Test and Sensor Locations To assess the efficiency of the Mountain Man 85 forced air furnace (Figures 3-6 and 3-7) in burning Western Arctic Deadfall Syncline coal, tests were performed on March 7 and March 22, 1987. The heating value of the coal described previously was used together with the coal feed rate to determine the thermal energy input to the furnace. For the March 22 test, the heating values and ash contents of the feed and the residue were all measured so the true thermal energy consumed could be determined. The coal feed rate was measured for each test (different diameter drive pulleys) by direct measurements of amount of coal fed into the combustion chamber over a given period of time with the furnace not firing. This rate was then multiplied by the total time in each test that the furnace was in the feed mode to determine the total mass of coal consumed during each test. In addition to the feed only mode when the stoker motor was on but the circulating fan motor was off, there are five other 3 > 14 o~ modes. In the off mode, neither motor is on. In the low heat (LH) modes, the circulating fan is at the low speed (875 cfm) setting while the fan setting is 1240 cfm in the high heat (HH) modes. The designators A and B denote if the stoker (and hence combustion air blower) is_ on and off respectively. The HH mode is activated when the temperature above the combustion chamber reaches 140°F while the LH mode requires a temperature of at least 120°F. Hence the total time the coal is feeding is the sum of the feed only plus LHA and HHA modes. During these modes, the combustion air gates were fully open. To determine the heat output of the furnace to the room (not including that portion of the flue that was in the room), we accounted for the forced convection, free convection, and radiative components of heat transfer (Figure 3-8). The forced convection was dominant and represented the heat transferred by the circulating fan. To calculate this heat output, we measured the temperatures at the locations shown in Figure 3-9 using type K and T thermocouples connected to a Fluke 2240C datalogger. For the mass flow rates of the air supplied to the room by the fan, we used data supplied by the manufacturer. For the mass flow rate of the stack gas, we used a velocity inferred from a pitot probe. To calculate the heat loss out the stack we would use the following equation (1): Qstack = MstackCp(T1 - Tamp); where Motack = (P AU)stack iS the mass flux of the products of combustion up the flue; p is the density of the stack gases where the stack velocity is u; and A is the cross sectional area of the stack. The specific heat C, of the flue gases is _ assumed to be that of air, Ti is the stack temperature leaving the furnace as shown in Figure 3-3, and Tan. is the ambient air temperature. Similar equations are used to calculate the heat input into the room by the fan with the relevant temperatures differences being (Ts - Te) for the air Caen 5 leaving the upper grate and (T, - T.) for the air leaving the side grates. The fan volumetric air flow is assumed to be apportioned among the grates by their area ratios. 3.4.2.3 Data Analysis The critical data for the two runs appears in Tables 3-5 and 3-6 and results of calculations in Tables 3-7 and 3-8. A sample calculation for the results appearing in Table 3-7 appears in Appendix B-1. Each temperature appearing in the first two tables represents an average over the time spent in the appropriate mode and hence would incorporate anywhere from 3 to several dozen readings. The average air temperature in the room during the first test was 80°F and 72°F during the second test. For each test, the total electrical energy consumed was less than 1% of the energy contained in the coal used during the test. 3'= 16 ~~ TABLE 3-5 Critical Data for March 7, 1987 Tests Temperatures (°F) Mode Stack Air Furnace Stack * (Min) Top Wall +0 1 2 3 4 6 5 8 7 OFF (105) 190 241 114 134 74 71 99 80 131 FEED ( 10) 355 547 113. 147 71 69 101 77 153 LHA ( 60) 538 687 126 109 134 86 104 82 277 LHB ( 27) 290 333 110 100 109 83 98 85 200 HHA ( 13) 579 745 138 #115 141 94 113 86 327 HHB ( 10) 471 557 129 111 133 97 111 88 294 Note: - *Location code numbers, see Figure 3-9 for locations. - Total Run Time = 3.75 hrs - Coal Feed Rate = 12.0. 1bm/hr - Total Coal Feed = 16.6 bm - At 10.8 K btu/lbm, total input energy in coal = 179K btu. - Total electrical energy consumed = .20 kwhr = .7K btu. - Average ambient temperature in room = 80°F. TABLE 3-6 Critical Data for March 22, 1987 Tests Temperatures (°F) Mode Stack Air Furnace Stack (Min) Top Wall 20 1 2 3 4 6 5 8 7 OFF ( 54) 207 234 --- 129 77 72 88 --- 137 FEED (100) 397. 472 --- 142 87 --- 90 --- 214 LHA = (239) 429 506 --- 95 106 74 87 --- 235 LHB (12) 280 297 --- 95 102 75 92 --- 193 Note *Location code numbers, see Figure 3-9 for locations. Total Run Time = 6.75 hrs Coal Feed Rate 6.85 1bm/hr Total Coal Feed = 38.7 lbm Energy in coal feed = 418 K btu Total electrical energy consumed = .68 Kwhr = 2.3 K btu. Average ambient temperature in room = 72°F. 3.= 17 TABLE 3-7 Results for March 7, 1987 Tests Radiation (btu) Mode Body Off 730 Feed 77 LHA 529 LHB 178 HHA 160 HHB 115 Total 1,789 Furnace Free Convection Forced Convection Stack Loss (btu) ; (btu) (btu) Body Plenum 324 2,261 een wenn 34 265 teen 10.2 K 244 2 === - 38.8 K 78.8 K 81 === 9.9K — seeeee 80 ----- 11.5 K 19.1 K =i] —_—_===== 6.0K ewes 820 2,526 66.2 K 108.1 K transfer (btu) Heat 447 transfer/hr (btu/hr) Note: 1) 2) 3) Total radiant and free convective heat transfer = 5.1 K btu 5.1 + 66.2 Furnace efficiency = ———-__ = 40.0% 179 E out 72 + 108 Energy balance: = 1.00 E out in 179 Average rate of energy input = 179 K/3.75 = 48 K btu/hr Average rate of energy output = 71.2K/3.75 = 19 K btu/hr If heat input to room from stack counted, system efficiency equals 56.0% because 29.2 K btu entered room from cooling of flue gases between monitoring points 1 and 0. 3 - 18 TABLE 3-8 Results for March 22, 1987 Tests Furnace Radiation Free Convection Forced Convection Stack Loss (btu) (btu) (btu) (btu) Mode Body Body Plenum Off 267 137 2,556 eee wens Feed 599 30900 mee wenn 102.3 K LHA 1,182 f= 108.7 K 262.7 K LHB 80 42 3,776 eee wee ene Total 2,128 1,075 9,332 108.7 K 365.0 K heat transfer (btu) Heat 304 16.1 K 54.1 K transfer/hr (btu/hr) Note: 1) Total radiant and free convective heat transfer = 12.5 K btu 12.5 + 108.7 2) Furnace efficiency — ———__ = 29.0% 418.1 E out 121 + 365 3) Energy balance: .————— = = 1.16 E out in 418 4) Average rate of energy input = 418 K/6.75 = 62 K btu/hr 5) Average rate of energy output = 121K/6.75 = 18 K btu/hr 6) If heat input to room from stack counted, system efficiency equals 50.0% because 66 K btu entered room from cooling of flue gases between 1 and 0. 7) If heating value of residue taken into account, system efficiency .quals 32.0% because total heat input in combusted coal = 377 K btu 3-25 19 The fundamental difference between the two runs was the coal feed rate, with this rate being about half as much for the second test. We decided to reduce the feed rate because we observed that much of the coal was carried over with the ash, incompletely burned, for the March 7 run. This lower auger speed resulted in a much more complete combustion of the coal for the March 22 test. The ash content and heating value of the residue were measured for the second test but not for the first. The furnace efficiency during the 3.75 hour first test was 40% and 29% during the 6.75 hour second test. Here, the efficiency is defined as heat delivered from the furnace to its surroundings divided by the gross thermal energy of the coal consumed. The latter does not account’ for any uncombusted coal that is carried over in the ash residue. For the second run, the efficiency is raised to 32% if we let the denominator in the efficiency expression be the net thermal energy of the coal. Here, the net refers. to only that part of the coal that is combusted completely. The system efficiencies presented in Tables 3-7 and 3-8 includes the heat that entered the room from the 7 feet of flue pipe (6" diameter stove pipe) in the room. It indicates the potential for heat recovery (with the accompanying danger of stack corrosion). The sample calculation in Appendix B-1 illustrates how the numbers appearing ‘in Table 3-7 were calculated. The forced convection terms are only associated with the modes involving the fan while the stack losses are associated with each of the three modes when the auger jis turning and _ hence combustion air is being supplied by the blower. The stack gas velocity was too small to measure using our draft gage during the other modes. During the feed modes, the stack velocity was estimated as 21.9 fps using the pitot probe. 3 - 20 The uncertainty here is about + 10% resulting in a comparable uncertainty in the mass flow up. the stack. The resultant mass flow, however, is within 10% of that estimated from the manufacturer's data on the combustion air blower (140 cfm) all of which is assumed to exit via the stack. With the combustion air to coal mass ratio being around 50, one can assume that the former represents essentially all the mass flux up the stack. Standard correlations: for free convection (Incropera and Dewitt, 1985) were used to estimate the free convection for the vertical and horizontal furnace surfaces. Radiation terms were estimated from the Stefan-Boltzmann Equation with an emissivity of 0.85 used for the furnace surface. The average ambient air temperature was used as the temperature of the surroundings and a shape factor of 1 was assumed. Some details are provided in Appendix B-1. 3.4.2.4 Combustion Product Analysis The measured CO levels were below 0.1 ppm both inside the “room containing the furnace and outside the home. We also measured radon levels and found them to range from 4.8 to 16.8 piC/1. The Environmental Protection Agency (EPA) recommends remedial action for levels greater than 4 piC/). Not enough data is available to establish any correlation of coal combustion and radon levels. We used 4 charcoal collectors left in place for about 10 days and the furnace was burning coal for over a day during that period. The flue gas had an average COz concentration of 2.0%, CO of 957 ppm, NO. of 239 ppm, and SOz of 50 ppm all by volume for a test performed on April 6, 1987. The measured concentrations in each case appear to be consistent and steady. The variabilities in the measurements are within the limits of error in measurement and other factors which could not be controlled. For these tests, the coal feed rate was the same 3) > 20) as on March 22. This low COz concentration indicates excess air was supplied to the combustion chamber which is consistent with the air gates being fully open. The much lower CO concentration in the room than in the stack gas indicates a good draft within the furnace. 3.4.2.5 Discussion of Results We believe the efficiencies we measured for the first run were adversely effected by the low reactivity of the coal. Much of the energy contained in the feed was not being transferred to the recirculating room air because of the incomplete combustion of the coal. Hence, we lowered the feed rate for the second run so that about 90% of the heating value of the coal was released during combustion. As a result, our average rate of energy input was too small to result in an efficient mode of operation. This relationship between efficiency and energy input or output is consistent with data supplied by the manufacturer (Masek, 1987). These data indicated efficiencies to increase from around 50% to over 70% as the heat output increased from 10K btu/hr to around 50K btu/hr. The total percent of time in the off mode was 47% in the first run and 13% in the second run. Although they were not calculated, we would assume the off cycle stack losses were greater than in the first run. The auger was on (and the combustion air) about 83% of the time during the second run partially because it was difficult to maintain a proper temperature in the heat exchanger at the low coal feed rate. Soon after the heat exchanger fan turned on, the temperature on the downstream side of the clean air heat exchanger would drop thus lowering the ability of the forced convection process to transfer heat to the room. Even though the coal feed rate was much less for the second than the first run while the stoker was operating, the average rate of coal 3 = 22 jnput over the test duration was higher for the second run. This is because the auger was turning during a much higher percentage of the run for the second rather than the first run. As one check on the cumulative errors of both our data and subsequent analysis, we also performed an energy balance to see the closeness of agreement between energy in and energy out. For the first run, the agreement is remarkably good with calculated output both up the stack and-heat actually delivered to the room being to within 1% of the gross energy contained in the coal. Of course, we know that not all the coal was combusted so the heat output should be less than the energy contained in the coal. For the second run, our calculations indicate that about 16% more heat exited than energy entered. Possible explanations include errors in our estimate of stack gas velocity, coal feed rate, the cfm provided by the fan, and the temperatures of the return and supply air. We measured coal feed rate when the coal was not burning. During actual operation, the ash and clinkers may offer some resistance to the feeding of coal thus resulting in a different feed rate. We assumed average temperatures for the return and supply air for each mode of operation. They were obtained from data taken at only three locations every five minutes. More complete temperature data both spatially and temporally would provide more accuracy here. We used manufacturer's data for the fan cfm instead of trying to measure it directly. The latter is difficult to do and requires lots of velocity measurements over time and space. However, we do feel confident that our efficiencies were not over 50% for this particular coal in these modes of operation. As stated before, this is largely because of the low reactivity of this coal and is not a condemnation of the Mountain Man 85 furnace. Sales The overall mechanical performance of the system was acceptable. We were able to operate the system in an unattended mode over a _ several hour period except for the removal of ash and clinkers and resupplying of coal when the feed bin became depleted. The system appeared to operate in a reasonably clean mode so the room was free of ash buildup. 3.4.3 Harmon Mark III Stove 3.4.3.1 Description of Heating Unit The Harmon Magnafire Mark III stove, designed to burn coal or firewood, was used for testing DFS coal. The stove is equipped with a heavy duty cast iron grate system to support coal as well as provide air flow through the grates to the coal for even combustion. A shaker lever located outside the stove permits removal of ash from the unburned coal, by grinding, breaking, or shaking until ashes fall through into the ash pan. The combustion zone that contacts hot coal is lined with refractory bricks. The stove has one draft control located on the ash pit door. Secondary air is supplied through slots under the door glass. These slots provide secondary air for coal burning. A blower located in the rear of the stove sweeps air across the back and top hot surfaces to air in better heat recovery. 3.4.3.2 Description of Test and Sensor Locations A test was performed on April 19 to determine the efficiency of the Harmon Mark III stove while burning DFS coal. The coal's heating value, and the mass of coal fed were used to find the energy input. Bags containing the coal were weighed before and after the stove was stoked. The mass difference was the amount of coal input. It was found that the larger chunks of coal used in the stove had a lower heating value 3 - 24 than the stoker sized coal used in the furnace. It seems that the coarser grade contained more contaminants. The heat input to the room by the stove (not including that contributed by the stovepipe) was found by evaluating the heat transferred by radiation, free convection, and forced convection. A Fluke 2240C datalogger was used to read the type K and T thermocouples arranged as shown in Figure 3-10. During the test a log was kept of the various combustion air settings. The temperature data were grouped according to these settings and average temperatures were found for each group. These average temperatures may be seen in Table 3-9. With empirical relations from Incropera and Dewitt (p. 198), the free convection and radiation heat transfer components were assessed. Forced convection was found by converting the manufacturer's cfm for the blower to a mass flow rate at the inlet air temperature. This was divided evenly between the two blower ducts. The following equation was used to find the heat added by forced convection: Qrorced,= 0-5: Mitcwer Cp (Vouctee — Tintee ) where: Micwer = total mass flow rate of the blower; C, = specific heat of the air; Toutiet = outlet air temperature; Tintet = inlet air temperature; and t = the length of time the stove operated at the combustion air setting. B= 125) oS -€E TABLE 3-9 Critical Data for Stove Test (April 19, 1987) Temperature (°F) Time # of Turns Blower Front Top Stack Rh Lh Stack Stack Period Combustion Inlet Inlet Surface Exterior Outlet Outlet Entrance Outlet Air Vent Was Air Air Opened Ts Te Is Ta Ts Te Ts To 1 2.2 hr 125) 70 485 489 160 228 237 652 325 2 0.5 hr 2.5 64 303 319 108 179 195 341 198 3 0.13hr 0.5 59 219 231 88 147 165 269 145 4 0.4 hr 0.75 58 229 193 81 134 151 241 127 5 0.35hr 1.25 58 149 166 81 125 140 265 131 6 0.28hr 125 67 223 232 117 154 182 550 251 7 0.22hr 1.25 73 408 392 140 201 218 656 309 8 0.2 hr 1.0 75 417 438 133 210 235 609 282 9 2.75hr 0.75 73) 298 313 104 163 180 381 182 10 2.97hr 1.5 68 295 Si 122 167 185 419 220 11 1.0 hr 4.0 69 408 392 144 190 212 473 297 Note: 1) Duration of test = 11 hrs 2) Total Coal Fed = 66.9 lb 3) Total Energy input with coal = 66.9 1b X 10.4 K btu/1b = 693.5 K btu / ‘ = Ideally stack losses would also be assessed so that an energy balance could be computed. This, however, was impossible for the velocity of the stack gases was too low to result ina draft detectable using our draft meter. 3.4.3.3 Data Analysis The critical data for this test appears in Table 3-9. The results obtained with these data appear in Table 3-10. Sample calculations supporting these results appear in Appendix B-2. The temperatures in Table 3-9 are averages over the time spent at each combustion air setting. Anywhere from 8 to 169 data points were used to arrive at these averages. It was found that the energy consumed by the blower was less than 1% of the energy input in coal. The stove efficiency during this 11 hour run was found to be 64%. This efficiency is defined as the total energy introduced into the test area from the stove divided by the total energy added in coal. The energy from the coal does not account for uncombusted coal removed with the ashes. Table 3-11 summarizes the heat recovered by the stovepipe. Including these figures increases the efficiency to 66.4%. Due to the stackgases' low temperature, very little heat is available for recapture. As mentioned earlier empirical relations were used to find the free convection from the sides and the top. Radiation was estimated using the Stefan-Boltzmann Equation. A surface emissivity of 0.90, and shape factor of 1 were assumed. The temperature of the surroundings was taken as the ambient air temperature. See Appendix B-2 for more detail. S27 TABLE 3-10 Results of April 19, 1987 Stove Test Time Radiation Free Convection Forced Convection Period (btu) (btu) (btu) ares Top Sides Top Sides tS 1 10.4 K 53.9 K 6.4 K 25.4 K 51.9 K 2 0.9K 4.4K 0.8K 2.9K 9.0 K 3 0.1K 0.6 K 0.1K 0.5 K 1.9 K 4 0.3K 2.1 K 0.3 K 1.5 K 5.1K 5 0.2K 0.8K 0.2 K 0.6 K 3.9 K 6 0.3 K 1.3 K 0.3 K 1.0 K 4.2K 7 0.6 K 3.7 K 0.5 K 2.0 K 4.3K 8 0.7 K 3.5 K 0.5 K 1.8 K 4.3K 9 4.9K 23.4 K 4.0K 15.1 K 39.4 K 10 5.3K 25.1 K 4.4K 16.6 K 42.1 K 11 2.9 K 16.7 K 2.1K 9.0 K 19.4 K 162.1 K 96 K 185.5 K 14.7 K btu/hr 8.7 K btu/hr 16.9 K btu/hr Note: 1) Total radiant and free convective heat transfer = 258.1 K btu 258.1 + 185.5 2) Furnace efficiency = ——— = 64.0% 693.5 3) If heat input to room from the stack is considered system efficiency = 66.4% because 17 K btu's entered the room from cooling of flue gases. 3 - 28 TABLE 3-11 Stack Loss Due To: Time Period, Radiation, and Convection Time Period Radiation (btu) Convection (btu) A 3426 2704 (i 318 125 3 52 39 4 124 88 5 108 77 6 213 164 7 243 186 8 189 140 9 1274 871 10 2486 1920 ola 1239 978 TOTAL 9672 7292 3.4.3.4 Combustion Product Analysis Stove stack gas data was collected by Dr. Bandopadhyay (UAF), (Figure 3-11). From the emission data from the furnace and stove, that: presented in Tables 3-12 and 3-13 it is observed Stove stack gases have higher concentration of CO and COz due to restricted air flow. NO, concentrations are similar. NO, is essentially produced from nitrogen contained in the coal. Stove stack gases had lower SO, concentrations. The sulfur in the coal reacts with calcium in the coal and is fixed. More sulfur is fixed in the stove than the furnace. This is also indicated in the ash analysis in Table 3-2. 3129 TABLE 3-12 Furnace Stack Emission Measurement Data CO. Measurement Data April 6, 1987 Time of Tube No. of Calculated Concentration Measurement Type Strokes of C02 (%Vol.) 10:15 Long 2 2.00 10:25 Long - 2.56 10:35 Short 2 1.50 11:00 Short 2 1.50 11:05 Long 2 1.50 11:20 Short 2 1.50 11:30 Long 2 2-50 12:00 Long - 3.00 12:05 Short 1 175 12:10 Long = 3.00 12:40 Short 1 2.00 12:45 Long 2 3.00 12:50) Short 2 2.50 12352 Short 2 2.00 1:00 Short 2 1.50 135) Short 2 2.00 1:20 Short 2 2.00 icas Short 2 2.00 1:45 Short 2 1.80 2235 Short 2 175 3 = 30) TABLE 3-12 (Continued) CO Measurement Data April 6, 1987 Time of Tube No. of Calculated Equivalent Measurement Type Strokes Concentration (ppm) 10:15 Long 2 900 10225 Long 2 1100 11:05 Long 2 700 11:30 Long 2 1000 12:00 Long 2 1000 12:10 Long 2 1000 12:45 ‘Long 2 1000 NO, Measurement Data April 6, 1987 Time of No. of Calculated Equivalent Measurement Strokes Concentration (ppm) 11:40 10 100 12:00 10 300 12:30 10 100 1235 5 (150 m1) 300 12255 10 200 1525 5 (200 m1) 400 135) 10 250 2210 10 250 2:30 10 250 SeeroL TABLE 3-12 (Continued) SO2 Measurement Data April 6, 1987 Time of No. of Conc. Calculated Equivalent Measurement Strokes (m1) Concentration m 10:30 2 10 50 11:10 2 10 50 11:30 2 9 45 12515 2 10 50 12:35 Z 10 50 12:45 2 10 50 1:20 2 10 50 1:40 2 10 50 2:40 zZ 10 50 Data Summary Low Average High C02 Concentration (% Vol.) 1.50 2.01 3.00 CO Concentration (ppm) 700 957 1100 NO, Concentration (ppm) 100 239 400 SOz Concentration (ppm) 45 50 50 3 - 32 TABLE 3-13 Stove Stack Emission Measurement Data Carbon Dioxide Stove Emission Data April 19, 1987 Measured Time of Tube No. of Concentration Measurement Type Strokes % Volume 11:45 Short 1 9.0 12:05 Long 2 a 12:35 Long 1 8.0 12:38 Long 1 8.0 12:50 Long 2 8.0 1:00 Short 1 8.0 i: Long 2 7.0 1:38 Short 1 6.5 1:40 Long 2 7.0 Measurement Summary Maximum Concentration 9.5% vol. Mean Concentration 7.8% vol. Minimum Concentration 6.5% vol. a -33 TABLE 3-13 (Continued) Carbon Monoxide Stove Emission Data April 19, 1987 Measured Time of Tube No. of Concentration Measurement Type Strokes ~ (ppm) 11:50 Short 1 2500 12:05 Long 2 1300 12:10 Long 2 1200 12:35 Long 2 2500 1:00 Short 1 1000 1520 Short 1 2000 Leee Long 2 1500 1335 Short 1 1500 1:40 Long 2 1700 Data Summary Maximum CO Concentration 2500 ppm Mean CO Concentration 1688 ppm Minimum CO Concentration 1000 ppm 3 - 34 TABLE 3-13 (Continued) Sulphur Dioxide Stove Emission Data April 19, 1987 Time of Tube No. of Measured Measurement Type Strokes Concentrations (ppm) 11:40 Short 10 3 12:00 Short 10 5 12230 Short 10 3 i: 10 Short 10 3 1:44 Short 10 5 Data Summary Maximum S02. Concentration 5 ppm Mean S02 Concentration 3.8 ppm Minimum S02 Concentration 3 ppm Oxides of Nitrogen April 19, 1987 Time of Tube No. of Measured Measurement Type Strokes Concentrations m 1255 Short 5 125 12215 Short 3 100 12:40 Short 5 65 12:45 ais 5 125 1:44 Short 5 100 Data Summary Max imum NO, Concentration 125 ppm Mean NO, Concentration 103 ppm Minimum NO, Concentration 65 ppm S35 3.4.3.5 Discussion of Results The stove seemed to be an efficient device for burning DFS coal. Hand stoking allows enough time for the coal to burn to completion. In actual operation it would be advisable to supply more combustion air. This would reduce the unit's efficiency by increasing stack losses, but it would prevent low stack’ gas temperatures thus minimizing the possibility of corrosion due to condensation. Average temperatures were assumed for each combustion air setting, and some of these settings were rather brief. The accuracy of this experiment could be improved by choosing one setting at which the experiment should run. This would make the empirical formulas more valid since they assume steady state conditions. Taking temperatures at more points would also help the accuracy. Measuring stack losses would allow an energy balance to be calculated. This would provide a useful check on our calculations. Overall this stove worked quite well. The unit seemed sturdy and tight. The collection ‘tray proved especially useful for ash removal. CO levels were measured at 0.1 ppm both inside and outside the house. The measured radon levels ranged up to about 17 pic/1. Since coal was burned in the stove for one half a day, compared to radon measurement times of 10 days, no correlation could be established between radon levels and coal combustion. 3.4.3.6 Fuel Equivalency Calculations Following is a sample calculation for converting fuel oi] demand to coal demand. Considered, are the heating values of the two fuels and the unit efficiencies for the combustion devices. The fuel conversion factor is derived as follows: 3 - 36 1) Heating value of fuel oil = 135,000 btu/gallon. At 75% efficiency, recoverable heat for fuel oi] = 135,000 x .75 = 101,250 btu/gallon; 2) Heating value of DFS coal = 10,800 btu/1b. At 66% efficiency, recoverable heat for coal = 10,800 x 0.66 = 7,128 btu/1b; and 3) Fuel conversion factor 101,250 btu/gal 7,128 btu/1b 14.2 1b of coal/gal fuel oil Thus, a residence requiring 1,000 gallons of fuel oi] per year would require 7.1 tons of DFS coal per year. This assumes the coal is burned in the Harmon Mark III stove. 3.4.3.7 Comparison of Sulfur Emissions All sulfur contained in combusted fuel oi] is emitted as SO3. The SO2 emitted for 1,000 gallons of combusted fuel oi] per year (7.7 1b/gal density) containing 0.58% S is 89 1b SOz/year. The S02 formed from burning 7.1 tons of DFS coal containing 0.27% S would be 76.7 1b SOQz. Since the Harmon Mark III stove retained 91% of sulfur in the ash, the SOz released as emissions from its combustion of 7.1 tons of DFS coal would be only 6.9 1b. About 8% of that produced from the combustion of oil. 3.4.3.8 Comparison of Stove Stack Emissions to EPA Emission Factors The stack emissions were measured as concentrations by volume of the stack gases. It was not possible to measure the stack velocities accurately due to low draft. The quantities of 3 = 37 pollutants produced are calculated using COz concentration in the stack gases as a measure of coal combusted. Quantities of pollutants produced from the stove test are presented in Table 3-14. TABLE 3-14 Quantities of pollutants Produced Gas Mean conc. Mol. Conc. x Emission Quantity Estimates — vol. % wt. mol wt. per 100 of gases from EPA (ppm) units of produced emission oo. per ton factors,Ib. of coal burned, 1b. CO, 7.8 44 343.2 100 4,840 -- co 0.17(1688) 28 4.76 1.39 67 90 NOx 0.01(103) 46 0.46 0.13 6.3 3 (as NO2) $0. 0.00038(3.8) 64 0.024 0.007 0.34 10 SOs |||) | | /s5s-4- Se! |||) | eee | |] | eee .97 —— (ash balance) Permissible CO concentration for the University of Alaska Power Plant stack gases is 100 ppm. In contrast, the stove stack contained an average of 1688 ppm. The stack gases should not be allowed to leak into the residences. CO concentrations in industrial work areas should not exceed 50 ppm. CO concentrations exceeding 10 ppm are considered unsuitable for residences. SOz and NOz levels exceeding 0.1 ppm can result in adverse effects on humans. 3.4.3.9 Ash Residues Annual combustion of 7.1 tons of coal in a stove will generate one ton of ash residue per year, assuming 7.66% ash in the raw coal and 50.9% ash in the stove ash residue. 3 - 38 3.5 Conclusions 1. The bulk sample tested was weathered and had a lower heating value compared to deeper drill core samples. e- Briquettes made from minus 10 mesh coal had excellent stability and combustion characteristics. 3. Mechanical performance of the furnace system was acceptable. The furnace may need to be shut down at least once a day for removal of ash and clinkers. Ash removal created dust in the area. Some fine dust particles permeated the area during the normal furnace operation although it generally operated dust free. 4. Furnace efficiency was no more than 40%, apparently due to low feed rate to furnace, largely dictated by the low reactivity of the coal. 5. The stove had an efficiency of 64%, attributed to low stack gas temperatures. 6. Analyses of the furnace and stove stack gases indicate that pollutant concentrations are reasonably low for the observed burn rates. Sulfur emissions from burning DFS coal ina stove would be substantially lower than produced by oil heating. EPA particulate sampling train should be used to determine particulate emissions. es It is recommended that a different furnace with automatic ash discharge and one that can yield higher efficiencies be investi gated. The efficiency measured for the furnace tested is too low to be acceptable. Use of a smaller topsize coal to feed the furnace should improve the burn rate as well as the efficiency. 3 - 39 8. It is recommended that briquetting, using locally available binders, be investigated. Briquetting would utilize all coal fines and provide a product that can be handled without dust generation. Briquettes would be the most acceptable form for users burning coal in a stove. 9. Firing tests of DFS coal in a spreader stoker as well as fluidized bed furnace are recommended in order to obtain sufficient information on the combustion behavior of the coal for the design of a plant serving large communities such as Nome or Kotzebue. 3.6 References Incropera, Frank P. and David P. Dewitt, Fundamentals of Heat and Mass Transfer, 2 ed., John Wiley & Sons, New York, 1985. Masek, T., Chippewa Traders, Salt Lake City, Utah, 1978, (personal communication). House located 0.75 mile Rosie Creek Road, Figure 3-1. used for coal testing, Figure 3-2. Stack gas measuring tube and gas suction devices. Figure 3-3. Tube coloration showing level of NOx concentration in stack gas. RAE,G.E. *" AlG 20 AVMS CE MC tL A21G2 Figure 3-4. Data logger used for recording temperatures, for furnace and stove testing. HEAT EXCHANGER FLUE BAFFLE CIRCULATION FAN STOKER CONTROL RELAY STOKER MOTOR TUYERES ws eee iit os REFRACTORY é RETORT ASH PAN BOWL COMBUSTION “a’ AIR FAN GEARBOX AIR CHAMBER FUNCTIONAL DIAGRAM - MOUNTAIN MAN 85 WESTERN ARCTIC BF. s1ope COAL_ DEVELOPMENT sngineer? PROJECT Functional Diagram Mountain Man 85 Prepared by: Date: April, 1988 M.IR.L. Fig. 3-5 Figure 3-6. Clarke Pelz and Dr. Johnson. Figure 3-7. Dr. Bandopadhyay measuring Measuring velocities of furnace stack gas composition. air through various louvers. FREE CONVECTION STACK FROM HEAT EXCHANGER LOSS = RADIENT ENERGY ROOM AIR FOR CIRCULATION FORCED CONVECTION ROOM AIR FOR COMBUSTION ENERGY BALANCE USING THE MOUNTAIN MAN 85 WESTERN ARCTIC BF. spe COAL_ DEVELOPMENT engineer? PROJECT Energy Balance Using the Mountain Man 85 Date: April, 1988 Fig. 3-8 O-STACK EXIT 1-STACK ENTRANCE 2-THERMOSTAT AREA 3-TOP GRATE 4-SIDE GRATE 5-HOT SURFACE AREA 6-INLET AIR TEMPERATURE 7-STACK EXTERIOR 8-COOL FURNACE EXTERIOR THERMOCOUPLE PLACEMENT ON THE MOUNTAIN MAN 85 WESTERN ARCTIC MF - stope COAL_DEVELOPMENT PROJECT Thermocouple Placement on the Mountain Man 85 1-BLOWER INLET AIR 2-FRONT SURFACE 3-TOP SURFACE 4-STACK EXTERIOR 5-RH OUTLET 6-LH OUTLET 7-STACK ENTRANCE 8-STACK EXIT THERMOCOUPLE PLACEMENT ON THE HARMON MARK Ili STOVE QD _ STS, consultees, PROJECT Thermocouple Placement on the Harmon Mark Ill Stove Date: April , 1988 Fig. 3-l0 4.0 COAL FIELD GEOLOGY PROGRAM Index Paragraph Page 4.1 Introduction . 2 4.1.1 General . -4-2 4.1.2 Approach -4-2 4.2 Geology ... -4-3 4.3 Bulk Sampling . . -4-4 4.3.1 Test Pit 1 4-4 4.3.2 Test Pit 2 4-5 4.3.3 Test Pit3 . 4-7 4.3.4 Test Pit 1A. «4-7 4.3.5 Coal Samples -4-8 4.4 Definition Drilling .4-6 4.5 Rippability Study -4-9 4.6 Cratering Test... 4-13 4.7 Magnetometer Survey -4-16 Bg 4.8 Conclusions -4-18 4.9 Definitions -4-19 4.10 References . -4-23 Tables Number Page 4-1 Seismic Velocity Profile of Test Pitl]........... .4-11 4-2 Seismic Velocity Profile of Test Pit2... +5 se Gall 4-3 Dynamic Material Properties of Deadfall Syncline Rocks Based on Seismic Analysis ............ .4°12 i 4-4 Cratering Test Data. 5 6 6 ss ss ee ew we ws HDD Attachments Figure 4-1 Project Area Map Figure 4-2 Cross-Section of Test Pit 1, Seam DFS-4 Figure 4-3 Longitudinal Section of Test Pit 2, Seam DFS-2 Figure 4-4 Level Plan of Test Pit 2, Seam DFS-2 | Figure 4-5 1986 Drill Hole Location Map Figure 4-6 1987 Drill Hole Location Map Figure 4-7 Detailed Test Boring Locations Figure 4-8 Magnetometer Survey Location Map Figure 4-9 Detailed Magnetometer Survey Along Burn Areas of DFS-4 4.1 Introduction 4.1.1 General Geology along with coal quality, reserve size, and mine location make up the four factors which affect the economic value of a coal reserve. The aspects which are critical to coal field geology include: seam thickness and consistency, quantity and quality of overburden, coal partings, stability of material above and below the coal seam, water table, coal bed attitude, and the extent of ' faulting or fracturing to which the coal has been subjected. The purpose of the Coal Field Geology Program was to expand on the coal geologic database in areas of the selected mining block which were identified in WACDP Phase II as having very little previous information. The results of Phase III provide much of the needed specific data for a more complete evaluation of the q mining plan and design. The program involved field activities conducted during the summer and fall of both 1986 and 1987. 4.1.2 Approach The 1986 field program involved constructing a four tent camp at the Deadfall Syncline in early October. The project area showing the camp site, winter airstrip and test pit locations is i presented in Figure 4-1. The 1987 field program utilized the camp constructed the previous year for the 1986 program. All camp supplies and field equipment were provided and supervised by Howard Grey and Associates (HGA). Personnel from the North Slope Borough sponsored Western Arctic Coal Demonstration Project (NSB i CODEM) assisted HGA in performing the field tests in both years. Coal analyses were performed by the Mineral Industry Research i Laboratory (MIRL). The objectives of the 1986 WACDP field program included exploratory auger drilling, bulk sampling, fracturing test of the 4-2 overburden and analysis, rippability study, and a cratering test to ascertain various mine design parameters. The 1987 field program involved additional auger drilling a surface magnetometer survey. 4.2 Geology The geology of the Deadfall Syncline area has been described in previous 1984 and 1985 WACDP reports. Previous work as well as additional data from new field programs are presented in the following discussion. Coal seams within the project area are hosted by the Upper Cretaceous Corwin Formation of the Nanushuk Group. The Nanushuk Group is believed to represent a prograding deltaic depositional system which supplied the Colville Trough with detritus shed during the uplift of the ancestral Brooks Range. The low ratio of course to fine clastics suggests a low stream gradient and the low sulfur content of the coals suggests fresh water deposition. Callahan and Martin (1980) state that this may be the product of a wide band of low coastal marshes traversed by numerous’ streams. Subsequent regional deformation has created a series of broad synclines separated by narrow tightly folded east trending anticlines. These anticlines have been further obscured by high angle reverse faults and erosion. The 1987 project area is located along the north limb of the northeast trending doubly plunging Deadfall Syncline. Bedding dips are reported to range from 11 degrees to 24 degrees in the vicinity of Kuchiak Creek and Mormon Point respectively. Steeper dips of up to 46 degrees were encountered in test pits along the DFS-4 coal seam and the overall dip encountered during this years NSB CODEM Project was 25 degrees. The lithology of the project area includes sandstone, siltstone, sand siltstone, turbidites, claystone, coal and burned coal seams. Six coal seams ranging in thickness from 4.5 to 17 feet were identified in the project area during previous WACDP projects. Several other seams have been identified within the project area but lack of data prevents inclusion of these into present reserves. 4.3 Bulk Sampling As part of the 1986 NSB CODEM project, approximately a 100 ton bulk sample of coal was excavated from one of four seams located along the northeastern side of the Deadfall Syncline. An additional three test pits were completed for the WACDP project. Thirty pound coal samples from each of the four test pits were sent to the MIRL for analysis. The test pits were completed to depths ranging from 3 feet to 17.5 feet. Test pit locations are shown in Figure 4-1. 4.3.1 Test Pit 1 Test Pit 1 was located approximately 350 feet northeast of the camp on coal seam DFS-4. Excavation began October 30 and was terminated on November 20, at a depth of approximately 15 feet. Coal was not intercepted and drilling indicated that a minimum of 6 feet of overburden concealed the estimated 12 foot thick coal seam. Due to the apparent depth of the coal and time constraints, it was judged unsafe and impractical under the prevailing conditions to excavate any deeper. The geology and lithology of bedrock exposed in Test Pit 1 is presented in Figure 4-2. It is important to note that bedding orientation was difficult to ascertain due to crossbedding. However, seam DFS-4 may dip somewhat steeper than the anticipated 22 degrees. This may impact surface mineable coal reserves. A gasoline powered breaker/rock drill was used in the breaker mode to excavate an 8 by 8 foot shaft through frozen soi] and colluvium comprising the upper 6 feet of overburden. The unit doubled as a rock drill capable of drilling blastholes up to 6 feet in depth 4-4 “ for conventional mining of rock overburden. A gas powered 8" ventilation fan and a 12" electric ventilation fan were both used to remove dust and fumes during drilling and excavation. In order to facilitate all-weather operations, a moveable shelter was constructed over the test pits. A visqueen covered quonset hut frame was erected over two 5 by 20 foot long sleds spaced 6 feet apart. Part of the floor was covered with heavy timber decking and ahead frame was constructed for hoisting coal and waste rock. A sinking bucket was: also fabricated on site to assist mucking operations. The shelter, affectionately termede the "cathedral" or visqueen palace", was moved during near surface blasts and between test pits by the larger Pac Trac. Winter operations would have been impossible without this shelter. 4.3.2 Test Pit 2 The second test pit, located approximately 1/4 mile south of the camp on seam DFS-2, was begun on November 4. A pattern of 17 blastholes was drilled to a depth of 8 feet within an 8 foot square area. The holes were loaded and blasted with good results. Little flyrock was produced and good breakage was achieved to a depth of 8 feet. Mucking operations were carried out concurrent with the excavation of Test Pit 1. However, personnel constraints severely limited the ability to field two crews. Excavation continued after the abandonment of Test Pit 1, after which the shelter was moved to Test Pit 2. A 12 inch thick layer of coal was intercepted at a depth of 10 feet. The thin seam was separated from the underlying 7.1 ft. thick coal by an 8 to 18 inch thick layer of coaly claystone or "bone", see Figure 4-3. Excavation to the base of the lower coal seam was conducted using the Wacker BHB-25 in the breaker mode. The vertical portion of the test pit was completed to a depth of 17.5 feet on December 4, 1986. Two exploration drifts were driven simultaneously east and west along strike, in the lower coal seam. When completed, these 4-5 drifts were 16 feet and 21 feet long respectively and varied from 5 to 10 feet in width. Structural geology and the drift configuration are illustrated by Figure 4-4. Blastholes were drilled to a depth of 3 feet using an electric auger. A standard V-cut drift round was used with good reliability and a powder factor of 4.5 to 5.5 pounds per ton was maintained. Coal blasted in this manner was somewhat finer than desired and was visually estimated at 80% passing 1 inch. In an effort to increase the particle size of the blasted coal, hole spacing was increased from the standard 2.5 feet to about 3 feet. This resulted in a sprung round which required re-drilling and blasting. Once drifting exposed sufficient coal in the rib, three hole and four hole slashes were used to expand the drift. Because the coal is less confined during a slash, particle size increased to approximately 30 to 40% plus 1 inch and the powder factor was reduced to approximately 3 pounds per ton. Future bulk sampling operations should maximize the use of wall slashes and narrow drifts. The coaly claystone parting overlying the coal separated easily from the coal and formed a smooth but undulating back or roof surface. Although this unit appeared competent, when samples were allowed to thaw they decomposed to a soft moist clayey gravel in which the clasts consisted of coaly claystone. This unit formed slabs in drift areas over 5 feet wide which failed shortly after blasting. Timbering will be required in drifts wider than 5 feet. The condition of this unit and the fine grain size of the coal may indicate periodic frost riving and weathering during warm cycles in the climate. A total of approximately 1360 bags of coal each weighing approximately 147 pounds were taken from Test Pit 2 for the NSB CODEM Project. Size gradation curves for three coal samples taken from Test Pit 2 are included in Appendix C-1. Sampling operations were completed on December 19. The shelter was left covering the test pit to restrict access by animals or people. 4.3.3 Test Pit 3 Exploratory drilling identified a near surface coal subcrop on seam DFS-1, located about 1/2 mile south of camp. On November 21, a two man crew began drilling blastholes to a depth of 6 feet using the Ambler drill rig. Initial blasting was completed on the 23rd and was followed by additional drilling and a secondary blast on December 5. The pit was completely mucked out to a_ depth of 6 feet on the same day. Test Pit 3 was completed as of December 10. Coal present from 4 to 6 feet appeared weathered and subsequent drilling intercepted only weathered coal. It appears that DFS-1 coal has deteriorated due to near surface weathering and frost riving. Coal quality will improve with depth as indicated by core drilling conducted under the 1984 WACDP Phase I field program. A 30 pound bulk sample of coal was taken for analysis from drill cuttings and the pit walls and sent to MIRL for analysis. 4.3.4 Test Pit 1A Drilling located an alternate bulk sample site on seam DFS 4, approximately 50 feet northeast of Test Pit 1. On December 9, a seventeen hole pattern identical to that used successfully at Test Pit 2 was blasted. In order to improve breakage, the center four holes were deck loaded and the charge was increased by 33 percent. Breakage was poor below a depth of 3 feet because a dud cap failed to detonate in sequence. Crew constraints and the probable low quality of this near surface coal forced the abandonment of Test Pit 1A on December 10. Test Pit 1A was completed within surficial colluvium. Backfilling and reclamation will be completed in the following summer or fall. 4.3.5 Coal Samples In addition to a 100 ton bulk sample of coal stockpiled adjacent to Test Pit 2, other samples were taken for reference and laboratory analysis. A list of all samples, collected, during the 1986 and 1987 field programs, including auger, channel, chip, and hand samples and their analyses are presented in Appendix C- 2\ Samples of coal and country rock were collected for future trace element analysis. Large specimens of coal and sandstone were retained for density determinations and possible drillability studies. Other samples of bagged coal were retained for sieve analysis and future reference. Laboratory results are summarized in Appendix C-1. 4.4 Definition Drilling In 1986, a total of 25 exploratory drill holes, 67 blastholes and approximately 6 tie down holes were drilled using a 3.5 inch diameter solid flight auger and shelby tubes. The locations of all exploratory borings are identified by Figure 4-5. The 1987 program involved additional test hole drilling conducted from July 30, through August 2, 1987. A total of 37 exploratory drill holes were completed using the 3.5 inch solid flight auger, and depths ranged from 4.5 feet to 22.5 feet. The test holes were located along 3 coal seams identified as DFS-4, DFS-3, and DFS-2. The location of the test borings are identified on Figure 4-6. Where numerous holes are drilled adjacent to each other only one location is shown. Detailed locations of test hole clusters are shown on Figure 4-7. A total of 14 auger samples of the coal were retrieved during the drilling program. Bore hole logs were prepared for all 62 exploratory borings performed during 1986 and 1987 and are presented in Appendix C-3. All holes were completed with a gasoline powered hydraulic drill mounted on a Pac Trac 3400 tracked carrier. Exploratory borings were backfilled with auger cuttings. 4.5 Rippability Study A rippability study was carried out during the latter part of the field program. This study provides baseline data for the evaluation of ripping as an alternative to blasting overburden during stripping operations. Production ripping is becoming increasingly popular as a cost effective method of excavation for small mines. Conventional ripping relies on the drawbar pull, weight, and traction of a tractor to force a rear mounted ripping tooth through rock and soil. Experience has shown ripping to be cost effective in areas of overconsolidated soils and weak, weathered, fractured and/or highly stratified bedrock. Technological advances such as heavier and more powerful tractors and stronger more wear-resistant materials have broadened ripping applications. The rippability of a given area is ideally determined by putting a ripping tractor on the site and measuring productivity. Since this is often impractical, guidelines have been developed for estimating rippability based on the seismic velocity and physical characteristics of the ground. It is cautioned that determining rippability is something of an art and is usually based on local experience. Obtaining an accurate estimate from seismic data and field observations is difficult at best. A rippability study was undertaken in early December. Seismic velocities were estimated using a Bison Geopro 8012A engineering seismograph. A twelve geophone array was placed at varying intervals in the east and south walls of Test Pit 1. Approximate one-half pound charges of Thermex T-100 were placed in shallow auger holes at distances of 250 and 1000 feet east of the test pit. The charges were 4-9 initiated with DuPont "SSS" seismograph electric blasting caps. An array of eight geophones were also set in the floor, north wall and east wall of Test Pit 2. The procedure differed from that outlined above only in that all trials were conducted at a distance of 250 feet and a one pound charge was utilized in one case. Data reduction was carried out in Anchorage at the close of the field program. Arrival times were identified for both the P-wave (compressional) and S-wave (shear) on each seismogram and velocities were calculated. In general, the seismic velocities appear to correlate well with text book velocity ranges. As with most geophysical data, there is a certain level of ambiguity inherent in seismic data. It is difficult to distinguish between the four different wave forms generated by a source and the problem is further complicated by the fact that each wave may arrive by up to three different paths, discounting multiples and other reflection events. Hence, one seismic event can result in over a dozen different wave forms, the sum of which is recorded at the geophone. Seismic velocities were estimated from the waveforms and relative arrival times. Seismic velocities are summarized in Table 4-1 and Table 4-2. 4 = 10 TABLE 4-1 Seismic Velocity Profile of Test Pit 1 P-Wave Velocity S-Wave Velocity Depth Material @ 250' ~@ 1000' @ 250' ~—@ 1000' Surface Topsoil and Scree 6168 7628 3411 3618 1.25 Colluvium 6427 7513 3401 3646 2.25 Colluvium 6158 7452 3294 3814 S.75 Colluvium 5910 7513 3222 3672 o.29 Weathered Coaly Silt-Stone 5995 7628 3177 3618 6.67 *Coaly Sandstone 6158 7289 3356 3348 6.75 Sandstone 5882 7570 3177 3713 8.25 Sandstone 5952 7452 3213 3729 9.75 Siltstone 6024 7289 aoe ———— 9.58 *Gravelly Coaly Siltstone 6158 7128 3294 3359 11.25 Conglomerate 6510 7289 3356 3592 11.00 *Conglomerate 6297 7236 3420 3490 *Geophone placed on south wall of Test Pit 1. TABLE 4-2 Seismic Velocity Profile of Test Pit 2 P-Wave Velocity S-Wave Velocity Depth Material @ 250' ft/sec @ 250' ft/sec 2 Colluvium 6127-7353 2884-4448 5" Colluvium 6086-7246 2800-4448 10' Siltstone 6158-7143 2762-4343 11' Coal 6158-7246 2733-4266 13.5' Coaly Claystone 6015-7246 2933-4307 14' *Coal 5947-7297 3143-4671 14' Coal 6158-7246 2853-4296 18.5! *Siltstone 6157-7297 3098-3891 *Geophones placed at 270 ft. from source. 4-11 Since both P- and S-wave velocities were identified, it was possible to calculate the dynamic material cannot be static properties of Dynamic properties of these materials. It overemphasized that the relationship between the dynamic and material in properties situ than their static counterparts. This rock and soil poorly understood. are generally significantly more extreme is attributed to the extremely short period of stress and small displacements experienced during a seismic event. Therefore, the dynamic material properties should not be relied upon as design criteria. The dynamic material properties calculated from the seismic velocities are presented as Table 4-3. TABLE 4-3 Dynamic Material Properties of Deadfall Syncline Rocks Based on Seismic Analysis Dynamic Dynamic Dynamic Dynamic Assumed Poisson's Modulus of Young's Bulk Material Density Ratio Rigidity Modulus Modulus d Tei oa a “a lbs/cu.ft. x10® psi x10° psi x10° psi x10° psi Colluvium 96 - 289 8.4 21.7 17.1 Siltstone 151 - 304 12.3 32.1 2iaa Sandstone 145 -292 10.6 27.4 22.0 Coal 81 -283 7.6 19.5 15.0 Conglomerate 150 305 12.0 31.3 26.8 Claystone 151 Prd) 14.3 36.8 2o.5 Note: Epon Ug = Ve 5-2 Zp ne ete Ve Ga=dvV, ? Ea = 2 Ga (1 - ua) ck -1 ka = 9S Es ( 1 - 2 wa) where V, = P-Wave velocity V. = S-Wave velocity d = material density 4 - 12 Based soley on the data presented in Tables 4-1 and 4-2, it would appear that all of the material encountered during the seismic survey would be considered marginally rippable by conventional methods according to the classification scheme compiled by Caterpillar Tractor Co. If the degree of weathering, moderate jointing and variable bedding thickness of the bedrock are considered, then a similar conclusion may be reached. However, the frozen nature of the colluvium and weathered bedrock may prove unfeasible to rip. In addition to increasing the strength of the ground, ice decreases the traction afforded a tractor. Furthermore, it should be remembered that the near surface seismic velocities determined by this study may be significantly lower than those of deeper less weathered rocks. In conclusion, the colluvium and bedrock exposed in Test Pits 1 and 2 appear marginally rippable. If these units are allowed to thaw prior to or in conjunction with ripping, then better results may be attained. However, as the excavation moves downslope away from the well drained ridgelines, the increased ice content and deeper weathering profile may discourage ripping. Furthermore, it is quite likely that less weathered bedrock encountered at depth will prove unrippable. 4.6 Cratering Test A cratering test is usually performed in operating mines or pilot operations to determine the blasting characteristics of the rock. The results of a cratering test are used to evaluate various explosives and ultimately in the design of blasthole patterns. The cratering test involves observing the effects of a given weight of explosives at various depths of burial. Based ona_ series of these tests, the depth at which the charge fails to break rock or Critical Depth and the depth at which the charge breaks the maximum volume of rock or Optimum Depth are determined. The ratio of the Optimum Depth to the Critical Depth is termed the Optimum Depth Ratio. 4-13 Practical application of this data is possible through the Weight Crater Method, expressed as follows: distance Optimum Depth Ratio X E Distance refers to the number of feet from the center of gravity of the charge. E is the strain energy factor for the given explosive. E is defined as the ratio of the Critical Depth to the cube root of the weight of explosives used. W is the weight in pounds of the charge required to break the burden when the burden equals the depth to the center of gravity of the charge. Based on this relationship, the diameter and spacing of boreholes necessary to insure breakage may be determined. Since the test was conducted under winter conditions and no areas of shallow colluvium were identified by drilling, colluvium was not removed. Therefore, the results of this test are applicable only to frozen colluvium. Five trials were conducted approximately 1000 feet east of Test Pit 1. Three additional trials were conducted about 250 feet east of Test Pit 2. Single cartridges of Thermex T-100 weighing approximately 0.5 pounds were used as the standard charge throughcut this. Boreholes were drilled to various depths using a 3.5 inch diameter solid flight auger. Holes were backfilled and carefully tamped with cuttings. The data and results are summarized by Table 4-4. 4- 14 TABLE 4-4 Cratering Test Data Depth to Charge Trial Center of Gravity Approximate Volume Broken A-1 4.7 feet 1.92 cubic feet A-2 ed | |) 4.71 cubic feet A-3 38/0.) |" No Surface Disturbance A-4 61.0 |||" No Surface Disturbance A-5 36/7 No Surface Disturbance B-1 ahi) 7 2.78 cubic feet B-2 2.7 ||" 0.18 cubic feet B-3 See ||| No Surface Disturbance The wide range of data reflects the relative inhomogeneity of the frozen colluvium. However, it would appear that the Critical Depth may be estimated at 3.0 feet and the Optimum Depth at 1.7 feet. Therefore, the Optimum Depth Ratio for Thermex T-100 in frozen colluvium is on the order of 0.57 and the Strain Energy Factor is 3.78. This may be compared to the performance of a slurry explosive in an iron formation which had an Optimum Depth Ratio of 0.525 and a Strain Energy Factor of 4.26. Blasthole spacings may be solved iteratively using the Weight Crater Methods in which burden is approximated by the distance term and the weight of explosives necessary to break various burdens is calculated. It must be emphasized that these results are valid only for Thermex T-100 in frozen colluvium. Appendix D summarizes the characteristics of Thermex T-100 for purposes of comparison with other blasting materials. Future cratering tests may establish blasting parameters for the various rock types comprising overburden and coal utilizing various explosives. The depth of colluvium which approaches 6 feet on the ridgelines and the greater depth of weathering will complicate such tests. Surfacial soil, colluvium and weathered rock will have to be 4 = |15; stripped from the test area. This will require the use of heavy equipment and should probably be conducted during the early phases of mining. 4.7 Magnetometer Survey The surface magnetometer’ survey was performed along the three main ridges within the project area (DFS-2, DFS-3, and DFS-4). Two lines were traversed along each ridge, approximately 100 ft. apart, with readings taken every 50 ft. Previous magnetometer studies during the 1985 field season were performed perpendicular to the strike orientation of the bedrock outcrops. Information obtained through the magnetometer field work portion of the 1985 field program indicated a strong magnetic anomaly in conjunction with known burn occurances. In order to best expand upon this information, the magnetometer lines for 1987 were performed parallel to strike orientation focusing primarily along the exposed ridge surfaces. In the area of the known burn rock outcrop on DFS-3, a strong magnetic anomaly was once again. observed. Another large anomaly was observed along the DFS-4 ridge, slightly west of the camp location. No other Magnetic anomalies were observed along DFS-4. The initial magnetometer lines when plotted showed a very strong, positive anomaly approximately 2,000 feet in length. In order to accurately delineate the north and south extent of this anomaly, seven additional magnetometer lines were performed. In this area the lines were spaced approximately 50 feet apart with measurements taken at intervals of 50 feet. The magnetometer survey was performed with an E.G. & G. geometrics 856 magnetometer. This is a proton precision magnetometer which uses a coil to polarize the spinning protons in a hydrocarbon fluid. On release from the polarizing field, the protons precess to the ambient field, and in doing so generate a signal which is received by a coil. The frequency of this signal is proportional to the total field intensity and independent of the sensor orientation. This magnetometer 4 = 16 features an eight bit microprocessor which records field data, but does not correct for diurnal variation. Because of the constantly shifting nature of the earths magnetic field, data collected through a magnetometer survey must normally be corrected for a diurnal drift. The E.G. & G unit which was used for this survey does not automatically correct for drift; however, due to the large magnetic anomalies associated with the burned coal seams and the considerable time required for manual data reduction, only magnetic data with diurnal drift greater than 20 gammas was corrected. The magnetometer information has been plotted at a vertical scale of 1 inch equals 200 gammas and a horizontal scale of 1 inch equals 500 feet. A profile of each line is presented in Appendix C-4. Identification and locations of the magnetometer lines are shown on Figure 4-8. The magnetic profiles which were developed through this magnetometer survey appear homogeneous over most of the project area. With the exception of DFS-4, all data accumulated this season confirms data that was obtained during previous field seasons. A local anomaly in excess of 1,000 gammas was found in the area of the burn rock along DFS-3. An area along DFS-4 slightly west of camp and extending approximately 2,000 feet in an east/west direction and approximately 300 feet ina north/south direction was also found to have an anomaly of approximately 1,000 gammas. This site had previously been identified as having a anomaly but the magnitude was unknown. A detailed map of a magnetometer survey in this area is presented as Figure 4-9. We believe that this magnetic anomaly is associated with the burn rock as observed in DFS-3. The size and shape of the anomaly is similar to that which was observed previously. Although no burn rock has been observed in this area, additional drilling should be performed in the near future to attempt a correlation to the features which this survey has delineated. 4-17 4.8 Conclusions Sample locations were chosen on the basis of time constraints and drill hole information. Bulk samples should be taken as close to the camp as possible. Based on conditions observed in the 1986 test pits, it is suggested that coal seams be sampled at a depth of about 20 feet. This should eliminate most weathering problems such as frost riven coal and will yield a more competent roof for exploratory drifts. The explosives used during this project were chosen because of their ease of transport, storage and handling. It is possible that different explosives may perform better in coal. However, such explosives may require special storage magazines and transportation. The use and cost of alternate explosives must be closely examined. In accordance with the guidelines of Coal Exploration Permit No. 03-84- 795 issued by the Alaska Department of Natural Resources, all waste rock was stockpiled on visqueen sheets to protect the ground surface. ‘This was a safety hazard during winter operations because even light snow cover reduced traction on the covered ground to near zero. This caused several falls, but luckily no injuries resulted. 4 - 18 4.9 10. a 2s 13. Definitions Assumed Density: For calculation purposes in determining the dynamic bulk moduli, it was necessary to assume densities for a variety of rock types based on text book values. Density is defined as the mass per unit volume and is presented as pounds per cubic foot. Auger Drilling: A method of boring exploratory holes which utilizes an unshielded steel spiral wrapped around a_ shaft with a cutting bit to carry away drill cuttings. Back: An underground mining term which refers to the roof of an underground opening. Bedding Orientation: The directional trend and slope of a former plane of, in this case, sedimentary deposition. Bedding orientation is usually described in terms of strike and dip where strike refers to the bearing of a horizontal line within the bedding plane. Dip is the vertical angle between a horizontal plane and a bedding plane measured perpendicular to the strike. Blastholes: Holes drilled to allow the placement of explosives during blasting operations. Blasthole patterns: Various configurations or arrangements of blastholes designed to achieve a variety of objectives. Critical Depth: With respect to a cratering test, the depth at which an explosive charge of a _ given weight produces no significant surface disturbance on detonation. Clast: An individual constituent, grain or fragment of a sediment or rock. Claystone: A sedimentary rock composed’ primarily of clay particles, that is rock or mineral fragments less than 4 microns in diameter. Colluvium: A general term applied to loose, heterogeneous soil deposited on or at the base of a slope. Competent: With respect to rock, a volume of rock that is capable of withstanding a given stress regime without undue deformation. Conglomerate: A sedimentary rock composed of rounded to subangular clasts greater than 2mm in diameter set in a fine grained matrix of sand silt and/or clay. Conventional mining: The most common method of advancing a tunnel in rock. which consists of three phases: drilling blastholes, blasting, and mucking or removal of the blasted rock. 4/19 14. 15. 16. Ls 18. 19. 20. 21. 22: 23. 24. 25. 26. 27. Core drilling: A method of drilling exploratory holes which utilizes a diamond’ encrusted cylindrical bit to retrieve cylindrical core samples of rock. Country rock: The rock enclosing a mineral deposit. Cratering test: A test which determines basic parameters for blasthole pattern design based on the performance of a given weight of explosives at various depths of burial. Cross bedding: A sedimentary feature of clastic rocks which is caused by the deposition of sediments in beds which are included at an angle to the main planes of stratification. Deconvolution: A data processing technique applied to seismic data which attempts to restore a wave shape to the form it is assumed to have had prior to a filtering event or convolution. Drawbar pull: The maximum horizontal force a given piece of heavy equipment can operate against. Drawbar pull is a product of horsepower, equipment speed, traction, and gear ratios. Drift: A nearly horizontal underground opening driven parallel to the prevailing strike of the enclosing rock or _ predominant geologic structure. Dynamic Bulk Modulus: A modulus of elasticity which relates a change in volume to the hydrodynamic state of stress. Dynamic material properties: The physical properties exhibited by materials under varying conditions of stress after relatively short periods of time. Dynamic Modulus of Rigidity: A measure of the ability of a material to resist deformation while undergoing changes in the prevailing stresses. Dynamic Poisson's Ratio: The ratio of lateral unit strain to the longitudinal unit strain in a body that has been subjected to dynamic stresses longitudinally and within its elastic limit. Dynamic Young's Modulus: A modulus of elasticity which relates the change in length of material to the change in dynamic stress, either tensile or compressive, along its length. Geophone: A seismic detector that produces a voltage proportional to the displacement, velocity or acceleration of ground motion, within a limited frequency range. Headframe: A structure erected over an excavation that facilitates the transfer of men, equipment and/or materials from the bottom of the excavation to the ground surface. 4 - 20 28. 29. 30. Si. 32 336 34. Sor 36. Sc 385 39. 40. 41. 42. 43. Impact ripper: A rear mounted attachment to a tractor which is used to break and loosen soil or rock prior to excavation. The impact ripper differs from a conventional ripper in that a hydraulic hammer drives the ripping tooth which’ improves performance Inhomogeneity: Used in reference to the highly variable nature of the physical characteristics of a frozen colluvial soil. Joint: A surface of fracture or parting in a_ rock without displacement. Jointing: The condition or presence of joints in a body of rock. Lithology: In this report, the term refers to the suite of rocks encountered. Magnetometer survey: A surface geophysical method which measures changes in the earth's magnetic field over a study area. Mucking: The removal of broken rock during mining is termed mucking. Optimum Depth: In reference to a cratering test, the depth at whcih an explosive charge of given weight will produce the greatest breakage. Optimum Depth Ratio: In reference to a cratering test, the ratio of the Optimum Depth to the Critical Depth. This can be used to design blasthole patterns through application of the Weight Crater Method. Overburden: Country rock and soil overlying a mineral deposit. Overconsolidated: Greater than normal consolidation of sediments due to glacial overriding, former depth of burial or desiccation. Photgrammetric: Pertains to the methods by which reliable measurements are taken from photographs. P-Wave: Also called a compressional wave, this is a type of seismic body wave in which the direction of particle motion alternates parallel to the direction of propagation. Rib: In underground coal mining terminology, rib refers to any vertical or near vertical wall of an underground opening. Sandstone: A sedimentary rock which is composed primarily of rock or mineral particles ranging in size from 1/16 to 2 millimeters. Seismic velocities: The rate of propagation of a wave through the earth. : a2), 44. 45. 46. 47. 48. 49. 50. 5A. 52s 53). Seismogram: The record made by a seismograph, an instrument that detects and records vibrations in the earth. Siltstone: A sedimentary rock composed primarily of particles ranging in size from 4 to 62 microns. Sinking bucket: An underground mining term which refers toa cylindrical container used to remove waste rock during the mucking of vertical underground openings. Slash: An underground blasthole pattern used to expand an existing underground opening. The pattern consists of one or more rows of nearly parallel holes drilled at an angle to an existing face. Spoil: Waste material removed from an excavation. Static properties: Refers to the physical characteristics of materials under static or stable condition of stress. Strike: In reference to bedding orientation, the bearing of the line produced by the intersection of a non-horizontal bed with a horizontal plane. S-wave: Also called a shear wave, this is a type of seismic body wave in whcih particle motion oscillates in a direction perpendicular to the direction of wave propagation. V-cut drift round: A blasthole pattern used in a_ excavation of drifts. The pattern usually consists of two or four holes drilled at an angle from opposite sides toward the center of the face. These holes are blasted first and provide an open space. for other blastholes to break toward. Weight Crater Method: An algebraic relationship between the weight of an explosive charge, the burden distance, the Optimum Depth Ration and the strain energy factor for a given explosive. This method allows the direct application of cratering test results to bench blast design. 4 = 22 4.10 References Arctic Slope Consulting Engineers and Howard Grey & Associates, Inc., 1984, Western Arctic Coal Development Project: 1984 Pre- Development Site Investigation, 50 p., illus., tables, maps. Arctic Slope Consulting Engineers and others, 1986, Western Arctic Coal Development Project - Phase II Final Report, 2 vols., 620 p., illus., maps, tables. Arctic Slope Consulting Engineers and others, 1984, Western Arctic Coal Development Project: Preliminary Economic Evaluation - Phase I Final Report, 242 p., illus., tables, maps. Barnes, F.F., 1967, Coal Resources of Alaska: U.S. Geological Survey Bulletin 1242-B, pp. 831-836, illus., tables. Barnes, F.F., 1967, Coal Resources of the Cape Lisburne-Colville River Region, Alaska, in Contributions to Economic Geology, 1966, U.S. Geological Survey Bulletin 1242-E, pp. £1-E37, illus. tables, geol. map. 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Callahan, J.E. and Martin, G.C., 1980, Coal Occurrences of the Nanushuk Group, Western Arctic, Alaska (an update): Focus on Alaska's Coal "80, University of Alaska - Mineral Industry Research Laboratory Report 50. Callahan, J.E. and Others, 1969, Geology of T1S, R44W, Unsurveyed, Umiat Principal Meridian, in the Kukpowruk Coal Field, Alaska: U.S. Geological Survey Open File Report 378, 19 pp., tables, illus. : 4 = 23 Callahan, J.E. and Sloan, E.G., 1978, Preliminary Report on Analysis of Cretaceous Coals from Northwestern Alaska: U.S. Geological Survey Open File Report 78-319, 2 pp., 29 pp., illus., tables, maps. Callahan, J.E., 1971, Geology and Coal Resources of T6S, R51W, Unsurveyed Umiat Principal Meridian, in the Cape Beaufort Coal Field, Northwestern Alaska: U.S. Geological Survey Open File Report 496, 18 pp., illus. Chapman, R.M. and Sable, E.G., 1960, Geology of the Utukok-Corwin Region, Northwestern Alaska: U.S. Geological Survey Professional Paper 303-C, pp. 7-20, illus., tables, geol. map. Clark, P.R., 1973, Transportation Economics of Coal Resources of Northern Slope Coal Fields, Alaska: University of Alaska- Mineral Industry Research Laboratory Report 31, 134 pp., tables, (M.S. Thesis, University of Alaska). Collier, A.J., 1906, Geology and Coal Resources of the Cape Lisburne Region, Alaska: U.S. Geological Survey Bulletin 278, 54 pp., jillus., tables, geol. map. Cooper, H.M. and Others, 1946, Description of Mine Samples, in Analyses of Alaska Coal: U.S. Bureau of Mines Technical Paper 682, pp. 70- 110. Dames & Moore, 1980, Assessment of Coal Resources of Northwest Alaska Phase I, Vol. 1 - Task 2: Coal Resources of Northwest Alaska, prepared for Alaska Power Authority. Dames & Moore, 1980, Assessment of Coal Resources of Northwest Alaska Phase I, Vol. 1 - Task 1: Fuel Utilization in Northwest Alaska and Summary of Coal Resources, prepared for Alaska Power Authority, 15 pp., 1, 7, 8, 11. Gates, G.0., 1946, Coal Fields of Alaska, in Analyses of Alaska Coals: U.S. Bureau of Mines Technical Paper 682, pp. 1-9. Grant, Charles H., 1964, "Simplified Explanation of Crater Method" in Engineering & Mining Journal, Vol. 165, No. 11, pp. 86-89. Heiner, L.E. and Wolff, E.N., 1969, Mineral Resources of Northern Alaska, Final Report: University of Alaska - Mineral Industry Research Laboratory Report 16, pp. 3, 10, 21-22, 169, maps. Howard Grey & Associates, Inc., 1985, 1985 Western Arctic Coal Geophysical Program, 45 p., illus., tables, geol. map, appendices. Howard Grey & Associates, Inc., 1986, 1987 Western Arctic Coal Field Program Summary Report, 24 p., illus., tables, appendices. 4 - 24 Hunter, J.A., Burns, R.A., Good, R.L., MacAulay, H.A. and Gagne, R.M., 1982, Optimum Field Techniques for Bedrock Reflection Mapping with the Multichannel Engineering Seismograph; in Current Research, Part B., Geological Survey of Canada, Paper 82-1B, pp. 125-129. Kaiser Engineers, Inc., 1977, Technical and Economic Feasibility Surface Mining Coal Deposits North Slope of Alaska, Final Report: prepared for the U.S. Department of the Interior Bureau of Mines, 157 pp., map. Knutson, H.A., Geologic and Economic Evaluation of Bituminous Coal, Kukpowruk River Region, Northern Coal Field, Alaska: Focus on Alaska' Coal '80, University of Alaska - Mineral Industry Research Laboratory Report 47, pp. 67-69. Landers, W.S. and Others, 1963, Carbonization Study on Bituminous Coal from the Kukpowruk River Area, Alaska: U.S. Bureau of Mines Special Report D-189 Project w/o 63-211, 67 pp., illus., (U.S. Bureau of Mines - Juneau). Lynch, D.F. and Others, 1976, Constraints on the Development of Coal Mining in Arctic Alaska Based on Review of Eurasian Practices: U.S. Bureau of Mines Open File Report 41-78, 219 pp., (U.S. Bureau of Mines - Juneau). Merritt, R.D. and Hawley, C.C., 1986, Map of Alaska's Coal Resources: Alaska Department of Natural Resources - Division of Geological and Geophysical Surveys, Special Report No. 37, 1 sheet. Mooney, Harold M., 1984, Handbook of Engineering Geophysics, Vol. 1: Seismic, Bison Instruments, Inc., Minneapolis, Mn., 202 p. Paul, Jyot P., 1985, Pers. Comm. dated June 17. Summary of the results of laboratory testing of overburden samples from the Deadfall Syncline area, conducted at the University of Alaska - Mineral Industry Research Laboratory under the guidance of Dr. M. Sengupta, 39 p. Pollard, B., circa 1972, (Estimated Production Costs Associated with Mining and Marketing the Coal at Cape Beaufort, Alaska), (unpublished): unpaged. (U.S. Bureau of Mines - Juneau). Pool Engineering, Inc., 1985, Western Arctic Coal Development Project Preliminary REport Phase II - Task 4 Preliminary Mine Design, 83 p., illus., maps, tables. Rao, P.D., 1981, Alaska's Coal Resources and Research in Coal Development: (pre-prints): Resource Development and Engineering Conference, National Cheng Kung University, Tainan, Taiwan, R.0.C. Rao, P.D., 1975, Characterization of Alaska's Coals: Focus on Alaska's Coal 75, University of Alaska - Mineral Industry Research Laboratory Report 37, pp. 33-47. 4 - 25 Rao, P.D., 1968, Distribution of Certain Minor Elements in Alaskan Coals: University of Alaska - Mineral Industry Research Laboratory Report 15, 47 pp., tables. Rao, P.Das 1980, Petrographic, Mineralogical, and Chemical Characterization of Certain Arctic Alaskan Coals from the Cape Beaufort Region: University of Alaska - Mineral Industry Research Laboratory Report No. 44, 66 pp., tables, illus. Robertson Research (North America) Limited, 1977, Alaska, U.S.A.: An Evaluation of Coal Resources, 6 pp., tables. Sanders, R.B., (in press) Coal Resources of Alaska: Focus on Alaska's Coal '80, University of Alaska - Mineral Industry Research Laboratory Report 47. Schraeder, F.C., 1904, A Reconnaissance in Northern Alaska Across the Rocky Mountains to Cape Lisburne in 1901, with notes by W.J. Peters: U.S. Geological Survey Professional Paper 20, pp. 106- 114, geol. map. Smith, Peter J., 1973, Topics in Geophysics, MIT Press, Cambridge, 246 pp. Smith, P.S., 1962, Mineral Industry of Alaska, in Smith, P.S. and others, Mineral Resources of Alaska Report on Progress of Investigations in 1924: U.S. Geological Survey Bulletin 783, pp. 26-27. Smith, P.S. and Mertie, J.B., 1930, Geology and Mineral Resources of Northwestern Alaska: U.S. Geological Survey Bulletin 815, pp. 290-320, geol. map. Stricker, Gary D., and Roehler, H.W., 1980, Deltaic Coals and Sediments of the Cretaceous Torok, Kukpowruk, and Corwin Formations in the Kukolik-Utukok Region, National Petroleum. Telford, W.M., Geldart, L.P., Sheriff, R.E. and Keys, D.A., 1976, Applied Geophysics, Cambridge University Press, New York, 860 p. Thorne, R.L., 1969, Sampling and Coking Studies of Several Coal Beds in the Kokolik River, Kukpowruk River, and Cape Beaufort Areas of Arctic Northwestern Alaska, (unpublished): (U.S. Bureau of Mines - Juneau). Toegnes, A.L. and Jolley, T.R., 1947, Investigations of Coal Deposits for Local Use in the Arctic Regions of Alaska and Proposed Mine Development: U.S. Bureau of Mines Report of Investigations RI- 4150, 19 pp., illus., map. University of Alaska - Mineral Industry Research Laboratory, 1966 Annual Report of Research Progress: Report No. 7, pp. 4-5. 4 = 26) Wanek, A.A., and Callahan, J.E., 1968, Coal Reserves along Kukpowruk River in U.S. Geological Research 1968: U.S. Geological Survey Professional Paper 600-A, p. A39. Warfield, R.S., 1967, Resume of Information on Alaskan Bituminous Coals with Particular Emphasis on Coking Characteristics: U.S. Bureau of Mines Open File Report 11-67, 20 pp. Warefield, R.S., Sampling and Coking Studies of Several Coal Beds in the Kokokik River, Kukpowruk River, and Cape Beaufort Areas of Arctic Northwestern Alaska: U.S. Bureau of Mines Report of Investigations 7321, 58 pp., illus., tables. Witte, W.K., and Stone D.B., 1980, Paleography and Paleoclimate of the Arctic Alaskan Cretaceous Coals: Focus on Alaska's Coal '80, University of Alaska - Mineral Industry Research Laboratory Report 50, pp. 79-91. Wolff, E.N., and others, 1973, Optimum Transportation Systems to Serve the Mineral Industry North of the Yukon Basin, Alaska: University of Alaska - Mineral Industry Research Laboratory Report, 29 pp. 4 - 27 North Boundary Of Permit Area Y 2 —— y ee Winter ArSa~ Y 1 ' ' , Access jlo Winter Airstrip ‘ 3 1986 PROJECT TP-1A (3.0) TP-1 ( 15.0") ormon~ _ TP-2 (17.5) eS et te ee pa ee Pee con & “ d 2 & % Access Route C€unchanged) SCALE 0.5 BASE MAP ENLARGED FROM U.S.G.S. 1:63,360 SCALE POINT LAY A-3, A~4 QUADRANGLE LEGEND WESTERN ARCTIC COAL DEVELOPMENT A. TEST PIT LOCATION AND DEPTH ey PROJECT Me SCCAMP AREA PROJECT AREA MAP @ = CRATER TEST SITE Prepared by: Date: HOWARD GREY & eae eee Coal Exploration Permit No 03-84-795 ASSOCIATES, INC FIGURE 4-1) LOOKING EAST wary 1 5/8° diam. percussion borehole. usa tin <o Estimated depth ot coal seam DFS-4 ™~ ae SCALE 012 3 4 S feet Lactation! Surtace, dry rubbly sandstone ridge. Colluvium, brown, flat sandstone bouiders to 1° in brown sandy-clayey silt matrix. Rare ice lenses to 2° thick. Boulders imbricated near base and grade into bedrock. Silly sandstone, gray, coarse to medium grained, interbedded with detrital coal Coaly-silty sandstone, light gray to black, coarse sand, “Sandstone, gray, some silt, crossbedded. Rare ice veins to 1/2”. Coaly-silty conglomerate, grey, interfingered with Massive grey sandstone. Approximately 40% plus 44 gray chert clasts, rounded. Coal is thin crenulated partings and occasional irregular clasts. Siltstone, gray, massive, some cheri pebbles and some detriial Coal fragments. Sandy-silty conglomerate, gray, some detrital coal. Similar to above unit, but Yess coal. Siltstone, gray-brown with some chert pebbles. BEDDING ORIENTATION NBSOW 40SW N75W 46SW N75W 30SW N88W 28SW Due E 30S N8O0E 40SE N8OE 20SE NOTE: Location of measurements denoted by circled numerals. JOINTS N1OW 74SE 1/ft. N70OW 72NE 0.75/ft. One set parailel to bedding, Varies 0.5 to 12/ft. WESTERN ARCTIC QD). da DEVELOPMENT see = PROJECT CROSS-SECTION OF TEST PIT 1, SEAM DFS-4 Prepared by: Sater HOWARD GREY & LYAN, 1987 ASSOCIATES, ING. [FIGURE 4-2) LOOKING NORTH A’ Surface, dry rubbly sandstone ridge. ‘Colluvium, brown, flat sandstone boulders to 1’ >in brown sandy clayey silt matrix, Weathered sandstone, tan to buff, cross-bedded, soft, Weather Sandy siltstane, hard, tan to varigated, some iron oxide staining. Colluvium, weathered brown to grey siltstone, in dark brown clayey silt mavix with some ice. Some etrital coal. ST Slog. Grey. soft, separates easily from coal. ‘oal, on varies from dull, soft and weathered to sh hard and unweathered ee | Coaly claystone, brown to greenish grey with Coal, black, dull to shiny, hard and apparently abundant coal partings. Appears sheared with unweathered but highly jointed. Moderately | abundant curved slickensides. Irregular contact frequent white to gray clay partings to 0.25" surfaces, but separates easily from coal. thick, but typically less than 0.1", Locally Appears competent, but forms slabs and abundant yellowish-orange stains of fracture decomposes when thawed. Coatings on joint surfaces, = SSNS LS SSS slightly curved joints. WESTERN ARCTIC Q2. coat DEVELOPMENT Seay == PROJECT LONGITUDINAL SECTION OF TEST PIT 2, SEAM DFS-2 Prepared by Date: HOWARD GREY & [YAN 1987 ASSOCIATES, INC. |FIGURE 4-3] LEGEND Coal thickness exposed in excavation in feet, wre Ke Ww 28 Sw 3 Milage coat or joint set with strike, dip and frequency as fractures per foot. ~e Measured true thickness of coal in feet. Bedding orientathon, strike approximate ti Cross section location. typically less than total thickness of seam. SCALE 0 1 2 3 4 5 FEET on Coal pillar highly fractured by blasting WESTERN ARCTIC Ge eps COAL DEVELOPMENT Sonne =| PROJECT LEVEL PLAN OF TEST PIT 2, SEAM DFS-2 Prepared by Date: HOWARD Grey & [YAN. 1987 ASSOCIATES, INC 1986 PRO ie AREA BOUNDARY SCALE 0 500 1000 feet a! LEGEND CAMP BOREHOLE LOCATION SECTION 16 BASE MAP ENLARGED FROM U.S.G.S. 1:63,360 SCALE POINT LAY QUADRANGLE WESTERN ARCTIC «COAL DEVELOPMENT Sgr PROJECT 1986 DRILL HOLE LOCATION MAP HOWARD GREY & [YAN. 1987 ASSOCIATES, INC. |FIG 4-5 0 Le 7 0 1/4 1/2 3/4 1 MILE 6 7000 2000 3000 4000 5000 FEET fab) CO, beve: bPlaecr a 32 i= PROJECT a . 1987 TEST BORING NUMBERS AND LOCATIONS DRILL HOLE (see figure 3 for detailed locations) : LOCATION MAP Precerec by: Date: HOWARD GREY & | FEB., 1988 ASSOC., INC. |FIG 4-6 87-9 7-1 2 87-11 87-10@ 87-4 I 87-120) SCALE Sa 5 1=10 10° 87-17 @ sr-20 ba7-23 { : vi 12! 6 87-21 Os7-24 10’ | 87-18 ©87-15 ? 87-30 i 87-32 © 7-34 f 87-36 10° 10° 10’ 10 Ld os b oo 4 DETAILED TEST BORING LOCATIONS FIGURE 4-7 HOWARD GREY AND ASSOCIATES, INC FEBRUARY, 1988 FIGURE 5 DETAILED MAGNETOMETER SURVEY ALONG BURN AREA OF DFS-4 ISOPACH CONTOUR INTERVAL: 200 GAMMAS DATUM REFERENCE: 70*57000 GAMMAS, ETC. MAGNETOMETER LINES: —150S INSTRUMENT: EG&G 856 =—101N 1800 ft 2000 tt. o 500 ft. 1000 ft, HOWARD GREY AND ASSOCIATES , INC. FEBRUARY, 1988 FIGURE 4-9 uz 1 mt y LE J 2000 3000 5000 FEET as COAL DEVELOPMENT PROJECT WESTERN ARCTIC MAGNETOMETER SURVEY AREA OF DETAILED MAGNETOMETER SURVEY SEE FIGURE 5 LOCATION MAP | Prepared by: Oate: HOWARD GREY & LFEB., 1988 ASSOC., INC. {FIG 4-8 5a1 52 523 Sof ei n eid ae 3 RNNNaERERS aie a4 2S 4 ners oe per copes ie eee POINT O'OIN tio: PPP Ls oO > uo Sais $ p> Qin 5.0 MINE ENGINEERING ANALYSIS Index roduction.... General... Sources of Information Limitations of Study e Survey General . . . Approach sip | ele elke lala Assimptions). =|. «| sis sais gle a |e i Results, 2 iaic is|e g| ala mldle ow lale | a S.t.49 08 Topographic en ee 5.2.4.2 Location Survey ....... : 5.2.4.3 Air Photo Control Panels... . II Mine Plan Revisions ........ General ..... ae wl ke wee le Mining Costs. 5. «|: « a eee ee Coal Reserves . . Aen Ton Per Year Production Rate <= eis General joie be) ale «| Appreeehn cc ek Assumptions ot el tele st le Mining Plan ..... 2.2... 5.4.4.1 Equipment nie miele ining COSts: i) a iz &) oe) 6 | lela! am |al @ 4. Jf “4. A n «#5. Approach. ae | lo ele le el 4. 4. 4.5 Reclamation .. 2... 68 sss n 52 BMAZaIon ore olligon Coal Transport Option... . Alternate Mining Sites ........ GIUSIONS) 2 (5) 3 5 je) = \- 4.2 Stripping and Mining. Plan : : : , i 3 Labor Requirements and Schedule . 4 Reserve Analysis ........ ‘4.5.2 Cost Analysis. ......... SGU CE UOC OTL oe O01 01 OF 07 07 07 OF OF 07 OF U7 07 07 OF OF OF OF 01 O01 OT 1 PWWWWWNMNYNNMAYDNR RRR RRR Re é ADOAWDOODNPODDDANDANKFOCOCOWOAYDUUNSP HWW Tables Mormon West Control Point Data . Air Photo Control Panel Locations. Reserve Summary, Mormon West Block . Calculation Variables Mining Equipment List Reserve Summary Minimum Recovery Case Reserve Summary Maximum Recovery Case . | be ie Reclamation Bond Amount Computation Hourly Crew Cost Summary . . Average Productivity Summary . Miscellaneous Annual Costs : 20,000 Ton Per Year Production Rate . Annual Stripping Cost 20,000 Ton Per Year Production Rate . Annual Coal Mining/Hauling Cost 20,000 Ton Per Year Production Rate . Cost Summary 20,000 Ton Per Year Production Rate . Attachments 5-1 Surface Feature Locations, Mormon West Block i-2 Stripping Ratio vs. Tons 5-3 Typical Section 5-4 Typical Section, Stripping Plan 5-5 Annual Schedule, 20,000 TPY Rate 5-6 Mining Areas oO 1 nN 5.1 Introduction 5.1.1 General The goal of the Mine Engineering task is to gather engineering data from the mining area in detail sufficient for permitting and design, evaluate the effects of the new data on the preliminary mining plan completed in WACDP Phase II, and prepare a preliminary mining plan for the reduced production scenario of 20,000 tpy. The purpose of these tasks is to provide the detail and level of confidence required to advance the project to market procurement and permitting phases of project development. The Mine Engineering task addresses only those project components associated with the physical extraction of the coal and transportation of the coal to the coal loading facility at the port site. Following is a general description of the basic subtasks which were performed and addressed in detail in the respective subsections of this section of the report. © Site Survey This included performance of a radial topographic survey of the mining area and location of surface features in the mine area. ° Mine Plan Revisions This included revisions to the WACDP Phase II mine plan that are indicated by new data gathered during the Phase III program. © Lower Production Mine Plan This included performing a preliminary mine design and cost estimate for a base production level of 20,000 tons per year. 5.1.2 Sources of Information Whenever appropriate, the WACDP Phase II Preliminary Mine Design Technical Memorandum was used as the source for design and cost information. New information gathered from the field work under Phase III of the WACDP and the North Slope Borough (NSB) Coal Demonstration Project (CODEM) was incorporated into the overall information base and used to modify Phase II analyses, as dictated by the new information. Geologic information was obtained from prior WACDP exploration programs, the ongoing WACDP and CODEM programs and various other past geologic programs. Specific information sources for the subtasks addressed in this section are identified in their respective subsection. 5.1.3 Limitations of Study As with the Phase II report, the new analyses contained in this report and the modifications to the Phase II studies should not be regarded as an operational plan, but only as a feasibility study. Certain aspects of the project database have been upgraded to the point required for detailed design, but gaps still remain. The information available is sufficiently reliable to perform a feasibility study and proceed with permitting, but not completed in sufficient detail in all areas to enable detailed design of the mining operation. As with the Phase II study, accuracy of computations in this report should be considered as no more than two significant digits. ~ 5.2 Site Survey 5.2.1 General One area of inadequate data for detailed design has been the lack of detailed topographic information for the mine site. Published data from the U.S. Geological Survey and the limited topographic data obtained in the Phase II site survey give only a general picture of the topography at the selected mine site. Since the entire Deadfall Syncline was under consideration for mining at the time of the Phase II site survey, the area was too large for detailed topographic surveys by surface methods and aerial photogrammetric mapping was beyond the scope of the study. Therefore, since the area of interest for the mining project has been narrowed to about one square mile, known as the Mormon West mining unit, detailed surface topography could be obtained ata reasonable cost. In addition to obtaining topographic information, the site survey was intended to provide information on the location of surface features such as drill holes and test sites. 5.2.2 Approach One of the primary goals of the site survey was to establish a control network that would provide for accurate location of features within the mine site using simple techniques and equipment. Therefore, a control traverse was first run around the perimeter of the proposed mine area that would place any point within 1000 feet of a control point. The control traverse was closed through "Mormon" and performed with electronic distance measuring equipment. The control points are marked by a 40d spike driven to ground level, a pile of rocks over the point and a piece of quarter round by 1 inch molding, about 3 feet long, placed vertically over the point and supported by the rock pile. Location of the control points are shown on the surface feature location 5-5 map in Figure 5-1 and the location data is listed in Table 5-1. TABLE 5-1 Mormon West Control Point Data Station Northing Easting Elev. * Mormon 5,549,844 .0 537, 482.1 504.0 * MW1 5,549,881.1 536,533.1 489.0 Mw2 5,549,740.7 535,645.6 415.7 Mw3 5,549,669.2 534,257.4 302.0 *MW4 5,549 ,964.1 532,718.7 285.7 MWS 5,550,060.8 531,431.8 252.9 MW6 5,551,171.2 530,904.6 182.2 *MW7 5, 951,125 1 532,297.6 256.0 Mw8 5,551,118.0 533,500.6 280.6 * MW9 5,551,183.0 534,505.9 350.3 * MW10 5,551,253.9 536,317.8 457.3 MW11 5,551,234.3 537,264.5 469.2 Notes 1) Station names preceded by * are part of the closed control traverse. Other stations are set radially from the closed traverse points. 2) Vertical Datum = Mean Sea Level 3) Horizontal Datum = Alaska State Plane Zone 7 4) Station MW11 has been obliterated. 5) Survey performed October 17 to 19, 1986. After establishment of the control network, location of surface features and collection of topographic data was performed by radial stadia survey. The spacing of the control stations will also allow fairly accurate location of points by distance and vertical angle measurement to two control stations using tape and Brunton compass. 5.2.3 Assumptions Following are the basis of control for this survey: Vertical Mormon Bench Mark = 504.0 feet above mean sea level; and Horizontal Alaska State Plane Transverse Mercator Projection Coordinate System Zone 7. Mormon North = 5,549,844.0 feet East = 537,482.1 feet Kodak North East " 5,538,709.1 feet 528,640.8 feet The control points used above were located in the field and found to be in good condition. These control points were established by the U.S. Coastal And Geodetic Survey. Kodak is a first order station and Mormon is a second order station, both were established in 1950. For purposes of the topographic survey a minimum horizontal closure for control traverses of 1:5000 was assumed to be sufficient. The use of stadia survey techniques for topographic and location surveys was assumed to provide adequate accuracy. Stadia surveys should generally provide horizontal accuracy of plus or minus one foot and vertical accuracy of plus or minus one tenth foot. 5.2.4 Results 5.2.4.1 Topographic Survey To obtain accurate topography of the mine area required thorough coverage of the surface with radial survey shots. All survey shots were reduced to the state plane coordinate system for horizontal location and to mean sea _ level for vertical location. The survey data from both the Phase II survey, performed in April 1985, and the Phase III survey, performed in October 1986, were combined to form the database for production of the surface topography map, which is attached to this report as Appendix E. The topography was 5-7 originally plotted at a scale of 1 inch to 200 feet and reduced by xerographic methods to the Appendix E scale. A total of approximately 600 data points from the combined surveys were used as the database for the topographic mapping. The area of coverage is about 7500 feet by 2500 feet, yielding an average data grid of about 175 feet by 175 feet. Reduction of the data to yield the contour lines was performed by linear interpolation between adjacent data points. Since both of the surveys were. performed during a time of the year when snow was on the ground, a certain amount of error, depending on snow depth is induced into the survey results. The effects of the snow on the accuracy of the survey is minimal inmost areas, since the survey rod could usually be shoved through the snow to solid ground. However, in areas prone to drifting, such as the north sides of the hogback ridges and the bottom of the Mormon Creek drainage, the topography may be high by a_ few feet due to deep snow. In general, the topographic map should be accurate to one contour interval and in most areas accurate to within one foot of the elevations shown. 5.2.4.2 Location Survey In addition to collecting data for topographic mapping, the site survey was intended to provide the location of surface features within the proposed mine site. A map of the surface features located within the mining area is shown in Figure 5-1. Most of the drill holes were surveyed as part of the April 1985 survey and were located using electronic distance measuring equipment. Surface location of the bulk sampling sites and other miscellaneous features were performed by radial stadia survey during August 1987. During future work at the mine site, accurate location of points of interest can be easily obtained without the need for sophisticated surveying equipment. Even if a survey transit is not 5-8 available for stadia or triangulation location of the points, location to within an accuracy of a couple feet can be obtained by tape measurement to any two surveyed points and clinometer measure of the taping angles. 5.2.4.3 Air Photo Control Panels During the 1987 field program, control panels were placed in anticipation of aerial photographic work planned for the area. Panels were constructed of white woven plastic material and held in place on the ground with rocks. Each panel was constructed in the shape of a cross centered over the survey point and measured about 12 feet by 12 feet. Table 5-2 lists the air photo control panels that were set. TABLE 5-2 Air Photo Control Panel Locations Station Type Station Name Northing Easting Elev. USC & GS * Mormon 5,549,844.0 537,482.1 504.0 * Omalik S Base 5,531,389.8 502,248.9 30.5 Uncontrolled Omalik 87-1 N/A N/A N/A 1986 Control MwW2 5,549,740.7 535,645.6 415.7 MW5 5,550,060.8 531,431.8 252.9 MW6 5,551,171.2 530,904.6 182.2 MW8 5,551,118.0 533,500.6 280.6 * MW10 5,551,253.9 536,317.8 457.3 1985 Control * MT1 5,540,914.2 554,811.7 574.5 1984 Drill * 107 5,540,467.8 550,776.7 332.4 Holes 110 5,546,993.9 545,374.0 306.7 113B 5,549,342.2 541,149.6 451.4 116B 5,548,320.0 541,112.8 437.5 *117 5,545,356.5 549,022.5 267.2 121 5,543,769.6 550,944.1 278.2 Notes 1) Vertical Datum = Mean Sea Level Horizontal Datum = Alaska State Plane Zone 7 2) Omalik 87-1 is unsurveyed point approx. 120' east and 240' north from edge tundra at north tip of Omalik Lagoon. Monumented by 2" diameter wood stake and pile of beach rocks. 3) Station names preceded by * are either USC&GS control or part of a closed traverse with minimum closure of 1:10,000 and should be given the greatest weight should discrepancies occur. 4) Point MT1's position should be verified from the position of other nearby points prior to use for photogrammetry. A pile of rocks was found where the point should have been, however, the identity of the point was obliterated. 5.3. Phase II Mine Plan Revisions 5.3.1 General This subsection covers revisions to the WACDP Phase II Final Report, and the WACDP Preliminary Mine Design Technical Memorandum 5 - 10 that appear to be necessary, based upon new data obtained during subsequent site investigations. General time related factors, such as inflation, were not considered in the revisions contained in this subsection. Revisions made herein are those which were deemed appropriate, based upon new physical evidence only. To the extent appropriate, assumptions and data used for the Phase II study were used for these revisions. Only those assumptions that required changing to conform to the new data were changed. Only two areas of the Phase II report required revision, due to the new information gathered during subsequent field programs. Several new data items made a reevaluation of the Mormon West reserve base prudent and data gained during the bulk sampling suggested minor revisions to the mining costs. Details of the new data and the revisions dictated therefrom are discussed below. 5.3.2 Mining Costs During the bulk sampling operations, completed as part of CODEM, it became evident that at least part of the overburden would not require blasting. Seismic velocities were measured for overburden materials encountered in test pits 1 and 2 by Howard Grey & Associates and the upper overburden appears to be rippable, or at least marginally rippable, based on the measured seismic velocities. Inspection of the open cut on DFS 4 Seam, during the 1987 program, revealed that the top several feet of overburden was fairly soft and much of it was later ripped with a D3 size dozer. Based on this information, it is safe to assume that at least the top 5 feet of overburden can be ripped by dozer and will not require blasting. The top 5 feet of overburden represents approximately 15 percent of the total overburden for the 4:1 stripping ratio. Prestripping of the top 5 feet of overburden by ripper dozers will reduce the 5 = i overall] amount of material that must be blasted, but it will not reduce the physical requirements for the blasting machinery appreciably. Therefore, the deletion of blasting for the top 5 feet will effect the labor and operating costs only and not capital costs. From Table 5-34 of the WACDP Phase II Final Report, the labor and operating cost for spoil blasting is $0.86 per Bank Cubic Yard (bcy). From the Caterpillar Performance Handbook, it is estimated that a D9 dozer could rip 1500 bcy per hour (net). At an hourly operating and labor cost for the D9 dozer of $110.60, the cost of ripping the top 5 feet of overburden is $0.07 per bcy. Therefore, the net savings for ripping versus blasting of the upper overburden is $0.79 per bcy. At a 4:1 stripping ratio with 15 percent of the overburden to be ripped rather than blasted, this translates into an anticipated reduction in mining cost of $0.48 per ton. 5.3.3 Coal Reserves Field work performed subsequent to the Phase II project resulted in several additions to the data base that could have a marked effect on the reserve base for the Mormon West mining unit. As a result, it was deemed necessary to revise the reserve estimates to account for the new information. Following are the key factors which formed the basis for the revised reserve estimate. 1) The topographic survey conducted as a result of this phase of the WACDP provides a much better data base for analysis of the effects of the surface configuration on the overburden quantities. 2) Bulk sampling of DFS 4 seam did not encounter the 2 to 3 foot clay parting that was logged in drill holes during the 1985 exploration program. The test pits revealed 5 - 12 3) 4) 5) that there was an area near the middle of the seam with frequent discernible thin clay lenses, but the analysis of this section of the seam indicated that the overall quality was acceptable. Apparently, the auger used in the 1985 drilling was selectively recovering a large portion of the clay lenses, while losing most of the coal. Therefore, the reserve estimate should be based on a greater recoverable thickness than previously used. Three point solutions to coal dip provided by new drilling data and the direct measurement of dip in the test pits indicates that coal dips for the proposed mining area are higher than originally anticipated. DFS 4 Seam dips of 21 degrees by three point solution of drill data and 25 degrees from a test pit in the same area, strongly suggest that greater coal dip be used in the reserve estimation. Therefore, coal dips within the proposed mining area were recalculated based on the same type of circular model used in the Phase II report, with coal dips on DFS 4 Seam ranging from 21 degrees on the eastern end to 30 degrees on the western end. A shallow test pit dug on the prominent ridge where DFS 3 Seam was thought to have been burned out, revealed a badly weathered, though unburned crop of coal. This coal was sampled and found to be of good quality. In the Phase II study it was assumed that all of the coal in the burn area would be gone and not recoverable. This assumption appears to be overly pessimistic. The test pit on DFS 3 Seam mentioned above is located almost directly updip from the exploration drill hole 84-3. The dip between the test pit and the coal intercept in Drill hole 84-3 is about 15 degrees, much less than that indicated by data for adjacent seams. The data for The DFS 4 Seam dip in the vicinity of the burn 5-=13 is difficult to ignore and it is therefore assumed that the low dip angle is anomalous to the burn area only. A warp in the coal structure might explain the rather unique nature of the DFS 3 Seam outcrop in the burn area. 6) Market analysis, completed after reserve calculations were completed in Phase II, indicates that demand could vary considerably from the base case rate of 50,000 tpy. Therefore, in order to assess the ability of the Mormon West mining unit to supply coal for a variable market, the reserve base needs to be estimated for stripping ratios both above and below the base case assumption of 431. All of the above factors seemed to point strongly towards the need for a general revision in the reserve estimates for the Mormon West mining unit. Table 5-3 gives a summary of the results of the revised reserve estimate, based on the new data described above. Note that the overall reserve base for the base case stripping ratio is less than that originally estimated, but still provides the one million tons required for the first ten years of operation. The data contained in Table 5-3 is shown in graphic form on Figure 5-2. Figure 5-3 shows a section through DFS 4 Seam at 33,500 East and the typical engineering assumptions and calculation variables used in the revised reserve estimate. Table 5-4 lists the calculation variables for each cross section used in the reserve estimate. = ST TABLE 5-3 RESERVE SUMMARY MORMON WEST BLOCK Typical Zone of Influence Ratio = 2 Ratio = 3 Ratio = 4 Ratio = 5 Ratio = 6 Ratio = 8 Section From To tons/ft tons tons/ft tons tons/ft tons tons/ft tons tons/ft tons tons/ft tons Dist DFS 2 Seam 31,000 30,500 31,300 0.0 0 0.0 0 0.0 0 23.6 18,880 33.3 "26,640 49.9 39,920 32,000 31,300 33,200 0.0 0 21.1 40,090 33.4 63,460 4k 8 85,120 56.2 106,780 77.7 147,630 1,900 34,100 33,200 35,100 0.0 0 0.0 0 0.0 0 22.8 43,320 32.6 61,940 49.1 93,290 1,900 36,000 35,100 37,500 0.0 0 17.7 42,480 28.5 68,400 40.3 96,720 52.0 124,800 75.2 180,480 2,400 Subtotal DFS 2 0 82,570 131,860 244,040 320,160 461,320 DFS 3 Seam 32,000 30,500 33,500 0.0 0 40.8 122,400 60.6 181,800 79.5 238,500 97.8 293,400 133.4 400, 200 3,000 33,800 33,500 34,600 0.0 0 46.2 50,820 72.6 79,860 97.1 106,810 120.7 132,770 166.9 ~ 183,590 1,100 35,400 34,600 35,600 40.6 40,600 71.8 71,800 100.3 100,300 127.0 127,000 153.0 153,000 202.7 202,700 1,000 36,400 35,600 36,600 15.3 15,300 37.7 37,700 = 88.9 88,900 123.9 123,900 152.6 152,600 203.6 203,600 1,000 37,200 36,600 37,500 0.0 0 0.0 0 0.0 0 65.0 58,500 94.1 84,690 145.4 130,860 900 Subtotal DFS 3 55,900 282,720 450,860 654,710 816,460 1,120,950 DFS 4 Seam 30,600 30,500 30,800 0.0 0 24.7 7,410 48.4 14,520 67.4 20,220 85.3 25,590 120.6 36,180 300 32,000 30,800 32,600 13.5 24,300 33.7 60,660 50.9 91,620 68.7 123,660 86.6 155,880 121.8 219,240 1,800 32,800 32,600 33,000 0.0 0 22.5 9,000 46.9 18,760 65.7 26,280 83.5 33,400 118.8 47,520 400 33,500 33,000 34,500 26.0 39,000 47.5 71,250 68.3 102,450 89.3 133,950 110.1 165,150 151.6 227,400 1,500 36,000 34,500 36,300 29.6 53,280 53.9 97,020 76.3 137,340 98.2 176,760 119.9 215,820 163.3 293,940 1,800 36,900 36,300 37,500 32.0 38,400 57.0 68,400 83.0 99,600 107.4 128,880 128.9 154,680 168.7 202,440 1,200 TOTAL FILL SEAMS 210,880 679,030 1,047,010 1,508,500 1,887,140 2,608,990 TABLE 5-4 Calculation Variables Recov. Crop Coal Dip Safety Bench Section Thkn. Cover (degrees) Height Width DFS 2 SEAM 31,000 6.5 10 27.6 10 10 32,000 6.5 3 27.6 5 10 34,100 6.5 10 25.0 10 10 36,000 6.5 10 23.0 15 10 DFS 3 SEAM 32,000 10.5 5.5 28.7 10 10 33,800 11.0 8 26.5 10 10 35,400 11.0 5 24.0 5 10 36,400 11.0 1 15.0 5 10 37,200 11.0 18 24.0 18 18 DFS 4 SEAM 30,600 , 10.0 10 30.0 10 10 32,000 10.0 5 30.0 5 10 32,800 10.0 10 27.5 i0 10 33,500 10.0 3 27.5 5 10 36,000 10.0 2 25.0 5 10 36,900 10.0 3 21.0 5 10 5.4 The cross section stationing has been changed for this report to conform to the state plane coordinate grid used for the topographic and location survey work. This will facilitate easier and more accurate location of cross sections, both on paper and in the field. 20,000 Ton Per Year Production Rate 5.4.1 General As part of Phase II of the WACDP and initial market investigations under Phase III it became apparent that a market of 20,000 tpy might be more likely than the 50,000 tpy base case market upon which the Phase II study was based. Furthermore, it appears that the 20,000 tpy scenario might be valid for several years after start-up. Extrapolation of costs for the 20,000 tpy rate in the 5 - 16 e Phase II report was based on the necessity to provide a mining plan and equipment fleet that could expand production to higher levels shortly after start-up. This necessitated use of a mining plan that is inefficient for the lower tonnages in order to provide the mine development necessary for rapid expansion of production without overhaul of the mining plan or replacement of the equipment fleet. Therefore, in order to provide a more realistic view of what a 20,000 tpy operation would look like, this section provides an analysis of a mining plan that will meet the 20,000 tpy production rate more efficiently. The mining plan presented herein is somewhat expandable, but is primarily oriented towards providing a cost effective solution to mining at production rates less than the base case rate of 50,000 tpy used in Phase II. 5.4.2 Approach A somewhat more conservative approach was taken in the analysis of the 20,000 tpy scenario than for the higher tonnages viewed in the Phase II study. One primary reason for this was the new geologic information obtained which indicated that coal dips were greater than had originally been anticipated. Conversely, the bulk sampling program(s) showed that coal quality at near surface deposits was satisfactory for boiler feed and that coal crops appear to be consistently shallower than were originally thought. Another key element in the approach taken in this section was the elimination of as many parts of the equipment fleet as possible. Reduction of the number of pieces of equipment required to perform the work will reduce the size of the crew and yield savings in infrastructure requirements. The Mormon West Block is used as the area where the first 10 years of production will take place and the minimum coal recoverable for the mining plan is therefore, 200,000 tons. Equipment selection 5 = 17 was generally based upon its ability to produce the required amount of coal from the Mormon West Block with an eye towards flexibility of function, so that multiple tasks could be performed by each piece of equipment. 5.4.3 Assumptions A general assumption which applies to the 20,000 tpy rate and largely controls timing of operations is that coal and supplies will be hauled from/to the port site over a winter road and surface access will not be available between the two points until about mid-October. Ownership and operating costs for equipment were obtained from the Rental Rate Blue Book for Construction Equipment, Volume I, published by Dataquest, Inc.. Ownership costs were computed as follows: Monthly rental rate times 1.3 divided by 176 where: 1.3 is the North Slope area adjustment factor (1.5) minus 0.2 to account for the overhead and profit included in the Blue Book values but figured separately in this study. 176 is the number of operating hours per month upon which the monthly rental rates are based in the Blue Book. Operating costs were computed as_ the Blue Book rate times the North Slope area adjustment factor of 1.5. Calculation of the ownership cost, as outlined above, provides a reliable and generally accepted method for figuring hourly equipment costs, but in many cases may not yield adequate return on the equipment over the mine life to fully pay it off. This 5-318 method of computing equipment costs requires the assumption that equipment which is not used for its full useful life, either yields adequate salvage value or is purchased used, at a cost which allows full recovery of capital over the mine life. Equipment data and capabilities were obtained from published sources, such as manufacturers data sheets and equipment production and operating guides. Following are basic assumptions or conditions arising from the mining plan which are of particular relevance to other parts of this study: 1) Major supplies such as fuel and explosives will need to be purchased a year in advance of when they will be used. This is necessary, assuming stripping will be done in the fall, since these materials could not be moved from the port site until after winter freeze-up. 2) Storage will be needed for the following major consumables: Fuel oi] 30,000 gallons Gasoline 5,000 gallons Lubricants & Coolant 1,000 gallons Explosives 25,000 pounds 3) There will be no blasting or crushing of coal. It is anticipated that the mining method proposed will produce coal which is primarily 6 inch minus, which should be acceptable for both hand fed domestic heaters and with only minimal crushing required for power plant use. 4) Equipment for loading coal onto the barge and for loading ramp construction will be brought in each year with the coal barges. Stockpile management that will be 5 - 19 performed by mine equipment is leveling and shaping during the hauling season when surface movements between the port and mine are possible. Assumptions and data derived in the Phase II report were used where applicable and reverification of assumptions and information contained in the Phase II report was not necessarily repeated herein. 5.4.4 Mining Plan 5.4.4.1 Equipment The equipment selected for mining at the 20,000 tpy production rate is contained in Table 5-5. The selected equipment meets the goal of providing flexibility witha minimum number of pieces. The primary pieces of excavation equipment will perform more than one function and, with the exception of the backhoe, will not result in total suspension of operations if one piece of equipment is down. The backhoe, since it is the only piece of loading equipment and the only machine capable of excavating the deeper overburden, is key to continued operation. For this reason the backhoe should be purchased new, to avoid excessive interruption of operations. The haul trucks would only be used for about 20 percent of their useful life over the first ten years and thus are good candidates for purchase as used equipment. The drill and dozers would be used about 30 percent of their useful life and grader about 20 percent. 5.4.4.2 Stripping and Mining Plan The mining plan as, proposed herein, will limit mining to the shallow coal deposits near coal outcrops outside of the major drainages. The mining plan was analyzed by use of a typical section through DFS 4 seam and the geometric limitations of 5 - 20 the selected equipment to develop an operating sequence for stripping and coal removal. Number TABLE 5-5 Mining Equipment List Description Backhoe, 215 Horsepower (Caterpillar 235) 12 foot boom and extra bucket for coal loading. . 335 Horsepower ripper dozer (Caterpillar D8) 335 Horsepower winch dozer. 35 ton articulated end dump trucks (Caterpillar D350) with light material beds and three axle configuration. 200 Horsepower road grader (Caterpillar 14G) Rotary blasthole drill with 5 inch hole diameter, 25 foot single pass capability and 25,000 1b. pulldown (Ingersol-Rand DM25) Mechanics truck, 45,000 GVW with 12 ton hydraulic crane, welder and air compressor. Water truck, 2,500 gallon Fuel service truck. Powder truck, 20,000 gph 4X4 Pickup or Crew Cab. Water pump, 10,000 gph. 3 KW worklight/generator sets 5 = 21 Figure 5-4 illustrates the mining plan as applied to a cross section through DFS 4 Seam at 36,000 east and is described as follows: 1) Weathered and thawed surface material would be ripped and piled south of the excavation limits using dozers only. Topsoil would be pushed to the southern limit of the dozer piled spoil, to facilitate segregation and recovery upon backfilling. 2) Zone 2 & 4 will be drilled and blasted prior to excavation. Zone 2 would be blasted first, so that excavation could commence prior to completion of all blasting and to provide a free face for improved fragmentation when blasting Zone 4. 3) Zone 2 would be excavated by the backhoe and stacked to the north, where it would be rehandled by a dozer to make adequate room for all] Zone 2 spoils. 4) Zone 4 would be excavated by the backhoe and cast to the south, where it would be _ rehandled by dozer. 5) Zone 3 would be excavated by the backhoe only and cast to the north. 6) Coal would be excavated in horizontal lifts by the backhoe and loaded into haul trucks traveling on the horizontal coal surface. A dozer will be used, as needed, to rip the coal where it is too tough for the backhoe to dig without assistance. 5-22 7) Dozers would be used to backfill the pit, from both sides, replacing the spoil materials in the area from which it came. Regrading of the surface would be performed concurrent with the backfilling operation. 8) Reseeding of the mined area would be performed during the next year's growing season. A haul road would be left down the middle of the regraded surface for access to subsequent years mining areas. A key feature of the mining plan is that the stripping, mining and backfilling operations are performed concurrent to one another and that stripping begins near the end of the thawing season. Operations conducted in this fashion are necessary to reduce “the effort required to move spoil materials. Stripping Zone 1 at the end of summer will reduce ripping effort. Backfilling of the pit prior to winter shutdown will eliminate the need for ripping stockpiled spoil, which might be required if the spoil were allowed to compact and refreeze over the winter. An alternative to the mining plan presented herein, is to do all stripping with the backhoe and eliminate prestripping with the dozers. This approach would reduce the stripping ratio and the overall amount of coal recoverable from the Mormon West Mining Unit. The amount of coal which can be recovered is primarily controlled by the digging depth of the backhoe, so elimination of dozer prestripping would reduce the’ dip length recoverable for most mining areas. This approach would also eliminate the need for a_ second dozer. Elimination of the second dozer would increase the chances for unscheduled work stoppage, since having- the dozer down could also potentially result in the inability to continue stripping. 5) 23 5.4.4.3 Labor Requirements and Schedule The basic daily operating schedule will be single shift, 10 hours per shift, except maintenance personnel are expected to work 12 hour shifts, so that someone is always available to tend the equipment. Maintenance personnel will be expected to start and warm up equipment prior to start of the production shift. Personnel will be rotated on a10 day frequency and may change assignments on different rotations, if appropriate. For instance, the drilling and blasting personnel could be used as the coal haul crew, since the two activities do not overlap. Following is a list of the personnel needed to perform the stripping, mining and backfilling operations: Dozer Operator This person will primarily operate the ripper dozer. 2 required. Utility Operator This person will need to be proficient in dozer and grader operation, with a working knowledge of the other equipment. 2 required. Backhoe Operator This person will primarily operate the backhoe. 2 required. Driller This person will operate the blasthole drill and work as_ the powderman's helper. 2 required. Powderman This person. will perform the blasthole loading and serve as the driller's helper as needed. 2 required. 5 =| 24 Mechanic This person will serve as_ the leadman for equipment maintenance and will work a twelve hour shift. 2 required. Oiler This person will be responsible for daily servicing of the equipment and work a 12 hour night’ shift. 2 required. Truck Drivers. 2 truck drivers will be required for coal hauling. 4 total required. Superintendent This person will have responsibility for supervision of the overall operation and provide fill-in help for persons, such as the mechanic and powderman. Will not be on rotation schedule. 1 required. Cook Given the small size of the crew this person will be expected to perform both cook and_bullcook duties and will work a 12 hour shift. 2 required. Figure 5-5 illustrates the annual operating schedule. This schedule is shown in compact form and could be expanded if conditions dictate doing so. Stripping operations could be performed earlier in the year to take advantage of warmer weather and a work break could be scheduled after completion of stripping until winter freeze-up occurs. If personnel shortages occur, some of the tasks, primarily stripping tasks, could be stretched over a_ longer time period and started earlier. The later would, however, result in an increase in overall cost since support functions would be 5 - 25 required over a longer time period. It is assumed that haul road construction could be performed starting about Mid-October and take about 2 weeks to complete. Coal hauling and backfilling would then be complete by Mid-December, with both operations conducted concurrently after about 8 days of coal removal. The coal removal and backfilling operations have little room for flexibility. Work stoppages or a_ reduced level of effort would push the operating window into the holiday season and the coldest part of the winter. A total of 8 days is figured lost to weather during the October through December period. 5.4.4.4 Reserve Analysis Analysis of the coal reserves for the Mormon West Block was performed by examining cross sections for each seam typical of the various terrains encountered in the mine area. Surface data was obtained from the topographic survey conducted in October 1986 and coal structure from combined geologic data from the various exploration programs conducted through fall 1987. As with the Phase II study, coal dips are modeled, based on a circular shape to the syncline and an assumed or measured dip for DFS 4 Seam. The dip for DFS 4 Seam ranged from 21 degrees, measured from 3 point solution of drill hole data at the east end of the Mormon West Block, to 30 degrees assumed for the West end. An area of anomalously low dip of about 15 degrees is indicated for DFS 3 Seam near the burn area at about section 36,000, which was used for reserve calculation in that area. Mining was assumed to be limited to the high areas outside of significant natural drainages in order to minimize the need for water control. Depth of cover over the coal seams ranges from 2 feet, near the outcrops, to about 35 feet for the deepest 4 Seam excavation, with an average depth based on 5 - 26 stripping ratio of about 24 feet. From Figure 5-2 of the Phase II Final Report this average depth of cover should yield an average coal quality of about 11,000 btu per pound. Typical cross sections for each seam were analyzed for a maximum and minimum coal recovery mining plan. The minimum recovery case is summarized in Table 5-6 and represents the stripping plan where no dozer prestripping is performed and depth of recovery is limited to about 27 feet below the existing ground, the maximum digging depth of the backhoe. The maximum recovery case is summarized in. Table 5-7 and represents the stripping plan where 5 to 10 feet of overburden is removed by dozers prior to blasting and excavation by the backhoe. Cross sections are taken along grid north lines and the section numbers represent the last 5 digits of the state plane east coordinate. Figure 5-6 shows the areas from which coal reserves were calculated for each coal seam. TABLE 5-6 Reserve Summary Minimum Recovery Case Seam Typical Zone of Crop Tons Tons Bank Section Influence Length Per Ft. Ratio Coal Yards From To Spoil 2 32000 31200 33200 2000 12.0 2233 24000 55920 3 32000 31500 32800 1300 T1521 2.03 19630 39849 4 32000 30800 32600 1800 12.0 2.38 21600 51408 Subtotal West of Mormon Creek 2.26 65230 147177 2 36000 35100 37500 2400 13:45 2.83 32400 91692 3 35400 34600 35600 1000 25.5 1.65 25500 42075 3 36400 35600 36600 1000 25.6 2.06 25600 52736 4 33500 33000 34500 1500 19.6 1.98 29400 58212 4 36000 34500 36300 1800 22.4 1.82 40320 73382 4 36900 36300 37500 1200 24.0 1.81 28800 52128 Subtotal East of Mormon Creek 2.03 182020 370225 TOTAL MORMON WEST BLOCK 2.09 247250 517402 TABLE 5-7 Reserve Summary Maximum Recovery Case Seam Typical Zone of Crop Tons Tons Bank Section Influence Length Per Ft. Ratio Coal Yards From To Spoil 2 32000 31200 33200 2000 Li2 3 32000 31500 32800 1300 23.55 4 32000 30800 32600 1800 18.8 Zi 2.83 30550 86457 3 3302 44800 157978 1.80 29900 53820 2.06 25600 52736 2220 38400 84480 22:28) 51840 118195 2.34 38400 89856 TOTAL MORMON WEST BLOCK 2.65 327810 867751 5.4.4.5 Reclamation . The total area disturbed during the first ten years of mining would be about 110 acres, not including the camp area and winter haul roads. The active mining area would disturb about 4.5 acres each year, with about half being the actual excavation limits and the remainder involved in the spoil stockpile area. Backfilling and grading would be accomplished at the end of each season, with the pit from which coal was just removed being backfilled and graded prior to winter shutdown. Performance of the regrading operations in this fashion will leave the mine area in a relatively stable condition when spring thaw occurs and should minimize erosion on disturbed areas. Due to the low stripping ratio for the proposed mining plan, the excavated spoil, plus swell, will not be adequate b= 28 to bring the regraded surface up to original contour. The final regraded surface will only be about 4 feet below the original ground level and will therefore not present a problem for smooth blending with surrounding terraine. In order to minimize the complexity and operating cost of drainage control, water treatment will be by surface filtration. A buffer zone of undisturbed vegetation will be left between the active mining areas and all active surface drainages. This buffer zone will act as a _ filter to remove sediments in runoff from spoil pile backslopes and regraded areas. Regraded pit areas will be crowned and sloped to drain through the vegetation buffers. During active mining operations the majority of runoff from spoil piles and pit areas will drain towards the excavation, where it will be collected in sumps and removed by pumping. Water removed from the pit will be pumped to a distribution manifold which will spread the discharge over an adjacent vegetative filter zone. Final reclamation of the mining area will entail removal of mine haul roads, removal of drainage control structures and reseeding of all remaining disturbed areas. Table 5-8 summarizes the anticipated cost for complete reclamation of the mine assuming abandonment of operations at the point of maximum disturbance. This represents the amount of the reclamation bond which would be required to ensure that reclamation under the mining plan would be completed. The costs outlined in Table 5-8 contain costs that are included as part of the normal annual mining cost and should only be used for bond cost computation. 5-29 TABLE 5-8 Reclamation Bond Amount Computation Unit Description Units Cost Amount Backfill Pit 46,090 cy $ 1.26 $ 58,073 Reseed Pit 4.5 acres 1100.00 4,950 Scarify Roads 60 hrs 137.00 8,220 Reseed Roads 11 acres 1100.00 12,100 Remove Culverts 400 If 5.00 2,000 Remove Road Fills 15,755 cy 3.00 47,265 Remove Geocloth 11,133 sy 1.00 11,133 Reseed Fill Dumps 2 acres 1100.00 2,200 Maintenance & Monitoring 40 acres 200.00 8,000 Clean-up L.Ss 10000.00 10,000 Supervision & Maintenance 46,090 cy 5.00 230,450 Camp Removal [Sos 20000.00 20,000 Sub Total 414,351 Overhead & Contingency 20% 82,878 TOTAL 497,229 $500,000 5.4.5 Mining Costs 5.4.5.1 Approach The source of cost information for this cost analysis is primarily the Rental Rate Blue Book, discussed further in section 5.4.3, and the labor rates developed in subsection 5.3.10.1 of the Phase II Final Report. Following are some additional assumptions used for derivation of equipment productivity and mining costs: 1) Mechanical availability assumed at 80 percent and job efficiency at 50 minutes per hour for an overall availability of 67 percent. 2) Seismic velocity for the surface materials to be ripped by dozer is assumed to be 4,000 feet per second. 5 - 30 3) The winter haul road assumed to be 4.5 miles long and average haul speeds assumed at 25 miles per hour. 4) Net load for coal haul trucks assumed at 30 tons per load. 5) Blasthole drill penetration rate of 100 feet per hour. 6) Explosive powder factor of 1.0 pounds per cubic yard. 7) Discount rate of 3.5 percent and interest (capital recovery) rate at 10 percent. 8) For purposes of timing of development costs, mining is assumed to begin at the west end of the mine area. A significant feature of the estimating method used for this cost analysis is that all equipment costs are figured on an hourly basis. That is, ownership cost for equipment is figured as an average cost per hour, rather than as an average cost per year over the life of the equipment. This approach is discussed further in Section 5.4.3., but one - favorable feature to this approach is that ownership cost computed thus, is relatively independent of the tonnage mined. That is, the costs developed herein can more easily be applied to differing conditions, such as change in production level or stripping ratio. Cost estimates are obtained by computing the hourly costs for each operating crew, estimating the hourly productivity for each task and calculating the time and crew(s) required to perform each task. Costs are then computed as_ crew hours 531, times crew cost per hour. Table 5-9 summarizes the mining crew costs and Table 5-10 summarizes productivities. Table 5-9 Hourly Crew Cost Summary Crew Lab. Own Oper. Tot. Crew Description # $/hr $/hr $/hr $/hr Ripper dozer D8R 45 93 49 187 Winch dozer D8wW 45 97 49 191 Backhoe El 45 83 42 170 Haul truck H1 42 56 28 126 Road grader Gl 45 62 30 137 Blasthole drill Bl 42 110 52 204 Powderman & truck B2 39 10 8 Si Mechanic & boom truck M1 46 33 25 104 Oiler & fuel truck M2 43 20 15 78 Superintendent & pickup Al 60 5 6 71 Crew cab pickup A2 7 5 7 12 Cook/Bul1cook A3 37 - = _ Water pump & hose Sl “ 10 4 14 Work lights (2) & gen 52 = 15 4 17 Straight time labor Li 40 = = 7 standby Table 5-10 Average Productivity Summary Task Crew(s) Productivity Dozer stripping D8R or DOW 58 bcy/hr Dozer ripping D8R 670 bcy/hr Dozer backfilling pit D8R or D8W 157 bcy/hr Backhoe excavation El + D8R 72 bey/hr Drilling & Blasting Bl + B2 149 bey/hr Load and haul coal El + H1 + 75 bey/hr H1 + D8R 5 = 32 5.4.5.2 Cost Analysis Derivation of mining costs contained herein, is based upon a detailed analysis of the typical mining section in Figure 5-4. From this, unit costs for stripping and coal mining are developed that are applicable over the range of conditions anticipated for the proposed mining plan. Tables 5-11, 5-12 and 5-13 show a breakdown of the miscellaneous, stripping and mining costs, respectively. Table 5-14 summarizes the mining costs for the typical section used as a basis for cost estimation. The stripping ratio for the typical section is 2.3 bank cubic yards per ton and mining cost is estimated to be $43.67 per ton. From Tables 5-6 and 5-7, the range of overall stripping ratios predicted for the proposed mining plan is 2.09 to 2.65 and from Table 5-12 the unit cost for overburden stripping is $7.46 per bank cubic yard. Therefore, depending on the recovery level targeted for the mining operation, mining costs are estimated to range from $42.10 to $46.28 per ton. 5a oS 7 - TABLE 5-11 MISCELLANEOUS ANNUAL COSTS 20,000 TON PER YEAR PRODUCTION RATE Description Units Quant. Unit Material Labor Owner Oper. Total Check Mtis. Unit Unit Unit Cost Cost Cost Equip. Cost Cost Total Unit Labor Owner Oper. Cost Cost Cost Cost Cost Cost Mobile Radios ea. 10 400 0 0 2,500 1,500 4,000 4,000 0 0 250 250 Pit Road Construction les. 1 10,940 1,094 4,376 2,735 2,735 10,940 10,940 1,094 4,376 2,735 = 2,735 Final Reclamation 16S 1 6,146 0 2,458 1,844 1,844 6,146 6,146 0 2,458 1,844 1,844 Annual Reclamation acres 4.5 1,100 2,610 2,340 0 0 4,950 4,950 580 520 0 0 Mechanic hrs 1,200 46 0 55,200 0 0 55,200 55,200 0 46 0 0 Oiler hrs 1,200 43 9 51,600 0 0 51,600 51,600 0 43 0 0 Mechanic Truck hrs 200 58 0 0 6,600 5,000 11,600 11,600 0 0 33 25 Fuel Truck hrs 360 35 0 0 7,200 5,400 12,600 12,600 0 0 20 15 Superintendent hrs 1,000 71 0 60,000 5,000 6,000 71,000 71,000 0 60 5 5 Cook hrs 1,200 37 0 44,400 0 0 44,400 44,400 0 37 0 0 Training & Standby hrs 610 40 0 24,400 0 0 24,400 24,400 0 40 0 0 Office Manager year 1 45,000 0 45,000 0 0 45,000 45,000 0 45,000 0 0 TOTALS 3,704 289,774 25,879 22,479 = 341,836 341,836 TONS PRODUCED: 20,000 COST PER TON: 17.09 se -S TABLE 5-12 ANNUAL STRIPPING COST 20,000 TON PER YEAR PRODUCTION RATE Description Units Quant. Unit Material Labor Owner Oper. Total Check Mtls. Unit Unit Unit Cost Cost Cost Equip. Cost Cost Total Unit Labor Owner Oper. Cost Cost Cost Cost Cost Cost Blasting Supplies hese 1 33,190 33,190 0 0 0 33,190 33,190 0 0 0 0 Drill Tools ft. 12,040 0.25 3,010 0 0 0 3,010 0.25 0 0 0 0 Drill & Driller hrs 282 204 0 11,844 31,020 14,664 57,528 57,528 0 42 110 52 Powderman & Truck hrs 310 LTA 0 12,090 3,100 2,480 17,670 17,670 0 39 10 8 Driller Only hrs 28 42 0 1,176 0 0 1,176 1,176 0 42 0 0 Ripper Dozer hrs 438 142 0 0 40,734 21,462 62,196 62,196 0 0 93) 49 Winch Dozer hrs 342 146 0 0 33,174 16,758 49,932 49,932 0 0 97 49 Backhoe hrs 357 125 0 0 29,631 14,994 44,625 44,625 0 0 83 42 Dozer Operator hrs 650 45 0 29,250 0 0 29,250 29,250 0 45 0 0 Utility Operator hrs 500 45 0 22,500 0 0 22,500 22,500 0 45 0 0 Backhoe Operator hrs 400 45 0 18,000 0 0 18,000 18,000 0 45 0 0 Crew Cab hrs - 180 12 0 0 1,260 2,160 2,160 0 0 5 . 7h Pump hrs 120 14 0 0 480 1,680 1,680 0 0 10 4 Lights hrs 65 7 0 0 260 1,105 1,105 0 0 13 4 TOTALS 36,200 94,860 140,604 73,358 344,022 344,022 TONS PRODUCED: 20,000 COST PER TON: 17-2 YARDS STRIPPED: 46,090 COST PER YEAR: 7.46 ge - SG TABLE 5-13 ANNUAL COAL MINING/HAULING COST 20,000 TON PER YEAR PRODUCTION RATE Description Units Quant. Unit Material Labor Owner Oper. Total Check Mtls. Unit Unit Unit Cost Cost Cost Equip. Cost Cost Total Unit Labor Owner Oper. Cost Cost Cost Cost Cost Cost Ripper Dozer hrs 135 142 0 0 12,555 6,615 19,170 19,170 0 0 93 49 Road Grader hrs 285 92 0 0 17,670 8,550 26,220 26,220 0 0 62 30 Backhoe hrs 267 125 0 0 22,161 11,214 33,375 33,375 0 0 83 42 Haul Trucks hrs 534 84 0 0 29,904 14,952 44 856 44 856 0 0 56 28 Dozer Operator hrs 150 45 0 6,750 0 0 6,750 6,750 0 45 0 0 Utility Operator hrs 300 45 0 13,500 0 0 13,500 13,500 0 45 0 0 Backhoe Operator hirs 300 45 0 13,500 0 0 13,500 13,500 0 45 0 0 Truck Drivers hrs 00 42 0 25,200 0 0 25,200 25,200 0 42 0 0 Crew Cab hrs 180 12 0 0 900 1,260 2,160 2,160 0 0 5: 7 Pump hrs 120 14 0 0 1,200 480 1,680 1,680 0 0 10 4 Lights hrs 70 7 0 0 910 280 1,190 1,190 0 0 0 0 TOTALS 0 58,950 85,300 43,351 187,601 += 187,601 TONS PRODUCED: 20,000 COST PER TON: 9.38 Table 5-14 Cost Summary 20,000 Ton Per Year Production Rate Material Labor Equipment Operating Total Cost Cost Item Cost Cost Cost Cost Cost Per Ton Miscellaneous $ 3,704 $289,774 $ 25,879 $22,479 $341,836 $17.09 TOTAL Stripping 36,200 94,860 140,604 72,358 344,022 17.20 Mining 0 58,950 85.300 _43,351 187,601 9.38 39,904 443,584 251,783 138,188 873,459 43.67 Cost Per Ton 1.99 22.18 12.59 6.91 5.4.6 Rolligon Coal Transport Option The cost estimate for coal hauling is contingent upon the ability to devise a relatively cheap method for construction of a winter haul road. If an all weather haul road is required that is of adequate fill depth to protect the tundra from thawing, then the haul road requirements are likely to be about equal to the 50,000 ton per year scenario. If an all weather road is required, then coal transportation to the port using all-terrain vehicles, such as rolligons, that can travel over the frozen and unprotected tundra without causing significant harm, may be a viable option to conventional truck haulage. A preliminary estimate of the rental cost for transport of 20,000 tons of coal from the mine to the coast using rolligons was provided by Mr. Bob Leonard of Bowhead Transportation. Rolligons that would be capable of hauling about 45 tons per trip could be chartered for a wet rental rate of approximately $412.00 per hour, assuming that fuel could be obtained at the camp ffor a price comparable to their cost. The equipment would be mobilized from Barrow each year and returned after hauling the required amount of coal. For safety reasons, at least two machines would be mobilized 5 sy, to the job site and the mine would be expected to provide room and board for the crew, which would probably consist of two drivers and a mechanic. The rolligons would be able to make one round trip in about 70 minutes and thus two machines would be able to haul about 76 tons per operating hour. Therefore, assuming an overall efficiency of 72 percent, 370 hours or 31 days at 12 hours’ per day would be required to move 20,000 tons to the port. Estimated cost for the rolligon transport option is approximately ~ $19.00 per ton. Comparable components of the conventional truck hauling cost are approximately $8.00 per ton (including road maintenance). Therefore, if the annual cost for road construction is in excess of $11.00 per ton, rolligon transport would appear to be the more cost effective solution to coal transportation between mine and port. The hauling cost of $8.00 per ton for conventional truck haulage stated above includes ownership cost and _ the rolligon option assumes that coal haulage will be performed by an _ outside contractor. Given the low utilization of the haulage equipment, it did not seem reasonable to assume purchase of rolligons, which could cost in excess of one million dollars each. Use of a contract hauler will result in an up front capital cost reduction for the coal hauling and road maintenance equipment of about $850,000. 5.4.7 Alternate Mining Sites Reconnaissance geophysical exploration and drilling have indicated the potential for significant coal reserves in areas other than the Mormon West mining unit, some of which may be capable of supporting the 20,000 ton per year production rate for many years. The Mormon West mining unit was selected as the initial mine site because it best met the criteria for the 50,000 ton per year base 5 - 38 case production and anticipated market expansion. Although the Mormon West mining unit can also meet the requirements for the 20,000 ton per year rate, the cost of haul road construction could better be amortized over a larger tonnage. Therefore, if the 20,000 ton per production rate appears to be the most realistic scenario for several years, some of the coal deposits south of Omalik Lagoon, that are closer to the coast, should be considered for initial mine development. Infrastructure capital costs and haulage operating costs could be reduced, and the information available indicates a likelihood that sufficient low ratio reserves exist near the coast to support a 20,000 ton per year production rate. Two areas are suggested from existing data as possibilities for mining of small tonnages and which are more accessible to the coastline. One is the Cape Beaufort area, which probably contains adequate reserves but a _ shallow coastline, local property conflicts and generally poorer quality than the Deadfall Syncline coals makes it a second choice. The 1985 Western Arctic Coal Geophysical Program report, prepared by Howard Grey & Associates, Inc. shows indicated reserves of approximately 1.2 million tons, at 3 to 1 ratio, in seam 21 about 4 miles southeast of Omalik Lagoon near the USCGS benchmark "Macaw". Although these reserves are not proven, it is likely that enough reserves exist at even lower than 3 to 1 ratios to meet the 20,000 ton per year requirement. Seam 21 is shown to be from 10 to 18 feet thick with dips less than 15 degrees. Geology of the Macaw block appears to be favorable for mining and, since it is part of the Deadfall Syncline the quality should be acceptable. Macaw is on the drainage divide between Omalik and Panikpiak creeks and no wetlands need to be crossed to access the coast. However, 50 percent or more of the access road from the coast to the mine area would be on top of barren hogback ridges and construction cost would be significantly Jess than construction over wetlands. The shoreline is probably shallower 5 = 39 near the mouth of Panikpiak creek, where the road would terminate, and thus shore to barge transfer of coal would likely be more costly than at the Omalik site. However, because the road would be usable year round, savings in other areas of coal handling are likely, such as the need for a smaller stockpile. In conclusion, the Macaw reserve block should be considered as a potential alternate mining site for the 20,000 ton per year production rate. 5.5 Conclusions Seven days were required to provide control and _ perform topographic survey of the Mormon West mining unit. Performance of the survey was severely hampered by logistics and cold weather and it is reasonable to expect that similar work could be performed in about half the time under favorable conditions. The topographic survey methods used for this study are a cost effective method for mapping of relatively smal] areas, but could become very costly if detailed mapping is required over a_ large area. If the area to be mapped is greater than one square mile, then alternative mapping systems should be considered. The information gathered for this phase of the WACDP does not suggest any need for major revisions to the mining cost analysis. It does appear, however, that a significant portion of the overburden can be excavated without blasting and mining costs can be reduced by about $0.48 per ton, due to the labor and operating savings for ripping versus blasting. Significant new geologic information gathered during this phase of the WACDP made a complete reevaluation of the mine area coal reserves prudent at this time. In general, there were factors which tended to effect the total reserve base in both directions. The net effect of the new geologic information is that the base case, 4:1 stripping ratio, reserve estimate for the Mormon West mining unit has been reduced by about ten percent to approximately 1,050,000 tons recoverable. A lower production rate of 20,000 tons per year can be mined for 5 - 40 nearly the same cost as the 50,000 ton per year production rate. Use of a large hydraulic excavator in the backhoe configuration can provide for adequate recovery of coal for the lower production rate and alleviate the need for spoil haulage by trucks. Spoil handling can be performed entirely by the backhoe and dozers and coal can. be hauled to the port site over awinter use only haul road. The annual stripping and mining requirements can be completed in about a three month period for an estimated direct mining cost of $42.00 to $46.00 per ton, delivered and stockpiled at the port site. 5 - 41 Not all drill holes, test pits and archeological sites are shown on tnis map. Only those locations wnich couid be surveyed in conjunction with the control and topography surveys are plotted 33/000 £ LEGEND Survey Control Station Exploration Drill Hole Bulk Sample Test Pit Archeological Site 34]o00 € 35|000 € 36|000 € Q'__590'_1000' 2090! APPROXIMATE SCALE ELEVATION DATUM: Mean Sea Level COORDINATE DATUM : Alaska State Plane Zone 7 add 5,500,000 to N coordinates 500,000 to E coordinates —— 51,000 N — 50,000 N —— 49,000 N WESTERN ARCTIC nme COAL DEVELOPMENT PROJECT SURFACE FEATURE LOCATIONS MORMON WEST BLOCK Prepared by Date Denton Civil & Mineral 2-1-88 FIGURE 5-1 ao uw (bank yards per ton) BS a o - < [id i) z a a a e n I 2 RECOVERABLE COAL (millions of tons) WESTERN ARCTIC =... COAL DEVELOPMENT — PROJECT STRIPPING RATIO vs. TONS ee Denton Civil & Mineral 2 Figure 5-2 Safety Bench Height & Width Variable ances. Surface from Survey Crop Cover Variable Sediments Hiwall Slope rn \/4V to | H Hanging Wall Waste = 0.5 ft Coal Dip Variable Recoverable Thickness Variable (see note) Note: Within burn area, DFS 3 Seam is considered 30% recoverable on ee from crop to 150' down dip a PROJECT 60% to 250' down dip @ 100% ree recoverable beyond 250'. TYPICAL SECTION Prepered by Date: Denton Civil & Minera In 31-88 Figure 5-3 CROSS SECTION at 36,000 East Scale |"=20' H&V ORIGINAL GROUND DOZER ONLY PUSH SOUTH \ HOE & DOZER SIj100 N 51|200 N 5 WESTERN ARCTIC C2. COAL DEVELOPMENT rest PROJECT TYPICAL SECTION STRIPPING PLAN Prepered by Date Denton Civil & Mineral |_! /!5 788 Figure 5-4 CREW ROTATION 4 5 6 CREWS UTILITY DOZER BACKHOE HAULING ORILL & BLAST orPpPqmorewregdrpw p> SUPERINTENDENT SUPPORT TOTAL PERSONS 6s8sg9999 8677889999 66 TASK STRIP ZONE | BLAST ZONES 1&2 STRIP ZONE 2 STRIP ZONE 3 STRIP ZONE 4 LOAD & HAUL COAL BACKFILL PIT CONSTRUCT HAUL ROAD WESTERN ARCTIC m= .. COAL DEVELOPMENT PROJECT ANNUAL SCHEDULE 20,000 TPY RATE Denton Civil & Mineral 1/15/88 Figure 5-5 E ° ® ” vt ” L a e ® o m no re a N SN S / DFS 2 Seam WESTERN ARCTIC COAL_ DEVELOPMENT PROJECT MINING AREAS Prepared by Figure 5-6 inera Denton Civil & M Paragraph 6.0 INFRASTRUCTURE EVALUATION Index Introduction. ................ 6.3.4 General . 3 2 sss ew « 7 6 0 © 6 0 6 Approach ........ Sources of Information .. coe eee Berthing Facility Location Option 33 as 16ers General .. 2 2. 2. ee Analysis ............2..2.. 6.2.2.1 Mitigation of Disturbance to Offshore Marine Life... ..... See ee 6.2.2.2 Impacts to Omalik Lagoon. ......... 6.2.2.3 Impacts to Mining Haul Road ........ 6.2.2.4 Impacts to Construction Costs for Channel and Basin «9.3 «2s ss sss =» 6.2.2.5 Impacts to Permitting | Requirements so epee Systems (50,000 tpy scenario) ......... General «5 6 6 3 ss ss ee 3s i at Bs Camp Population. ............ a ater Supply System. ......... =e 3.1 Water Source... 5. . «6 6 6 ss « « ._4 2 Water Supply ......... ~ 5 © «js © 3 Water Reservoir ..........2.. =. 4 Water Treatment... << «4 4 8 s « s % s « Waste Disposal/Hazardous Waste Management . . . 35 3.3. 323% 3.3. lid 3.4.1 Solid Waste... 2... 2... 2. ee ee 3.45 : ; r / 6 W 6. 6. 6. 6. So 6. 6. Sewe Fuel 6. ue 3.6.1 Power Generation for Camp .......... 6.3.6.2 Oi] Spill Contingency Plan ......... 6.3.7 Preliminary Facilities Cost Estimate ........ Camp Facility Requirements (20,000 tpy Scenario) ...... 6.4.1 General... 2... 2... ee eee 6.4.2 Camp and Maintenance Facilities ........... 6.4.3 ano PPP aon 6.4.2.1 Camp Units... ...........024. 6.4.2.2 Maintenance Building. ........... Camp Utility Systems = 5. 6 2 5 ss oe Ss ee ee 6.4.3.1 Water Supply System ............ 6.4.3.2 Solid Waste re 6.4.3.3 Sewer Treatment .. ee ee a se 6.4.3.4 Power Generation for Camp. ee Fuel Storage ...... ee Camp Capital Costs ......... sees Camp Operation and Maintenance Costs ........ wv @ © oe ee i ADAAAAA an BWW Aan . 2 8) bee a aR OMOWMDIN UND anu AAAAAAAH wv gy © Paragraph 6.5 Road, Airport, and Sensina/ Stockett Area Requirements . General po. 47s oo 6.5. i : 6.5.2 Material Sources — 6.5.3 Road Options (20,000 tpy “Scenario) | 6.5.4 6.5.5 Airstrip (20,000 tpy Scenario) Stockpile/Staging Area ..... 6.5.5.1 General ........ 6.5.5.2 Stockpile Pad and Ramp (50,000 tpy Scenario) . 6.5.5.3 Stockpile Pad and Ramp (20,000 tpy Scenario) . 6.6 Revised Marine Transportation Facility . 6.6.1 General... 6.6.2 Discussion of Lighterage Operation ‘Options. 6.6.3 Barge Leading Cost Estimate... 6.7 Conclusions ee ee ee 6.8 References ID? ay in: a PHPH HH HSH AAALPwWMHPM ao i > ~N ioe eo Awnwowonra GPG) GY G1 'Gy Gy AaiLPrPeppLp Tables Number : Page 6-1 Solid Waste Calculations... ie sj) & @ OP 20 6-2 Effluent Quantity Requirements, “Maximum Averages ae » 2 « « 6728 6-3 Facilities Construction Cost Summary - 50,000 tpy ..... 6-35 6-4 Facilities Annual Operations and Maintenance Cost - 50, 000 tpy —.—. 6. 0 9 oo 8 se se ee es ws 038 6-5 Facilities Construction Cost Summary - 20,000 tpy ..... 6-41 6-6 Facilities Annual Operations and Maintenance Cost - 20,000 tpy . ie os 4 6 Be oe se ee es a we 2 6M 42 6-7 Barge Loading Costs. a «1 6-8 Infrastructure Cost Summary ............... . 6755 Attachments Figure 6-1 Deadfall Syncline Project Site Plan Figure 6-2 Marine Berthing Facility Option: NE Corner of Omalik Lagoon 6.1 Introduction 6.1.1 General A previous Phase II report, entitled Western Arctic Coal Development Project Infrastructure Preliminary Design Technical Memorandum (ASCE 1986a) (hereafter abbreviated IPDTM) was prepared in February 1986 by ASCE; that report presented conceptual design criteria for the buildings, airfield, road, berthing facility, utilities and other relevant infrastructure elements. The purpose of the Phase III infrastructure tasks were designed to augment Phase II by providing some special studies identified as necessary in the Phase II report. Specifically, the scope of this section Vs: 1) Provide an alternative location option for a marine berthing facility on Omalik Lagoon; 2) Examine options for disposal of dredged spoils assuming construction of a dredged channel at Omalik Lagoon; 3) Elaboration of requirements for, and costs of, the utility infrastructure at the camp assuming a 50,000 tons per year (tpy) production rate; 4) Examination of the infrastructure requirements and costs at a 20,000 tpy production rate. 5) Incorporate results of the hydrology investigations to be performed by ASCE. 6) Incorporate results of the coastal sediment transportation assessment to be conducted by Coastline Engineering and Consulting. 6.1.2 Approach The present report can be viewed as an outgrowth of the Phase II report, and the methodology as described in that report has been followed also in Phase III. The basic approach used by ASCE has been to develop a series of options for the various infrastructure components. Once proposed, these options were examined on the basis of environmental, technical, and economic practicality for that specific component, If still a potential contender, the environmental, technical, and economic impact on the overall system was then determined. The options that proved too expensive or technically impractical were eliminated from further consideration. The Phase II report defined the most economic technically feasible options for the infrastructure components as were identifiable at the time the final report was prepared. The Phase III report follows the example of the Phase II approach, insofaras new options are proposed. 6.1.3 Sources of Information In the conceptual development of the design alternatives, ASCE applied tried and proven technologies in the field of cold regions engineering and design. Subconsultants were retained to add depth of experience in various disciplines to the project, and general engineering literature was used to enhance the foundation of the conceptual designs. In addition, a number of suppliers were contacted to obtain information on cost and availability of utility systems for remote camp applications. Several previous reports were issued by ASCE and its subconsultants during Phases I through III of the WACDP. These reports, and many other information sources, were examined in the process of selecting the infrastructure component alternatives. (See Subsection 6.7, References.) 6.2 Marine Berthing Facility Location Option 6.2.1 General So as to minimize channel requirements, construction costs, and impacts to natural conditions within Omalik Lagoon, the IPDTM proposed siting of the dredged turnaround basin at the northwest corner of the lagoon. Review agency comments requested an analysis of the impacts of shifting the basin location to the northeast corner of the lagoon so as to increase the separation distance between barge loading operations and the marine environment offshore (refer to Figure 6-1). Of particular interest was the minimization of the disturbance of belukha migration patterns by barge movements (occurring as both acoustic and wave generation patterns) and on-shore heavy equipment operations (acoustic disturbances). 6.2.2 Analysis 6.2.2.1 Mitigation of Disturbance to Offshore Marine Life Discussions with the Environmental Task Leader indicate that shifting the basin inland will have a positive impact on mitigating potential disruption of belhuka migration patterns. 6.2.2.2 Impacts to Omalik Lagoon The approximate surface area of Omalik Lagoon is 450 acres. Construction of the turnaround basin and berthing facilities as proposed in the IPDTM will result in’ the withdrawal of approximately 20 acres, or 4.5%, of this surface area. Relocation of the turnaround basin, berthing facility, and entrance channel (reference Figure 6-2) to the NE corner will withdraw 55 acres or 12% of the lagoon's existing surface 6-5 area. ‘The impacts of this diminished surface area upon biological activity in the lagoon are minimal. It should be noted that Omalik Lagoon jis actually not an estuary, as its name may imply. Rather, it is really a brackish freshwater lake. 6.2.2.3. Impacts to Mining Haul Road Shifting of the berthing facilities inland will yield a net reduction in road length of approximately 1530 linear feet, or 5% of the overall length estimated in the IPDTM. Incorporating the unit cost of $55.45 per linear foot of roadway developed in the IPDTM, a construction cost savings of approximately $85,000 is realized. There will also be small reduction in the maintenance burden for the haul road. 6.2.2.4 Impacts to Construction Costs for Channel and Basin Shifting of the berthing facilities inland will increase the length of the dredged channel by approximately 700 linear feet. Utilizing the typical cross-section developed for the channel proposed in the IPDTM, an estimated increase in initial dredging requirements of 60,000 cubic yards is estimated. Based upon the unit cost of $3.10 (operation and labor costs) developed in the IPDTM for dredging, a construction cost increase of $186,000 is calculated. Embankment for construction of the dike walls for the channel is assumed to be incidental to the dredge excavation operations. Discussions with the sediment transport consultant (Doug Jones, Coatline Engineering and Consulting, pers. comm. 1987) indicated that the additional maintenance dredging requirements developed by extending the channel into the lagoon will be negligible, as the width of the lagoon breach 6-6 6.3 Camp created by the channel is insufficient to generate impacts from the sediment-laden longshore currents. Dredging will still have to be done annually (see Appendix G). Dredged spoils would probably be disposed of by constructing the lagoon berthing facility and, perhaps, a portion of the haul road. Excess spoils would likely be disposed of at sea, down current from the dredged channel]. However, the disposal must occur within the constraints of permitting requirements (see Appendix F). 6.2.2.5 Impacts to Permitting Requirements As development of the channel, turnaround’ basin, and berthing facilities will require approval from the Corps of Engineers (COE) (as well as other regulatory agencies), a preliminary inquiry was made with the COE Regulatory Branch to solicit an opinion as to their probable position on the location of these facilities. Discussion with Permit Officers indicated that the COE is not inclined to favor any intrusion into the lagoon without a detailed analysis. They will probably require an exhaustive analysis of other transportation options and a determination of benign impact upon construction both offshore and within the lagoon. It therefore seems reasonable to assume that obtaining permitting for facility locations at the northeast corner of the lagoon will be significantly more difficult than a northwest location adjacent to the Chukchi Sea. Utility Systems (50,000 tpy scenario) 6.3.1 General This section presents a limited design analysis of a utility system to provide basic services such as water, power, and waste C7 disposal for a permanent camp supporting the WACDP's proposed mining operations. The development of a 50,000 tpy facility is the focus in this subsection; jJater, in the next subsection, there is a discussion of the case wherein a 20,000 tpy production scenario is assumed. Conceptual site and floor plans for the camp and maintenance facilities were developed in Section 6.0 of the IPDTM. The present report addresses the provision of basic utilities as well as development of a camp facility which provides for the overall] health, safety and convenience of the workforce and protection of the natural environment. These criteria find expression in generally accepted engineering standards for cold climates (Smith, 1986) and in-State and Federal environmental regulations. Specific topics covered herein are: 1) Camp Population 2) Water Supply 3) Wastewater treatment and disposal 4) Solid waste/hazardous waste management 5) Fuel/power supply and oi] spill contingency plan 6.3.2 Camp Population As outlined in the WACDP Phase II Final Report, Volume I (ASCE, 1986b), the “base case" coal production scenario of 50,000 tpy anticipates the employment of eighteen people in the WACDP Deadfall Syncline mining area during an April to September annual operating period. Should market demand push annual production above 75,000 tpy, the number of employees at’ the coalfield will rise to 20. During the mine operating season, camp facilities must not only provide for a resident population employed in mining operations, 6-8 "? but also for visitors to the site. Visitors are expected to include representatives of the North Slope Borough as_ well as State and Federal agencies; geologists; engineers; flight crews; suppliers; and additional repair/maintenance personnel. The number of transients on-site at any given time should be regulated by the camp staff. In theory, the maximum on-site population will be fixed by the availability of sleeping quarters, a scarcity of which should discourage visitors extraneous to the mine operation. The actual numbers of transients utilizing camp facilities is difficult to predict. For purposes of this analysis a maximum of 24 personnel jis assumed, consistent with the sleeping quarters. During the off-season months of December through March, the camp is assumed to support only 2 caretakers, with occasional visitors. 6.3.3 Water Supply System The water supply system to the campsite can be described as consisting of the following components: - Water Source - Supply Line to Camp (including pumps) - Untreated Water Reservoir - Water Treatment Plant - Treated Water Reservoir - On-site Distribution (pipe, pressurization equipment, etc.) In this subsection, we will outline the components of the system and estimate the costs of constructing and operating the system. 6.3.3.1 Water Source A freshwater lake, designated as "Freshwater Lake" by the 6-9 project team, has been identified as the water source for the Mormon West Block mining unit camp (reference Figure 6-1 for location and Appendix H for hydrology data of the area). Freshwater Lake was selected as the primary water source for four reasons: - near-pristine water quality; - proximity to proposed camp facilities and road corridor; - appropriate isolation from proposed mine drainage area; - apparent adequate volume and recharge potential to support annual water supply requirements. Freshwater Lake is located within Section 25, T. 3 S., R. 45 W., Umiat Meridian, approximately 2.3 miles southwest of the proposed campsite, and within 500 feet of a proposed access road between the mining area and proposed berthing facilities at Omalik Lagoon. Freshwater Lake's water surface elevation is believed to fluctuate to some extent, although no precise survey data is currently available. At present, best available mapping vertically locates Freshwater Lake between 75 and 100 feet above mean sea level (msl); it also indicates two small streams flowing from Freshwater Lake and daylighting at about the 75 foot elevation. By interpolation, the lake surface appears therefore to be located between 80 and 85 feet msl; however, an ASCE field geologist reports that the lake's surface in June, 1987 was approximately 5 feet below the outlet stream elevations, (Tom Mortensen, ASCE, pers. comm., 1987). Thus, a conservative estimate for the lake surface elevation is 75 feet msl. A field survey to establish the surface elevation more exactly will be necessary during the detailed design effort. 6 - 10 A water sample was taken from Freshwater Lake on July 26, 1985, with analysis performed by an Anchorage laboratory on August 12, 1985. (ASCE, 1986a). The analysis focused on inorganic compounds regulated by the EPA, and determined that all constituents had concentrations of 10% or less than the EPA's maximum allowable limits, except for turbidity and iron content. The water was found to have a turbidity level of 16 NTU, sixteen times greater than the EPA's limit of 1 NTU. It was also reported that the water had an iron content of about three times the acceptable limit. No bacteriological tests were performed in this analysis. A second sample was taken from Freshwater Lake on June 21, 1987 and analyzed on July 2, 1987, yielding similar positive results against sanitary criteria, again with problems in turbidity and iron content. Based on orthophotographic mapping, Freshwater Lake is estimated to have a_ planimetric surface area of approximately 499,000 sq. ft (11.4 acres). Three lake depth soundings were taken from a helicopter, using a fiberglass tape and weight, on July 23, 1985. The measured depths were 13', 10' and 9', within an accuracy of plus or minus one foot. If the average depth of the lake is taken to be 9 feet, then the estimated volume of water in the lake is 4,490,000 cubic feet, or about 34 million gallons. A typical value for per capita water consumption in Arctic construction camps is 85 gallons per capita per day (gpcd). Given an average population of 24 people in camp for 180 days per year, an annual water demand of 367,000 gallons is estimated, exclusive of fire flows. However, if measures to control water consumption are employed, per-capita consumption can be reduced to 55 gpcd, and annual water demand for a six-month season would be about 240,000 gallons. 6 - 11 Withdrawal of this quantity of water from Freshwater Lake represents an estimated 0.7% annual volumetric depletion. The impact of a regular withdrawal upon Freshwater Lake's water budget can, however, only be crudely estimated. Field survey indicates that Freshwater Lake is a local depression with no prominent drainages entering or exiting the lake bed. A flat, barely defined swale was observed during the site visit to provide a channel for limited runoff from the lake. Water loss through surface runoff is therefore assumed to be- minor (less than 10% of precipitation). Given the .narrow range of the active layer at Freshwater Lake's latitude, water loss (and recharge) through soil infiltration is assumed to be negligible (approaching 0%). A final source of Joss is evaporation. The limited data base of evaporation studies in the Arctic suggests that an annual lake evaporation rate of 5 inches is conservative. Consequently, given an estimated annual precipitation of 10 inches (Hartman and Johnson, 1978) and an estimated annual water loss of 6 inches (5 inches through evaporation and 1 inch through runoff), Freshwater Lake appears to be increasing in volume. A second hypothesis, based only upon a visual field survey, is that Freshwater Lake has bottom ice which is slowly melting, realizing a decrease in aggregate water volume without a loss in water mass, thus lowering the lake's surface elevation. If the rate of decrease in water volume through ice-melt equals or exceeds the precipitation rate, the lake's surface elevation will either remain stable or slough. The annual water budget for Freshwater Lake may be roughly estimated as having a surplus of 4 inches. Assuming a 50% overestimation, an annual surplus of 2 inches, or 600,000 gallons, still remains, sufficient to accommodate anticipated 6 - 12 ~~ water demand for the mining operation. Thus it appears that the annual withdrawal from Freshwater Lake will be offset by surpluses in the water budget. Should unaccounted water losses become apparent, mitigative measures, such as snow fencing and subsequent accumulation, can be employed to increase Freshwater Lake's recharge potential. The Chukchi Sea is also a_ potential supply alternative. Package desalination units are commercially available and have been successfully used in North Slope operations. However, this system would be problematic in at least two respects: = the Chukchi Sea lies over five miles from the proposed camp, requiring a longer transmission main than a system utilizing Freshwater Lake, with consequent increased construction, operation, and maintenance costs; and, = because the winter ice freezes fast to the seafloor for several hundred feet offshore, special measures (either extension of the intake line or expanded storage facilities) will be necessary for winter and spring water supply. In view of these undesirable expenses and operational complications, desalination is not recommended as a water supply option. 6.3.3.2 Water Supply Water supply in remote Arctic areas is generally accomplished by one of two systems. Water may be pumped from the lake into a_ truck-mounted tank, hauled to the campsite, and unloaded into a reservoir. Alternatively, a permanent pump station may be installed at the lake, and a raw water 6== 13 supply line constructed to- the camp, where it would be treated and distributed. As the uninterrupted delivery of potable water is a limiting factor in mining operations, the selection of a supply system must address three critical components: access to the supply route, storage capacity, and winter pumping operations. - Road requirements: Regardless of the water transport option selected, development of an access road is an essential element of the construction, operation, and maintenance of a water supply system. .~ Reservoir: As with an access road, a water reservoir located near camp is necessary, regardless of the method of transport utilized. The reservoir provides for supply during interruptions of the transport system and during fire-related emergencies. Fire flow requirements will be more fully discussed in a later section. The transport system selected will, to some extent, control the appropriate reservoir capacity. - Winter Pumping Operations: During summer operations, or during periods when the freeze depth on the lake surface is shallow, water pumping operations are uncomplicated. Should mining operations continue into the winter months however, the increasing depth of freeze in Freshwater Lake (and all _ local waterbodies) will impede access to liquid water. Moreover, because the freezing process leads to the concentration of impurities in the liquid water, the presence of turbidity and iron concentrations in drinking water will increase geometrically, realizing a significant decline in water quality. Consequently, as winter progresses, the depth of liquid will grow shallower and impurities become more concentrated until finally 6 - 14 treatment is impractical. If a reservoir sufficient for winter and spring water requirements has not been developed, it will be periodically necessary to fracture and collect ice from the lake surface, drop it into a melting tank, melt the ice and transport the water to the camp for treatment and distribution, a costly, labor, and energy-intensive system which will be discussed in greater detail below. Following are options available for the water supply: 1 OPTION 1: WATER HAULING: Water hauling is a very basic system that has some flexibility. Should the primary 4 equipment, the truck or pump, fail, replacement or substitution may be available, if spare parts or spare equipment are at hand as well as a mechanic. One further advantage of water hauling is the avoidance of pipeline construction, a significant economic benefit during the construction phase of the camp facility. Water hauling typically has minimal capital costs (limited to mobilizing a truck and small pump to the project area), but high operation and maintenance costs, particularly in labor, fuel, and repairs. However, a truck's reliability does not compare favorably with a water supply line, in that a truck is periodically out of operation to permit maintenance or repairs. Such down time is more frequent, in general, for a moving piece of equipment than a_ stationary pump operating for only part of the year. Moreover, if spare parts are not available, as indeed they may not be in a remote site such as the coal project area, then it can be a very long time before equipment for hauling water can be brought back into 4 operation once broken down. 6 - 15 There is a further potential cost savings with water: hauling in the minimalization of reservoir capacity requirements. Because the system is easier, although not necessarily more cost effective, to keep on-line year-round, the storage reserve necessary to buffer systematic failure is reduced. Winter and spring water collection pose special problems, when it will be necessary to either regularly penetrate several feet of ice to permit pumping or to fracture and collect ice for a melting operation. A melting operation is problematic in two respects: 1) A melter unit, mounted on a truck or other dedicated hauling vehicle, would have been purchased in addition to a proper truck. 2) During the winter, the melter would have to shuttle back and forth between the lake and the camp. In addition, a ripper and/or loader would have to be stationed at or continually hauled to the lake in order to feed the melter. Thus, much additional crew time would have to be expended, on perhaps on a daily basis, simply to provide for camp water in the winter months. A significant contingent of equipment would be dedicated entirely to water supply needs representing both an increased capital cost anda maintenance ‘burden. Thus melting/pumping has some serious. drawbacks. The capital cost of a 2000 gallon melter unit, to be towed by truck, would be about $20,000 to $30,000 (Doran, 1987). The burner unit uses about 1 gallon of fuel per 20 gallons of melted water. Other associated costs include: truck cost, ripper & loader costs, and operator costs. 6 - 16 OPTION 2: WATER LINE OPTION: The conventional configuration for a water transmission and treatment system is to set up a stationary pump at a water source and pump to a nearby treatment facility. In this manner, the length of the raw water supply lines are minimized and the length of treated water supply lines is maximized. For typical municipal applications, this is the most efficient configuration: it centralizes supply operations and maximizes the amount of water main available to provide water service to abutting areas. J In this case, however, there will be only one central user of treated water: the camp. Clearly, the preferred location for the water treatment plant will be at the camp, in that a centralized location will minimize construction and operation costs, and will avert problems associated with trying to maintain remote facilities. Indeed, the Infrastructure Preliminary Design Technical Memorandum (ASCE, 1986a) does 5 assume that a package water treatment plant will be located at the camp complex. Nonetheless, it will be necessary to locate a pump at the water source. The pump horsepower requirements will be a function of the design flow rate, (which in turn will be influenced by the design water treatment rate if the storage is to contain treated water rather than raw water), pipe size and type, and the elevation difference between the reservoir and the source. Calculation of the needed horsepower was not attempted for this report, because many of the variables are yet undetermined. However, the pump will] probably be a centrifugal "trash pump." For year-round pumping, pre-insulated high density polyethylene pipe (HDPE) is the preferred material. KG pumping is summer-only, then non-insulated HDPE can be used. At least three options exist for the water supply line 6 = i7 installations. 1) The pipe may be placed within an above-ground utilidor, either at-grade or on pile supports. 2) The pipe may be buried within the road embankment fill. 3) The pipe may be placed directly on the tundra. Some advantages and disadvantages of these options are as follows: a. Utilidor: Advantages: 1) Provides a conduit for multiple utility lines; 2) Utilidor is insulated; preinsulated pipe not required. Disadvantages: 1) High cost of fabrication, design, installation; 2) Unlikely that there will be a need for other utilities in the utilidor; 3) Exposure to damage from thermal effects, errant vehicle collisions, wind loading, and vandalism. b. Buried Pipe (in road embankment): Advantages: 1) Cheaper than utilidor; 2) Not exposed to environmental damage; 3) Increased protection from freezing. Disadvantages: 1) Maintenance requires excavation of roadway; 2) More expensive than option 3; 6= 18 c. Pre-insulated Exposed Pipe (laid directly on ground): Advantages: 1) Avoids excavation; 2) Economical; 3) Accessible for maintenance and repairs. Disadvantages: 1) Exposed to damage from errant vehicle collisions, wind loading, and vandalism. d. Non-insulated Pipe (summer only operation): Advantages: 1) Cheapest overall; 2) Avoids excavation; Disadvantages: 1) Exposed to environmental damage per option 3. As mentioned in the previous section, these are serious problems associated with winter water pumping, related to cost of water recovery, maintenance of pumping equipment, and water quality. As a practical matter, year-around pumping is problematic at best and should be discarded as an option. Thus, only seasonal (summer-only) pumping is viable. This means that a non-insulated HDPE pipe can be laid on the ground, if a certain amount of maintenance is acceptable. Pumping can occur over a 2 to 3 month period in the summer/fall, using a trash pump. A sufficient storage capacity must .be provided to accommodate use after the pumping period ends. In summary, the recommended mode of transmission is an exposed HDPE line. (This concept is used in other Arctic communities in which similar constraints are present). The estimated cost of a 4" transmission main installed on the ground from the Freshwater Lake to a reservoir located 6 - 19 near the camp is approximately $109,000 (this figure excludes pump house costs estimated at $60,000). 6.3.3.3 Water Reservoir In an earlier section it was mentioned that the maximum demand scenario yields an annual water demand of about 367,000 gallons. This assumes an average of 24 persons present, using 85 gallons per-capita-per-day (gpcd), for 6 months a year. Implementation of water conservation measures, such as use of incinolet or watersaving toilets, or spring-loaded fixtures, can be employed to reduce the daily water use to 55 gpcd which yields an annual demand of 250,000 gallons. This lower demand value has been achieved in a number of Arctic camp installations. Assuming a two month pumping period within a six month operating season, a four month supply must be developed plus a residual fire protection supply. It is recommended that one extra month be added for supply purposes, to guard against the danger of prematurely draining the reservoir dry. Then for 24 people, using 55 gallons each per day for 5 months, and adding to this a required fire supply of about 30,000 gal (subject to ISO-type analysis), the required total storage is about 230,000 gallons. It is recommended that required storage be developed using multiple tanks instead of just one. There are two advantages to this. First, if the actual camp population can be an average under 24 people, then less storage is needed. (If, at a later date, additional storage is needed, it can be added). Second, it is desirable to use two or more tanks for the purpose of assuring flow if one tank is subject to freezing or some other mode of failure. 6 - 20 The tank or tanks will have to be insulated and heated (using water circulation). They can, perhaps, be partially buried in a non-ice-rich area of the initial mining excavation to help reduce insulation requirements. The cost of the tank or tanks, is estimated at about $250,000 including surface preparation (sandblasting) and painting and insulation. 6.3.3.4 Water Treatment The water treatment process selected will be a_ function of the physical and biological characteristics of the water source. As noted earlier, if Freshwater Lake is chosen, and pumping is limited to the summer months, about 15 NTU of turbidity must be removed. Although no information is presently available, it is assumed that the water source wil] be treated for removal of bacteria and, probably, giardia cysts. This will require filtration and chlorination or jodination. Water treatment is a _ physical/chemical process requiring some level of skill and attention on the part of the operator. The process will probably include sedimentation, flocculation, filtration and iodination. Specific units would likely include: - Raw water transfer pumps - Sedimentation (grit) chamber - Polyelectrolyte (flocculent) injector - Flocculation basin - 10 micron sediment filter - 5 micron giardia filter - lodinator - Flow control valve - Pressurization pump tank Cel - Taste-and-odor-control carbon filter - Treated water storage (minimum 2 day storage) The finish assembly could be assembled with a _ sewage treatment plant in the same modular unit, but only if the size of the water treatment unit is compatible. The cost of the treatment plant (assuming that the unit cannot be combined in the same building with the sewage treatment unit) is estimated at about $50,000. 6.3.4 Solid Waste Disposal/Hazardous Waste Management 6.3.4.1 Solid Waste An important consideration in the planning of the proposed camp is the method of solid waste disposal. Because of the remoteness of the camp, reliance upon existing landfills, j.e., the Point Lay landfill, is not appropriate. Thus, it is likely that some means of independent solid waste disposal must be developed. The disposal is, however, complicated by the presence of shallow, ice-rich permafrost, which renders the typical methods of sanitary landfilling non-applicable. The "Cold Climate Utilities Manual" (Smith, 1986) cites generation rates for pipeline construction camps at 2.7 kg/person/day, (6.0 1b/person-day). This compares with an Alaska Department of Environmental Conservation (ADEC) design value of 3.6 kg/person/day (8.0 1b/person-day). Loose refuse density (with no processing) is reported to be 60 to 120 kg/m> (4-8 1b/ft*). It is further estimated that the combustible component of the total solid waste stream includes paper products, food wastes, wood and textiles is approximately 65%. Noncombustibles for incineration purposes would include plastics, rubber and leather, as well as such inert materials as metals, grit, glass and ceramics. 6 = 22 An incinerator should be constructed in the camp to reduce organic and garbage to a relatively inoffensive, inert state and thus compact the refuse volume. A brief review of the technical literature does not produce an average or typical volume reduction factor for incinerated waste, but ash density is reported to be 1100 to 1400 lb/cu. yd. (41 to 52 lb/cu.ft.), or an average of 1250 1b/cy (46 1b/cu.ft.) Using ADEC's design value of 3.6 kg/p.d (8.0 1b/p.d.), and assuming a loose refuse density of 90 kg/m? (5.6 1b/ft?) and a backfilled density of 400 kg/m* (25.0 1b/ft?) the following values for a 24-person, 6-month camp are presented in Table 6-1. TABLE 6-1 Solid Waste Calculations Item Weight Loose Volume Backfilled Volume Daily total waste 192 1b 24.3 cu.ft. tener (pre-incineration) Daily combustible waste 125 1b 22.3 cu.ft. 2.7 cu.ft. (pre-incin. ) (post-incin.) Daily noncombustible waste 67 1b 12.0 cu.ft. Z.7 cu.ft. (no incineration) Daily post-incinerated 192 1b n/a 5.4 cu.ft. total backfill Annual post-incinerated 34,600 1b. n/a 979 cu.ft. total backfill n/a (36 cu.yard) Note: The above figures conservatively assume no mass loss during incineration. 6 > 23 Disposal options after the incineration of combustibles includes: 1) Shipment to Point Lay landfill 2) Trenching and backfilling 3) Landfill in abandoned mine areas The first option is possible but is not recommended at this stage, due to the logistical uncertainties (particularly ina winter operation) and the uncertainty of the landfill's availability. The second option is used widely in the North Slope, and the third option would take advantage of the fact that the mining operations themselves open up possibilities for landfilling. In any event, the operation of a landfill will require a waste disposal permit from the ADEC per 18 AAC 60. The permit will require, among other things, plans. and specifications, an aerial photograph of the area, an operational description, and an evaluation of the site's leachate generation and water pollution potential. Cost for an incinerator and trenching and landfill operation is as follows: 1) Incinerator $21,000/each 2) Trenching/Landfilling 5 ,000/year While not directly related to solid waste operations per se, it will also be necessary to provide fencing around the campsite to prevent temporarily-stored solid waste from functioning as a food source for wildlife (e.g., bears). 6.3.4.2 Hazardous Waste Hazardous wastes anticipated to be generated by project operations include some waste oils, fuel sludges, cleansers 6 - 24 and solvents, coolants, grease, and other products typical of an earth moving operation. Not all waste oils need be disposed of as hazardous waste. An Environmental Protection Agency (EPA) approved incinerator can, and _ should, be available on-site to burn non-hazardous waste oils, as well as reducing solid wastes. Relatively few disposal options exists for hazardous waste: regulations require that it be packaged in an approved manner and transported to an approved hazardous waste disposal facility. At the time of this writing, no such facility exists in the State of Alaska. Thus, the waste must be transported to facilities on the West Coast, such as exist in the state of Washington. Hazardous waste generation is expected to occur almost entirely within the camp facilities, particularly in the vehicle and equipment maintenance facility. Accumulated liquid products, anticipated to be the most common form of waste, will be stored in 55-gallon drums in an ADEC and EPA approved facility and removed at the close of each mining season. Transportation and disposal out-of-state will be arranged through private firms which specialize in hazardous materials disposal. These firms act essentially as brokers, and can arrange for shipment/disposal and can even package the material on-site. A very conservative estimate places annual waste quantities at 2,000 gallons. Disposal costs, including transportation, are estimated at $400 per drum. 6.3.5 Sewer Treatment The conceptual sewer treatment plant depicted in the IPDTM indicated a package sewer plant within a modular utility/life support building, which would drain to a sewage lagoon. The 6-=—25 lagoon itself was facultative and would either leach out to the tundra or incorporate an alternative outfall method. Upon investigation, it-has been determined that this lagoon will probably be unnecessary, and that construction and proper operation of a package plant should be sufficient. A properly operating system can, according to suppliers, discharge wastewater meeting secondary treatment standards. In this case, discharge would go onto the tundra. Needless to say, permits would have to be obtained from all regulatory agencies prior to beginning the operation of sewage discharge. As noted in the previous section, a water consumption rate of 55 gpcd can be expected for the camp. The domestic usage rate assumes that Incinolet-type toilets will be installed (at a cost of about $2000 each, F.0.B. Anchorage), but does not assume the use of water-saving measures such as watersaver faucets/showerheads and saunas. If flush toilets are installed, estimates of use will be more like 85 gpcd. It should be noted, however, that water-conserving fixtures could reduce usage to as low as 30 gpcd. For purposes of this discussion, we will assume a usage of 55 gpcd with Incinolet toilets, which reduce urine and feces to biologically inert ash. Experience has demonstrated the Incinolet to be of great value and has worked well in numerous remote camp installations. There are, however, several disadvantages. First, Incinolets require frequent and proper’ cleaning, an operation which essentially amounts to ash _ disposal. Second, users must be educated to their proper use which involves placement of a paper liner in the basin, and proper procedure most be enforced. Third, they are associated with particularly unpleasant odors, especially when liquid wastes are involved. From an engineering and planning perspective, these factors- especially the last two- 6 - 26 are potentially serious drawbacks, as they directly relate to user acceptance, a human factor that cannot be predicted. (If people will not accept the proper use of the Incinolets, it will probably be necessary inthe end to replace them with watersaving flush toilets. Nonetheless, Incinolets use will be assumed for design calculations). In addition to water conservation, the use of Incinolets will have one major advantage: it will eliminate "blackwater" discharge into the sanitary sewage stream. Thus, sewage treatment would be for graywater only. While this would not necessarily translate to reduced suspended solid and BOD loadings in the sewage stream, it would at least dramatically reduce the coliform and pathogen loading. It should be noted that this would not necessarily hange the treatment process design, but would be of obvious sanitary benefit. The Incinolet ashes, which is all that remains of the human waste, are disposed of as solid waste. For purposes of sewage treatment design, the critical variable is maximum daily flow. Total seasonal flows are not normally important unless extended-storage lagoons are used. However, existing package plant designs do not generally require use of lagoons. The population for design purposes will be assumed at 24. Then the average daily flow is 24 hrs. persons x 55 gpcpd = 1320 gal/day. The maximum daily flow will be assumed during 24 hrs using 24 persons @ 85 gpcd = 2,040 gpd. To comply with federal effluent quantity requirements, the following monthly/weekly maximum averages shown in Table 6-2 must accrue: 6) = 27 TABLE 6-2 Effluent Quantity Requirements Maximum Averages Maximum Monthly Maximum Weekly Parameter Average Average Biochemical oxygen demand (BOD;), mg/1 30 45 Suspended solids (SS),mg/1 30 45 “Fecal coliform (1b/100m1) 200 400 pH (required average range) 6-9 6-9 The influent stream characteristics will not be known to any degree of certainty until the camp is in operation. However, it is possible to estimate influent characteristics based on historical data from other installations. The "Cold Climate Utilities Manual" (Smith, 1986) cites an average chemical oxygen demand (for graywater) at 210 mg/1, with influent suspended solids averaging 290 mg/1. Biochemical oxygen demand can be considered negligible, but only if food grinders (garbage disposals) are not installed in kitchen sinks and grease traps are installed. In summary, the following design operating parameters of the sanitary sewage stream have been identified: - Maximum flow 2040 gpd = Coo 210 mg/1 - Ss 290 mg/1 In a municipal applications, where much higher flows are typical it would be necessary to conduct a rigorous analysis and process selection/design for the characteristics of the wastewater. It would then be necessary to construct, as a unique facility, a wastewater treatment plant. This process proves very cumbersome 6 - 28 for a small-scale operation such as the subject project. Fortunately, sewage disposal problem in remote camps’ has an extensive history, and several prefabricated package treatment plants are commercially available. Two Anchorage suppliers of these systems were contacted and offered descriptions of package plants which have been widely used in rural Alaskan villages and remote camp installations. In the following discussion, the processes involved are briefly described. OPTION 1: ALASKAPAK SYSTEM (Supplier: Steel Fabricators) This extended-aeration package plant is designed to handle 3000 GPD of domestic sewage averaging 200 mg/l (+30%) BODs (Doran, 1987). The tank has two compartments. The treatment process is as follows: Raw sewage enters the plant in the 3,000 gallon aeration compartment wherein the sewage is continuously rolled and aerated by the aeration system as it flows toward the clarification compartment. The aeration process is designed to last twenty-four hours. The sewage, now identified as mixed liquid, flows into the 700 gallon clarification compartment which is maintained in a quiescent state and wherein the suspended solids are allowed to settle by gravity into the hopper bottom. The solids are air lifted back into the aeration compartment as return sludge for recirculation. The clarified effluent flows over a weir into a collection trough and is discharged out of the compartment through a chlorinator unit (which kills remaining pathogenic bacteria), then to the environment. Optional equipment can include a surge tank, digester, sand trap, comminutor, and other features. The extended aeration plant is installed inside a modular unit that can be supplied by the 6 - 29 fabricator. The configuration can include not only the Alaskapak plant, but also the sewage lift station, water treatment plant, and, if desired, an incinerator unit garbage compactor and laboratory. The structural steel unit is skid-mounted. The supplier will, on request, size the units to fit onto a Hercules aircraft in sections, or completely assembled ona barge. The Alaskapak removes 85% - 95% of BOD and TSS. Effective operation requires that garbage disposals not be allowed in kitchen sinks and that grease traps be installed. OPTION 2: PHYSICAL/CHEMICAL PROCESS UNIT (Supplier: Garness Industrial) Garness Industrial of Anchorage fabricates a modular package treatment plant which uses a different kind of treatment process (Garness, 1987). This is a "physical chemical" (PC) process, similar in kind to processes used in water treatment. (The Alaskapak system, by contrast, uses a biological treatment process). A typical PC-process used in the Garness plants is as follows: raw sewage influent is brought into the plant area by use of a sewage lift pump. The influent may be directed into a surge tank if desired. Flocculating agents (e.g., polymer, alum, or soda ash) are added. The influent then enters the flocculating chambers in which floc formation occurs. Thence, the flow discharges into an upflow clarifier in which the chemical sludge is deposited. Supernatent from the clarified is discharged into a tube settler clarifier, in which further sedimentation occurs. The clarified flow then enters a multimedia filter; after draining through layers of anthracite, sand and gravel, filtrate effluent discharges. The effluent is chlorinated to kill remaining pathogens and is discharged into the environment. 6-30 The system, itself, has an excellent design is considerably more complex than the extended aeration unit previously described. Flocculants must be continually stocked and filter media backwashed, among other maintenance operations. The primary disadvantage is that trained operators must be _ provided, or locally hired individuals must be trained and educated in the processes control. While this is a very viable option, it is also true that, in general, complex processes have been problematic and have experienced failure through negligence in many rural Alaskan applications. To recognize this problem is not to criticize the supplier or the product; but it is important to be aware and vigilant prior to process selection. Like the Alaskapak, the physical/chemical unit is assembled ina modular unit, typically alongside the water treatment unit. The units can be assembled on-site in a_ stick-built building or shipped to the site via barge or air in a_ prefabricated building. The building would have to be altered to fit inside a Hercules aircraft, if shipped by air. At this time, it is assumed that the plants will be put into a stick-built building constructed at the site. The cost of a sewer treatment plant, is estimated at $50,000. It should be added that sewage lift pumps will be required regardless of the type of treatment system. The costs quoted for this system include necessary pumps. Sludge is an inevitable byproduct of either process. The preferred alternative for disposal will be to dewater the sludge and incinerate it in the camp incinerator. However, the fuel costs for incineration can be considerable. Landfill disposal is another option, one which is likely to be less costly, but which will require ADEC approval and special disposal operations. 6.3.6 Fuel/Power In order to successfully operate the coal mine and camp, it will 6 - 31 be necessary to provide power, heat, and machinery fuel. The heavy equipment will also require diesel fuel, which must be mobilized to the site. The diesel should be type No. 1 for functionability in cold weather. On-site storage must be developed for this fuel, which includes containment within a diked storage area. 6.3.6.1 Power Generation for Camp The IPDTM recommends that two 150 KW generators (one primary and one standby) be constructed inside the modular life support facility. The generator(s) would be powered from a 100 gal fuel oi] day tank. The generator size appears, using a rough check, to bea reasonable size, -if we assume that the modular camp units may be heated using electric heat. The generator must also accommodate peak loads about 2 or 3 times the average demand, which further supports the use of 150 KW = generators. However, the exact size is subject to final design. It should be noted that, because of the small unit size of the camp heating and power generation units, it will not be feasible to use coal produced energy; diesel #1 must be used. Using an average demand of 100 KW for an assumed 7 month operating period, and a diesel #1 heating value of 138,000 Btu/gal, the total diesel needed for power (including electric heat) is estimated at around 60,000 gallons per year. We will use this value for purposes of estimated fuel storage requirements. Adequate on-site storage for diesel (and possibly gasoline) must be provided, and diking provided to contain possible fuel spills. (See Section 6.3.6.2 below). Fuel storage Cae development costs are estimated at $1.50 per gallon in-place. It is also estimated that vehicle fuel requirements ina 50,000 tpy scenario are about 155,000 gallons (diesel and gasoline combined) (ASCE, 1986a) so it is estimated that about 215,000 gallons of storage will be needed for vehicles and power. The IPDTM estimated that 470,000 gallons of bulk fuel storage would be needed under a 50,000 tpy production scenario. This estimate included the fuel needed for vehicles, camp power, and mining operation. It also includes fuel needed for marine transportation and port operations. Thus, since the fuel requirements estimated above are folded into the IPDTM estimate, there is no need to provide a new cost estimate. However, it will be necessary to provide additional storage at the campsite, enough for several days of fuel. Two 10,000 gallon tanks, such as_ can be obtained from Ace Tank Company can be readily shipped to the camp. It is recommended that this weekly storage capability be developed. (Mobile fuel storage is also a possibility.) Two 10,000 gallon tanks to be delivered to the site and installed are estimated to cost $20,000 each or $40,000 total. This assumes that diked tanks from a Seattle or Alaskan manufacturer must be shipped in; it is possible, however, that surplus tanks can be obtained from the North Slope Borough at lower cost or for free. 6.3.6.2 Oi] Spill Contingency Plan Any on-site fuel storage must be contained by an impermeable impoundment basin or structure. ADEC design guidelines call for the impoundment basin or structure to contain 110% of the volume of the largest tank contained within. Supplemental regulations pertaining to containment area design are provided by the Uniform Fire Code. 6 - 33 In addition to the design standards, State and Federal laws require development of spill prevention and contingency plans. The EPA requires a document referred to as_ the Spill Prevention Control and Countermeasure Plan (SPCCP) while ADEC requires an 011 Discharge Contingency Plan. The SPCCP must be prepared by a registered professional engineer. These documents require detailed description of the fuel storage facilities, and methods of containing oil spills, including containment area design and operational practices. They also require a plan of containment if a spill should occur and a plan for removal and disposal of spilled oil. The ADEC document will require many particulars to be spelled out, such as contact personnel, equipment, estimated response time, and the like. 6.3.7 Preliminary Facilities Cost Estimate The facilities construction and operating cost estimates are presented below in Table 6-3 and 6-4, for the 50,000 tpy scenario. These estimates include the more detailed analysis of the camp utility requirements as presented above. 6 - 34 TABLE 6-3 Facilities Construction Cost Summary - 50,000 tpy Facilities WACDP Phase II, Construction Cost (1) Deduct Utility Facilities Utility Building Generator Module Total Phase II Cost Less Utilities Phase III Utilities Camp Fuel Tanks 20,000 gal. Power Generation. 2 @ 150 KW (2) Water Supply Pump, pumphouse, and 60,000 4" HDPE pipe 109,000 12,000 1f. @ $9/1f 250,000 gal. insulated tank 250,000 Treatment Plant (2) 50,000 Wastewater Treatment Plant (2) Solid Waste Incinerator TOTAL CONSTRUCTION COST Notes 1) Reference ASCE, 1986b Pg. G-29. incorporate life support facility building 2) Plant costs costs. 6 - 35° $1,911,280 <346 ,400> <306 , 400> <_ 40,000> $1,564,880 695 ,000 40,000 115,000 469,000 50,000 21,000 $2,259,880 Say $2,260,000 TABLE 6-4 Facilities Annual Operations and Maintenance Cost - 50,000 tpy Utilities $171,200 Fuel Oi] 7°? 48,000 Power Generation® ‘ 51,200 Water 17,000 Pumping Maintenance 7,000 Treatment Plant 10,000 Wastewater Maintenance 15,000 Solid Waste 25,000 Trenching/land filling 5,000 Incinerator fuel 5,000 Haz. Waste Disposal _ 15,000 Telephone? 15,000 Maintenance* 43,400 Custodial & Laundry 18,000 Preventive Maintenance 5,400 Specialty Maintenance 10,000 Miscellaneous 10,000 Food - 24-Man Camp $ 189,000 TOTAL FACILITIES O&M $ 403,600 Say $ 405,000 Notes 1) Fuel oil amount does not include mining requirement. 2) These costs are the same as WACDP Phase II Final Report (ASCE 6, 1986), pg. 6-57. 3) O&M costs are force account utilizing mining personnel. 6.4 Camp Facility Requirements (20,000 tpy Scenario) 6.4.1 General From the WACDP marketing efforts conducted during Phase II and early in Phase III, it appears the initial WACDP market most likely would be 20,000 tpy instead of 50,000 tpy as assumed in WACDP Phase II. The intent of this subsection is to explore the 20,000 tpy mining scenario camp facility requirements. 6 - 36 Building structures are planned to support the mining operation for the 20,000 tpy scenario. The structures consist of a 12-man camp, life support facilities, fuel storage, and vehicle and equipment maintenance/warm storage facility. 6.4.2 Camp and Maintenance Facilities WACDP Phase II performed a short alternative analysis of providng temporary facilities for a 20,000 tpy mining operation. This alternative looked at utilizing selected facilities for the 50,000 tpy mining scenario proposed in Phase II with the understanding the mining operation would increase to the 50,000 tpy scenario within a short period of time. This alternative utilized the 4,800 sf. pre-engineered metal structure proposed for the Vehicle and Equipment Maintenance/Warm Storage facility for both a temporary camp and maintenance building by modifying the building, through addition of a mezzanine and partitions. In the IPDTM the building costs were estimated to be reduced by $141,000 at the 20,000 tpy coal production level. This reduced the overall camp capital cost to $1,770,000. Early Phase III marketing efforts established a 20,000 tpy market in the initial phase of the project. Expansion to the 50,000 tpy scenario shortly after start-up is not anticipated as was the case in the Phase II 20,000 tpy analysis. Further, data pertaining to the vehicle maintenance requirements, mining method, camp population were not investigated in WACDP Phase II for the 20,000 tpy scenario. This information was developed in WACDP Phase III and appears ina January 1988 report, Denton Civil and Mineral (DCM, 1988). Equipment lists, mining methods, duration, and camp populations were presented in the report. It established a relatively short mining period (3 months) and low camp population (9 people). Based on the factors presented, it was determined to investigate a more efficient and appropriate camp and maintenance facilities for the 20,000 tpy production rate. On== 37: 6.4.2.1 Camp Units The camp will consist of four (4) ATCO camp units: 1 each 10' x 56' sleeper unit; 1 each 10' x 56' comination sleeper and lavatory unit; 1 each 10' x 56' combination kitchen and dining unit; and 1 each 10 x 40' water unit. All 4 units are heated by electricity. Fluoresent lighting will be installed throughout. The sleeper, kitchen and lavatory units are complexed by using four foot insulated floor and walkway sections. A description of each unit follows: 1) ATCO 10' x 56' sleeper has 4 sleeper rooms, each : room contains 2 closets, 1 desk, 1 chair and 2 beds. 2) ATCO 10' x 56' combination sleeper and lavatory has 2 sleeper rooms as in unit #1. The lavatory, 10' x 28' in size, has a linoleum floor and marlite walls. Three (3) electric Inocinolet toilets and 1 electric Inocinolet urinal will be installed, along with a 100 gallon electric hot water heater, 4 wash basins, 4 showers, 1 janitors sink, 1 washing machine and 1 dryer. 3) ATCO 10! x 56' kitchen and dining unit has commercial grade electrical kitchen equipment consisting of: Lang counter fryer; counter grill; stock pot range; Wells hot plates; Victory griddle stand; refrigerator; Lang convection oven; 10' stainless steel range hood with Ansul restaurant fire suppression system; dishwasher; 3 compartment sink; counters; Kelivnator freezer; coffee maker; toaster; mixer; work table; bus cart; dishes; flatware; glasses; ash trays and 100 gallon electric hot water heater. The 10' x 28' dining room has 3 each 5' diameter laminated tables with 6 - 38 12 each folding chairs. The 10' x 56' ATCO buildings are to be renovated to meet the requirements of this camp. The kitchen and lavatory ujnits will be retrofitted with new commercial grade appliances and Fixtures. 6.4.2.2 Maintenance Building A 40' x 100' ATCO Foldaway building (used) will be utilized for the vehicle maintenace and warm storage facility. It has fluorescent lights, electrical panel, and a 400,000 btu Pinn- Ohio model +34FS coal fired forced air furnace with stoker, blowers and controls. The maintenance building was provided with the same shop and industrial equipment as stated in the Phase II report, except for the bridge crane. This has been replaced with a movable gantry crane, which will augment the boom truck provided under the mining equipment. 6.4.3 Camp Utility Systems 6.4.3.1 Water Supply System Water supply requirements were estimated assuming the mining operation will take 100 days and there will be 12 people in the camp. Using 55 gpcd, then the average annual demand is 66,000 gallons. Adding about 15% for a safety factor, and adding 25,000 gallons for fire flow reserve, then a minimum storage volume of about 100,000 gallons should be provided. A 100,000 gallon insulated water storage tank would be erected at the camp site. The storage tank would be filled during the early fall by a 2,000 gallon tank truck, provided under the mining equipment, and will draw water from 6. =.39 Freshwater Lake as required to fill the water storage tank prior to freeze-up. The ATCO Potable Water/Grey Water trailor Unit (10' x 40') contains 2 each 5,000 gallon steel tanks, 1 tank is for potable water with water filtration and iodination systems and water pump. This tank would be connected by piping to the 100,000 gallon water storage tank. 6.4.3.2 Solid Waste An incincerator, 3' x 6' x 5', would be used to reduce garbage to a relatively, inert state and thus compact the refuse volume. The incinerator selected is an Econoline, rebuilt oil fired incinerator with 8' stack and 150 gallon fuel oil tank. Landfill of the incinerated material will take place in the mine pit areas that are to be reclaimed. 6.4.3.3 Sewer Treatment Human waste will be incinerated by Incinolet toilets and urinal located in the lavatory of the sleeper and lavatory ATCO trailor. Grey water from the lavatory will be pumped to the 5,000 gallon grey water tank in the ATCO Potable Water/Grey- Water trailor where it will be- stored, chlorinated, and pumped out into an evaporation lagoon. The solid waste from incineration will be landfilled in the abandoned mine area. 6.4.3.4 Power Generation for Camp Two (2) 100 KW generators (one primary and one standby) will be placed, one each, in a steel generator van, 8' x 20'. The 6 - 40 generators would receive fuel supplied by a 50 gallon fuel oil day tanks. The tanks would be piped into a 10,000 gallon fuel storage tank located at the camp. Waste heat from the generators will be ducted to heat the Maintenance/Warm Storage Facility. 6.4.4 Fuel Storage Bulk fuel storage requirements are estimated to be 190,000 gallons. A 190,000 gallon storage tank would be provided at the port site gravel pad. A 10,000 gallon storage tank would be installed at the camp. Fuel would be transferred from the 190,000 gallon fuel storage tank to the 10,000 gallon fuel tank as required by a fuel truck. 6.4.5 Camp Capital Costs A facilities construction cost summary is presented in Table 6-5 and in Table 6-7, Infrastructure Cost Summary. Table 6-5 Facilities Construction Cost Summary - 20,000 tpy Camp and buildings $ 346,000 Purchase price 234,000 Installation 75,000 Gravel pad 23,000 Fencing 12,000 Explosives magazine 2,000 Equipment 84,500 Shop equipment 25,000 Industrial equipment 14,500 Gantry crane 20,000 Communications 25,000 Utilities 100,000 gallon insulated water tank 100,000 Total Facilities Cost $ 530,500 Say $ 530,000 6 - 41 6.4.6 Camp Operation and Maintenance Costs The operations and maintenance costs are based on a 100-day working schedule and a 12 person operation. These costs are presented in Table 6-6. Allowance for wages for the mining operation; maintenance of roads and port facilities, maintenance and operation of mining equipment, and cost of mining are not included. These costs are presented in Section 5.0. Table 6-6 Facilities Annual Operations and Maintenance Cost - 20,000 tpy Utilities $ 47,000 Power generation 35,000 Heat - coal f/a (elec in power gen) Water, wastewater, and solid waste maint. 8,000 Telephone 4,000 Facility Maintenance 10,000 (includes custodial, laundry, preventative, specialty) Food, 12 man camp 76,000 Total Operating & Maintenance Cost $ 133,000 6.5 Road, Airport, and Staging/Stockpile Area Requirements 6.5.1 General Construction of the mining haul road, airfield, and staging/ stockpile area is dependent upon borrow material developed from either the mining operation or from dredged materials from the Chukchi Sea. The availability of borrow material is not an issue if the 50,000 tpy scenario is pursued. However, at 20,000 tpy, the overburden stripped to expose coal seams is insufficient to provide enough material to supply all fill materials needed. Thus, a borrow-type operation of some sort must be developed. 6 - 42 Another issue is the type of staging/stockpile area and barge loading earth ramp that will be developed at Omalik Lagoon. Under the 50,000 tpy scenario, there will be a need to develop a 10 acre (approx.) staging/stockpile area, along with one of the following: a) Berthing facility / turnaround basin; or b) Ramp for lightering barges. (An LCM operation would require a short ramp, or none at all.) The size of the stockpile/staging area would be essentially the same as assumed in the IPDTM, but the berthing facility discussed in that report would not be developed. The 20,000 tpy scenario would also require construction of a stockpile/staging area, but only about 4 acres in size. A berthing facility, which jis probably impractical even for the 50,000 tpy scenario, is totally ruled out in the 20,000 tpy scenario. This means that a ramp will probably be constructed (annually) to accommodate a lighter barge operation. Alternatively, LCM's could be employed. This section is written to discuss these alternate road, airfield, and stockpile/staging area requirements and to estimate the alternative costs. 6.5.2 Material Sources The road, airfield, and staging/stockpile area are related in that they are all earthwork structures which must be designed to mitigate thermal degradation (thawing) of the underlying permafrost. This fact generally forces thick embankments to be used unless the interface between tundra and embankment is lined with insulation. 6 - 43 There are very few identified borrow sources in the project vicinity. The only two that show any promise are the Chukchi Sea bottom and the ridge areas on the coal seams. The Chukchi Sea bottom materials are generally of very poor quality as fill materials according to test boring logs. The overburden over the seams is, by contrast, relatively high quality materials froma construction, maintenance, and structural/thermal standpoint. There is, however, not necessarily a requirement that high quality materials be used, particularly since the road and airfield will primarily be used in winter months, and the stockpile area is only a pad for supporting coal. The question is, therefore, primarily one of cost: is it cheaper to develop a ridge-top borrow area on the western flank of seam DFS-4 (just west of Mormon Creek) or is it cheaper to dredge. Consider development of the stockpile/staging pad as a test case. It is estimated that mining and hauling costs from DFS-4 to this area will be around $9.00/cu. yd. Under a 20,000 tpy scenario, about 4 acres of staging area will be needed. If this area is built to a4 ft. thickness, then about 26,000 cu. yd. of borrow will be needed (excluding the ramp). Importing from DFS-4 will thus cost 26,000 x $9.00 = $234,000, exclusive of shipping, grading, and compacting. By contrast if dredging is performed, a dredge must be mobilized and demobilized to the site at $150,000 each. In addition, dredging costs are $6.00/cu. yd. So the total cost for the stockpile using inferior dredged materials would be $456,000, exclusive of shaping, grading, and compacting. Thus, dredging is clearly not economical and is hereforth dismissed from consideration. 6.5.3 Road Options (20,000 tpy Scenario) As. noted above, stripping over coal seams would provide insufficient fill for the roadway in the 20,000 tpy scenario. Thus, the cost of stripping from a borrow site must be absorbed as 6 - 44 part of the cost of road building. It cannot be included as incidental to the mining costs. On the other hand, hauling costs from the stripping (borrow) site to the road will remain as previously assumed. The IPDTM estimated that to build a 5.4 mile haul road would require 170,360 cubic yards of fill. The total cost was estimated to be $1,581,000, or about $9.28/cu. yd.. To adjust this cost to the cost for building a road under the 20,000 tpy scenario, we first note that the 20,000 tpy stripping operations would provide about 46,000 cubic yards of fill so that 124,000 cubic yards of additional borrow is needed. Denton Civil and Minerals (DCM, 1988) estimates that the stripping costs for the additional borrow is $5.00/cu. yd. A further adjustment is needed for incremental addition to average haul; this is estimated at $0.50/cu. yd. Thus the net additional cost to the road is estimated to be 124,000 cu. yd. x $5.50/cu. yd. = $682,000, for a final cost of $2,260,000 (which is about $418,500/mile. Under this option, the full thickness of the haul road would not be built initially. The road would initially be built two feet thick and would be increased in thickness in subsequent years, as more stripped overburden became available. The additional buildup would be a force account operation, incidental to the mining operation. There would be initial savings in cost under this option. The basic cost of the road is estimated to be halved, to $790,000 (exclusive of additional borrow). The borrow stripping requirements are estimated to be about 39,000 cu. yds., so that the additional costs are 39,000 cy. yds x $5.50/cu. yd. = $214,500. Therefore the total cost of the reduced cross-section is estimated to be $214,500 + $790,000 = $1,004,500 or about $1,000,000. 6 - 45 This option would certainly save initial construction costs, as opposed to use of the 4 ft. thick section. However, there are potentially serious maintenance and environmental problems associated with a reduced cross-section, particularly if the road is not soon brought to finish grade. That is because the fill surface will absorb more heat in the summertime than will the surrounding tundra, and will cause differential melting of the underlying permafrost. This phenomenon could make even a 2 ft. thick section impossible in summer and difficult to negotiate in winter, and could cause sinking of .the road. The extent of the problem is difficult to predict at this time, so the option cannot be entirely ruled out. However, the fact that the problem is likely makes is impossible to issue an unqualified recommendation. Hence, construction of the full 4 ft. section remains the preferred approach. 6.5.4 Airstrip (20,000 tpy scenario) In the case of the airfield, it is not feasible to construct a reduced-thickness section. The IPDTM estimated a fill quantity of 59,850 cy, for a total cost of $886,000. It is necessary to count additional costs for stripped borrow, as was true of the road. Adding $5.50 per cu. yd. for the required quantities, the adjusted cost is $1,213,690, or about $1,210,000. 6.5.5 Stockpile/Staging Area 6.5.5.1 General The 20,000 tpy scenario forces three changes in the design and cost picture for the stockpile/staging area. They are: 1) The staging area is reduced from 10 acres to 4 acres. 6 - 46 2) Due to the high dredge mob-demob and operating costs, the fill must be imported from a borrow site, such as DFS-4, as was. true of the road and airstrip. 3) The berthing facility option becomes completely impractical, yielding lighterage as the only viable option: thus, a ramp should be planned instead of a dredge channel and turnaround basin. The costs must therefore be adjusted from those developed in the IPDTM to reflect these changes. In addition, the lighterage option is now preferred for the 50,000 tpy scenario, so the costs assumed by the IPDTM for a 13' dredged channel and turnaround basin in Omalik Lagoon will be replaced by the costs for a ramp to service lighter barges. It is assumed that the ramp will require complete replacement each season (Appendix 4G). Annual ramp replacement is estimated at $70,000 for both the 20,000 and 50,000 tpy scenarios. 6.5.5.2 Stockpile Pad and Ramp (50,000 tpy Scenario) It is currently estimated that a 10-acre pad will be needed for the 50,000 tpy scenario. Construction of this pad to a 4 ft. thickness, along with a ramp to the lighter barge, is estimated to require 68,700 cu. yds. of fill. The pre-design estimate, accounting for length of haul to the staging area is $755,700 or about $760,000 (at $11.00 per cu. yd., in place). It should be noted, again, that the fill material cost is incidental to the mining cost in this case. 6.5.5.3 Stockpile Pad and Ramp (20,000 tpy Scenario) If the pad is reduced to 4 acres, it is estimated that 30,000 cu. yds. of material must be imported for the pad and 6 - 47 ramp. The pre-design (concept) estimate is that this facility would cost approximately $450,000 (at about $15.00/cu. yd.) 6.6 Revised Marine Transportation Facility 6.6.1 General The WACDP Phase II Technical Memorandum detailing marine transportation options (ASCE, 1968a) concluded that the optimal economy under a 50,000 ton per year coal production scenario lay in the development and maintenance of a permanent port facility at Omalik Lagoon. Several variances in assumed conditions have, however, become apparent during the Phase III analysis of WACDP: a. Probable start-up production will be less than 50,000 tons per year; b. Sediment transport within the channel area may generate unacceptable dredging maintenance requirements and possible make even annual construction of the channel impractical; and c. The permitting process for the port facility promised to be extensive, complex, adversarial at nearly all agency levels, and of unpredictable outcome. Therefore a detailed analysis of alternate transportation methods, not requiring a port facility, was undertaken. Several options were considered and ultimately dismissed for impracticality, lack of economy, and questionable opportunities for agency approval. Only the lighterage operation options presented a feasible solution. 6 - 48 6.6.2 Discussion of Lighterage Operation Options Lighterage operation options involving light barges capable of moving small loads through very shallow drafts are proposed to ferry coal between the shore and a line barge anchored nearby in deep water. Several trips would be needed to fully load the line barge, thus incurring transhauling costs. Two barge types were evaluated for lighterage operations: Option A-1 proposes self-propelled LCM, with typical dimensions of 21'x75' and having a 3' maximum draft; Option A-2 employs a light barge with typical dimension of 160'x50' and having a 12' maximum draft. Option A-1: LCM The LCM has a marked advantage in its ability to drive nearly onto the shore, thus minimizing both the time-length of the load cycle and the equipment configuration necessary to move the coal off of the beach. The obvious disadvantage of this barge is its small payload capacity, a probable maximum of 60 tons and the difficulties inherent in transhauling bulk coal to line barge without a berthing facility. A review of current journals for bulk transportation systems indicates the increasing application of specialized bulk containers to transhauling problems such as the use of LCM lighters would develop. The appropriate bulk container of this operation would have dimensions of 50'x15'x5', a weight capacity of 60 tons, and either a letterbox (end) discharge hatch ora bottom discharge hatch which could be operated by cable froma boom. Given these characteristics, the container can easily be placed or removed from the LCM with minimum operational complexity and take full advantage of the LCM's capacity. 6 - 49 Manipulation of the bulk container wil] occur only at the line barge and be accomplished by a 300 ton crane with a 20' boom length to be mounted on the line barge. The crane will be used to lift the container from the LCM, position the container over the on-deck stockpile, trigger the discharge hatch, close the hatch, and replace the container in the LCM. The sequence proposed for one cycle of an LCM lightering operation, with estimated time requirements, is as follows: TASK ESTIMATED TIME (min) is LOAD LCM Directly from Stockpile With 966 Loaders With 60 Tons Coal 15 2. LCM travel 3000' to line barge 7 3. Docking at barge 2 4. Remove, discharge, and replace container 5 5. Cast off from barge and travel to shore 8 ESTIMATED TIME TO LIGHTER 60 TONS 37 15% Safety Factor 6 TOTAL ESTIMATED TIME 43 The sequence yields an estimated production rate 84 tons per hour, exclusive of contingencies for major repairs or weather delays. Option A-2: 160-foot barge The use of the significantly larger 160-foot barge as a lightering craft increases the productivity of each lightering cycle, but also complicates the equipment configuration for the operation. The light draft requirement of a 160' barge requires construction of a temporary ramp approximately 320' out into the sea, to reach the -2' contour on the sea floor and allow clearance for the barge's light draft. The ramp will serve two purposes: asa berthing point for light barges and as a superstructure for a 100- foot portable adjustable height conveyor system. The ramp is proposed to be constructed on an annual basis using 6 - 50 fi11 material from the shoreline downstream of the major longshore current. Discussions with the sediment transport consultant indicate that the high energy level of the long shore current, in concert with the scouring action of the winter jice-pack, will probably result in annual destruction of the ramp and transport of the embankment material. Estimated annual excavation and embankment quantities for the ramp, including at least one complete reconstruction of the ramp during the season, are 4000 cubic yards. A staging platform, using portable reinforced concrete planks, will be installed at the end of the ramp for the portable conveyor. It is proposed that the coal be stockpiled a t the shore during winter mining operations as discussed in “Preliminary Mining Plan for 20,000 TPY Production Rate" (DCM, 1988). On or about July 15 of each year, after passage of the belukha whale herds, the line and light barges will assemble offshore of the project area, carrying all equipment and materials necessary to perform the Jlightering and marine transportation operations. Assisted by locally-hired construction workers, the barge crews will mobilize the equipment and materials dedicated to onshore operations to shore, construct the temporary ramp, and deploy the coal handling equipment. The sequence proposed for one cycle of a lightering operation incorporating a 160' light barge, with estimated time requirements, is as follows: TASK ESTIMATED TIME (min. ) 1. Load barge directly from stockpile with 966 loader and tandem conveyors with 300 tons coal 72 2. Barge travels 900' to line Barge 6 3. Dock at barge and reposition conveyor 15 4. Discharge 300 tons coal 72 5. Cast off, reposition, return to beach —20 ESTIMATED TIME TO LIGHTER 300 TONS 185 15% Safety Factor —28 TOTAL ESTIMATED TIME 213 6-151 The sequence yields an estimated production rate 85 tons per hour, exclusive of contingencies for major repairs or weather delays. In both the LCM and lightering cases, the use of two lightering craft, operating in a staggered cycle, should effectively double the aggregate lighterage rate. Al) further analysis assumes this operational mode. In summary, two transhauling systems incorporating lighterage operations have been identified as offering a feasible methodology for moving coal off of the project area shore and onto a line barge for transportation to market areas. The two lighterage options appear to offer equally attractive production rates, and, although use of the 160' barge demands a greater compliment of heavy equipment, both options are probably equally sensitive to the operational and maintenance problems characteristic of marine- oriented activities in the Chukchi Sea. In short, with productivity and reliability being relatively equal, the choice between these options will probably rely upon an economic comparison. Estimated capital, operating, and maintenance costs for the lighterage options should be developed for final option selection; for purposes of the infrastructure analysis,it is assumed that the lighter barge option will prevail, thus requiring development of a ramp. 6.6.3 Barge Loading Cost Estimate The barge loading function requires two stacker conveyors and a 966 type loader. For the Phase II 50,000 tpy scenario, the loader was purchased under the mining function and the radial stacker conveyor was purchased as part of the infrastructure requirement and kept at the Omalik Lagoon marine berthing facility. For the 50,000 tpy scenario, it is assumed that the loader is still part of the mining equipment. For the 20,000 tpy scenario, the mining equipment does not include a loader (DCM, 1988) and it is assumed that the loader is mobilized in with the barge equipment each 6 - 52 year. In both scenarios, conveyors are also mobilized in with the The barge loading costs and are presented in labor rates were it is assumed that the two stacking coal haul equipment. are under the infrastructure requirement Table 6-7. Phase II hourly operating and (ASCE, 1986b, Sec. a loading production rate of 85 tph was assumed, including contingency. Table 6-7 Barge Loading Costs 50,000 tpy 966 loader operating $58/hr x 588 hrs $34,100 966 Operator $47.59/hr x 588 hrs $28,000 Laborer $39.19/hr x 588 hrs $23,000 Total Cost $23,000 20,000 tpy 966 loader operating $58/hr x 235 hrs $13,600 966 Operator $47.59/hr x 235 hrs $11,200 Laborer $39.19/hr x 235 hrs $ 9,200 Total Cost $34,000 6.7 Conclusions This report has followed through on several issues not addressed or not dealt with in detail in the WACDP Phase II Final Report. In brief, it can be concluded that camp utility costs appear to exceed the budget originally set forth in the Phase II report, and that a mining production reduction from 50,000 tpy to 20,000 tpy would allow reductions in some infrastructure cost components, as tabulated in Table 6-8. However, road, airstrip, and stockpile pad fill material costs will increase as coal production is decreased to 20,000 tpy due 6 - 53 to the reduced overburden generated during the initial mine pit opening, necessitating the need of an additional borrow source . With regard to the revised marine berthing facility, it does appear to provide some environmental advantages over the original plan, but its construction cost picture is mixed. It will also face an uncertain future with regard to regulatory agency permits. An alternative to the berthing facility - i.e., Jlighterage transport, has been explored concurrently and appears to avert many of the costs and problems associated with the berthing facility. Comparative infrastructure costs for the revised 50,000 tpy and 20,000 tpy scenarios are compared with Phase II estimates in Table 6-8. The estimate presents Phase III infrastructure capital and operating costs adjustments due to revisions in the design of the port facilities, road and airstrip construction, and camp utilities costs. 6 - 54 GS - 9 TABLE 6-8 Infrastructure Cost Summary Phase II Report Scenario Phase III Infrastructure Development Infrastructure Components _(50,000tpy) (1) 50,000 tpy Scenario 20,000 tpy Scenario Capital Operating Capital Operating Capital Operating 1.0 MARINE BERTHING FACILITY 1.1 Lighter Barge Option = ----- wee 760,000 70,000 450,000 70,000 1.2 Dredged Channel & Basin 13' Phase II Option 1,842,000 212,000 2.0 STOCKPILE / COAL HANDLING 2.1 Conveyor w/966 Loader 682,000 29,000 renee eee 2.2 Barge Loading Onto Line Haul ————“‘—sSs—s—sSC ee 85,000 © -=----- 34,000 3.0 BULK FUEL STORAGE 3.1 Tank Farm 490,000 F/A 490,000 F/A 270,000 F/A 3.3 Camp Storage 20,000 Gal. ----- 2 === 40,000 F/A 10,000 F/A 4.0 ROAD 1,750,000 F/A 1,750,000 F/A 2,260,000 F/A 5.0 AIRSTRIP (PRVT. W/ROAD) 970,000 F/A 970,000 F/A 1,210,000 F/A 6.0 CAMP 6.1 Used Modular 1,911,000 419,000 2,260,000 405,000 530,000 215,000 6.2 Fire Sprinklers 55,000) ==>== 55.000 TOTAL 7,700,000 660,000 6,325,000 560,000 4,730,000 319,000 Notes: F/A = Force Account (1) ASCE, 1986b 6.8 References Arctic Slope Consulting Engineers (ASCE a), 1986. Western Arctic Coal Development Project Infrastructure Preliminary Design Technical Memorandum. Report prepared for Alaska Native Foundation. ASCE, Anchorage, Alaska. Arctic Slope Consulting Engineers (ASCE b), 1986. Western Arctic Coal Development Project Phase II Final Reports (Volumes I & II). Report prepared for State of Alaska Department of Community and Regional Affairs and Alaska Native Foundation. ASCE, Anchorage, Alaska. Denton Civil & Mineral, 1988. WACDP Phase III Draft Report: Preliminary Mining Plan for 20,000 tpy Production Rate. Report prepared for Arctic Slope Consulting Engineers. ASCE, Anchorage, Alaska. Denton, S., 1988. Personal Conversation. Doran, V., 1987. Personal Communication. Garness, D., 1987. Personal Communication. Garness, D., 1988. Personal Communication. Hartman, C. and Philip Johnson, 1978. Environmental Atlas of Alaska. Institute of Water Resources Engineering Experiment Station, University of Alaska-Fairbanks, Fairbanks, Alaska. Hanson Environmental Research Services (HERS), 1987. Personal communication with W. Hanson. Jones, D.F. (Coastline Engineering and Consulting), 1987. Personal communication. Mullis, D., 1987. Personal Communication. Mortensen, T., 1987. Personal Communication. Smith, D.W. (ed.), 1986. Cold Climate Utilities Manual. Canadian Society for Civil Engineering, Montreal. 6 - 56 Western Arctic Coal Development Project ~ N Mormon W. Block Mining Unit Mormon Benchmark Deadfall _ UESTERN ARCTIC | PROJECT project. Project PROJECT SITE PLAN Prepared by Date arctic slope| Jjan.i988 Site Plan conelting core =A) 0 500' 1000' 1500’ -_—= mt aE SCALE: |" = 1000' WESTERN ARCTIC 2 COAL DEVELOPMENT PROJECT MARINE BERTHING FACILITY OPTION: N.E. CORNER OF OMALIK LAGOON Prepared by Date arctic slope JAN.1988 consulting engineers 7.0 ECONOMIC ANALYSIS Index Paragraph 7.1) Introduction . 2/4. « « 7.2 Financial Evaluation . . 7.2.1 General ..... 7 7.2.2 20,000 Ton Per Year Base. Case : Case Description . Development Costs Reclamation Costs : Mine Operation Costs . NNN MNMNNN OuPWHE 7 7 7 7 7.2. Ts Tae 2. 7 Ownership Benefits . MaCaw Case. ..... awe Rolligon Case. . 7 Staged Development case , 7.3. Economic Evaluation. .... General ..... NY mMNNNN 2 2 2. hie O° 3 3 -3.2.1 Mine and Infrastructure. Royalties. 7 Taxes and Assessments. . Conversion Costs . . Cost of O11. 4) ale Crude 011 Prices . . Oo ee ee 9 9 9 BW WW LW { Seve Ny ew! ON FO Oe) 7 7 7 7 7 Ts 7.3.3 £E 7. thse Ts Ss 7.3.4 ummary of Economic Evaluation. . 7.3.5 Results of the Economic Evaluation. 7.4 Conclusions. Tables Number Base Case 20,000 tpy Mine Cost. . Revised 50, 000 tpy Mine Cost... SNSna4YNNY ' OPWwWNe Infrastructure Costs . : : ; Non Production Costs... . 3 4 5 sl ke lola le le 6| |Conclusions |. ja || 3!) 5)5)5)2/2\2 « 2 0 1 2 Economic Cost of Coal : : Tid Th ; : : Transportation and Distribution. Summary of the Economic. Cost of Coal Adjustments to Prices of P Petroleum Products Summary of the Economic Cost of Oi]. 20,000 tpy to 50,000 tpy Annual Cost Comparison. . 20,000 tpy to 50,000 tpy Cost Per Ton Comparison . Pro Forma Annual Income and Expense Statement 20,000 tpy Mine and Related Activities . . —~ 1 an Tied 20,000 tpy Base Case ANSCA 7(i) Assessment . SNA NNN NN ' PR vo » @ i OOMNPPWWW a~nxaynNwn ' OMIA 7-7 7-8 7-9 20,000 tpy Base Case Benefits to Mine Developer. MaCaw Case 20,000 tpy Mine Cost . « Pro Forma Annual Income and Expense Statement 20,000 tpy Mine and Related Activities . Rolligon Case 20,000 tpy Mine Cost... . Pro Forma Annual Income and Expense Statement 20,000 tpy Mine and Related Activities Rolligon Case . Two Staged Development 30,600 tpy Mine Cost. Two Staged Development 47,590 tpy Mine Cost. Transportation Cost Estimates ..... ; Summary of Economic Cost of Coal Use at 20,000 tpy Production Level. ... Summary of Economic Costs of Coal Use at 30,600 and 47,590 Production Level... Economic Analysis Summary Table 20,000 tpy Base Case. Distribution of Demand for Economic Analysis . Economic Analysis Summary Table Stage Development Approach : : Economic Analysis Summary Table Staged Development Approach (With Grants for Generation Facilities). 7.1 Introduction This section presents the results of both the financial and economic evaluation of Phase III. The financial evaluation updates work completed for Phase II of the Western Arctic Coal Development Project (WACDP). The report focuses on financial changes due to project design or scale modifications. Only areas where significant conceptual changes have occurred since the Phase II report are examined. The issues of business structure, financing options, taxes and obligations, and business strategies, which were separate subsections in the Phase II document, were not reexamined. The economic analysis of Phase’ III evaluates the proposal from the viewpoint of the benefits and costs to the residents of the State of Alaska, rather than the vantage of the mine operator. 7.2 Financial Evaluation 7.2.1 General Marketing findings presented in the Phase II report indicated that a 20,000 ton per year (tpy) mine production, increasing over time, should be. explored for initial development. This was confirmed by initial marketing efforts conducted during Phase III. This conceptual shift, from a 50,000 tpy Phase II mine to a 20,000 tpy mine, represents a significant change and is examined in this subsection. Three variations of the 20,000 tpy case are presented: 1) The 20,000 tpy “Base Case" situates the mine, road and camp and other infrastructure similar to the 50,000 tpy case; 2) the Macaw Case moves the mine location closer to tidewater and realigns the road along ridge tops; and 3. )the Rolligon. Case eliminates the road anduses Rolligons for winter coal hauling. In addition to these three mine alternatives and based on the 7=3 conclusions of the exploratory marketing task conducted in Phase III, an additional case is presented which assumes 30,600 tpy production to meet initial market demands, increasing in 5 years to 47,590 tpy after further market penetration. The 20,000 tpy "Base Case" will be presented in detail. Modifications to the "Base Case" resulting in the Macaw and rolligon cases, and the market driven case are presented as separate sections. All cases are based on financing, business structure and tax assumptions similar to those presented in Chapter 11, Financial Analysis of the Phase II WACDP Final Report (Arctic Slope Consulting Engineers, 1986). The 50,000 tpy Phase Il Base Case financial statement was calculated using the same financing and labor rates as the current 20,000 tpy Base Case for comparison. Refinements were also made in the infrastructure, camp, and utility requirements for the 50,000 tpy scenario. 7.2.2 20,000 Ton Per Year Base Case 7.2.2.1 Case Description The 20,000 tpy "Base Case" offers significant capital cost reductions over the 50,000 tpy case presented in Phase II. A major portion of these reductions are directly related to the smaller mine and resulting labor and equipment savings. Other savings are the result of conceptual changes made to reduce costs. Offsetting these savings, however, are fixed costs and certain economies of scale that cannot be proportionally reduced and, as a result, represent larger per ton costs than the 50,000 tpy Phase II case; any fixed cost that cannot be reduced by a factor of 2.5 (50,000/20,000) results ina higher per ton cost. The net effect of these countering variable sets is an 7-4 increase in the cost per ton of coal f.o.b. shipping port from $78 To $107 per ton. Table 7.1 summarizes the financial costs of the 20,000 tpy Base Case. Table 7.2 presents the revised 50,000 tpy Phase II case using the same financing, labor, and other rates for comparison. Adjustments are described in the following sections. Table 7-3 presents a comparison of the annual costs of the 20,000 tpy Phase III Base Case with 50,000 tpy Phase II case costs. Table 7-4 presents similar information on a per ton basis. These figures demonstrate the impact of scale; while the project cost is reduced by approximately 45 percent, the per ton cost is 37 percent higher. 7.2.2.2 Development Costs Initial transportation costs are reduced by 50 percent to a cost estimated at $250,000. This is the result of the reduced equipment complement and changes in the camp design which reduced material requirements. The reduced project size does not significantly change the scope of required environmental studies and the estimated cost remains $110,000 (W. Hanson, personal communication, 1988). Developmental drilling costs are not directly proportional to mine size. This cost will be reduced approximately 1/3 to $200,000 (S. Denton, personal communication, 1988). TABLE 7-1 Base Case 20,000 tpy Mine Cost Initial Annual Annual Total Cost Capital Capital Operating Annual Per Cost Factors: Cost Cost Cost Cost Ton Development Costs: Initial Transportation 250,000 28,369 0 28,369 $1.42 Environmental Studies 110,000 12,482 0 12,482 $0.62 Development Drilling 200,000 22,695 0 22,695 $1.13 Engr. & Construct. Mang. 767,600 87,105 0 87,105 $4.36 Contingency 485,436 55,086 0 55,086 2.75 Subtotal 1,813,036 205,737 07) 2055737 10.29 Reclamation Costs: Annual Reclamation 0 0 4,950 4,950 $0.25 Final Reclamation 0 0 6,146 6,146 $0.31 Reclamation Bond $500,000 0 0 10,000 10,000 $0.50 Subtotal 0 0 21,096 21,096 $1.05 Mine Operation Costs: ; Equipment Cost 2,033,000 323,788 136,344 460,132 $23.01 Labor Cost (12 hr days) 329,090 329,090 16.45 Subtotal 2,033,000 323,788 465,434 789,222 39.46 Infrastructure Costs: Bulk Fuel Storage 280,000 31,773 0 ai,71a $1.59 Marine Berthing Facility 450,000 51,065 70,000 121,065 $6.05 Road (5.4 mi) 2,260,000 256,457 F/A 256,457 $12.82 Airstrip 1,210,000 137,307 F/A 137,307 $6.87 Camp Cost 530,000 60,143 133,000 193,143 $9.66 Subtotal 4,730,000 536,745 203,000 739,745 $36.99 Total Production Costs: 8,576,036 1,066,270 689,530 1,755,800 $87.79 Non Production Costs: Profit 68,953 $3.45 Royalty 68,120 $3.41 Insurance, Liability 72,000 $3.60 Insurance, Equipment 9,149 $0.46 Taxes, Local 160,372 8.02 Total 378,593 18.93 Wholesale Costs: 2,134,393 $106.72 Cost Factors: Development Costs: Initial Transportation Environmental Studies Development Drilling Engr. & Construct. Man Contingency Subtotal Reclamation Costs: Annual Reclamation Final Reclamation Reclamation Bond $500, Subtotal Mine Operation Costs: Equipment Cost Labor Cost (12 hr days Subtotal Infrastructure Costs: Bulk Fuel Storage Marine Berthing Facili Road (5.4 mi) Airstrip Camp Cost Subtotal Total Production Costs: Non Production Costs: Profit Royalty Insurance, Liability Insurance, Equipment Taxes, Local Total Wholesale Costs: TABLE 7-2 Revised 50,000 tpy Mine Costs Initial Annual Annual Total Cost Capital Capital Operating Annual Per Cost Cost Cost Cost Ton 500,000 56,738 0 56,738 $1.13 110,000 12,482 0 12,482 $0.25 300,000 34,043 0 34,043 $0.68 g. 947,600 107,351 0-107, 351 $2.15 723,839 82,139 0 82,139 1.64 2,581,439 292,753 0 292,753 5.86 0 0 12,000 12,000 $0.24 0 0 38,718 38,718 $0.77 000 0 0 36,000 36,000 0.72 0 0 86,718 86,718 1.73 3,976,375 451,226 571,989 1,023,215 $20.46 ) 641,151 641,151 12.82 3,976,375 451,226 1,213,140 1,664,366 33.29 530,000 60,143 F/A 60,143 $1.20 ty 760,000 86,242 85,000 171,242 $3.42 1,750,000 198,584 F/A 198,584 $3.97 970,000 110,072 F/A 110,072 $2.20 2,260,000 256,457 405,000 661,457 13.23 6,270,000 711,499 490,000 1,201,499 24.03 12,827,814 1,455,478 1,789,858 3,245,336 64.91 178,986 $3.58 143,667 $2.87 72,000 $1.44 17,894 $0.36 235,647 4.71 648,193 12.96 3,893,529 $77.87 Cost Factors: TABLE 7-3 20,000 tpy to 50,000 tpy Annual Cost Comparison 20,000 tpy Total Annual Cost 50,000 tpy Total Annual Cost 20,000 tpy as % of 50,000 tpy Development Costs: Initial Transportation . Environmental Studies Development Drilling Engr. & Construct. Mang. Contingency Subtotal Reclamation Costs: Annual Reclamation Final Reclamation Reclamation Bond $500,000 Subtotal Mine Operation Costs: Equipment Cost Labor Cost (12 hr days) Subtotal Infrastructure Costs: Bulk Fuel Storage Marine Berthing Facility Road (5.4 mi) Airstrip Camp Cost Subtotal Total Production Costs: Non Production Costs: Profit Royalty Insurance, Liability Insurance, Equipment Taxes, Local Total Wholesale Costs: 460,132 329,090 789,222 315773 121,065 256,457 137,307 193,143 7395745 1,755,800 68,953 68,120 72,000 9,149 160,372 378,593 2,134,993 56,738 12,482 34,043 LOW, S51 82,139 292-753 12,000 38,718 36,000 86,718 1,023,215 641,151 1,664,366 60,143 171,242 198,584 110,072 661,457 1,201,499 3524515336: 178,986 143 ,667 72,000 17,894 235,647 648,193 3,893,529 50% 100% 67% 81% 67% 12h 41% 16% 28% 24% 45% 51% 47% ~~ 20,000 tpy to 50,000 tpy Cost Per Ton Comparison Cost Factors: TABLE 7-4 20,000 tpy Cost Per 50,000 tpy Cost Per 20,000 tpy as % of 50,000 tpy Development Costs: Initial Transportation Environmental Studies Development Drilling Engr. & Construct. Mang. Contingency Subtotal Reclamation Costs: Annual Reclamation Final Reclamation Reclamation Bond $500,000 Subtotal Mine Operation Costs: Equipment Cost Labor Cost (12 hr days) Subtotal Infrastructure Costs: Bulk Fuel Storage Marine Berthing Facility Road (5.4 mi) Airstrip Camp Cost Subtotal Total Production Costs: Non Production Costs: Profit Royalty Insurance, Liability Insurance, Equipment Taxes, Local Total A NPRrOPR Ownrnnr as oO} wool NIMWOr ADL rt ooo ra oo O]M w ro Pu +A nN wo ° - 16.4 39.46 or aed ae ad ad NOr woouw NM Ow A ty Ore NOOF WIDKRPAN-H DI 1 O 1 Ww aw oO nN > aad rIOO SIN ~S win 125% 248% 167% 203% 168% 176% Wholesale Costs: Engineering and Construction management costs are based on a fixed percentage of 12 percent of the capital cost and are reduced by capital cost savings. The contingency cost estimate was reduced by both the reduction in capital costs and a reduction in the contingency factor from 10 percent to 6%. The lower rate reflects the greater confidence achieved by the Phase III analysis. The net effect of these savings is a 30 percent capital cost reduction over the Phase II study for development costs. 7.2.2.3. Reclamation Costs Changes in the mine design significantly reduced reclamation costs for both capital requirements and operating cost. Asa result savings were achieved for both capital outlay and ona per ton basis. The savings is about $0.70 per ton. 7.2.2.4 Mine Operation Costs Mine operating cost changes are discussed in detail in section 5.0, Mine Engineering Analysis. The reduced equipment complement and the conceptual change of buying used equipment with an appropriate useful life results in a capital cost reduction of about $1.9 million or slightly less than half. Labor rates were reduced for both the 50,000 tpy and 20,000 tpy case by 25 percent to reflect reduced Alaska wage rates since the Phase II report. 7 = 10 7.2.2.5 Infrastructure Costs Major redesign of the various infrastructure components reduced the project capital costs by $1.5 million. This represents an annual savings of over $460,000. The infrastructure changes are described in section 6.0, Infrastructure Evaluation. 7.2.2.6 Non Production Costs Some non production costs, such as royalty payments, are proportional to the production rate and do not alter the cost per ton with changes in the mine size. Other non production costs, such as insurance and local taxes, are based on the installed value of assets. The 20,000 tpy case has a higher asset base per unit of production and asa result these costs are higher on a per ton basis. 7.2.2.7 Ownership Benefits Subsection 7.3 discusses the economic benefits and costs associated with the current project design. In addition to the broad economic benefits are the financial benefits specific to the direct and indirect project owners. Table 7-5 presents the likely financial benefits of the mine for the "Base Case". The gross profit from operations is expected to be $235,000 with additional tax benefits of $206,000. Table 7-6 presents the likely benefits to the ANCSA 7(i) participants and Table 7-7 the benefits to the Mine Developer. Tei Pro Forma Annual Income and Expense Statement TABLE 7-5 20,000 tpy Mine and Related Activities Gross Revenue (20,000 tons @ $107/ton fob) Expenses Fixed Capital Recovery Development Mine Operation Fuel Storage Port Related Road Airstrip Camp Total Fixed Expenses Variable Operating: - Reclamation Mine Operation Port Related Road Airstrip Camp Non Operating: Royalty Insurance Total Variable Expenses Gross Profit Deductions Taxes arid Assessments Local Taxes Alaska Mining Tax 7(i) Assessment State Income Tax Tax Allowances Depletion Depreciation Taxable Income Federal Income Tax % 205,737 9. 323,788 15. 31,773 51,065 137,307 60,143 21,096 465,434 2 70,000 F/A F/A 133,000 NOWWHr 68,120 81,149 Ww 160,372 7,224 0 0 ooonm 99 ,846 106,627 uP T= ¥2 1 2 256,457 12. 6 2 6% 1% 5% -4% 0% -4% -8% -0% «Th -3% -0% -0% -2h -1% -8% -5% 3% -0% -0% «7% -0% 1,066,270 1,066,270 50% 50% 689,530 32% 149,268 7% 838,798 39% 167,596 8% 206,473 10% $ % 2,140,000 100% (1,066,270)-50% ( 838,798) -39% 234,932 11% (374,069) -17% (139,137) -7% 0 Oo 70 Percent of Gross Profit Less Allowable Deductions: Local Taxes Alaska Mining Tax State Income Tax Allowable Deductions 7(i) Income TABLE 7-6 20,000 tpy Base Case ANSCA 7 (i) Assessment $164,453 $160,372 $7,224 0 $167,596 0 TABLE 7-7 20,000 tpy Base Case Benefits to Mine Developer Profit from Operations (Profit-Taxes) $ 67,336 Total 7(i) Income Depletion Benefits Depreciation Benefits Total Income 0 $ 99,846 Hite 82 273,809 7 = 13 As % of Gross Sales 3.2% 0.0% 4.7% 5.0% 12.8% % of Profit 100.0% 97.5% 4.4% 0.0% 101.9% 7.2.3 MaCaw Case The Macaw Case locates the mine at the southwest limb of the Deadfall Syncline. This realigns the road along the ridge tops reducing the haul road length by 1/2 mile to 5.0 miles and substantially reducing the amount of fill required and the distance the fill is hauled. These changes reduce the road cost by over $1.5 million and the airstrip cost by over $1 million. A cost reduction of almost $20 per ton results. In fact the Macaw case dock side coal price is within $10 per ton of the revised 50,000 tpy scenario and cheaper than the Phase II 50,000 tpy scenario. Table 7-8 presents the Macaw case mine costs and Table 7-9 the pro forma financial statement. 7.2.4 Rolligon Case The Rolligon Case substitutes contracted rolligons and winter coal hauling for the haul trucks and haul road. This eliminates the road construction cost, reduces the airstrip costs, and eliminates the haul trucks and part of the grader cost. The marine berthing facility costs, however, increase substantially, from $0.45 million to $1.26 million due to the higher cost of material transportation by rolligon. The net effect is a capital cost reduction of about $2.5 million. The capital cost savings are negated by the higher operating costs associated with the rolligons. The net difference between the Rolligon Case and "Base Case" is about $4 per ton in favor of the "Base Case". Table 7-10 presents the Rolligon Case costs and Table 7-11 the rolligon pro forma financial statement. 7-14 TABLE 7-8 MaCaw Case 20,000 tpy Mine Cost Initial Annual Annual Total Cost Capital Capital Operating Annual Per Cost Factors: Cost Cost Cost Cost Ton Development Costs: Initial Transportation 250,000 28,369 0 28,369 $1.42 Environmental Studies 110,000 12,482 0 12,482 $0.62 Development Drilling 200,000 22,695 0 22,695 $1.13 Engr. & Construct. Mang. 447,200 50,747 0 50,747 $2.54 Contingency 596,700 67,712 0 67,712 3.39 Subtotal 1,603,900 182,005 0 182,005 9.10 Reclamation Costs: Annual Reclamation 0 0 4,950 4,950 $0.25 Final Reclamation 0 0 6,146 6,146 $0.31 Reclamation Bond $500,000 0 0 10,000 10,000 0.50 Subtotal 0 0 21,096 21,096 pe Mine Operation Costs: Equipment Cost 2,033,000 323,788 136,344 460,132 $23.01 Labor Cost (12 hr days) 329,090 329,090 16.45 Subtotal 2,033,000 323,788 465,434 789,222 8 46 Infrastructure Costs: Bulk Fuel Storage 280,000 31,770 0 31,773 $1.59 Marine Berthing Facility 350,000 39,717 70,000 109,717 $5.49 Road (5.4 mi) 750,000 85,108 F/A 85,108 $4.26 Airstrip 150,000 17,022 F/A 17,022 $0.85 Camp Cost 530,000 60,143 133,000 193,143 $9.66 Subtotal 2,060,000 233,762 203,000 436,762 21.84 Total Production Costs: 5,696,900 739,555 689,530 1,429,085 72545 Non Production Costs: Profit 68,953 $3.45 Royalty 68,120 $3.41 Insurance, Liability 72,000 $3.60 Insurance, Equipment 9,149 $0.46 Taxes, Local 106,532 505) Total 324,754 16.24 Wholesale Cost 1,753,839 $87.69 Teo A15 TABLE 7-9 Pro Forma Annual Income and Expense Statement 20,000 tpy Mine and Related Activities Gross Revenue ae (20,000 tons @ $88/ton fob) Expenses Fixed Capital Recovery Development Mine Operation Fuel Storage Port Related~ Road Airstrip Camp Total Fixed Expenses Variabie Operating: Reclamation Mine Operation Port Related Road Airstrip Camp Non Operating: Royalty Insurance Total Variable Expenses Gross Profit Deductions Taxes and Assessments Local Taxes Alaska Mining Tax 7(i) Assessment State Income Tax Tax Allowances Depletion Depreciation Taxable Income Federal Income Tax 182,005 323,788 31,773 39,717 85,108 17,022 60,143 21,096 465,434 70,000 F/A F/A 133,000 68,120 81,149 106,532 6,086 0 0 91,640 73,956 % 10 = Wr PMH OO Ls 26. 3% -4% -8% -3% - 8% -0% -4% 2% 5% 409% Pw ooon Pu 7 - 16 - 0% -0% -6% -9% - 6% -0% -4% -0% 0% -2% -2h% ae 739,555 739,555 689,530 149,269 838,799 112,618 165,596 % $ % 1,760,000 100% 42% 42% ( 739,555) -42% 39% 9% 48% (_ 838,799) -48% 181,646 10% ( 278,214)-16% 6% 9% (95,568) -6% 0 0 TABLE 7-10 Rolligon Case 20,000 tpy Mine Cost Initial Annual Annual Total Cost Capital Capital Operating Annual Per Cost Factors: Cost Cost Cost Cost Ton Development Costs: Initial Transportation 250,000 28,369 0 28,369 $1.42 Environmental Studies 110,000 12,482 0 12,482 $0.62 Development Drilling 200,000 22,695 0 22,695 $1.13 Engr. & Construct. Mang. 556,808 63,185 0 63,185 $3.16 Contingency 630,000 71,490 0 71,490 Ro Subtotal 1,746,808 198,222 0 198,222 9.91 Reclamation Costs: Annual Reclamation 0 0 4,950 4,950 $0.25 Final Reclamation 0 0 6,146 6,146 $0.31 Reclamation Bond $500,000 0 0 10,000 10,000 $0.50 Subtotal 0 0 21,096 21,096 $1.05 Mine Operation Costs: Equipment Cost 1,353,000 215,487 501,392 716,879 $35.84 Labor Cost (12 hr days) 329,090 329,090 16.45 Subtotal 1,353,000 215,487 830,482 1,045,969 52.30 Infrastructure Costs: Bulk Fuel Storage 280,000 31,773 0 31,773 $1.59 Marine Berthing 1,263,400 143,366 70,000 213,366 $10.67 Facility Road (0 mi) 0 0 F/A 0 $0.00 Airstrip 900 ,000 102,129 F/A 102,129 $5.11 Camp Cost 530,000 60,143 173,000 233,143 11.66 Subtotal 2,973,400 337,412 243,000 580,412 29.02 Total Production Costs: 6,073,208 751,121 1,094,578 1,845,698 92.28 Non Production Costs: Profit 109,458 $5.47 Royalty 62,962 $3.15 Insurance, Liability 72,000 $3.60 Insurance, Equipment 13,530 $0.68 Taxes, Local 113,569 5.68 Total 371,519 18.58 Wholesale Costs: 2,217,217 $110.86 7-17 Pro Forma Annual Income and Expense Statement Gross Revenue TABLE 7-11 20,000 tpy Mine and Related Activities Rolligon Case —_i_ (20,000 tons @ $110.86/ton fob) Expenses Fixed Capital Recovery Development 198,222 Mine Operation 215,487 Fuel Storage 31,773 Port Related 143,366 Road 0 Airstrip 102,129 Camp 60,143 Total Fixed Expenses Variable Operating: Reclamation 21,096 Mine Operation 830,482 Port Related 70,000 Road F/A Airstrip F/A Camp 173,000 Non Operating: Royalty 62,962 Insurance 85,530 Total Variable Expenses Gross Profit Deductions Taxes and Assessments Local Taxes 113,569 Alaska Mining Tax 4,081 7(i) Assessment 0 State Income Tax 0 Tax Allowances Depletion 70,469 Depreciation 75,112 Taxable Income Federal Income Tax * _$ 751,121 -9% -7% -4% 5% -0% -6% 7% NPODr WOW 751,121 1,094,578 -0% 5% 2h -0% -0% -8% NOOWNFH 148,492 -8% -9% 1,243,070 wn 117,650 1% 2% -0% -0% ooouwm 145,581 -2h 4% Ww 7 - 18 % 34% 34% 49% 7% 56% 5% Th % 2,217,200 100% ( 751,121) -34% (1,243,070) -56% 223,009 10% { 263,231) -12% (40,222) -2% 0 0 7.2.5 Staged Development Case The staged development case assumes an initial production rate of 30,600 tpy (Stage 1), increasing to 47,590 tpy (Stage 2) over a five year period. These production levels are achieved with essentially the same fixed capital outlay as the 20,000 tpy “Base Case". Variable costs described in the 20,000 tpy "Base Case", which change directly with production levels , were increased by a scaling factor equal to the change in production. The first stage production level of 30,600 tpy increases variable costs by a factor of about 1.5 and by a factor of about 2.4 for the 47,590 tpy production level of Stage 2. These increases are reflected in the higher annual operating costs shown in Tables 7- 12 and 7-13. The annual operating cost increases are directly proportional to the increased production rates and do not alter the production costs on a per ton basis. Fixed costs represented by the initial capital costs were held constant with the exception of the bulk fuel storage costs, and stockpile and loading costs. The bulk fuel storage costs were increased from $280,000 for the 20,000 tpy "Base Case" to $285,000 for Stage 1 and $447,000 for Stage 2. Stockpile and loading costs were increased from $450,000 to $654,000 for Stage 1, and to $896,000 for Stage 2. Holding capital costs constant while substantially increasing production rates provides corresponding economies of scale. Asa result, the cost per ton drops’ from $107 for the “Base Case" to $83 for Stage 1 and $68 for Stage 2. This represents a price reduction of $24 and $39 per ton. The percentage decrease is 22% for Stage 1 and 36% for Stage 2. 7 - 19 Cost Factors: TABLE 7-12 Two Staged Development 30,600 tpy Mine Cost Development Costs: Initial Transportation Environmental Studies Development Drilling Engr. & Construct. Mang. Contingency Subtotal Reclamation Costs: Annual Reclamation Final Reclamation Reclamation Bond Subtotal Mine Operation Costs: Equipment Cost Labor Cost (12 hr days) Subtotal Infrastructure Costs: Bulk Fuel Storage Stockpile & Loading Road (5.4 mi) Airstrip Camp Cost Subtotal Total Production Costs: Non Production Costs: Profit Royalty Insurance, Liability Insurance, Equipment Taxes, Local Total PHA A ArewmNooo WlO ON Pwo WOO Pr Ww Sadana ooo ru | vo Oo] WP ww e ~ - oO 16.4 w w ©. oor Saad PR NO ro A Pa Pwo woo we nN a} oo SIO SID a co a > Wholesale Costs: Initial Annual Annual Total Capital Capital Operating Annual Cost Cost Cost Cost 250,000 28,369 0 28,369 110,000 12,482 0 12,482 200,000 22,695 0 22,695 795,200 90,237 0 90,237 520,200 59,031 0 59,031 1,875,400 212,814 0 212,814 0 0 7,574 7,574 0 0 9,403 9,403 0 0 15,300 15,300 0 0 Seen 32,277 2,033,000 323,788 208,606 532,394 503,507 503,507 2,033,000 323,788 712,113 1,035,901 285,000 32,341 0 32,341 654,000 74,214 70,000 144,214 2,131,000 241,214 F/A 241,819 1,210,000 137,307 F/A 137,307 530,000 60,143 203,490 263 , 633 4,810,000 545,823 273,490 819,313 8,718,400 1,082,425 1,017,880 2,100,305 101,788 84,905 72,000 9,149 165,839 433,681 2,533,986 7! = 720 Cost Factors: Development Costs: Initial Transportation Environmental Studies Development Drilling Engr. & Construct. Mang. Contingency Subtotal Reclamation Costs: Annual Reclamation Final Reclamation Reclamation Bond Subtotal Mine Operation Costs: Equipment Cost Labor Cost (12 hr days) Subtotal Infrastructure Costs: Bulk Fuel Storage Stockpile & Loading Road (5.4 mi) Airstrip Camp Cost Subtotal Total Production Costs: Non Production Costs: Profit Royalty Insurance, Liability Insurance, Equipment Taxes, Local Total TABLE 7-13 Two Staged Development 47,590 tpy Mine Cost Initial Annual Annual Total Cost Capital Capital Operating Annual Per Cost Cost Cost Cost Ton 250,000 28,369 0 28,369 $0.60 110,000 12,482 0 12,482 $0.26 300,000 34,043 0 34,043 $0.72 840,440 95,370 0 95,370 $2.00 532,226 60,395 0 60,395 20, 2,032,666 230,660 0 230,660 4.85 0 0 11,774 1774 $0.25 0 0 14,618 14,618 $0.31 0 0 23,785 23,785 0.50 0 0 50,177 50,177 105: 2,033,000 323,788 324,294 648,082 $13.62 782,739 782,739 16.45 2,033,000 323,788 1,107,034 1,430,822 30.07 447,000 50,724 F/A 50,724 $1.07 896,000 101,675 70,000 171,675 $3.61 2,131,000 241,819 F/A 241,819 $5.08 1,210,000 137,307 F/A 137,307 $2.89 530,000 60,143 318,341 378,483 395 5,214,000 591,667 388,341 980,008 $20.59 9,279,666 1,146,116 1,545,551 2,691,667 $56.56 154,555 $3.25 112,641 $2.37 72,000 $1.51 9,149 $0.19 175,830 3.69 524,174 11.01 3,215,841 $67.57 Wholesale Costs: Valais 7.3 7.2.6 Conclusions The Phase III 20,000 tpy case substantially reduces the total project cost from the Phase II 50,000 tpy case. The 20,000 tpy case does not overcome the issue of scale in terms of cost per ton. The Macaw case offers significant financial advantages over the 20,000 tpy "Base Case" and is competitive with the original 50,000 tpy Phase II case. The Rolligon Case is financially similar to the “Base Case" and offers no financial savings. It does, however, reduce the initial capital outlay in exchange for higher operating costs. The staged approach builds upon the capital cost savings of the smaller production levels and primarily by lengthening the mining season, enables the mine to achieve relatively low production costs. It is the preferred mining approach if the market is available. Economic Evaluation 7.3.1 General The economic evaluation conducted for the 20,000 tpy "Base Case" allocate costs for coal use only if the costs for each specific use (e.g., residential heating using coal) were less than the costs for using oi] for the same use. The staged approach assumes that a subsidy for power generation facilities would be used to support the project until such time as increasing production levels and/or fuel oil prices result in positive benefits. 1.= 22 7.3.2 Economic Cost of Coal The Phase II Economic Analysis adjusted various costs presented in the Phase II Financial Options report to approximate the true economic benefits and costs to the state. The following sections present comparable adjustments to the 20,000 tpy "Base Case" and the staged approach described above. For purposes of this analysis, the 20,000 tons of coal is assumed to be used in the North Slope villages of Wainwright, Pt. Lay and Pt. Hope, and, Kotzebue, and Nome. The staged approach includes these communities plus the City of Bethel. 7.3.2.1 Mine and Infrastructure Capital requirements for the mine at the 20,000 tpy production level total about $8.6 million (See Table 7-1). This includes costs for pre-development activities, mining equipment, facilities construction, and final reclamation. Reclamation is assumed at the end of a 20-year mine life. Mining equipment replacement is also assumed to occur in Year 10, and represents a time-averaged replacement of mobile equipment. Comparable costs for the staged approach are taken from tables 7-12 and 7-13, with expansion to 47,590 tpy occurring in the fifth year after production commences. The financial analysis includes the full cost of labor at the actual wage rates expected to prevail over the period of analysis. However, given the relatively high unemployment rate in Alaska particularly in the project area, the true economic cost of employing this labor is considerably lower than the prevailing wage rates. When there is a high rate of unemployment, the use of Alaskan labor on the project does not result in withdrawing labor from other productive activities in the state. Other uses of the labor force are d= 23 not foregone, and the opportunity cost of the labor is relatively low. In effect this cost adjustment is a reflection of the benefits of employing labor which would otherwise be unemployed or underemployed. If the labor would otherwise be completely unemployed and if people in these circumstances put a low value on their leisure time, the economic cost of labor on the project would be close to zero. However, it is recognized that employment on the project, especially in the summer months, would detract from subsistence activities in the region to some extent, and that people do place some value on their leisure time. Squire and van der Tak (1986), two econamists with the World Bank, suggest that for previously unemployed or underemployed laborers, a rough estimate of the minimum wage that labor will accept for employment will give an acceptable measure of the opportunity cost for labor. Information from the Alaska Department of Labor (1988) indicates that an entry level position in the construction trades for the Kobuk, Nome, and North Slope Borough Census Areas would pay $9:00 per hour or less. This minimum wage is substantially lower than the $10 to $12 per hour range used in the Phase II economic analysis, and about 25 percent of the burdened rate for labor at the mine. As a result, the cost for labor in this analysis is calculated at 25 percent of the Phase II report. This reduction is applied in the following tables. 7.3.2.2 Royalties Royalty payments are not included in the economic analysis since the coal in the ground has no alternative use, and it will not be used in the absence of this or a similar project. 7 - 24 As a result, the opportunity, or economic, cost of the resource jis close to zero. 7.3.2.3 Taxes and Assessments The payment of taxes to government entities within Alaska does not represent a use of resources. It represents a transfer payment from the coal producing company to the government. Such payments have a proper place in the financial evaluation, but are not relevant to the economic evaluation. They are not included in the costs of the project in keeping with conventional methods of economic analysis. 7.3.2.4 Transportation and Distribution These activities represent a use of resources and are included in the economic analysis even though the coal producing company will not conduct them. Transportation costs are based upon coal delivery to the North Slope villages, Kotzebue, Nome, and Bethel. Transportation cost estimates by Ogden Beeman & Associates (1988) are shown in Table 7-14. From Table 7-14 the delivered price of WACDP coal can be calculated for each community by adding the transportation cost to the production cost for each production level. d= 29 TABLE 7-14 Transportation Cost Estimates (Cost Per Ton) Production Level 20,000 tpy 30,600 tpy 47,590 tpy North Slope Villages $46.87 $31.56 $23.53 Kotzebue 36.44 36.30 24.91 Nome 44.89 es BL Bethe} 48.55 Production Cost $106.72 $82.81 $67.57 (f.o.b. Mine Portside) Distribution and sales costs for residential users and smaller commercial users were estimated at 30 percent (Coal Bunker, 1988) of the landed price, while comparable costs for larger commercial and utility users were estimated at $12 per ton. This latter cost includes transfer from the landing site to a storage stockpile, inventory, and transfer to the power or heating plant. 7.3.2.5 Conversion Costs Converting heating and power generation equipment from diesel to coal is a real economic cost that represents a use of resources. Conversion costs were developed in Section 2.0 and the WACDP Phase II Village End-Use Technology Assessment Report for heating and power generation for typical units in a village and a _ Jarger community. Residential conversion costs were estimated at $1,500 installed. Smaller commercial heating units were estimated at $1,500 per unit, while larger units were estimated to cost an average of $100,000. Asa result of the marketing survey, two large heating units were assumed for each village, 2 large units were estimated for Kotzebue and Bethel, and 3 for Nome. Ua 20 Annual conversion operating and maintenance costs include $23,000 for each large institutional heating plants, $50 each for the smaller institutional and residential furnaces, and $670,000 for each coal-fired plant. State grants for generation facilities are assumed to be provided, consistent with previous experience for most rural communities. 7.3.2.6 Summary of the Economic Costs of Coal The financial cost of coal development, production, transportation, and user conversions are presented in other subsections of this report. The capital and operating costs of the WACDP and coal use, applying the adjustments described above, are shown in Table 7-15 for the 20,000 tpy "Base Case" and in Table 7-16 for the staged approach. The “Base Case" estimates assume a 20,000 tpy production level, a 20 year analysis period, and constant 1987 dollars. The staged development assumes production levels of 30,600 and 47,590 tpy, with other variables the same as the 20,000 tpy base . 7.3.3 Economic Cost of Oi] The major benefit of the project arises from the displacement of oil for heating and power generation in the market area. Determination of these benefits requires the development of costs for oi] which correspond to those shown for coal. 7 - 27 TABLE 7-15 Summary of Economic Costs of Coal Use at 20,000 tpy Production Level (1,000's of 1987 $) Mine Capital Costs Mine and Infrastructure $ 8,576 Equipment and Facilities Equipment Replacement, $ 2,033 Year 10 Reclamation, Year 20 3 0 Subtotal 10,609 Conversion Capital Costs Power Generation $ 0 Residential Heating $ 159 Institutional Heating $ 688 Equipment Replacement, $ 247 Year 10 Subtotal 1,094 Total Capital Costs $11, 703 Annual Operating Costs Mine and Infrastructure $ 593 Transportation $ 812 Distribution and Sales $ 287 Conversion 142 Total Operating Costs ; 1,834 i= 2o TABLE 7-16 Summary of Economic Costs of Coal Use at 30,600 and 47,590 Production Level (1,000's of 1987 $) 30,600 tpy 47,590 tpy Mine Capital Costs Mine and Infrastructure Equipment and Facilities $ 8,718 $ 9,280 Equipment Replacement, Year 10 $ 2,033 $ 2,033 Reclamation, Year 20 0 0 Subtotal 10,751 tom Conversion Costs Power Generation $ $ Residential Heating $ 424 $ 424 Institutional Heating $ $ Equipment Replacement, Year 10: 424 424 Subtotal 1,448 2,148 Total Capital Costs 12,199 13,461 Annual Operating Costs Mine and Infrastructure $ 823 $ 1,194 Transportation $ 2,400 $ 1,486 Distribution and Sales $ ©6469 $ ©6645 Conversion 1,498 2,200 Total Operating Costs 3,900 5,657 ZF \29 7.3.3.1 Crude 011] Prices Crude oi] prices have shown extreme volatility over the past few years, with the prices for Alaska North Slope crude oi] sold on the U.S. Gulf Coast declining from almost $27 per barrel at the end of 1985 to about $10 in July, 1986 and rebounding to over $16 per barrel in April, 1988. The uncertainty about future oil prices has a_ significant influence on projects such as the WACDP which compete with oil as an energy source. This volatility increases the potential for loss and forces sponsors to be more conservative in evaluating the project. The March 1988 mid-level crude oil price scenario developed by the Alaska Department of Revenue (Malone, 1988) anticipates lower than current real prices (adjusted for inflation) through 1992, with only minor price increases from 1993 through 2005. Real prices in 2005 would be less than $1.00 higher than present prices. Crude oi] prices used in this analysis are based upon expected 1990 prices (anticipated commencement date of mining operations) with subsequent annual changes associated with the mid-level real price estimates for Saudi Arabian crude oi]. 7.3.3.2 Adjustments to Prices of Petroleum Products The delivered price of fuel oi] to the market area includes the cost of production, refining, transportation and distribution, and is thus reasonably comparable to the coal costs shown in the preceding section. For the economic analysis, some adjustments are necessary to make the coal and oil prices comparable. 7 = 30 es As discussed in the Phase II report, the fuel oi) distribution and marketing system in western Alaska has changed radically in the last few years. Chevron, which was the sole supplier of fuel products to the region in 1984, has no operations in western Alaska, and refineries in Nikiski and Puget Sound have become significant sources of fuel. Tesoro Alaska representatives estimate that 75 percent of the total fuel sales in western Alaska come from Alaska refineries (Measles, 1988). Labor - The financial cost of labor for the production and refining of fuel oi], and delivery to the market area was estimated at approximately $0.10 per gallon in the Phase II report, and corroborated by Weddleton (1986) . The opportunity cost for this labor is expected to have less impact on reducing oi] costs than on coal costs for two reasons: 1) Coal production is more labor intensive than oi] production; and 2) much of the oi] and transportation labor force is urban-based, more highly skilled, and less subject to unemployment than is the labor force in western Alaska. The average monthly wage for Alaska refineries in the first quarter of 1987 was $4,051, and the average monthly wage for deep sea domestic water transportation during the same period was $3,770 (Alaska Department of Labor, n.d). Wages for similar entry level transportation occupations averaged approximately $2,460, or 65 percent of the deep sea domestic transportation wage. The Department of Labor does not report wages for any industries comparable to petroleum refining. It seems reasonable to assume that a number of relatively skilled persons would be willing to accept a monthly wage of $2,630 (65 percent of $4,051) for employment. However, if 25 percent of the fuel consumed in western Alaska originates 7 |=) 3% outside of Alaska, the maximum reduction is limited to 75 percent times the 35 percent reduction (1-.65) or about 26 percent. Thus the cost of fuel oi] in the region is reduced by an average of $0.026 per gallon (26 percent X $0.10 per gallon) to reflect the adjustment for the economic cost of labor. Royalties - As previousiy discussed in the Phase II report, the crude 01] resource has an opportunity cost since Alaska crude oi] producers (with the exception of Conoco's operation at Milne Point) can profitably sell all the oi] they can produce at prevailing market prices. As a result, royalty payments are not deducted from the 011] costs for that portion supplied from Alaska sources. Royalty payments to other producing regions represent a cost to Alaska consumers and remain in the oi] price structure. Taxes and Assessments - Taxes and assessments paid to the state and other local government entities are transfer payments and do not represent a use of resources. These jtems were estimated to be about $0.07 per gallon for fuel oil refined from Alaska crude and delivered to the market area. Average fuel costs are reduced by 75 percent of this amount (to account for the volume of oi] supplies from outside the state), or approximately $0.05 per gallon to permit comparisons with coal. 7.3.3.3 Summary of the Economic Costs of 0i1 The adjustments described in the preceding sections total approximately $0.076 per gallon or $3.19 per barrel. Subtracting that amount from the present market price of about $16.10 for oi] results in an economic cost of $12.91 per barrel. This economic cost of $12.91 is equal to a financial cost of $16.10 per barrel. 1 = 32 7.3.4 Summary of Economic Evaluation Table 7-17 below summarizes the economic evaluation for a 20,000 tpy "Base Case" production level with the adjustments described above for coal and oi]. The table assumes a 20-year life at that production schedule and compares the use of coal and oi) at varying discount rates in terms of benefit/cost ratios, and net present values. Uniess discussed in the following sections, the assumptions and methodology employed in the Phase II report are used in this analysis. The capital cost for mining (column 1 of Table 7-17 ) is the initial capital cost of the mine ($8.576 million) plus $2.033 million for replacement of equipment in year 10 of the analysis period. In order to estimate the costs for conversion, transportation, and operations and maintenance, of WACDP coal for the economic evaluation, the distribution of demand by sector and community is required. Table 7-18 shows this distribution for 20,000 ton production level, and $16.10 crude oil price. The coal requirements are based upon thermal value of 22 million btu's per ton, rather than the 24 million used in Phase II to account for the lower btu basis of surface coals. 7 - 33 Table 7-17 Economic Analysis Summary Table 20,000 tpy Base Case (1,000's of 1987$) hE - L Coal Capital Cost Coal 0 & M Cost Total Mine & Mine & Coal Oi] Year Infra. Conv. Total Infra. Trans. Distr. User Total Cost Cost Savings Benefit 1987 1987 0 0 0 0 0 0 0 0 0 0 0 0 1988 -2 0 0 0 0 0 0 0 0 0 0 0 0 1989-1 0 0 0 0 0 0 0 0 0 0 0 0 1990 1 8,576 847 9,423 593 812 287 142 ~=-1,834 11,257. 1,931 (9,326) 97 1991 2 0 0 0 593 812 287 142) 1,834 1,834 1,630 (204) (204) 1992 3 0 0 0 593 812 287 142) 1,834 1,834 1,630 (204) (204) 1993 4 0 0 0 593 812 287 142 1,834 1,834 1,630 (204) (204) 1994 5 0 0 0 593 812 287 142) «1,834 1,834 1,630 (204) (204) 1995 6 0 0 0 593 812 287 142) «1,834 1,834 1,630 (204) (204) 1996 i 0 0 0 593 812 287 142 «1,834 1,834 1,630 (204) (204) 1997 8 0 0 0 593 812 287 142) «1,834 1,834 1,630 (204) © (204) 1998 9 0 0 rt) 593-812 287 142 «1,834 1,834 1,630 (204) (204) 1999 10 2,033 247 2,280 593 812 287 142 )=«-1,834 4,114 1,747 (2,367) (87) 2000 +11 0 0 0 593 812 287 142 «1,834 1,834 1,630 (204) (204) 2001 12 0 0 0 593 812 287 142) 1,834 1,834 1,630 (204) (204) 2002 = 13 0 0 0 593 812 287 142) «1,834 1,834 1,630 (204) (204) 2003 14 0 0 0 593 812 287 142) «1,834 1,834 1,630 (204) (204) 2004 15 0 0 0 593 812 287 142) «1,834 1,834 1,630 (204) (204) 2005 16 0 0 0 593 812 287 142 = 1,834 1,834 1,630 (204) (204) 2006 17 0 0 0 593 812 287 142 =«-1,834 1,834 1,630 (204) (204) 2007 18 0 0 0 593 812 287 142 ~=-1,834 1,834 1,630 (204) (204) 2008 19 0 0 0 593 812 287 142 (1,834 1,834 1,630 (204) (204) 20098 20 0 0 0 593 812 287 142 = 1,834 1,834 1,630 (204) (204) Totals 10,609 1,094 11,703 11,860 16,240 5,740 2,840 36,680 48,383 33,018 (15,365) (3,662) Benefit/ Present Cost Net PV Benefit Cost Meurer WN IE I I WI VA I) Semmes I I TTT TE A WW ST TPE TW IT Ti] Hoses <eecesareerics) || ||| tesa teins at 5% 8,134 828 8,961 6,384 8,741 3,090 1,529 19,744 28,705 17,857 (10,848)(1,886) -0.21 Discount 10% 6,446 650 7,096 3,793 5,194 1,836 908 11,731 18,827 10,666 (8,162)(1,065) -0.15 Rate 15% 5,234 524 5,758 2,441 3,342 1,181 584 7,548 13,306 6,900 (6,407) (648) =0.41, } 5 ’ ‘ , —_ ? = Cm TABLE 7-18 Distribution of Demand for Economic Analysis (tpy) Sectors Community Residential Institutional Utility Total 20,000 tpy Base Case North Slope Villages 1,697 3,440 0 5,137 Kotzebue 588 0 0 588 Nome 0 0 ) 0 Total 2,285 3,440 0 5,725 30,600 tpy stage 1 North Slope Villages 5,200 * 0 5,200 Kotzebue 0 0 10,000 10,000 Nome 0 0 15,400 15,400 Total 5,200 o* 25,400 30,600 ‘ 47,590 tpy stage 2 North Slope Villages 5,200 * 0 5,200 Kotzebue 0 900 10,000 10,900 Nome 0 1,960 15,400 17,360 Bethel 0 1,130 13,000 14,130 Total 5,200 3,990* 38,400 47,590 * Note Residential and institutional combined for North Slope Villages. , Conversion costs (column 2) are based upon the demand for each use in each community. These capital costs include $1,500 to purchase smaller institutional users, and $100,000 for the a coal-fired stove for each household using coal, $1,500 for larger institutional users. The estimated number of households is determined by dividing the average number of tons each community into the delivered tonnage. institutional users are assumed for each village, Kotzebue and Bethel, and 3 in Nome. 7 - 35 Two estimated for large with 2 in Transportation costs shown jin Table 7-17 are estimated at approximately $812,000. This cost is relatively static for the existing transportation scheme since fixed costs (e.g.,mobilization and demobilization, capital costs) dominate this cost category. The markup on residential and small institutional sales and distribution costs has been increased from the 20 percent markup on landed cost used jin the Phase II report, to 30 percent based upon information from the Coal Bunker in Fairbanks. A $12 per ton markup for large institutional and utility users is comparable to estimates in Phase I1. Coal user operation and maintenance costs are calculated using the same annual cost estimates as Phase II. Table 7-19 shows the economic evaluation for a staged development production level with the adjustments described above for coal and oil, including capital costs of $26.4 Million for 3 coal-fired power generation facilities. Table 7-19 assumes a 20-year life at a 30,600 tpy production schedule for the first 5 years, and 47,590 tpy for the remaining 15 years. The table also compares the use of coal and oj] at varying discount rates in terms of benefit/cost ratios, and net present values. The assumptions and methodology employed in this analysis are similar to those described above for the 20,000 tpy "Base Case". Table 7-20 presents a similar case with an assumption that power generation equipment will be provided by a State of Alaska grant, and the capital cost is not included in the analysis. 7 - 36 Le - 21 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 Totals Present Value at Discount Rate Coal Capital Cost Mine & Year Infra. Conv. Total -3 0 0 0 “2 0 0 0 =] 0 0 0 A 8,718 18,624 27,342 2 0 0 0 a\ 0 0 0 4 0 0 0 5 562 9,500 10,062 6 0 0 0 7 0 0 0 8 0 0 0 9 0 0 0 10 2,033 424 2,457 iat 0 0 0 12 0 0 0 13 0 0 0 14 0 0 0 15 0 0 0 16 0 0 0 17 0 0 0 18 0 0 0 19 0 0 0 0 0 0 20 10% 15% 5% 8,631 21,977 30,608 6,806 17,275 24,081 5,499 13,823 19,321 ATA 6,754 4,218 Table 7-19 Economic Analysis Summary Table Staged Development Approach (1,000's of 1987$) Coal 0 & M Cost . Trans. Distr. User 0 0 0 0 0 0 0 0 0 4,110 469 1,498 1,210 469 1,498 15890 469 1,498 1,110 469 1,498 1,486 G5 | 2.332 1,486 645 2,332 1,486 64D |Z. 382 1,486 645 | 2,332 1,486 645)||)||2,.382 1,486 645) 2.3382 1,486 645 2,332 1,486 645 2,332 1,486 645 2,332 1,486 645 2,332 1,486 645 2,332 1,486 645 |||2 432 1,486 645)))'2). 362 1,486 G85))||'253382 1,486 645 25332 1,486 645 2,332 28,216 12,196 43,304 14,846 6,405 22,550 8,610 3,707 12,930 5,430 2,324 8,032 106,112 55,518 32,000 19,984 0 31,242 3,900 3,900 3,900 15,719 5,657 5,657 5,657 5,657 8,114 5,657 5 657 5 657 5,657 5,657 5,657 5,657 5,657 5,657 5,657 145,973 86,125 56,080 39, 305 Total 0i1 Cost Savings Benefit 0 0 0 0 0 0 0 0 0 11,215 (20,027) 7,315 5,305 1,405 1,405 S009) Leer) Le 5,355 1,455 1,455 10,423 (5,296) 4,766 W608) ))!)||/s, 950.)))/ L951 7,667 2,010 2,010 TET OOUN OetOS I 2103) 7,828 oP AD eens 8,191 FEF) 2534 PNSSSiN| 2e 07 GN) Qua. 7,821 2,164 2,164 PASTS) 26158) 20158 PESOS UN 2 we tiili2 isd FSIS) Nl 222162 TTS 2) 2d Sul) 20135 TSO Met aS ull elie 5 TTS 2 Miler) Zaks 5) i ip Ee am a Ts Sl 33 7,792 24135)||'2,4355 1545725 ))|||85752) 48,013) Net PV Benefit 83,034 (3,091)27,516 49,234 (6,846)17,234 31,660 (7,645)11,677 Benefit/ Cost ge - 2 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 Totals Present Value at Discount Rate 10 11 12 13 14 15 16 17 18 19 20 5% 10% 15% Coal Capital Cost Mine & Infra. Conv. Total 0 0 0 0 0 0 0 0 0 8,718 1,024 9,742 0 0 0 0 0 0 0 0 0 562 700 1,262 0 0 0 0 0 0 0 0 0 0 0 0 2,033 424 2,457 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 8,631 1,541 10,172 6,806 1,149 7,954 5,499 883 6,382 Mine & 11,717 6,754 Table 7-20 Economic Analysis Summary Table Staged Development Approach (With Grants for Generation Facilities) (1,000's of 1987$) Coal 0 & M Cost Total Coal Oi) Trans. Distr. User Total Cost Cost Savings Benefit 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 1,110 469 1,498 3,900 13,642 5,775 (7,867) 1,875 1,110 469 1,498 3,900 3,900 5,305 1,405 1,405 Lae 469 1,498 3,900 3900 |i pour aay ay, 1,110 469 1,498 3,900 3,900 5,355 1,455 1,455 1,486 645 2,332 5,657 6,919 7,703 784 2,046 1,486 O15 2.332 5,657 5,657 7,608 1,951 1,951 1,486 645 2,332 5,657 5,657 7,667 2,010 2,010 1,486 645 2,332 5,657 5,657 7,760 2,103, 2,103 1,486 6451 /2))332)1// (15057, SESH MSZe ieee ieee 1,486 G45 2,332 6,657 8,114 8,191 7] 2,534 1,486 645 2,332 $,657 5657! t SSSi 20076 2076 1,486 645 2,332 5,657 5,657 7,821 2,164 2,164 1,486 645 2,332 5,65) S657 Hi STOMA. 58 (2258 1,486 645 72,332 5,657 5,657 7,808 2,151 2,151 1,486 645 2,382 5,657 5,657 7;879' 25162. 2,162 1,486 645 2,332 5,657 SOS T MMOS ZS oillli2, 5035 1,486 645 2,332 5,657 5.6570 75,892 25135 25135 1,486 O45 2,332. 5,857 SOT MMM NOe ees Dee eso 1,486 645 2,332 5,657 5,657 7,792 2,135 2,135 1,486 645 2,332 5,657 HOST Hyde tice k So eed 35 28,216 12,196 43,304 106,112 119,573 146,565 26,992 40,453 Net PV Benefit 14,846 6,405 22,550 55,518 65,689 76,717 11,028 21,200 8,610 + 3,707 12,930: 32,000 39,954 44,250 4,296 12,250 5,410 2,324 8,032 19,984 26,366 27,661 1,295 7,677 4,218 Benef it/ Cost 7.3.5 Results of the Economic Evaluation The results of the 20 year economic evaluation are presented in terms of net present values and benefit-cost ratios. The net present value (NPV) represents the present value of the savings of the project, jess the present value of the capital costs. Using the 10 percent discount rate as an example, the 20,000 tpy "Base Case" results in a NPV of -$8,162,000. The benefit/cost (B/C) ratio is the ratio of the present value of the benefits compared with the present value of the capital costs. At a 10 percent discount rate, the B/C ratio is -0.15; the negative benefits are 0.15 times the capital costs. A comparable analysis was conducted for the Macaw site at 20,000 tpy, and resulted in a NPV of -$6,824,000 at the 10 percent rate, with a B/C ratio of 0.09. The small annual savings were not enough to counter the coal costs. The staged development with generation equipment capital costs included (Table 7-19) resulted in a NPV of -$6,846,000 and a B/C ratio of .72 at the 10 percent discount rate. Total costs for coal use are less than oi] over the 20 year time period, but the large power generation capital investments required in the earlier years of the project offset the operational savings. Annual coal costs are cheaper than oi] in all years except those where coal related capital expenditures are made. If generation equipment capital costs are excluded from the analysis, the NPV for the staged development changes to $4,296,000, and the B/C ratio increases to 1.54. Total savings over the 20 year time frame exceed $26 million. 7 = 39 7.4 Conclusions The WACDP Phase III investigated a near term approach to project development. The results demonstrate the effect of the relatively large capital investment for the mine and generation equipment on very jJow production levels. Even though substantial cost reductions were achieved for the mining operations and infrastructure, they were not enough to offset the reduced production. Demand levels at the delivered prices are not able to accommodate the 20,000 ton production output. Coal costs at minimum production levels will always be higher than at higher production levels. The staged development approach takes advantage of this decreasing cost curve to attain lower coal production costs and, with state grants for generation facilities, achieves positive benefits. At demand levels greater than 47,590 tpy, Stage 2, and /or crude oi] prices above current levels, the project economic benefits will also increase to the residents of the region. 7 - 40 8.0 RECOMMENDATIONS Index Paragraph Page 8.1 Introduction ..... - 8.2 Project Development. - 8.2.1 Mine Development. . . 8.2.2 Market Development. . 8.3 Summary. elie | el |e ©2'00 100:09) @oOnrPMmP 8.1 Introduction The recommendations presented in this report are relevant to project implementation and are supplemental to those presented in Section 14.0, Recommendations, Western Arctic Coal Development Project (WACDP) Phase Il Final Report. The Phase II recommendations addressed implementation issues from an_ overall perspective of project development. It covered the following areas: 1) pre-development activities necessary to advance the project from its current status to operations. Some of those activities were conducted during Phase III; 2) identified constraints to development off the market due to the economic condition of the market area and current energy policies of the state; and 3) identified mine and market development options available to the state if it chooses to participate in and/or expedite the development of the project. The Phase II recommendations will not be repeated in this report. The Phase III recommendations are specific and technical in nature and are based on the new information gathered during Phase III. These recommendations are intended to be incorporated into the overall project development recommendations presented in Phase II. 8.2 Project Development The findings of the WACDP Phase III concluded a staged approached to project development was the preferred development = strategy. Infrastructure requirements, mining methods, and the market were established for the staged scenario based on Phase III marketing activities and mine development occurring in the Mormon West Block mining unit of the Deadfall Syncline coal prospect. The initial production rate of the stage development scenario assumes 30,600 tpy (stage 1) increasing over a five year period to 47,590 tpy (stage 2). Although this approach is recommended by the study team, the regional concept of the project provides a wide range of development alternatives to the WACDP, several of which have been discussed in this report and in the WACDP Phase II report. The major factors that allow for such flexibility and diversity in development options are: 1) any increases in the annual production tonnage of the mine will provide considerable economic benefits to the consumer and improve upon the marketability of the coal; 2) the total potential market demand of the study area is very large in comparison to the initial market demand proposed by the staged development scenario (less than 10% of total market); and 3) the Deadfall Syncline coal reserves are of sufficient size to accommodate any increases in market volumes within the study area (400 years supply at 100,000 tpy). With several development options available to the study team the staged approach was preferred for the following reasons: 1) the communities and organizations representing the initial project market have shown the highest interest in the project; 2) initial development involves a smal] scale easy-to-implement program, with a relatively low financial risk; 3) staged development will allow for an expeditious startup of the mine and will allow for knowledge and experience to be gained in the field prior to reaching maximum production; 4) it takes advantage of increasing annual coal volumes while decreasing production costs; and 5) allows for the gradual development of the market over a realistic period of time. At full production the staged development case will place the WACDP in a viable position whereby both, the long term benefits and further market penetrations would be realized. Implementation of the project will require development activities in two areas, mine and market development. Supplemental to Phase II recommendations, additional recommendations are presented in the following two sub-sections, mine development and market development. 8.2.1 Mine Development 1) 2) 3) The potential for significantly reducing mining costs through elimination of blasting needs to be further investigated. Seismic velocities seem to indicate that ripping of all overburden may be feasible but the frozen state of the overburden makes the assumption of rippability overly optimistic at this time. The only way the question of rippability will be conclusively answered is to try it. The operating cost difference between ripping and blasting jis potentially in the two to three dollar per ton range and at least part of the estimated $85,000.00 per year capital cost for the blasting and drilling equipment could be saved. Therefore, it is recommended that the use of a D7 or larger dozer be strongly considered for any future open cut bulk sampling programs. This will also provide realistic mining parameters to better establish the economics of mining Deadfall Syncline coal. To date all bulk sample tests from the Deadfall Syncline have been taken at shallow depths and have been weathered with lower heating values compared to deeper drill core samples taken in previous field programs. It is suggested that future coal seam bulk samples be taken at a depth of 20 to 40 feet. This will establish the coal quality and characteristics of Deadfall Syncline coal at the normal operating depths and will eliminate most weathering problems such as frost riven coal. The aerial photography for which the photo control panels were set during August, was not taken due to poor weather conditions. The photo control panels were constructed of material which should last for at least a year and they were wel] anchored with rocks. Many of the panels may still be 8-4 4) visible next summer. Therefore, if the opportunity to dovetail the photography of the Deadfall Syncline area arises again, it should be done. Even if the photo panels are obliterated, post flight control can be performed and still yield acceptable control for mapping purposes. Reconnaissance geophysical exploration and drilling have indicated the potential for significant coal reserves in areas other than the Mormon West mining unit, some of which may be capable of supporting the 20,000 ton per year production rate for many years. The Mormon West mining unit was selected as the initial mine site because it best met the criteria for the 50,000 ton per year base case production and anticipated market expansion. Although the Mormon West mining unit can also meet the requirements for the 20,000 ton per year rate, the cost of haul road construction could better be amortized over a larger tonnage. Therefore, if the 20,000 ton per production rate were selected as the most realistic scenario for several years with only a moderate expansion of market anticipated, some of the coal deposits south of Omalik Lagoon, that are closer to the coast, should be considered for initial mine development. Infrastructure capital costs and haulage operating costs could be reduced, and the information available indicates a likelihood that sufficient low ratio reserves exist near the coast to support a 20,000 ton per year production rate. Two areas are suggested from existing data as possibilities for mining of small tonnages and which are more accessible to the coastline. One is the Cape Beaufort area, which probably contains adequate reserves but a shallow coastline, local property conflicts and generally poorer coal quality than the Deadfall Syncline coals makes it a second choice. The 1985 Western Arctic Coal Geophysical Program report, prepared by Howard Grey & Associates, Inc., shows indicated reserves of Sites 5) approximately 1.2 million tons, at 3 to 1 ratio, in seam 21 about 4 miles southeast of Omalik Lagoon near the USCGS benchmark "MaCaw". Although these reserves are not proven, it is likely that enough reserves exist at even lower than 3 to 1 ratios to meet the 20,000 tpy requirement. Seam 21 is shown to be from 10 to 18 feet thick with dips less than 15 degrees. Geology of the MaCaw block appears to be favorable for mining and, since it is a part of the Deadfall Syncline, the quality should be acceptable. MaCaw is on the drainage divide between Omalik and Panikpiak creeks and no wetlands need to be crossed to access the coast. The coal deposits are about 5 miles from the coast. However, 50 percent or more of the access road from the coast to the mine area would be on top of barren hogback ridges and construction costs would be significantly less than construction over wetlands. The shoreline is probably shallow near the mouth of Panikpiak creek, where the road would terminate, and thus shore to barge transfer of coal would likely be more costly than at the Omalik site. However, because the road would be usable year round, savings in other areas of coal handling are likely, such as the need for a smaller’ stockpile. In conclusion, the MaCaw reserve block should be considered as a potential alternate mining site for the 20,000 tpy production rate if that production rate is selected for development. At the lower tonnages proposed by the staged development case an alternative to the berthing facility ie.,lighterage transport, appears to avert many of the capital and operating costs, social and environmental concerns, and regulatory agency permit requirements associated with the berthing facility. Coal transport remains a large portion of the overall cost of the price of coal delivered to its destination. Work in this area should continue with 8 - 6 consideration being given to innovative concepts and/or technologies associated with marine transportation and material handling. With a staged approach to development the optimum transport scenario would be developed at _ full production or Stage 2 of the mining operation. 8.2.2 Market Development 1) 2) 3) 4) The communities and their utilities and/or institutions identified as part of the WACDP Phase III market should undertake coal conversion feasibility studies as part of their planning cycle. It is recommended that coal briquetting using locally available binders be investigated and demonstrated in the market area. Briquetting would utilize all coal fines and provide a product that could be handled without dust generation. Further from the coal combustion furnace and stove tests conducted by the Mineral Industry Research Laboratory (MIRL) the briquettes had excellent stability and combustion characteristics and were highly recommended for residential use. It is recommended that a furnace with automatic ash discharge and one that can yield higher efficiencies than the one tested by MIRL be investigated. The combustion tests performed by MIRL did not present any particulate emissions data. It is therefore suggested any future residential coal stove and furnace combustion tests utilize an EPA particulate sampling train to determine particulate emissions. 5) Firing tests of Deadfall Syncline coal in a spreader stoker as well as fluidized bed furnace are recommended in order to obtain sufficient information on the combustion behavior of the coal for the design of a coal fired power plant and associated systems serving large communities such as Nome or Kotzebue, military installations, and industries. It was found in all combustion tests performed by MIRL that sulfur emissions from burning Deadfal) Syncline coal would be substantially lower than that produced by the combustion of fuel oil. Due to the low sulfur, high calcium, and relatively high btu content of the coal, a combustion test would provide the data to assess the desulferization equipment required by a power plant application. This equipment represents a significant capital and operating costs to the power plant. To date all cost estimates in this area have been conservative. Further in-depth investigation may provide significant data that could translate into lower power plant and large institutional coal use costs. 8.3 Summary The recommendations presented here and in the Phase II report present a logical and low risk strategy to project implementation. Further, it appears development of the project will provide significant long term benefits to the residents, local governments and organizations of the region and the State of Alaska such as: 1) provide an abundant, economic, and stable price energy resource to a region that traditionally pays some of the highest cost for energy in the nation; 2) provide long term permanent employment in an area of high unemployment; 3) stimulate and diversify the state and regional economy; 4) and reduce the states participation in energy assistance programs in the region. These benefits would have an extended effect and potential to expand due to the long-term nature and regionalized concept of the project. Despite the potential benefits, the economic condition of the region, characterized by high unemployment, high energy costs, and low capital availability, would more than likely preclude the region from taking advantage of those benefits. It appears a catalyst in the form of market development assistance would be required to initiate the project. It is recommended, if the state chooses to continue to participate in the development of the project, that state assistance in the area of feasibility studies and capital expenditures be considered for market development. In this area there is a wide range of assistance alternatives available to the state. Many such options were presented in the Phase II Final Report. However, this report recommends market assistance for the development of power generation facilities. This specific area was targeted due to the relatively large expenditure required for coal- fired power generation facilities and the difficulty rural utilities have in generating capital funds through power sales. Further , its unlikely any utility would commit major funds in developing a large project involving an unproven alternative energy source and unfamiliar technology. Because of this and depending on the result ofa feasibility study conducted by a prospective utility it may be prudent to initiate a coal-fired power plant pilot project. Such a program would go a long way in: establishing the suitability of Western Arctic Coal as a power generation fuel for rural Alaska; and obtaining final commitments on the part of potential power plant customers . A SUBSIDIARY OF ARCTIC SLOPE REGIONAL CORPORATION consulting engineers 6700 Arctic Spur Road, Anchorage, Alaska 99518-1550 Telephone: (907) 349-5148 Fax: (907) 349-4213 April 4, 1988 Mr. Arnie Handsche Kotzebue Technical Center Northwest Arctic Borough School District Kotzebue, Alaska 99752 Subject: Western Arctic Coal Development Project (WACDP) Phase III Institutional Coal Boiler Conversion Attached is a conceptual design of a coal based heating system retrofit for your facility. The design is schematic in nature and is intended to be informational only, presenting the overall concept of a coal fired heating plants' installation, operation and maintenance, and estimated costs for the installation and energy price. The coal based heating system has been designed using coal from the Western Arctic coal region. The development of this resource has been investigated for the State of Alaska through the ongoing Western Arctic Coal Development Project, conducted on behalf of the Alaska Native Foundation by Arctic Slope Consulting Engineers. If you should have further questions, please call Kent Grinage at (907) 852-4556, or myself at (907) 349-5148, ext. 138. Very truly yours, ARCTIC SLOPE CONSULTING ENGINEERS L&- Patrick L. Gillen Project Engineer PLG: 1mw Attachments KOTZEBUE TECHNICAL CENTER HEATING CONCEPTUAL DESIGN There are two main buildings at the Kotzebue Technical Center consisting of the Center and adjacent Dormitory. The boiler rooms for these buildings are in the building interiors and are quite full of equipment. It would not be practical to locate new coal boilers in these rooms, nor to move coal in from or ash out to the outside. One alternative would be to build a new stand-alone boiler building which would contain two 1600 MBH coal fired boilers serving both the Technical Center and the Dormitory Building. However, this is not the most attractive option from the financial view point. The simple payback period for the capital investment would be around 20 years based on current oi], and projected coal expenditures. The reason for the long payback is the cost of running long insulated heating mains to both buildings, and the cost of the boiler house structure. A more cost effective design would be to build a new boiler house on the north side as an appendage to the Technical Center. It would contain a single 1600 MBH coal fired boiler, which would be used as a lead boiler serving the Technical Center only. A 30-day coal bunker and ash bin would also be provided outside the boiler house. Coal would be delivered from the bunker to the boiler, and ash removed from the boiler to the ash bin by means of screw augers, automatically controlled by the boiler controls. This is the concept shown in the attached Figures 1 and 2, and the basis for the cost estimate presented. It is assumed that 2/3 of the reported 24,000 gallon annual oil consumption is used to heat the Technical Center, and 1/3 heats the Dormitory. Then, the annual coal requirement for the Kotzebue Technical Center building only is estimated at 100 tons of coal with a heating value of 12,000 Btu/1b. The coal bins shown are sized to provide one months supply during January weather. The bin could be filled by front end loader from a covered yard stockpile. Alternatively, the yard stockpile could be eliminated and the coal bunkers filled directly by the coal supplier, depending on the operational requirements and coal delivery contract. The supplier filled bunker is the preferred method today in Fairbanks, in all but utility sized installations. Also, ash storage and removal could utilize a drop box and be handled by the local refuse collection service. Additional routine boiler maintenance due to coal conversion would include more frequent cleaning of the boiler tubes and maintenance of the coal and ash material feed systems. Careful operator attention should be observed during loading of the coal bunkers to ensure that foreign material (such as rocks, metal, etc.) is not admitted. Kotztech 2 COST ESTIMATE The cost estimate is based on building a new boiler house as an appendage to the Technical Center. A single 1600 MBH coal fired boiler serving the Technical Center only would be housed there and used as lead boiler to the existing boilers. New Boiler House $ 20,000 1600 MBH Coal Boiler w/Controls and Coal Auger $ 40,000 Boiler Pumps $ 3,000 New Insulated Piping $ 4,000 Coal Bunker $ 12,000 Ash Removal System $ 4,000 Power Supply $ 2,000 Mob/Demob $ 10,000 TOTAL $ 95,000 The cost of Western Arctic coal delivered to the community of Kotzebue is a function of the annual market demand, which impacts the mining production level and transportation scenarios. At a production level of 50,000 tons per year, the delivered price of coal is estimated at $108/ton, or about $4.50/million Btu. At a production level of 20,000 tons per year, the delivered price of coal is estimated at $154/ton, or $6.42/million Btu. This delivered cost for coal compares with fuel oi] which, as of April 1987, was delivered at a cost of $1.28/gal, or $9.27/million Btu. Kotztech 3 aS Z EXISTING NORTH TECH. CENTER WALL SCN B/ 2 ASH WAGON OR DUMPSTER 1600 MBH COAL BOILER —— AUTO. COAL AUTO. ASH AUGER AUGER NEW 14'x 15' BOILER HOUSE | = — COAL BOILER HOUSE P 1 — 30 DAY COAL BIN / LAN WESTERN ARCTIC © siope COAL DEVELOPMENT engineer: PROJECT Conceptua! Boiler Room Layout Plan Kotzebue Tech Center Prepared by: Date: arctic slope, van. 1988 consult ‘ cnenaae Figure 1 1600 MBH COAL BOILER 30 DAY COAL BIN W/ UNDERFEED STOKER AUTO. ASH REMOVAL AUGER I; AUTO. COAL FEED AUGER ASH WAGON OR DUMPSTER US /s HASH SECTION A-A SECTION B-B WESTERN ARCTIC I< slope COAL DEVELOPMENT engines’ PROJECT Conceptual Boiler Room Section For Kotzebue Tech Center Prepared by: Date: Jan. 1988 ongneer Figure 2 arctic slope consulting engineers A SUBSIDIARY OF ARCTIC SLOPE REGIONAL CORPORATION 6700 Arctic Spur Road, Anchorage, Alaska 99518-1550 Telephone: (907) 349-5148 Fax: (907) 349-4213 March 29, 1988 Director of Public Works City of Bethel Department of Public Works Bethel, Alaska 99559 Subject: Western Arctic Coal Development Project (WACDP) Phase III Institutional Coal Boiler Conversion Attached is a conceptual design of a coal based heating system retrofit for your facility. The design is schematic in nature and is intended to be informational. only, presenting. the overall concept of a coal fired heating plants' installation, operation and maintenance, and estimated costs for the installation and energy price. The coal based heating system has been designed using coal from the Western Arctic coal region. The development of this resource has been investigated for the State of Alaska through the ongoing Western Arctic Coal Development Project, conducted on behalf of the Alaska Native Foundation by Arctic Slope Consulting Engineers. The coal prices presented are based on the initial phases of the mine development and are subject to decrease as the market area expands. If you should have further questions, please call Kent Grinage at (907) 852-4556, or myself at (907) 349-5148, ext. 138. Very truly yours, ARCTIC SLOPE CONSULTING ENGINEERS PO SES Patrick L. Gillen Project Engineer PLG: 1mw Attachments NOME JAIL HEATING CONCEPTUAL DESIGN The utility building at the Nome Jail houses two Weil McLain, 2017 MBH output, oil fired, cast iron, heating boilers, and two 1200 MBH domestic water heaters. It is not possible to convert the boilers or water heaters to coal firing. This concept proposes that one boiler be replaced by a coal fired boiler with tankless water heaters so that this boiler could act as lead boiler both for building heating and domestic water heating. The new boiler would have an underfeed stoker and be provided with automatic coal feed and ash removal capabilities. A coal bunker and ash bin would also be provided and located outside the utilities building as shown in the attached Figures 1 and 2. Coal would be delivered from the bunker to the boiler, and ash removed from the boiler to the ash bin by means of screw augers, automatically controlled by the boiler controls. The annual coal requirement for the Nome Jail is estimated at 250 tons of coal with a heating value of 12,000 Btu/1lb. The coal bins shown are sized to provide one months supply during January weather. The bin could be filled by front end loader from a covered yard stockpile. Alternatively, the yard stockpile could be eliminated and the coal bunkers filled directly by the coal supplier, depending on the operational requirements and coal delivery contract. The supplier filled bunker is the preferred method today in Fairbanks, in all] but utility sized installations. Also, ash storage and removal could utilize a drop box and be handled by the local refuse collection service. Additional routine boiler maintenance due to coal conversion would include more frequent cleaning of the boiler tubes and maintenance of the coal and ash material feed systems. Careful operator attention should be observed during loading of the coal bunkers to ensure that foreign material (such as rocks, metal, etc.) is not admitted. Nome jail COST ESTIMATE The cost estimate is based on the foregoing narrative and it is assumed that the lead boiler will carry nearly all the load. New 3430 MBH Coal Fired Boiler with Tankless Heaters, Auger, Stoker and Controls $ 75,000 Piping Revisions $ 5,000 Coal Bunker $ 13,000 Ash Removal System $ 5,000 Wiring $ 2,000 Mob/Demob $10,000 TOTAL $ 110,000 The cost of Western Arctic coal delivered to the community of Nome is a function of the market demand which impacts the annual mining production level and transportation scenarios. At a production level of 50,000 tons per year, the delivered price of coal is estimated at $113/ton, or about $4.71/million Btu. At a production level of 20,000 tons per year, the delivered price of coal is estimated at $154/ton, or $6.42/million Btu. Nome jail ASH WAGON OR DUMPSTER EXISTING GENERATOR 3430 MBH COAL BOILER WITH AUTOMATIC UNDERFEED STOKER AND TANKLESS WATER HEATER AMP | EXISTING FUEL OIL BOILER REPLACE WITH | | DAY COAL BIN EXISTING BOILER HOUSE . EXISTING 2 COMBUSTION AIR VENT TO EXISTING EUEL, OL BOILER EXISTING WATER STORAGE TANK WESTERN ARCTIC = ...COAL DEVELOPMENT consultin aly PROJECT Conceptual Boiler Room Layout Plan Nome Jail . Prepared by: Date: Jan. 1988 Figure 1of2 EXISTING FUEL Ol BO] 30 DAY COAL BIN a © NEW 3430 MBH COAL BOILER AUTOMATIC COAL’ W/UNDERFEED STOKER AND AND ASH AUGERS TANKLESS WATER HEATER SECTION A-A SECTION B-B WESTERN ARCTIC stone COAL_ DEVELOPMENT pnoraer? PROJECT Conceptual Boiler Room Section For Nome Jail Prepared by: Date: arctic sope Jan. 1988 conning | Figure 20f2 engineers 0 serie engineers A SUBSIDIARY OF ARCTIC SLOPE REGIONAL CORPORATION 6700 Arctic Spur Road, Anchorage, Alaska 99518-1550 Telephone: (907) 349-5148 Fax: (907) 349-4213 April 4, 1988 Mr. Myron Michaels State of Alaska Anvil Mountain Corrections Center Nome, Alaska 99762 Subject: Western Arctic Coal Development Project (WACDP) Phase III Institutional Coal Boiler Conversion Attached is a conceptual design of a coal based heating system retrofit for your facility. The design is schematic in nature and is intended to be informational only, presenting the overall concept of a coal fired heating plants' installation, operation and maintenance, and estimated costs for the installation and energy price. The coal based heating system has been designed using coal from the Western Arctic coal region. The development of this resource has been investigated for the State of Alaska through the ongoing Western Arctic Coal Development Project, conducted on behalf of the Alaska Native Foundation by Arctic Slope Consulting Engineers. If you should have further questions, please call Kent Grinage at (907) 852-4556, or myself at (907) 349-5148, ext. 138. Very truly yours, ARCTIC SLOPE CONSULTING ENGINEERS tix Patrick L. Gillen Project Engineer PLG: 1mw Attachments BETHEL LOWER KUSKOKWIM SCHOOL DISTRICT HIGH SCHOOL COMPLEX CONCEPTUAL DESIGN The Boiler Room serving the high school complex houses three oil fired boilers with space for the addition of a fourth boiler. Engineers at the Superior Boilerworks, Hutchinson, Kansas, confirm that the boilers (Superior Model 3-143) can be converted to coal firing, through the addition of an underfed stoker base. This concept proposes that one boiler be converted to coal firing, so that it could act as lead boiler. The boiler would have automatic coal feed and ash removal capability. The coal bunker and ash bin would be located outside the boiler room as shown in attached Figures 1 and 2. The annual coal requirement for the High School Complex is estimated at 960 tons of coal with a heating value of 12,000 Btu/1b. The coal bins are sized to provide one months supply during January weather. Coal would be delivered from the bunker to the boiler, and ash removed from the boiler to the ash bin by means of screw augers, automatically controlled by the boiler controls. The bunker could be filled by front end loader from a covered yard stockpile. Alternatively, the yard stockpile could be eliminated and the coal bunkers filled directly by the coal supplier, depending on the operational requirements and coal delivery contract. The supplier filled bunker is the preferred method today in Fairbanks, in all but utility sized installations. Also, ash storage and removal could utilize a drop box and be handled by the local refuse collection service. Additional routine boiler maintenance due to coal conversion would include more frequent cleaning of the boiler tubes and maintenance of the coal and ash material feed systems. Careful operator attention should be observed during loading of the coal bunkers to ensure that foreign material (such as rocks, metal, etc.) is not admitted. The estimated cost to retrofit one oil boiler with a underfed coal stoker is shown below. Stoker Base, Auger and Controls $ 13,000 Coal Bunker $ 25,000 Ash Removal System $ 10,000 Wiring $ 2,000 Modify existing equip./piping $ 15,000 Mob/Demob $ 10,000 Total Installed Cost $ 75,000 lksdcoal The cost of Western Arctic coal delivered to the community of Bethel is a function of the annual mining production level and transportation scenarios. At a production level of 50,000 tons per year, the delivered price of coal is estimated at $121/ton, or about $5.04/million Btu. At a production level of 20,000 tons per year, the delivered price of coal is estimated at $164/ton, or $6.83/million Btu. This delivered cost for coal compares with fuel oil which, as of June 1987, was delivered into the High School Complex tanks at a cost of $.90/gal, or $6.52/million Btu. 1ksdcoal 4 t EXISTING FUEL TANK LOADING RAMP “ge BOILER ROOM EXISTING iv OIL BOILERS EXISTING SUPERIOR 3-143 BOILER W/ NEW 100 #/HR. STOKER BASE COAL AUGER ASH AUGER BENETH EXISTING UTILIDOR 30 DAY COAL BIN ASH DUMPSTER ASH AUGER \? WESTERN ARCTIC BF. stone COAL_DEVELOPMENT engineers PROJECT Conceptual Boiler Room Layout Plan Bethel Reg. High School Pr red by: Date: een e os Mar. 1988 aNG a Figure 1of2 EXISTING BOILER ROOM EXISTING SUPERIOR 3-143 |BOILER W/NEW 100 #/HR. 30 DAY COAL BIN STOKER BASE ed YAAAA7/N COMB. BLOWER, TRANSFER AUGER Soak aden COAL FEED AUGER ° ASH AUGER SECTION A-A s~ BOILER ROOM BEYOND—~ 30 DAY COAL BIN ASH DUMPSTER WESTERN ARCTIC slope COAL DEVELOPMENT organ PROJECT Conceptual Boiler Room TRANSFER AUGER” COAL FEED AUGER ASH AUGER 4 EXISTING Sections , UTILIDOR Bethel Reg. High School Prepared by: Date: arctic slope SECTION B=s8 engineer? arctic slope consulting engineers A SUBSIDIARY OF ARCTIC SLOPE REGIONAL CORPORATION 6700 Arctic Spur Road, Anchorage, Alaska 99518-1550 Telephone: (907) 349-5148 Fax: (907) 349-4213 March 29, 1988 Director of Plant and Facilities Lower Kuskokwim School District Bethel Regional High School Bethel, Alaska 99559 Subject: Western Arctic Coal Development Project (WACDP) Phase III Institutional Coal Boiler Conversion Attached is a conceptual design of a coal based heating system retrofit for your facility. The design is schematic in nature and is intended to be informational only, presenting the overall concept of a coal fired heating plants' installation, operation and maintenance, and estimated costs for the installation and energy price. The coal based heating system has been designed using coal from the Western Arctic coal region. The development of this resource has been investigated for the State of Alaska through the ongoing Western Arctic Coal Development Project, conducted on behalf of the Alaska Native Foundation by Arctic Slope Consulting Engineers. The coal prices presented are based on the initial phases of mine development and are subject to decrease as the market area expands. If you should have further questions, please call Kent Grinage at (907) 852-4556, or myself at (907) 349-5148, ext. 138. : Very truly yours, ARCTIC SLOPE CONSULTING ENGINEERS bio SG Patrick L. Gillen Project Engineer PLG: 1mw Attachments CITY OF BETHEL PUBLIC WORKS BUILDING HEATING The existing Public Works boiler Room houses 2 - 1400 MBH, oi] fired, cast iron, heating boilers and a 400 mbh domestic hot water heater. This concept proposes the replacement of one of the oil] fired heating boilers with a coal fired boiler of the same capacity, which would act as lead boiler. The coal boiler would have automatic coal feed and ash removal capability. The coal bunker and ash bin would be located outdoors as shown in attached Figures 1 and 2. Coal would be delivered from the bunker to the boiler, and ash removed from the boiler to the ash bin by means of screw augers, automatically controlled by the boiler controls. The annual coal requirement for the Public Works building is estimated at 275 tons of coal with a heating value of 12,000 Btu/1lb. The coal bins are sized to provide one months supply during January weather. The bin could be filled by front end loader from a covered yard stockpile. Alternatively, the yard stockpile could be eliminated and the coal bunkers filled directly by the coal supplier, depending on the operational requirements and coal delivery contract. The supplier filled bunker is the preferred method today in Fairbanks, in all but utility sized installations. Also, ash storage and removal could utilize a drop box and be handled by the local refuse collection service. Additional routine boiler maintenance due to coal conversion would include more frequent cleaning of the boiler tubes and maintenance of the coal and ash material feed systems. Careful operator attention should be observed during loading of the coal bunkers to ensure that foreign material (such as rocks, metal, etc.) is not admitted. The estimated cost to replace one oil boiler with a underfed stoker coal boiler of the same capacity is shown below. Boiler, Stoker, Auger and Controls $ 40,000 Coal Bunker $ 15,000 Ash Removal System $ 8,000 Wiring $ 2,000 Modify existing equip./piping $ 5,000 Mob/Demob $ 10,000 Total Installed Cost $ 80,000 Boiler The cost of Western Arctic coal delivered to the community of Bethel is a function of the annual mining production level and transportation scenarios. At a production level of 50,000 tons per year, the delivered price of coal is estimated at $121/ton, or about $5.04/million Btu. At a production level of 20,000 tons per year, the delivered price of coal is estimated at $164/ton, or $6.83/million Btu. This delivered cost for coal compares with fuel oi] which, as of June 1987, was delivered into Public Works tanks at a cost of $.85/gal, or $6.16/million Btu. Boiler EXISTING BOILER ROOM L—_- EXISTING OIL BOILER EXISTING WATER HEATER NEW 414MMBH COAL BOILER WITH 150#/HR. STOKER BASE EXISTING DAY TANK é ASH DUMPSTER { X TRANSFER AUGER ASH AUGER 30 DAY COAL BINS WESTERN ARCTIC BF. siope OAL DEVELOPMENT once PROJECT Conceptual Boiler Room Layout Plan Bethel Public Works Bldg. Prepared by: arctic sAope Mar 1988 consutting : engineers | Figure lof 30 DAY COAL BIN Y aa COMB. AIR OPENING \ fai | AUGER | \ RELOCATED STAIRS DUMPSTER EAST ELEVATION 30 DAY NEW 1.4 MMBH COAL BOILER COAL BIN is 150 #/HR STOKER BASE | \ TRANSFER AUGER EXISTING OIL BOILER l WESTERN ARCTIC F< 1ope COAL DEVELOPMENT ory, PROJECT Conceptual Boiler Room Elevation & Section Bethel Public Works Bldg. FEED AUGER ASH AUGER ‘ Prepared by: Date: fope SECTION A-A engines APPENDIX B Test Results Sample Calculations B-1 Sample Calculation for March 7, 1987 Run B-2 Sample Calculation for the Harmon Mark II Stove Test @ B-1 Sample Calculations for March 7, 1987 Run Appendix B - 1 Sample Calculation for March 7, 1987 Run a Stack Losses In firing mode, P= .05 in H20 for 6" stack P = Pstagnation - Pstatic = {24 p/p via Bernoulli's Eqn. P at T= 6879F, a= = 00108 slugs/£t? RT with P = 1 atn AP = .26 1b /£t?2 Hence, v = 2(.26)/.00108 21.9 fps . lbm 62 s Ms = = .035 —— X —— ft? x 21.9 fps x 60 = 9.0 lbm/min £t3 4-144 min During feed mode, Q stack = mC, (T] - T amb) X time lbm Btu = 9.0 X .24 —————_ (547-80) (10 mins) min lbm°F = 10.2 K Btu During LHA mode, Qstack = 9.0 (.24) (687-80) (60) = 78.8 K Btu During HHA mode, Qs = 9.0 (.24) (745-80) (13) = 19.1 K Btu 25 Forced Convection During LH modes, Vean = 875 cfm Letting, 9a = .074 lbm/ft? Mean = a Vean = 64.7 lbm/min Apportioning by .areas mside = 48.5 lbm/min Appendix B - 1 (Continued) mtop = 16.2 lbm/min Hence, during LHA mode Q side = nee (Tg - Tg) (time) = 48.5(.24) (134-86) (60) = 33.4 K Btu Q top = 16.2(.24) (109-86) (60) = 5.4 K Btu During LHB mode Q side = 48.5 (.24) (109-83) (27) = 8.1 K Btu Q top = 16.2(.24) (100-83) (27) = 1.8 K Btu During HH modes, Ves, = 1240 cfm so m side = 68.5, m top = 22.8 lbm/min During HHA mode Q side = 68.5(.24) (141-94) (13) = 10.0 K Btu Q top = 22.8(.24) (115-94) (13) = 1.5 K Btu During HHB mode Q side = 68.5(.24) (133-87) (10) = 6.0 K Btu Q top = 22.8(.24) (111-97) (10) = .8 K Btu Se Free Convection During OFF mode, with char. lengths = .45 ft for top and 3.17 £t for sides 2gL3 Ts - Tw Top: Ray, = ———— ———_ is the Rayleigh number va Ts + Tw Here g is the gravitational constant, v the kinematic viscosity and x the thermal diffusivity. 2(32.2) (.45)3 £4752 99-80 16.8x1075 ft2 2.37x1074 £t2 994794920 s s Appendix B - 1 (Continued) 2.7 x 106 and _ hL Nuy = .54 Ray,*29 = 21.8 = —————_ is the Nusselt number (from K Incropera, cited on p. 33). Here h is the convective heat transfer coefficient, La characteristic length, and K the thermal conductivity of air. Q top = 4(T.-T.. ) (time) (Area) Btu 105 21.8 .0151 ———— (99.80) °F( ft hrop 60 hrs (3.73) £t2 «45 £t = 96 Btu Sides: Ray, = 4.7 x 108 4. Radiation Q= 0 (T.4 - 7.4) A (time) during OFF mode 105 Q = .85 (.171x1078) (5594-5394) (21.6) (__.) 60 = 730 Btu Appendix B - 2 Sample Calculations for the Harmon Mark III Stove Test 1. Energy input in coal: Mass of coal fed Heating value of coal Energy input 66.9 lbm 10,366 BTU/1bm 10,366 BTU * 66.9 lbm uouou lbm 693,485 BTU 2. Forced Convection Vean (as rated) = 135 CFM For Period 2: 135 £t.3 0.0761 lbm = 10.27 1bm/min m= Véan ° Yair < Pm Assuming this m is divided evenly between the ducts Meus = Mg = 5.14 lbm/min QrHs = MRAS *-Cp__ Tt: 5.14 lbm 0.24 BIU = ——— - ———._ (179-64) OF* 0.49 hr°60 min min lbm F hr 4171 BTU 5.14°0.24(195-64) +0.49°60 Qrxs 4751 BTU 3. Free Convection From Sides: Ray, = 98 (Ts-T, )L3/ v0 is the Rayleigh number all properties at: (Tg + To) sere £ 2 Appendix B - 2 (Continued) and where 8= 1/T¢ is the coefficient of thermal expansion. __ 0.387 Raz 1/6 Nu; = {0.825 + 2 0.492 [1+ (9/16 8/27 Pr For Period 2: Te = (303+64) / 2 = 184°F = 644°R a= 1.203 £t2/hr v= 23.24 x 1075 £t2/s k= 0.01768 BTU/hr ft°F Pr= 0.696 32.2 ft 3600s 1 (303-64)R * (32.5/12)3 £t3 hrs Ray = ———__—_- +> Le . a u s2 hr 644°R 1.203£t2 + 23.24 x 1075£t = 305 x 105 0.387 Raz1/6 Noy, = { 0.825 + 32 0.492 [1+ ( ) 9/16 18/27 0.696 = 173 Nuys ke Tete A L Q= L = 173+ 0.01768 BTU (303-64) F + 0.49 hr + = £t2 ( ) oo (32.5/12) ft) shrftOr 144 = 2.9 K BTU From Top: L = As/P = 24 + 25/98 + 12 = 0.51 ft Nuy, = 0.54 Razl/4 ~~ for 104 z Ray, z 107 or Nuy = 0.15 Razl/3— for 107 Z Raz, z lott Av Finding Ray, from equation above, Appendix B - 2 (Continued) Nuy = 0.15 * (20,805,070)1/3 = 41 Q= (41 + 0.01786 | (319-64) + 0.49 - (24 + 25) (0.51 ) 144 = 0.8 k BTU 3. Radiation 7 4 4p ene Qeq © Pi (fs = TD A £ Where: Pij =] For the sides during period 2: 4 Q= 0.9 +1 + 0.1714 x 10-8 Bru (7634-5244)R - 98 + 32.5 £t2 - 0.49hr ft2 hrr4 (444) = 4.4 k BTU For the top during period 2: Q = 0.9 + 0.1714 x 10-8 + (7794-5244) - 24.25 + 0.49 Cy44? 0.9 k BIU Gel C.2 Cus G.4 APPENDIX C Coal Field Geology Data Laboratory Results Sample Inventory Drill Logs Magnetometer Line Profiles APPENDIX C.1 LABORATORY RESULTS A. Specific Weight Estimates Coal reserves and takeoff estimates have to date been based upon text book approximations of the specific weight of coal and overburden rocks. Two samples collected during the 1986 field program were suitable for a laboratory determination of specific weight. Each sample was weighed and the volume was determined by immersion in water. The results of this exercise are presented below: SPECIFIC WEIGHT DETERMINATION SPECIFIC TONNAGE MATERIAL WEIGHT VOLUME WEIGHT FACTOR lbs cu.ft. | tbs/euw fe. (cu.£t./ton Coal 1256 55 81 24.7 Coaly-silty sandstone 47 302 156 1228 NOTE: The tonnage factor is based on short tons. B. Moisture Determination The water content of nine samples of soil, colluvium and overburden from the project area. The samples were weighed before and after being dried in a microwave oven and the moisture content was estimated from this data. The results are summarized by the following table: SAMPLE NO. TYPE DESCRIPTION MOISTURE 86-4, S-1 Auger Topsoil and colluvium 102% 86-4, S-2 Auger Colluvium 160% 86-11, 3-4' Auger Colluvium 84% TP—1,,| Soil Chip Topsoil and colluvium 183% TP-1, 2=-3' Chip Colluvium 56% TP-1, 10-14' Chip Siltstone 83 TP-3, Soil Chip Topsoil and colluvium 343 TP=3 7) 2" Chip Colluvium 203% TP-3, 4' Chip Colluvium 9% The moisture content is defined as the ratio of weight of contained water to the dry weight of the sample. - U.S. STANDARD SIEVE SIZE Zin. 1.5in. 34in.3/8in 4 10 20 40 60 100 200 HYDROMETER i 100 ; — 0.0l 0.001 GRAIN SIZE IN’ MILLIMETERS SAND = ag Pe mT CLAY Western Arctic PROJECT —Coal Demonstration Project WORK ORDER Test Upper Boring_Pit 2 SampleSeam__ Depth_9-10 ft. Dust Ratio % Passing 200 Fr bi 9 WW = 5 a ao ld = & = 2 uJ O © Ww a GRAIN SIZE DISTRIBUTION HOWARD GREY & ASSOC. INC. U.S. STANDARD SIEVE SIZE © Oo @ °o N ° D ° BAS ° ws o = ke T 9 WwW = >» a a tu 5O z iL - 2 WW oO iv ui a. nN oO 3 10 ; GRAIN SIZE IN MILLIMETERS GRAVEL SAND | copstes COARSE | FINE _ |COARSE] MEDIUM Western Arctic PROJECT _Coal Demonstration Project WORK ORDER = Test Boring Pit 2 SampleCSP-1_ Depth_11-18 ft. Dust Ratio _% Passing 200 GRAIN SIZE DISTRIBUTION HOWARD GREY & ASSOC. INC. Py - {i .. ptt OY U.S. STANDARD SIEVE SIZE © oO @ ° N o = co 9 WwW = > a a WW z we i= 2 ud O oc WwW ao 100 1.0 GRAIN SIZE IN MILLIMETERS ented ee GRAVEL SAND Western Arctic PROJECT _Coal Demonstration Project WORK ORDER = Test Boring_Pit 2 Sample_CSP-2 Depth_11-18 ft. Dust Ratio % Passing 200 GRAIN SIZE DISTRIBUTION HOWARD GREY & ASSOC. INC. APPENDIX C,2 SAMPLE INVENTORY SAMPLE NO. WEIGHT DESCRIPTION SPECIMENS NA 6.1 1 piece burn rock NA 47. 1 piece coaly-silty sandstone, TP-1 NA 12.6 1 piece coal, TP-2, lower seam CHIP SAMPLES TP-1, Soil naa Toupsoil, Test Pit i PRP, | 23) Sif Overburden, Test Pit 1 TP=1y,)) 0-1 4) 2.6 Overburden, Test Pit 1. TP-2 Overburden 1.8 Colluvium TP-2 Thin Coal Lae Coal, DFS-2, upper seam TP-2 Bone 1.8 Claystone parting TP=—2)) Coal: 18 Coal, DFS-2, lower seam TP-2 Underburden 1.8 Clayey siltstone TP-3 Soil 2.4 Soil and colluvium TP-3 Overburden-1 32 Overburden @ 2' TP-3 Overburden-2 Sisd Overburden @ 4' AUGER SAMPLES 86-3 sod Coal 13-15' 86-4, S-1 Lid) Topsoil and organics 86-4, S-2 2.2 Organic silt 86-6 (5-6') 135 Coal, 5-6" 86-6 (13-14') eS Coal, 13-14" 8io=1'7) || (3=4") =16 Silic B65) | (S=d) U5 Coal GRAB SAMPLE TP=2 S23) TP-2, upper seam stockpile CSP =, 6.6 TP-2, lower seam stockpile CSP-2 6.6 TP-2, lower seam stockpile APPENDIX C.3 Drill Logs LOG OF BORING NO, 86-1 LOG OF BORING NO. 86-2 PROJECT W-A.C.D.P. DATE Oct. 29, 1986 PROJECT W.A.C.D.P. DATE Oct. 29, 1986 TYPE BORING 34 Inch Solid Flight Auger SURFACE ELEVATION N.A. TYPE BORING 3% Inch Solid Flight Auger SURFACE ELEVATION N.A. LOCATION See Figure 6 COMPLETION DEPTH 4.0 ft. LOCATION See Figure 6 COMPLETION DEPTH 11.5 ft. Ee CONTENT % NT DEPTH, FT. SOIL DESCRIPTION SOIL DESCRIPTION SAMPLES MOISTURE CONT, SAMPLES ISTURI DEPTH, FT. MOL DEPTH, FT. ONIFIED SOIL CLASSIFICATION FROZEN DEPTH, FT. “UNIFIED SOL CLASSIFICATION Surface: vegetation free rubble ridge. Surface: vegetation free rubble ridge. Colluvium, brown, contains numerous large flat Colluvium, brown, contains numerous large flat particles mixed with gravel, sand and silt, De caer aera CL GAtEn ee ne sand and silt, slow quick penetration, low moisture/ice content, ger p G appears thawed at about 3} to 4} feet. (F-1) 2 = Coal, black, dull, weathered, soft, low moisture content, refusal below coal on hard rock. ml TD = 4.0 feet Bedrock, gray to brown sandstone, very slow penetration, impossible to determine if frozen, dry. Coal, black, dull, weathered, moist, possibly thawed (?) Bedrock, apparently gray sandstone, very slow penetration, refusal, TD = 11.5 feet FROST CLASSIFICATIONS ARE APPROXIMATE EXCEPT WHERE DETERMINED BY HYOROMETER ANALYSIS FROST CLASSIFICATIONS ARE APPROXIMATE EXCEPT WHERE OETEAMINED BY HYOROMETER ANALYSIS HOWARD GREY & ASSOCIATES, INC HOWARO GREY & ASSOCIATES, INC LOG OF BORING NO. 86-3 LOG OF BORING NO. 86-4 PROJECT W.A.C.D.P. DATE Oct. 29, 1986 PROJECT W-A.C.D.P. OATE Oct. 30, 1986 SURFACE ELEVATION N.A. TYPE BORING 3} Inch Modified Shelby Tube SURFACE ELEVATION N.A. TYPE BORING 3} Inch Solid Flight Auger 16.5 ft. LOCATION See Figure 6 COMPLETION DEPTH 10.0 ft. LOCATION See Figure 6 COMPLETION DEPTH MOISTUR' CONTENT % SOIL DESCRIPTION SOIL DESCRIPTION SAMPLES MOISTURE _ SAMPLES DEPTH, FT. CONTENT DEPTH, FT. DEPTH, FT. “UNIFIED SOL | CLASSIFICATION “URIFIED SOIL CLASSIFICATION Surface: level tussock surface with short 0'-4" fiberous organics, dark brown to brown, consists of fibers and roots, frozen. Surface: vegetation free rubble ridge. ov San Colluvium, brown, gravel mixed with sand and silt, moderate moisture content, quick penetration. (F-1) « 4"-18" organics and organic silt, dark brown, consists of fibers mixed with organic silts, thawed from 4" to 7". Coal, black, dull and weathered from top to about 10 feet, below 10 feet coal becomes shiny with Ice, white, massive, contains only trace amounts some coarse particles recovered, quick penetration, Of sade snd)isands.. low moisture content, appears frozen, may contain a thin claystone parting toward top of seam. Bedrock, gray siltstone, hard, dry, slow penetration. TD = 16.5 feet FROST CLASSIFICATIONS ARE APPROXIMATE EXCEPT WHERE DETERMINED SY HYOROMETER ANALYSIS FROST CLASSIFICATIONS ARE APPROXIMATE EXCEPT WHERE DETERMINED BY HYOROMETER ANALYSIS HOWARD GAREY & ASSOCIATES, INC HOWARO GAREY & ASSOCIATES, INC LOG OF BORING NO. 86-5 LOG OF BORING NO. 86-6 PROJECT W.A.C.D.P. OATE Nov. 1, 1986 PROJECT W.A.C.D.P. OATE Nov. 1, 1986 TYPE BORING 3} Inch Solid Flight Auger SURFACE ELEVATION N.A. TYPE BORING 34 Inch Solid Flight Auger SURFACE ELEVATION N.A. LOCATION See Figure 6 COMPLETION DEPTH 12.0 ft. LOCATION See Figure 6 COMPLETION DEPTH 19.0 ft. SOIL DESCRIPTION SOIL DESCRIPTION SAMPLES MOISTURE CONTENT % DEPTH, FT. DEPTH, FT. MOISTURE | CONTENT % DEPTH, FT. UNIFIED SOIL CLASSIFICATION DEPTH, FT. zo| UNIFIED SOL Ge CLASSIFICATION Surface: vegétation free rubble ridge. Surface: vegetation free rubble ridge. Sandy gravelly silt, brown, moist, contains some large flat particles, quick penetration, color changes to black from 1 to 2 ft. (F-3) ERS Coal, black, weathered, dull, damp to dry, shiny below 5 ft., contains clay parting between 4 and 4} ft., relatively easy penetration. 2 = Silty sandy gravel, brown to gray at depth, contains numerous large flat particles, relatively ff quick penetration. (F-1) Coal, black, dull, weathered, shiny below 10 ft., damp to dry, quick penetration, contains clay parting from 7 to about 8 feet. Claystone/siltstone, brown, weathered, dry to damp, edsy penetration, hard at 12 ft. TD = 12.0 feet Claystone/siltstone, brown, weathered, dry, quick penetration. TD s 190 ft. FROST CLASSIFICATIONS ARE APPROXIMATE EXCEPT FROST CLASSIFICATIONS ARE APPROXIMATE EXCEPT WHERE OETERMINED BY HYOROMETER ANALYSIS * WHERE OETERMINED BY HYOROMETER ANALYSIS HOWARD GAEY & ASSOCIATES, INC HOWARD GREY & ASSOCIATES, INC PROJECT W.A.C.D.P. 3} Inch Solid Flight Auger TYPE BORING LOCATION See Figure 6 LOG OF BORING NO. 86-7 DATE Nov. 1, 1986 SURFACE ELEVATION N.A. COMPLETION DEPTH 5.0 ft. PROJECT W.A.C.D.P. TYPE BORING LOCATION See Figure 6 LOG OF BORING NO. 86-8 OATE Nov. 1, 34 Inch Solid Flight Auger SURFACE ELEVATION 1986 N.A. COMPLETION DEPTH 6.0 ft. DEPTH, FT. URFIED SOL CLASSIFICATION SOIL DESCRIPTION Surface: vegetation free rubble ridge. Silty sandy gravel, brown to gray at depth, damp to dry, difficult penetration, contains numerous large flat particles. (F-1) SAMPLES ISTURI DEPTH, FT. Sandstone, gray, dry, very hard, refusal at 5.0 ft. FROST CLASSIFICATIONS ARE APPROXIMATE EXCEPT 'NHERE DETERMINED BY HYOROMETER ANALYSIS HOWARD GREY & ASSOCIATES, INC DEPTH, FT. UNIFIED SOIL CLASSIFICATION SOIL DESCRIPTION SAMPLES MOISTURE CON ENT & DEPTH, FT. Silty sandy gravel, brown to yellow brown and gray with depth, damp to dry, difficult penetration, contains numerous large flat particles. (F-1) Sandstone, gray, very hard, dry, refusal at 6.0 ft FROST CLASSIFICATIONS ARE APPROXIMATE £XCEPT WHERE OETERMINEO BY HYOROMETER ANALYSIS han HOWARD GREY & ASSOCIATES, INC LOG OF BORING NO. 86-9 LOG OF BORING NO. 86-10 PROJECT W.A.C.D.P. DATE Nov. 1, 1986 PROJECT W-A.C.D.P. DATE Nov. 2, 1986 TYPE BORING 34 Inch Solid Flight Auger SURFACE ELEVATION N.A. TYPE BORING 3} Inch Solid Flight Auger SURFACE ELEVATION N.A. LOCATION See Figure 6 COMPLETION DEPTH 24.0 ft. LOCATION See Figure 6 COMPLETION DEPTH 14.0 ft. SOIL DESCRIPTION SOIL DESCRIPTION DEPTH, FT. SAMPLES MOISTURE CONTEN DEPTH, FT. DEPTH, FT. UNIFIED SOIL CLASSIFICATION FROZEN SAMPLES MOISTURE CONTENT % DEPTH, FT. UNIFIED SOL | CLASSIFICATION Surface: vegetation free rubble ridge. Surface: hummacy tundra with grasses, 2 = Silty sandy gravel, brown, relatively easy Fiberous organics, dark brown to brown, consisting eae cerere damp to dry, contains numerous large of roots and fibers, overlying organics and organic lat particles, (F-1) silts, brown, thawed from about 6 to 9 inches, moderate ice content, ice content decreases with depth. Sandstone, brown to yellow brown, dry, Silt, brown to dark gray, contains some organics, intermittent quick and slow penetration. contains some coal which increases with depth, no coarse particles noted, moderate ice ee slow penetration. (F-4) Clayey/silty coal, black, highly weathered, dull, moderate ice content, sticky. TD = 140 feet Coal, black, dry, weathered, dull at top, shiny below 20 ft. Terminated in coal at 24.0 ft., clay parting noted between 17 and 18 ft. TD = 24.0 feet FROST CLASSIFICATIONS ARE APPROXIMATE EXCEPT FROST CLASSIFICATIONS ARE APPROXIMATE EXCEPT 'NHESE DETERMINED BY HYOROMETER ANALYSIS WHESE DETERMINED BY HYOROMETER ANALYSIS HOWARD GREY & ASSOCIATES, INC HOWARD GREY & ASSOCIATES, INC DEPTH, FT. PROJECT W-A.C.D.P. TYPE BORING LOCATION See Figure 6 CLASSIFICATION LOG OF BORING NO, 86-11 OATE Nov. 15, 34 Inch Solid Flight Auger SOIL DESCRIPTION level tussock covered with tundra with short grasses. Surface: Fiberous organics, brown, consists of roots and fibers overlying icy organic silts, ice content increased with depth, show auger penetration. 1986 SURFACE ELEVATION N.A. COMPLETION DEPTH 8.5 ft. SAMPLES MOISTURE DEPTH, FT. PROJECT W.A.C.D.P. TYPE BORING LOCATION See Figure 6 LOG OF BORING NO. 86-12 DATE Nov. 15, 1986 34 Inch Solid Flight Auger SURFACE ELEVATION N.A. COMPLETION DEPTH 6.0 ft. DEPTH, FT. UNIFIED SOIL CLASSIFICATION SOIL DESCRIPTION Surface: low rubble ridge with scattered low grasses and tussocks. Silty-gravelly sand, light brown, low moisture/ice, contains large particles, weathered, relatively fast penetration. (F-3) SAMPLES MOISTURE CONTENT % DEPTH, FT. Coaly-ice, black, dull, weathered, very high ice content, very slow penetration. Bedrock, penetration, dry, sandstone, brown, very hard, refusal at 6.0 ft, very slow Silty/clayey ice, brown, contains some coal, possibly a parting, very high ice content, very slow penetration, TD = 6.5 feet FROST CLASSIFICATIONS ARE APPROXIMATE EXCEPT WHERE DETERMINED BY HYOROMETER ANALYSIS HOWARD GREY & ASSOCIATES, INC TD = 6.0 feet FROST CLASSIFICATIONS ARE APPROXIMATE EXCEPT WHERE DETESMINED BY HYOROMETER ANALYSIS HOWARO GREY & ASSOCIATES, INC LOG OF BORING NO. 86-13 LOG OF BORING NO. 86-14 PROJECT W.A.C.D.P. OATE Nov. 15, 1986 PROJECT W-A.C.D.P. DATE Nov. 15, 1986 TYPE BORING 3} Inch Solid Flight Auger SURFACE ELEVATION N.A. TYPE BORING 3} Inch Solid Flight Auger SURFACE ELEVATION N.A. LOCATION See Figure 6 COMPLETION DEPTH 5.5 ft. LOCATION See Figure 6 COMPLETION DEPTH 5.0 ft. SOIL DESCRIPTION SOIL DESCRIPTION MOISTURE | CONTENT % DEPTH, FT. “UNIFIED SOIL SAMPLES MOISTURE CONTENT % DEPTH, FT. | UNIFIED SOIL | CLASSIFICATION SAMPLES DEPTH, FT. CLASSIFICATION Surface: low rubble ridge with scattered low qrassesi Surface: low rubble ridge with scattered low qrasses| and some tussocks. and tussocks. Silty-gravelly sand, brown, low moisture/ice Silty-gravelly sand, red brown, low moisture/ice, content but increasing with depth, contains large contains numerous large particles, fast drilling at with depth, (F-3) flat particles, weathered, fast penetration. f-sh| Bedrock, sandstone, brown to gray, very hard, weathered on top, dry, very slow penetration. Bedrock, sandstone, brown to gray, very hard, dry, very slow penetration. TD = 5.0 feet TD = 5.5 feet FROST CLASSIFICATIONS ARE APPROXIMATE EXCEPT FROST CLASSIFICATIONS ARE APPROXIMATE EXCEPT WHERE OETERMINEO BY HYOROMETER ANALYSIS WHERE DETERMINED BY HYOROMETER ANALYSIS HOWARD GREY & ASSOCIATES, INC 5 HOWARD GREY & ASSCCIATES, INC LOG OF BORING NO. 86-15 LOG OF BORING NO. 86-16 PROJECT W-A.C.D.P. DATE Nov. 15, 1986 PROJECT W.A.C.D.P. OATE Nov. 17, 1986 SURFACE ELEVATION N.A. TYPE BORING 3} Inch Solid Flight Auger SURFACE ELEVATION N.A. TYPE BORING 3} Inch Solid Flight Auger LOCATION See Figure 6 COMPLETION DEPTH 10.0 ft. LOCATION See Figure 6 COMPLETION DEPTH 9.0 ft. SOIL DESCRIPTION SOIL DESCRIPTION DEPTH, FT. SAMPLES MOISTURE CONTENT DEPTH, FT. DEPTH, FT. “UNIFIED SOIL CLASSIFICATION SAMPLES JOISTURE CONTENT % DEPTH, FT. UNIFIED SOIL CLASSIFICATION Surface: low ridge with tussock, low grasses and Surface: low ridge with scattered rubble and tussock' scattered gravels. Silty gravelly sand, brown, moderate ice content which decreases with depth, contains large particles fast penetration. (F-3) Silty-gravelly sand, brown, contains some large flat particles, fast penetration. (F-3) Rock, red, burned, slow but steady penetration. Rock, sandstone, brown to gray, weathered on top - harder with depth, color darkens to black at bottom, Coal, black, dull on top - shiny with depth, dry to very low moisture, hard-slow penetration, particles to }". FROST CLASSIFICATIONS ARE APPROXIMATE EXCEPT FROST CLASSIFICATIONS ARE APPROXIMATE EXCEPT WHERE DETERMINED BY HYOROMETER ANALYSIS oI WHERE DETERMINED BY HYOROMETER ANALYSIS HOWARD GREY & ASSOCIATES, INC HOWARD GREY & ASSOCIATES, INC LOG OF BORING NO. 86-17 LOG OF BORING NO, 86-18 PROJECT W-A.C.D.P. DATE Nov. 17, 1986 PROJECT W-A.C-.D.P. DATE Nov. 17, 1986 TYPE BORING 34 Inch Solid Flight Auger SURFACE ELEVATION N.A. TYPE BORING 3} Inch Solid Flight Auger SURFACE ELEVATION N.A. LOCATION See Figure 6 COMPLETION DEPTH 7.0 ft. LOCATION See Figure 6 COMPLETION DEPTH 5.0 ft. LK DEPTH, FT. SOIL DESCRIPTION SOIL DESCRIPTION SAMPLES MOISTURE DEPTH, FT. SAMPLES MOISTURE CONTEN UNIFIED SOIL DEPTH, FT. URIFIED SOIL CONTENT % DEPTH, FT. CLASSIFICATION CLASSIFICATION Surface: low ridge with scattered rubble and Surface: tussocks. Sandy silt, with some gravel, brown, moderate to high moisture/ice content which appears to decrease with depth. Thin organic veneer on top. (F-4) Silty-gravelly sand, brown to red brown, contains some large particles, fast penetration. (F-3) Rock, red, burned, slow penetration. “TD = 5.0 Feet FROST CLASSIFICATIONS ARE APPROXIMATE EXCEPT FROST CLASSIFICATIONS ARE APPROXIMATE EXCEPT WHERE DETERMINED 8Y HYOROMETER ANALYSIS WHERE DETERMINED BY HYOROMETER ANALYSIS HOWARD GREY & ASSOCIATES, INC HOWARO GREY & ASSOCIATES, INC PROJECT W.A.C.D.P. TYPE BORING LOCATION See Figure 6 LOG OF BORING NO, 86-19 3} Inch Solid Flight Auger DATE Nov. 17, 1986 SURFACE ELEVATION N.A. COMPLETION DEPTH 6.0 ft. SOIL DESCRIPTION Surface: low rubble ridge. Gravelly-silty sand, brown, with thin veneer of organics on top, contains numerous large particles, fast penetration. (F-3) SAMPLES Ui CONT, DEPTH, FT, PROJECT W.A.C.D.P. TYPE BORING LOCATION See Fiyure 6 LOG OF BORING NO. 86-20 DATE Nov. 17, 1986 34 Inch Solid Flight Auger SURFACE ELEVATION N.A. COMPLETION DEPTH 9.0 ft. DEPTH, FT. UNIFIED SOIL CLASSIFICATION SOIL DESCRIPTION Surface: low rubble ridge Gravelly silty sand, red, high ice moisture content, contains large particles, fast penetration, has thin organic veneer on top. (F-3) SAMPLES DEPTH, FT. Rock, siltstone, gray, slow penetration, dry. FROST CLASSIFICATIONS ARE APPROXIMATE EXCEPT WHERE DETERMINED BY HYOROMETEA ANALYSIS HOWARD GAREY & ASSOCIATES, INC Rock, red, burned, soft, thawed from 5 to 6 ft. with water coming up hole, fast penetration, highly weathered. TD = 9.0 feet FROST CLASSIFICATIONS ARE APPROXIMATE EXCEPT WHERE DETERMINED BY HYOROMETER ANALYSIS HOWARD GREY & ASSOCIATES, INC PROJECT W-A.C.D.P. 34 Inch Solid Flight Auger TYPE BORING LOCATION LOG OF BORING NO. 86-21 DATE Nov. 18, 1986 See Figure 6 SURFACE ELEVATION N.A. COMPLETION DEPTH 9.0 ft. PROJECT W-A.C.D.P. TYPE BORING LOCATION See Figure 6 LOG OF BORING NO. 86-22 DATE Nov. 21, 1986 3} Inch Solid Flight Auger SURFACE ELEVATION N.A. COMPLETION DEPTH 9.0 ft. DEPTH, FT. UNIFIED SOIL CLASSIFICATION Pp? a c SOIL DESCRIPTION Surface: tundra with tussocks and low grasses adjacent to ridge. Fibrous organics and organic silts, dark brown, high ice content, very slow penetration. Clay, gray, slow penetration. very sticky, (F-4) low ice/moisture content, SAMPLES jOISTURi CONTENT # Coaly-ice, black, very high ice content, quick auger penetration. DEPTH, FT. DEPTH, FT. CLASSIFICATION SOIL DESCRIPTION Surface: south sloping tundra with low tussocks. SAMPLES MOISTURE CONTENT & % DEPTH, FT. Fibrous organics and organic silts, brown to gray, high ice content, contains trace sands and fine gravels, upper organics consist of roots and fibers Clayey silt, gray, high ice content which decreases with depth, color darkens with depth, slow auger Penetration. (F-4) FROST CLASSIFICATIONS ARE APPROXIMATE EXCEPT WHERE DETERMINED BY HYOROMETER ANALYSIS HOWARD GREY & ASSOCIATES, INC FROST CLASSIFICATIONS ARE APPROXIMATE EXCEPT WHERE DETERMINED BY HYOROMETER ANALYSIS HOWARD GREY & ASSOCIATES, INC PROJECT W.A.C.D.P. 34 Inch Solid Flight Auger TYPE BORING LOCATION See Figure 6 DEPTH, FT. LOG OF BORING NO. 86-23 DATE Nov. 21, 1986 SURFACE ELEVATION NLA. COMPLETION DEPTH 7.0 ft. PROJECT W.A.C.D.P. TYPE BORING LOCATION See Figure 6 LOG OF BORING NO. 86-24 DATE Dec. 14, 1986 3} Inch Solid Flight Auger SURFACE ELEVATION N.A COMPLETION DEPTH 7.0 ft. ONIFIED SOIL _| CLASSIFICATION SOIL DESCRIPTION Surface: south sloping tundra with low tussocks. Fiberous organics and organic silt, brown, high ice content, organics consist of roots and fibers, slow auger penetration. Clayey-silt, gray but grading to black with depth, high ice content, very slow auger penetration. (F-4 SAMPLES Coaly-ice to icy-coal, black, very high ice content coal is highly weathered, very slow auger penetration. SOIL DESCRIPTION Surface: ge with sperse vegetation among rock particles. Colluvium, brown, contains large flat particles mixed with gravels, sand and silt, random hard Particles encountered, how moisture content which appears to decrease with depth. (F-1) SAMPLES MOISTUR CONTENT % DEPTH, FT. TD = 7.0 feet FROST CLASSIFICATIONS ARE APPROXIMATE EXCEPT WHERE DETERMINED SY HYOROMETER ANALYSIS. FROST CLASSIFICATIONS ARE APPROXIMATE EXCEPT WHERE DETERMINED BY HYOROMETER ANALYSIS. HOWARD GREY & ASSOCIATES, INC HOWARD GREY & ASSOCIATES, INC LOG OF BORING NO. 86-25 PROJECT W.A.C.D.P. DATE Dec. 17, 1986 TYPE BORING 34 Inch Solid Flight Auger SURFACE ELEVATION N.A. LOCATION See Figure 6 COMPLETION DEPTH 9.0 ft. SOIL DESCRIPTION DEPTH, FT. SAMPLES DEPTH, FT. | UNIFIED SOL _| CLASSIFICATION Surface: vegetation free rubble ridge. Colluvium, brown, consists of large flat weathered Particles mixed with gravel, sand and silt, low moisture content. (F-1) Coal, black, dull on top but lusture becomes shiny with depth, very low moisture content, easy auger penetration. FROST CLASSIFICATIONS ARE APPROXIMATE EXCEPT WHERE DETERMINED 3Y HYOROMETER ANALYSIS HOWARD GREY & ASSOCIATES, INC LOG OF BORING NO. 87-2 PROJECT W.a.c.D.P. DATE = 7/31/87 TYPE BORING 3.5 inch Solid Flight Auger SURFACE ELEVATION Na LOCATION See Location Sketch COMPLETION DEPTH 9.0 feet LOG OF BORING NO, 87-1 PROJECT W.a.C.D.P. DATE = 7/30/87 TYPE BORING 3.5 inch Solid Flight Auger SURFACE ELEVATION Na LOCATION See Location Sketch COMPLETION DEPTH 15.5 feet SOIL DESCRIPTION SOIL DESCRIPTION DEPTH, FT. UNIFIED SOIL] CLASSIFICAIION CONTENT % DEPTH, FT. DEPTH, FT. URIFIED SOL CLASSIFICATION FROZEN SAMPLES MOISTURE CONTENT % DEPTH, FT. SAMPLES ) MOISTURE FROZEN Colluvium, brown, damp, loose, consiscs predominately of sands and silc. (FI-F2) Colluvium, brown, predominately sand and silc with gravel and large flac rocks, easy auger penetration. (F1-F2) 2 = Coal, black, dull at top becoming shiny at about 5 ft., soft, low moisture content. Coal, black, dull becoming shiny at about 9.0 fr., soft. Refusal on bedrock at 15.5 fc. TDs 15.5 ft. HOWARD GREY & ASSOCIATES, INC HOWARD GREY & ASSOCIATES, INC FROST CLASSIFICATIONS ARE APPROXIMATE EXEPT WHERE ‘DETERMINED BY HYDROMETER ANALYSIS LOG OF BORING NO. 87-6 PROJECT w.a.c.p.P. DATE 7/30/87 TYPE BORING 3.5 inch Solid Flight Auger SURFACE ELEVATION NA LOCATION See Location Sketch COMPLETION DEPTH 21.0 feet LOG OF BORING NO. 87-5 PROJECT wW.a.C.D.P. DATE = 7/31/87 TYPE BORING 3.5 inch Solid Flight Auger SURFACE ELEVATION NA LOCATION See Location Sketch COMPLETION DEPTH 20.0 feet SOIL DESCRIPTION SOIL DESCRIPTION SAMPLES MOISTURE CONTENT % DEPTH, FT. DEPTH, FT. UNIFIED SOIL CLASSIFICATION MOISTURE CONTENT % DEPTH, FT. DEPTH, FT. UNIFIED SOIL CLASSIFICATION FROZEN Colluvium, brown, moist, soft, consists predominately of sand and silt with some large flat rocks, easy auger penetration. Colluvium, brown, damp, loose, consists predominately of sand (F1-F2) and silt with some large flat rocks. (F1-F2) Siltstone/claystone, brown, soft, low moisture content. Clay, brown, hard, frozen. (F4) Coal, black, soft, dull at top becoming shiny wich depth. Coal, black, dull at top becoming shiny with depth, low moisture content, easy auger penetration. Refusal on bedrock at 21.0 ft. TD 21.0 fe. TD= 20.0 fr. HOWARD GREY & ASSOCIATES, INC HOWARD GREY & ASSOCIATES, INC FROST CLASSIFICATIONS ARE APPROXIMATE EXEPT FROST CLASSIFICATIONS ARE APPROXIMATE EXCEPT WHERE DETERMINED BY HYDROMETER ANALYSIS WHERE DETERMINED BY HYDHOMETER ANALYSIS LOG OF BORING NO. 87-8 PROJECT W.a.c.D.P. DATE 7/30/87 TYPE BORING 3.5 inch Solid Flight Auger SURFACE ELEVATION NA LOCATION See Location Sketch COMPLETION DEPTH 20.0 feet LOG OF BORING NO. 87-7 PROJECT wW.A.C.D.P. DATE 7/30/87 TYPE BORING 3.5 inch Solid Flight Auger SURFACE ELEVATION Na LOCATION See Location Sketch COMPLETION DEPTH 14-0 feet TURE CONTENT % SOIL DESCRIPTION SOIL DESCRIPTION SAMPLES MOIS DEPTH, FT. SAMPLES MOISTURE CONTENT % DEPTH, FT. DEPTH, FT. UNIFIED SOIL CLASSIFICATION DEPTH, FT. UNIFIED SOL _| CLASSIFICATION Colluvium, brown, loose, damp, consists predominately of sand Colluvium, brown, loose, damp, consists predominately of sand and silc wich some large flac rock particles. (F1-F2) and silt with some large flat rock particles. (F1-F2) Siltstone/claystone, tan, soft, easily penetrated by auger, contains occasional thin sandstone layers. Siltstone/claystone, tan, soft, easily penetrated by auger, contains occasional thin sandstone layers. Coal, black, dull, low moisture content. TDs 14.0 ft. Coal, black, soft, dull at top becoming shiny with depth, low moisture content. TD=20.0 ft. HOWARD GREY & ASSOCIATES, INC HOWARD GREY & ASSOCIATES, INC FROST CLASSIFICATIONS ARE APPROXIMATE EXCEPT FROST CLASSIFICATIONS ARE APPROXIMATE EXEPT WHERE DETERMINED BY HYDROMETER ANALYSIS WHERE ‘DETERMINED BY HYDROMETER ANALYSIS. LOG OF BORING NO. 87-10 PROJECT wW.a.c.D.P. DATE 8/2/87 TYPE BORING 3.5 inch Solid Flight Auger SURFACE ELEVATION NA LOCATION See Location Sketch COMPLETION DEPTH 10.0 feet LOG OF BORING NO. 87-9 PROJECT wW.a.c.D.P. DATE 8/2/87 TYPE BORING 3.5 inch Solid Flight Auger SURFACE ELEVATION Na LOCATION See Location Sketch COMPLETION DEPTH 5-0 SAMPLES MOISTUN| SOIL DESCRIPTION SOIL DESCRIPTION CONTENT % DEPTH, FT. DEPTH, FT. SAMPLES DEPTH, FT. DEPTH, FT. CLASSIFICATION UNIFIED SOIL] CLASSIFICATION Colluvium, brown, loose, damp, consists predominately of sand Colluvium, brown, loose, damp, consists predominately of sand and silt with:some large flac rock particles. (F1-F2) and silt with some large flat rock particles. (F1-F2) Coal, black, dull, low moisture content. Clay, gray, moist when thawed. (F4) \ Siltscone/clayscone, tan to brown, soft, contains thin sandstone TD= 5.0 fr. layers. Coal, black, soft, dull at top becoming shiny with depth, low moisture content. Tb= 10.0 ft. HOWARD GREY & ASSOCIATES, INC FROST CLASSIFICATIONS ARE APPROXIMATE EXEP1 WHERE: DETERMINED BY HYOROMETER ANALYSIS HOWARD GREY & ASSOCIATES, INC FROST CLASSIFICATIONS ARE APPROXIMATE EXCEPT WHERE DETERMINED BY HYDROMETER ANALYSIS LOG OF BORING NO. 87-12 LOG OF BORING NO. 87-11 8/2/87 DATE 8/2/87 SURFACE ELEVATION NA PROJECT w.a.c.D.P. DATE TYPE BORING 3.5 inch Solid Flight Auger SURFACE ELEVATION NA LOCATION See Location Sketch COMPLETION DEPTH 9.0 PROJECT wW.a.C.D.P. TYPE BORING 3.5 inch Solid Flight Auger LOCATION See Location Sketch COMPLETION DEPTH 5.0 SOIL DESCRIPTION SAMPLES MOISTURE SOIL DESCRIPTION CONTENT &% DEPTH, FT. DEPTH, FT. URIFIED SOIL SAMPLES MOISTURE CONTENT % DEPTH, FT. DEPTII, FT. UNIFIED SOIL CLASSIFICATION CLASSIFICATION Colluvium, brown, loose, damp, consists predominately of sand and silt with some large flat rock particles. (F1-F2) Colluvium, brown, loose, damp, consists predominately of sand and silt with some large flat rock particles. (F1-F2) Coal, black, soft, dull at top becoming shiny with depth, low moisture content. Clay, gray, firm, low moisture content. (F4) Siltscone/claystone, tan to brown, soft, contains thin sandstone layers. Coal, black, soft, dull, low moisture content. HOWARD GREY & ASSOCIATES, INC FROST CLASSIFICATIONS ARE APPROXIMATE EXEPT FROST CLASSIFICATIONS ARE APPROXIMATE EXCEPT ERE* Hite itera eit ale IL WHERE: DETERMINED BY HYDROMETER ANALYSIS HOWARD GREY & ASSOCIATES, INC LOG OF BORING NO, 87-13 LOG OF BORING NO. 87-14 DATE 7/30/87 PROJECT w.a.c.D.P. DATE 7/30/87 SURFACE ELEVATION NA TYPE BORING 3.5 inch Solid Flight Auger SURFACE ELEVATION NA PROJECT wW.a.c.D.P. TYPE BORING 3.5 inch Solid Flight Auger LOCATION See Location Sketch COMPLETION DEPTH 16.0 feet LOCATION See Location Sketch COMPLETION DEPTH 11.0 feet SAMPLES MOISTURE CONTENT % DEPTH, FT. SOIL DESCRIPTION SOIL DESCRIPTION DEPTH, FT. UNIFIED SOIL CONTENT & DEPTH, FT. DEPTH, FT. UNIFIED SOIL CLASSIFICATION CLASSIFICATION SAMPLES | MOoisSTUNE | Colluvium, brown, loose, damp, consists predominately of sand Colluvium, brown, loose, damp, consists predominately of sand and silt with some large flat rock particles. (F1-F2) and silt with some large flat rock particles. (F1-F2) Siltstone/claystone, tan to brown, soft, contains thin sandstone layers. Coal, black, soft, dull at top becoming shiny with depth, low moisture content. Coal, black, soft, dull at top becoming shiny with depth, low moisture content. TD= 11.0 fr. TD= 16.0 ft. HOWARD GREY & ASSOCIATES, INC HOWARD GREY & ASSOCIATES, INC FROST CLASSIFICATIONS ARE APPROXIMATE EXCEPT FROST CLASSIFICATIONS ARE APPROXIMATE EXEPT WHERE DETERMINED BY HYDROMETER ANALYSIS WHERE: DETERMINED BY HYDROMETER ANALYSIS PROJECT W.a.C.D.P. TYPE BORING 3.5 inch Solid Flight Auger LOCATION See Location Sketch LOG OF BORING NO. 87-15 DATE 7/30/87 SURFACE ELEVATION NA COMPLETION DEPTH 43.5 feet LOG OF BORING NO. 87-16 PROJECT W.a.c.p.P. DATE 7/31/87 TYPE BORING 3.5 inch Solid Flight Auger LOCATION See Location Sketch SURFACE ELEVATION NA COMPLETION DEPTH 16.0 feet DEPTIL Fi URIFIED SOIL CLASSIFICATION % SOIL DESCRIPTION SAMPLES MOISTURE CONTENT Colluvium, brown, loose, damp, consists predominately of sand and silc with some large flat rock particles. (F1-F2) ridioocd Silcscone/claystone, tan to brown, soft, contains thin sandstone layers. Coal, black, dull, soft, low moisture content. TDs 13.5 ft. DEPTH, FT. HOWARD GREY & ASSOCIATES, INC FROST CLASSIFICATIONS ARE APPROXIMATE EXCEPT WHERE DETERMINED BY HYDROMETER ANALYSIS DEPTH, FT. UNIFIED SOIL CLASSIFICATION SOIL DESCRIPTION SAMPLES MOISTURE CONTENT % DEPTH, FT. Colluvium, brown, loose, damp, consists predominately of sand and silt with some large flat rock particles. (F1-F2) Siltstone/claysctone, tan to brown, soft, contains thin sandstone layers. Coal, black, soft, dull at top becoming shiny with depth, low moisture content. Bedrock, hard, refusal at 16.0 fc. HOWARD GREY & ASSOCIATES, INC FROST CLASSIFICATIONS ARE APPROXIMATE EXEP1 WHERE: DETERMINED BY HYDROMETER ANALYSIS LOG OF BORING NO, 87-17 PROJECT wW.a.C.D.P. DATE 7/31/87 TYPE BORING 3.5 inch Solid Flight Auger LOCATION See Location Sketch COMPLETION DEPTH SURFACE ELEVATION NA 11.0 feet LOG OF BORING NO. 87-18 PROJECT w.a.c.D.P. DATE 7/31/87 TYPE BORING 3.5 inch Solid Flight Auger LOCATION See Location Sketch SURFACE ELEVATION NA COMPLETION DEPTH 6.0 feet SOIL DESCRIPTION URIFIED SOL _| CLASSIFICATION SAMPLES MOISTUI CONTENT % DEPTH, FT. DEPTH, FT. UNIFIED SOL CLASSIFICATION SOIL DESCRIPTION SAMPLES MOISTURE CONTENT % DEPTH, FT. Colluvium, brown, loose, damp, consists predominately of sand and silt with some large flac rock particles. (F1-F2) oo ze Silcstone/claystone, tan to brown, soft, contains thin sandstone layers. Colluvium, brown, loose, damp, consists predominately of sand and silt with some large flat rock particles. (F1-F2) Siltscone/claystone, light brown, soft to hard, low moisture. Refusal at 6.0 fr. Coal, black, soft, dull ac cop becoming shiny wich depth, low moisture content, TD= 11.0 fc. HOWARD GREY & ASSOCIATES, INC FROST CLASSIFICATIONS ARE APPROXIMATE EXCEPT WHERE DETERMINED BY HYOROMETER ANALYSIS HOWARD GREY & ASSOCIATES, INC FROST CLASSIFICATIONS ARE APPROXIMAT WHERE DETERMINED BY HYDROMETER ANALYSIS LOG OF BORING NO, 87-20 PROJECT w.a.c.D.P. DATE 7/31/87 TYPE SORING 3.5 inch Solid Flight Auger SURFA EVATION NA LOCATION See Location Skezch COMPLETION DEPTH 22.5 feet LOG OF BORING NO. 87-19 PROJECT W.4.C.D.P. DATE 7/31/87 TYPE SORING 3,5 inch Solid Flight Auger SURFACE ELEVATION NA LOCATION See Location Sketch COMPLETION DEPTH 20.0 feer SOIL DESCRIPTION 0 Son *| CLASSIFICATION SOIL DESCRIPTION SAMPLES MOISTURE CONTENT DEPTII, FT. “UNIFIED SOI CLASSIFICATION DEPTH, FT. DEPTH, FT. FNOZEN . ~UN Colluvium, brown, loose, damp, consists predominately of sand and sile with some large flac rock particles. (F1-F2) Colluvium, brown, loose, damp, consists predominately of sand and silt with some large flac rock particles. (F1-F2) Siltscone/claystone, tan to brown, soft, contains thin sandstone Silestone/claystone, tan to brown, soft, contains thin layers. sandstone layers. Sandstone, brown, soft to hard, low moiscure content, slow Coal, black, soft, dull at top becoming shiny with depth, low auger penetration. moisture content. black, dull, moderate to high moisture/ice content, contains numerous thin claystone/siltstone partings to 16.0 fc. coal is shiny with low moisture content., Refusal on rock at 22.5 fr. TDs 22.5 fc. TD= 20.0 fr. HOWARD GAREY & ASSOCIA HOWARD GAEY & ASSOCIATES, INC FROST CLASSIFICATIONS ARE APPROXIMATE EXEPT FROST CLASSIFICATIONS ARE APPROXIMATE EXCEPT WHERE: DETERMINED BY HYDROMETER ANALYSIS WHERE DETERMINED BY HYDROMETER ANALYSIS LOG OF BORING NO, 87-21 LOG OF BORING NO. 87-22 PROJECT w.a.c.D.P. DATE 7/31/87 TYPE BORING 3.5 inch Solid Flight Auger SURFACE ELEVATION NA LOCATION See Location Sketch COMPLETION DEPTH 4.5 feet PROJECT w.a.c.D.P. DATE 7/31/87 TYPE BORING 3.5 inch Solid Flight Auger SURFACE ELEVATION NA LOCATION See Location Sketch COMPLETION DEPTH 46.0 feet SOIL DESCRIPTION SOIL DESCRIPTION SAMPLES MOISTURE CONTENT % DEPTH, FT. DEPTH, FT. UNIFIED SOIL SAMPLES MOISTURE CONTENT DEPTH, FT. DEPTH, FT. URIFIED SOIL % CLASSIFICATION FROZEN CLASSIFICATION Colluvium, brown, loose, damp, consists predominately of sand and sile with some large flat rock particles. (F1-F2) Colluvium, brown, loose, damp, consists predominately of sand and silt with some large flat rock particles. (F1-F2) 2 z= Coal, black, soft, dull at top becoming shiny with depth, low moisture content. Bedrock, sandstone, very slow auger penetration. Refusal at 4.5 fc. Bedrock, hard, slow auger penetration. Refusal at 16.0 fr. HOWARD GREY & ASSOCIATES, INC FROST CLASSIFICATIONS ARE APPROXIMATE EXEPT WHERE: DETERMINED BY HYDROMETER ANALYSIS HOWARD GREY & ASSOCIATES, INC FROST CLASSIFICATIONS ARE APPROXIMATE EXCEPT WHERE DETERMINED BY HYDROMETER ANALYSIS LOG OF BORING NO. 87-24 PROJECT W.a.c..P. DATE 7/31/87 TYPE BORING 3.5 inch Solid Flight Auger SURFACE ELEVATION Na LOCATION See Location Sketch COMPLETION DEPTH LOG OF BORING NO. 87-23 PROJECT W.a.C.D.P. DATE 7/31/87 TYPE BORING 3,5 inch Solid Flight Auger SURFACE ELEVATION NA LOCATION See Location Sketch COMPLETION DEPTH 18.0 feet w ° ° ° SOIL DESCRIPTION SOIL DESCRIPTION SAMPLES MOISTURE CONTENT % DEPTH, FT. SAMPLES MOISTURE CONTENT % DEPTH, FT. DEPTH, FT. DEPTH, FT. “URIFIED SOI CLASSIFICATION FROZEN UNIFIED SOIL CLASSIFICATION _| Colluvium, brown, loose, damp, consists predominately of sand and silt with s large flat rock particles. (F1-F2) Colluvium, brown, loose, damp, consists predominately of sand and silt with some large flat rock particles. (F1-F2) Sandstone, tan, hard, very slow penetration. Refusal ac 5.0 fr. Coal, black, soft, dull at top becoming shiny with depth, low TDs 5.0 fe. moisture content. Contains claystone parting at 12.0 ft. Refusal on bedrock at 18.0 ft. TDs 16.0 ft. HOWARD GREY & ASSOCIATES, INC HOWARD GREY & ASSOCIATES, INC FROST CLASSIFICATIONS ARE APPROXIMATE EXEPT FROST CLASSIFICATIONS ARE APPROXIMATE EXCEPT WHERE-DETERMINED BY HYDROMETER ANALYSIS WHERE DETERMINED BY HYDROMETER ANALYSIS PROJECT TYPE BORING LOCATION See Location Sketch LOG OF BORING NO. 87-25 DATE 8/1/87 SURFACE ELEVATION COMPLETION DEPTH W.a.C.D.P. 3.5 inch Solid Flight Auger NA 19.0 feet PROJECT W.a.c.D.P. TYPE BORING 3.5 inch Solid Flight Auger LOCATION See Location Sketch: LOG OF BORING NO. 87-26 DATE = 8/1/87 COMPLETION DEPTH SURFACE ELEVATION NA 21.5 feet DEPTH, FT. [UNIFIED SOIL | CLASSIFICATION FROZEN SOIL DESCRIPTION SAMPLES MOISTURE CONTENT % DEPTH, FT. DEPTH, FT. OL | ION. CLASSIFICATI FROZEN SOIL DESCRIPTION SAMPLES MOISTURE CONTENT % DEPT (FT: Silty sand, brown, medium dense, moist. (F2) Sandy silt, brown, high moisture/ice content. (F4) Icy silt to silty ice, gray, very high moisture/ice content. (F4) Clay, gray, moderate moisture/ice content contains some coal fragments, contains thin sandstone layers at 17.5 ft. (F4) Refusal on rock at 19.0 fr. TD= 19.0 fr. HOWARD GREY & ASSOCIATES, INC FROST CLASSIFICATIONS ARE APPROXIMATE EXCEPT WHERE DETERMINED BY HYDROMETER ANALYSIS Silty sand, brown, damp, loose, contains some fine to medium gravels. (F2) Silc, gray, moderate moiscture/ice content. (F4) Clay, gray, moderate to high ice content. (F4) Refusal on rock at 21.5 ft. TD= 21.5 fr. HOWARD GREY & ASSOCIATES, INC FROST CLASSIFICATIONS ARE APPROXIMATE EXEPT WHERE: DETERMINED BY HYDROMETER ANALYSIS LOG OF BORING NO. 87-27 PROJECT w.a.C.D.P- DATE 8/2/87 TYPE BORING 3.5 inch Solid Flight Auger SURFACE ELEVATION Na LOCATION See Location Sketch COMPLETION DEPTH 19-0 feet LOG OF BORING NO. 87- 28 PROJECT wW.a.c.D.P. DATE 8/2/87 TYPE BORING 3.5 inch Solid Flight Auger SURFACE ELEVATION NA LOCATION See Location Sketch * COMPLETION DEPTH 10.0 feet SOIL DESCRIPTION SOIL DESCRIPTION SAMPLES MOISTURE CONTENT % DEPTH, FT. DEPTH, FT. SAMPLES MOISTURE CONTENT % DEPTH, FT. > | UNIFIED SOL —| = =| CLASSIFICATION DEPTH, FT. URIFIED SOL CLASSIFICATION FROZEN FROZEN Colluvium, brown, loose, damp, consists predominately of sand and silt with some large flat rock particles. (F1-F2) Colluvium, brown, loose, damp, consists predominately of sand and silt with some large flat rock particles. (F1-F2) Silty clay, dark gray, moist, firm. (F4) Siltstone, tan, soft, low moisture content. Siltstone/claystone, tan to brown, soft, contains thin sandstone layers. Siltstone/claystone, tan to brown, soft, contains thin sandstone layers. TDs 10.0 fr. TDs 19.0 fc. HOWARD GREY & ASSOCIATES, INC HOWARD GREY & ASSOCIATES, INC FROST CLASSIFICATIONS ARE APPROXIMATE EXCEPT ] FROS1 CLASSIFICATIONS ARE APPROXIMATE EXEPT WHERE DETERMINED BY HYDROMETER ANALYSIS WHERE- DETERMINED BY HYDROMETER ANALYSIS LOG OF BORING NO. 87-29 PROJECT W.a.C.D.P. DATE 8/2/87 TYPE BORING 3.5 inch Solid Flight Auger SURFACE ELEVATION NA LOCATION See Location Sketch COMPLETION DEPTH 15.0 feet LOG OF BORING NO. 87-30 PROJECT W.a.c.p.P. DATE 8/1/87 TYPE BORING 3.5 inch Solid Flight Auger SURFACE ELEVATION NA LOCATION See Location Sketch COMPLETION DEPTH 15.0 feer SOIL DESCRIPTION SOIL DESCRIPTION DEPTH, FT. SAMPLES MOISTURE CONTENT % DEPTH, FT. SAMPLES MOISTURE CONTENT % DEPTH, FT. URIFIED SOIL CLASSIFICATION DEPTH, FT. URIFIED SOL CLASSIFICATION Colluvium, brown, loose, damp, consists predominately of sand and silt with some large flac rock particles. (F1-F2) Colluvium, brown, loose, damp, consists predominately of sand and silt with some large flac rock particles. (F1-F2) Siltstone, brown, soft, low moisture content, easy auger penstract oe’ Coal, black, sofc,- dull at top becoming shiny with depth, low moisture contenc. Siltstone/claystone, tan to brown, soft, contains thin sandstone layers. Contains thin claystone parcings from 12.5 to 14.5 fr. Bedrock, gray, hard very slow auger penetration, refusal ac 15.0 fc. TDs 15.0 fr. TDs 15.0 fr. HOWARD GREY & ASSOCIATES, INC HOWARD GAREY & ASSOCIATES, INC FROST CLASSIFICATIONS ARE APPROXIMATE EXCEPT FROS1 CLASSIFICATIONS ARE APPROXIMATE EXEP1 WHERE DETERMINED BY HYDROWETER ANALYSIS WHERE: DETERMINED BY HYDROMETER ANALYSIS LOG OF BORING NO. 87-31 LOG OF BORING NO. 87-32 PROJECT wW.A.C.D.P. DATE 8/1/87 TYPE BORING 3.5 inch Solid Flight Auger SURFACE ELEVATION LOCATION See Location Sketch COMPLETION DEPTH PROJECT wW.A.C.D.P. DATE 8/1/87 TYPE BORING 3.5 inch Solid Flight Auger SURFACE ELEVATION NA LOCATION See Location Sketch COMPLETION DEPTH 17.5 feet o = ° . ° ° SOIL DESCRIPTION SOIL DESCRIPTION SAMPLES MOISTURE CONTENT % DEPTH, FT. DEPTH, FT. UNIFIED SOL] CLASSIFICATION CONTENT DEPTH, FT. SAMPLES | MOISTURE DEPTH, FT. CLASSIFICATION Colluvium, brown, loose, damp, consists predominately of sand Colluvium, brown, loose, damp, consists predominately of sand and silt with some large flat rock particles. (F1-F2) and sile with some large’ flat rock parcicles. (F1-F2) Coal, black, soft, dull at top becoming shiny with depth, low moisture content. Siltstone, dark gray, high moisture/ice content. Coal, black, soft, dull at top becoming shiny with depth, low moisture content. Thin gray claysctone partings at 13.0 ft. Bedrock, hard, refusal at 15.0 ft. Thin claystone partings at bottom of coal. TD= 15.0 fr. Bedrock, hard, refusal at 17.5 ft. TD= 17.5 ft. HOWARD GREY & ASSOCIATES, INC HOWARD GREY & ASSOCIATES, INC FROST CLASSIFICATIONS ARE APPROXIMATE EXCEPT FROST CLASSIFICATIONS ARE APPROXIMATE EXEPT WHERE DETERMINED BY HYDROMETER ANALYSIS WHERE: DETERMINED BY HYDROMETER ANALYSIS LOG OF BORING NO. 87-34 PROJECT w.a.c.D.P. DATE 8/1/87 TYPE BORING 3.5 inch Solid Flight Auger SURFACE ELEVATION NA LOCATION See Location Sketch COMPLETION DEPTH 15.6 feet LOG OF BORING NO. 87-33 PROJECT W.A.C.D.P. DATE 8/1/87 TYPE BORING 3.5 inch Solid Flight Auger SURFACE ELEVATION NA LOCATION See Location Sketch COMPLETION DEPTH 46.6 feer SOIL DESCRIPTION SOIL DESCRIPTION MOISTURE DEPTH, FT. SAMPLES MOISTURE CONTENT % DEPTH, FT. DEPTH, FT. “UNIFIED SOIL CLASSIFICATION SAMPLES CONTENT % DEPTH, FT. UNIFIED SOI CLASSIFICATION FROZEN Colluvium, brown, loose, damp, consists predominately of sand ‘ , loose, damp, consists predominately of sand col tuvives tre eerie r and silt with some large flat rock particles. (F1-F2) and silt with some large flat rock particles. (FI-F2) Coal, black, soft, dull at top becoming shiny with depth, low moisture content. Silty/clay, gray, damp, firm. (F4) [| Coal, black, soft, dull ac cop becoming shiny with depth, low moisture content. Thin gray partings at bottom of coal. Bedrock, gray, hard, refusal at 15.0 fc. Contains thin gray claystone partings at bottom of coal. Bedrock, gray, hard, refusal at 18.0 ft. TD= 15.0 ft. TD= 18.0 ft. HOWARD GREY & ASSOCIATES, INC HOWARD GREY & ASSOCIATES, INC FROST CLASSIFICATIONS ARE APPROXIMATE EXCEPT FROST CLASSIFICATIONS ARE APPROXIMATE EXEPT WHERE DETERMINED BY HYDROMETER ANALYSIS WHERE- DETERMINED BY HYDROMETER ANALYSIS LOG OF BORING NO. 87-36 PROJECT wW.a.C.D.P. DATE 8/2/87 TYPE BORING 3.5 inch Solid Flight Auger SURFACE ELEVATION NA LOCATION See Location Sketch COMPLETION DEPTH 45.0 feet LOG OF BORING NO. 87-35 PROJECT w.a.c.D.P. DATE 8/1/87 TYPE BORING 3.5 inch Solid Flight Auger SURFACE ELEVATION Na LOCATION See Location Sketch COMPLETION DEPTH 19.0 feet SOIL DESCRIPTION SOIL DESCRIPTION DEPTH, FT. UNIFIED SOIL CLASSIFICATION SAMPLES MOISTURE CONTENT % DEPTH, FT. DEPTH, FT. UNIFIED SOIL FROZEN SAMPLES CONTENT % CLASSIFICATION Colluvium, brown, loose, damp, consists predominately of sand Colluvium, brown, loose, damp, consists predominately of sand and silt with some large flat rock particles. (F1-F2) and sile wich some large flat rock particles. (F1-F2) Coal, black, soft, dull ac top becoming shiny with depth, low moisture content. Silty clay, gray-brown, damp, firm. (F4) / Coal, black, soft, dull at top becoming shiny with depth, low moisture concent. Thin gray claystone partings at 13.5 ft. Bedrock, hard, refusal at 15.0 ft. Thin gray claystone partings at 17.0 fr. TD= 15.0 fe. Bedrock, claystone, gray, low moisture, soft. TDs 19.0 ft. HOWARD GREY & ASSOCIATES, INC HOWARD GREY & ASSOCIATES, INC FROST CLASSIFICATIONS ARE APPROXIMATE EXCEPT FROST CLASSIFICATIONS ARE APPROXIMATE EXEPT WHERE DETERMINED BY HYDROWETER ANALYSIS WHERE: DETERMINED BY HYDROMETER ANALYSIS PROJECT w.a.c.D.P. TYPE BORING 3.5 inch Solid Flight Auger LOCATION See Location Sketch LOG OF BORING NO. 87-37 DATE 8/2/87 SURFACE ELEVATION COMPLETION DEPTH NA 19.0 feer DEPTH, FT. UNIFIED SOIL CLASSIFICATION SOIL DESCRIPTION SAMPLES MOISTURE CONTENT % DEPTH, FT. Colluvium, brown, loose, damp, consists predominately of sand and silt with some large flat rock particles. (F1-F2) Silty clay, gray-brown, firm, damp. (F4) Coal, black, dull, low moisture, soft. Claystone, gray, low moisture/ice content. Coal, black, soft, dull at top becoming shiny with depth, low moisture content. Thin gray clayscone partings at 18.0 fr. || : TD= 19.0 ft. HOWARD GREY & ASSOCIATES, INC FROST CLASSIFICATIONS ARE APPROXIMATE EXCEPT WHERE DETERMINED BY HYDROMETER ANALYSIS APPENDIX C.4 Magnetometer Line Profiles TOTAL MAGNETIC FIELD INTENSITY IN GAMMAS 800 600 400 200 57000 800 600 400 56200 MAGNETOMETER SURVEY LINE - 100 LINE BEARING: EAST SECTION LOOKING: NORTH TOTAL DRIFT: 15 g INSTRUMENT: EG&G 856 ti tt ld 1000 2000 HORIZONTAL DISTANCE IN FEET 3000 TOTAL MAGNETIC FIELD INTENSITY IN GAMMAS 800 600 400 200 57000 8c0 600 400 56200 MAGNETOMETER SURVEY LINE - 101 .N LINE BEARING: EAST SECTICN LOOKING: NORTH TOTAL DRIFT: 2g INSTRUMENT: EG&G 856 1000 2000 3000 HORIZONTAL DISTANCE IN FEET TOTAL MAGNETIC FIELD INTENSITY IN GAMMAS 57000 800 600 400 200 56000 MAGNETOMETER SURVEY LINE - 101 S LINE BEARING: EAST SECTICN LOOKING: NORTH TOTAL DRIFT: 3 g INSTRUMENT: EG&G 856 1000 2000 3000 HORIZONTAL DISTANCE IN FEET TOTAL MAGNETIC FIELD INTENSITY IN GAMMAS MAGNETOMETER SURVEY LINE - 103 LINE BEARING: EAST SECTION LOOKING: NORTH TOTAL DRIFT: 6 g INSTRUMENT: EG&G 856 57000 800 600 400 200 56000 1000 2000 3000 m HORIZONTAL DISTANCE IN FEET TOTAL MAGNETIC FIELD INTENSITY IN GAMMAS 57000 800 600 400 200 56000 MAGNETOMETER SURVEY LINE - 104 LINE BEARING: EAST : SECTION LOOKING: NORTH TOTAL DRIFT: 2g INSTRUMENT: EG&G 856 1000 2000 HORIZONTAL DISTANCE IN FEET 3000 TOTAL MAGNETIC FIELD INTENSITY IN GAMMAS 57000 800 600 400 200 56000 MAGNETOMETER SURVEY LINE - 105 LINE BEARING: EAST SECTION LOOKING: NORTH TOTAL DRIFT: 2g INSTRUMENT: EG&G 856 1000 2000 HORIZONTAL DISTANCE IN FEET 3000 TOTAL MAGNETIC FIELD INTENSITY IN GAMMAS 57000 800 600 400 200 56000 MAGNETOMETER SURVEY LINE - 106 LINE BEARING: EAST SECTION LOOKING: NORTH TOTAL DRIFT: 5g INSTRUMENT: EG&G 856 1000 2000 HORIZONTAL DISTANCE IN FEE 3000 TOTAL MAGNETIC FIELD INTENSITY IN GAMMAS MAGNETOMETER SURVEY LINE - 150 N LINE BEARING: EAST SECTICN LCOKING: NORTH TOTAL DRIFT: 219 INSTRUMENT: EG&G 856 800 600 200 sco 600 SS CAMP Ss 56200 1000 2000 3000 4000 5000 6000 7000 HORIZONTAL DISTANCE IN FEET TOTAL MAGNETIC FIELD INTENSITY IN GAMMAS MAGNETOMETER SURVEY LINE - 150 N cont. LINE BEARING: EAST SECTION LOOKING: NORTH TOTAL DRIFT: 219 INSTRUMENT: EG&G 856 800 600 57000 800 600 56200 8000 9000 10000 11000 12000 13000 14000 HORIZONTAL DISTANCE IN FEET TOTAL MAGNETIC FIELD INTENSITY IN GAMMAS MAGNETOMETER SURVEY LINE - 150 S LINE BEARING: EAST SECTICN LOOKING: NORTH TOTAL DRIFT: 10 g INSTRUMENT: EG&G 856 57000 800 600 ow Ww CAMP sb 400 200 56000 1000 2000 3000 4000 5000 6000 7000 HORIZONTAL DISTANCE IN FEE TOTAL MAGNETIC FIELD INTENSITY IN GAMMAS MAGNETOMETER SURVEY LINE - 150 S cont. LINE BEARING: EAST SECTION LOOKING: NORTH TOTAL DRIFT: 10 g INSTRUMENT: EG&G 856 600 200 57000 sco 600 400: 56000 8000 9000 10000 11000 12000 13000 14000 HORIZONTAL DISTANCE IN FEET TOTAL MAGNETIC FIELD INTENSITY IN GAMMAS MAGNETOMETER SURVEY LINE - 250 N LINE BEARING: EAST SECTION LCOKING: NORTH TOTAL DRIFT: NLA. INSTRUMENT: EG&G 856 600 400 200 57000 800 600 400 56000 2000 3000 4000 5000 6000 7000 HORIZONTAL DISTANCE IN FEET TOTAL MAGNETIC FIELD INTENSITY IN GAMMAS 600 400 200 57000 sco 600 400: 200 56000 1000 2000 3000 4000 HORIZONTAL DISTANCE IN FEET 5000 MAGNETOMETER SURVEY LINE - 250 S LINE BEARING: WEST SECTION LOOKING: SOUTH TOTAL DRIFT: N.A, INSTRUMENT: EG&G 856 6000 7000 TOTAL MAGNETIC FIELD INTENSITY IN GAMMAS MAGNETOMETER SURVEY LINE - 350 N LINE BEARING: EAST SECTION LOOKING: NORTH TOTAL DRIFT: 7g INSTRUMENT: EG&G 856 600 200 57000 sco 600 400: 56000 1000 2000 3000 4000 5000 6000 7000 HORIZONTAL DISTANCE IN FEET TOTAL MAGNETIC FIELD INTENSITY IN GAMMAS 57000 800 600 400 200 56000 MAGNETOMETER SURVEY LINE - 350 N cont LINE BEARING: EAST SECTION LOOKING: NORTH TOTAL DRIFT: 79 INSTRUMENT: EG&G 856 8000 9000 10000 HORIZONTAL DISTANCE IN FEET MAGNETOMETER SURVEY LINE - 350S LINE BEARING: EAST SECTION LOOKING: NORTH TOTAL DRIFT: 8g INSTRUMENT: EG&G 856 “a 400 4 200 57000 sco TOTAL MAGNETIC FIELD INTENSITY IN GAMMAS 600 400: 56000 1000 2000 3000 4000 5000 6000 7000 HORIZONTAL DISTANCE IN FEET TOTAL MAGNETIC FIELD INTENSITY IN GAMMAS MAGNETOMETER SURVEY LINE - 350 § cont LINE BEARING: EAST SECTION LOOKING: NORTH TOTAL DRIFT: 8 g INSTRUMENT: EG&G 856 57000 800 600 400 200 56000 10000 8000 9000 HORIZONTAL DISTANCE IN FEET TOTAL MAGNETIC FIELD INTENSITY IN GAMMAS 57000 800 600 400 200 56000 MAGNETOMETER SURVEY LINE - 450 N LINE BEARING: WEST SECTION LOOKING: SOUTH TOTAL DRIFT: 5g INSTRUMENT: EG&G 856 1000 2000 3000 HORIZONTAL DISTANCE IN FEET TOTAL MAGNETIC FIELD INTENSITY IN GAMMAS MAGNETOMETER SURVEY LINE - 450 S LINE BEARING: WEST SECTION LOOKING: SOUTH TOTAL DRIFT: 5g INSTRUMENT: EG&G 856 57000 800 600 400 200 56000 1000 2000 3000 HORIZONTAL DISTANCE IN FEET APPENDIX D Characteristics of .Thermex T-100 TWO COMPONENT STICKS Introduction THERMEX Energy Corporation scientists have achieved a major technological breakthrough with the develop- ment of their new formulations called “the T100 Series” Thermex Explosives. With this technology the company Advantages Safety — THERMEX products, when mixed, offer in- creased resistance to impact, shock, and fire when compared with dynamite. Temperature — THERMEX explosives remain cap and cord sensitive below -40°F, and their performance and detonation characteristics are not impaired. Power — THERMEX explosives deliver more shock and total energy than dynamites, siurries, and other two- component products. Reduced Drilling Costs — Improved packaging, which increases the explosive energy per foot of bore hole, permits expanded patterns thereby lowering blasting costs. Properties and Specifications Velocity MRRREEEEREE THERMEX 100 Energy Orang Sem Geeen Serene, Density = 1.22 Water Resistance — indefinite when package remains intact; approximately 8 hours if container is ruptured. Work Energy — T100 explosives are 130% better than TNT and 150% better than a semi-gelatin dynamite. SERRE THEAMEX 7100 has developed a new and improved family of two- component explosives for the construction and mining industries. These T100 two-component explosive pro- ducts are not Class “A” until they are mixed. Eliminates Toe — When used as a bottom load in rock, THERMEX explosives develop maximum borehole pressure for the toughest jobs. Non-Headache — THERMEX explosives contain no nitroglycerine and, therefore, do not cause nitroglycerine headaches. Water Resistance — good water and oil resistance. Magazines — No high explosives magazines required until mixed. Transportation — no transportation problems — as non- explosives, movement by commercial carriers, U.P.S., etc. Gas Volumes THERMEX T100 ‘Bean “x Brana Sem Getaon Oynamae Sem Getaen Oynaman Water Get Shurry Shock Energy — In plate dent tests, T100 explosives deliver over 300% more shock energy when compared to a semi-gelatin dynamite, and over 275% when com- pared to a water gel slurry. Sensitivity — #6 cap or 50 grain detonating cord. Shelf Life — one year Temperature Restrictions — tested and usable from -40° F to 140° F. APPENDIX 5 Packaging Packaged in rigid plastic cartridges. Approximate Sticks Size Ibs/stick (mixed) per case THERMEX Yellow 1%" x 8” 5 lb 72 THERMEX Green 2” x 12” 1.5 Ib 35 - CHARACTERISTICS OF THERMEX T-100 CONTINUED Solid Liquid Case Cases Pallet Case Cases Pallet Weight Per Pallet Weight Weight Per Pallet Weight C26 Ib 36 936 lb 1351b | 36 486 Ib 41 Ib 24 984 Ib 16.0 Ib 24 384 Ib Uses Construction — rock ledge blasting; primer for ANFO; trench line shooting; boulder busting; pole hole shooting; snag removal; log jam breaking; ice jam breaking; demolition; seismic survey. Quarry — column charge for production blasting; ANFO Primer; boulder busting; secondary breakage; ditching; crusher jam breaking. Safety Tests Drop Test — No explosions, partials or burns occurred when a 30 Ib. steel weight was dropped upon a sample from 10 ft. (300 ft-Ibs). Bullet Impact Sensitivity — No detonations occurred when 22 caliber and 30 caliber rifles were fired into samples, backed with steei plates, at 50 and 100 feet. The 30 caliber projectile impacted with approximately 2,800 ft- Ibs of energy. Storage No special storage requirements. No high explosives magazines are needed until the two components are mixed. Agriculture — rock ledge blasting, ditch shooting, fence post hole shooting, stump blasting, tree planting, concrete busting, beaver dam bursting, demolition, log jam breaking, ice jam breaking. Burn Test — In all fire tests, unconfined THERMEX ex- plosives burned with supported combustion — no detonations. NOTE: THESE TESTS WERE CONDUCTED UNDER CONTROLLED CONDITIONS TO SHOW THE SAFETY OF THERMEX PRODUCTS. THE USER SHOULD RECOGNIZE THAT THESE PROOUCTS ARE STILL EXPLOSIVES AND SHOULD BE HANDLED AND TREATED AS EXPLOSIVES. Shipping Shipment — by common carriers, U.P.S., etc. Solids — THERMEX Yellow shipped without a label — none required; THERMEX Green shipped with oxidizer label. Liquids — shipped in one gallon or less quantities marked “Flash point over 96° F or higher” — no label required. Shipped Mixed — will be labeled “Class ‘A’ Explosive — Dangerous.” Disclaimer: Information and suggestions herein are based upon THERMEX Energy's tests and the tests of others using our products. These products are intended for use by persons with technical skill in explosives, and are to be used at their own discretion and risk. The manufacturer or seiler of the product disclaims and negates all warranties expressed or im- plied, except for merchantability for the use soid, in contract or tort, including without limitation, strict liability, and in no event shall manufacturer or seller be liable for consequential or special damage. Statements concerning the possible uses of our products are not intended as a recommendation to use it in the infringement of any patent, whether owned by THERMEX Energy or by others. THERMEX ENERGY CORPORATION 13601 PRESTON RD., SUITE 1007-W LOCKBOX 372 DALLAS, TEXAS 75240 (214) 387-1112 TELEX ¢ 73-2273 PV INT DAL APPENDIX F OPTIONS FOR DISPOSAL OF DREDGED SPOILS: REQUIRED PERMITS AND AUTHORIZATIONS The following is a brief summary of the permits and authorizations that will be necessary for the placement of dredge spoils. The permits required for each option are discussed later in this memo. DISCHARGE OF DREDGED OR FILL MATERIAL INTO U.S. WATERS - DEPARTMENT OF ARMY PERMIT, SECTION 404 DESCRIPTION The permit applies to all tidal influenced waters shoreward to the extreme high tide line and their adjacent wetlands, and all other waters of the United States landward to the ordinary high water line and their adjacent wetlands. Permits under this section will also require that the applicant obtain a 401 Water Quality Certification from the State of Alaska. The application for a Corps Permit will serve as an application for the State certification under a joint memorandum of understanding. PURPOSE The Discharge of Dredged or Fill Material Permit is issued to insure that all factors which may be relevant to the proposal will be considered. Among these factors are conservation, economics, aesthetics, general environmental concerns, historic values, fish and wildlife values, navigation, recreation, and water quality. If there are no substantive objections to the proposed activity, a permit can be issued within 90 days (but can easily take much longer) after receipt of a completed application. The permittee then normally has one year from the date of permit issuance to start work and must complete work within three years of the permit issuance date. A public hearing will be held if there is sufficient interest to warrant such action. The decision whether to issue a permit will be based on an evaluation of the probable impact of the proposed activity and its intended use on the public interest. AUTHORITY 33 USC 1344, Permits for Dredged or Fill Material (Section 404 of the Clean Water Act). PMTS . AUT Memorandum Greg Kinney February 1, 1988 Page 2 STRUCTURES OR WORKS IN OR AFFECTING NAVIGABLE WATERS OF THE U.S.- DEPARTMENT OF ARMY PERMIT, SECTION 10 DESCRIPTION This permit applies to all tidal influenced waters shoreward to the mean high tide line, and all navigable fresh waters landward to the ordinary high water line. It is required for the construction of any structure in or over a navigable water of the U.S., the excavation of material in such waters, or the accomplishment or any other work affecting the course, location, condition or capacity of such waters. PURPOSE The Permit for Structures or Work in or Affecting Navigable Waters of the U.S. is issued in order to insure that all factors which may be relevant to the proposal will be considered. Among these factors are conservation, economics, aesthetics, general environmental concerns, historic values, fish and wildlife values, navigation, recreation, and water quality. Since the ocean offshore from Omalik Lagoon is within the Alaska Maritime National Wildlife Refuge (PL96-487) the fish and marine mammal wildlife values will play a critical role in the permit Process. The U.S. Fish and Wildlife Service, which has management authority over the refuge, can be one of the more difficult regulatory agencies to deal with. If there are no substantive objections to the proposed activity, a permit can be issued within 90 days after receipt of a completed application. The permittee then normally has one year from the date of permit issuance to start work and must complete work within three years of the permit issuance date. A public hearing may be held if there is sufficient interest to warrant such action. The decision whether to issue a permit will be based on an evaluation of the probable impact of the proposed activity and its intended use on the public interest. Certain Section 10 activities may require that the applicant obtain a 401 Water Quality Certification from the State of Alaska. AUTHORITY 33 USC 403, Obstruction of Navigable Waters Generally: PMTS.AUT Memorandum Greg Kinney February 1, 1988 Page 3 Wharves, Piers, etc: Excavation and Filling In (Section 10 of the River and Harbor Act of 1899). TRANSPORTATION OF DREDGED MATERIAL TO DUMP IN OCEAN WATERS - DEPARTMENT OF THE ARMY PERMIT, SECTION 103 DESCRIPTION The transportation of dredged material by vessel for the purpose of dumping it in ocean water at designated dumping sites. This type of activity also requires a Department of the Army Permit under Section 10 of the River and Harbor Act of 1899 for dredging in navigable waters. This permit applies to all waters of the open sea lying seaward of the baseline from which the territorial sea is measured. PURPOSE The Permit for Transportation of Dredged Materials to Dump in Ocean Waters is issued to insure that all factors which may be relevant to the proposal will be considered. Among those factors are: conservation, economics, aesthetics, general environmental concerns, historic values, fish and wildlife values, navigation, recreation and water quality. A permit can usually be issued within 90 days after receipt of a completed application. The permittee normally has one year from the date of permit issuance to start work and must complete work within three years of the permit issuance date. A public hearing may be held if there is sufficient interest to warrant such action. The decision whether to issue a permit will be based on an evaluation of the probable impact of the proposed activity and its intended use on the public interest. AUTHORITY 33 USC 1413, Dumping Permit Program for Dredged Material. (Section 103 of the Marine Protection, Research, and Sanctuary Act of 1972, as amended). ALASKA COASTAL MANAGEMENT PROGRAM REQUIREMENTS PMTS .AUT Memorandum Greg Kinney February 1, 1988 Page 4 Conclusive Consistency Determinations The State has a system for reviewing and processing resource-related permits, leases, and approvals for proposed projects in Alaska's coastal areas. The process is governed by regulations entitled "Project Consistency with the ACMP". Each project is reviewed one time for approvals required by the resource agencies (the Departments of Environmental Conservation, Fish and Game, and Natural Resources) and for consistency reviews conducted by the DGC in the OMB. The process includes: specific deadlines for conducting and completing the review and issuing permits; the responsibilities of the applicants; state agencies, and local coastal districts; and a mechanism for resolving conflicts. The coordinating agency will review the project on either a 30 or 50 day schedule. The 50 day schedule is used for projects requiring public notice and comment periods. Authority 16 USC 1456 Coastal Zone Management Act of 1972 NORTH SLOPE DEVELOPMENT PERMIT A permit from the North Slope Borough will be required for any proposed development activity. Authority Title 29, Alaska Statutes NSB 19.10 - 19.90 NSB Comprehensive Plan and Land Management Regulations In addition to the permits required, any construction offshore would be located on state owned tide and submerged lands which will require a long term lease from the state. Any work done on the bed of Omalik Lagoon should also be covered by a state lease because the ownership of the bed will probably be questioned by the state. The USGS map shows Omalik Lagoon to be tidal which would place the bed under state ownership. However, Omalik Lagoon is, in fact, a lake which places the bed under ASRC ownership. The determination of ownership will be made when BLM surveys this presently interim conveyed land prior to granting ASRC a patent. If Omalik Lagoon is determined to be non-tidal at the time of survey then the bed will be owned by PMTS .AUT Memorandum Greg Kinney February 1, 1988 Page 5 ASRC. If this occurs, which is likely, the state will probably try to assert that Omalik Lagoon is navigable. If Omalik Lagoon is then determined to be navigable at some future date, the state would end up owning the bed. For any permanent work done in Omalik Lagoon, it would be advisable to lease the land from the state with the rent put into an escrow account until the final ownership of the bed is determined. If any material is removed from state-owned tide and submerged land and placed on private or leased land, the state will charge a royalty on this material. A royalty will not be required for dredge spoils that are discharged back onto state-owned submerged lands. It will take 120-360 days for the state to process a tide and submerged lands lease and material sale application if there are no substantive objections. DREDGE SPOILS OPTIONS 1. Infill Lagoon for Berthing Facility Required Permits: USACE Section 10 USACE Section 404 Alaska Coastal Management Consistency Determination DEC Section 401 Water Quality Certification North Slope Borough Development Permit Other Authorizations: State of Alaska Material Sale State of Alaska Submerged Land Lease 2. Deep Sea Disposal Required Permits: USACE Section 103 USACE Section 404 Alaska Coastal Management Consistency Determination DEC Section 401 Water Quality Certification 33 Land Disposal Required Permits: USACE Section 404 Alaska Coastal Management Consistency Determination DEC Section 401 Water Quality Certification PMTS AUT i Memorandum Greg Kinney February 1, 1988 Page 6 4. PMTS .AUT North Slope Borough Development Permit Other Authorizations: State of Alaska Material Sale Near Shore Disposal Required Permits: USACE Section 404 Alaska Coastal Management Consistency Determination DEC Section 401 Water Quality Certification r APPENDIX G Sediment Transportation Study COASTAL SEDIMENT TRANSPORTATION STUDY WESTERN ARCTIC COAL DEVELOPMENT PROJECT March 7, 1988 prepared for: Arctic Slope Consulting Engineers 6700 Arctic Spur Road Anchorage, Alaska Prepared by: Coastline Engineering and Consulting 5900 Lynkerry Circle Anchorage, Alaska 1.0 2.0 3.0 4.0 5.0 6.0 Table of Contents SUMMARY AND CONCLUSIONS INTRODUCTION 2:1 PURPOSE 22 BACKGROUND 2.3 APPROACH 2341 Coastal Reconnaissance and Site Inspection 2.3.2 Estimate of Sedimentation Rates from Hindcast Wave Climate 2.3.3 Sedimentation inot a Dredged Channel ANALYTICAL METHODS 3:1 WIND ANALYSIS 3.2 WAVE ANALYSIS 5.3 SEDIMENT TRANSPORT ANALYSIS 3.dul Littoral Transport 3.3.2 Wave-Induced Transport 33:3 Summary of Transport Quantities DISCUSSION REFERENCES APPENDIX 6.1 LITTORAL TRANSPORT 6.2 WAVE-INDUCED TRANSPORT eS NN NY NY NN @ ). bw HS SE OS oa 16 18 19 19 19 Figure 1 Figure 2 Figure 3 Figure 4 Figure 5 Table of Figures Coastal Sediment Transport Study Area Definition Sketch of Wave Approaching Shoreline Sum of littoral (longshore) transport directed toward and away from Pt. Lay, at the project site Sum of wave-induced transport directed toward and away from Pt. Lay, at the project site Cumulative sediment quantities for littoral and wave-in- duced transport modes, at the project site Page 10 11 13 15 Table of Tables Table 1 Table 2 Table 3 Table 4 Table 5 Percent frequency of winds at Pt. Lay, Alaska for selected directions 5 Deep water wave heights in feet and periods in seconds for selected wind speeds 8 Breaking wave heights in feet and angles in degrees for selected wind speeds and directions at the project site 9 Littoral transport quantities at the project site (cubic yds 12 per month) Wave-induced transport quantities at the project site 14 (cubic yds per month) EEE EEE 1.0 SUMMARY AND CONCLUSIONS ee ee A dredged channel is proposed to allow a 13-foot deep waterway to a proposed coal-loading facility on the Chukchi Sea coast. While this channel would not directly increase or decrease the net sediment transport rates, it would locally interrupt the sediment flow and temporarily inhibit sediment transport. On its downstream side, which is a function of the wind direction, sediment trapping by the channel could result in some erosion. The subject of this’ report are those potentially trapped sediments. This sediment transport analysis considereds two modes of transport. These modes were the wave-induced transport due to non-breaking waves seaward of the breaker zone and the littoral transport within the breaker zone. The principal wave modifying agent which could impact these transport modes was considered to be refraction which would result as waves moved from deep to shallow water. The analysis suggests that dredging requirements would be on the order of 192,000 yd3 for a normal year; a normal year being characterized by averaging all the available wind speed and direction infomation. Since the proposed channel would be maintained at a length no more than 700 yards, this quantity would require that the channel be completely redredged at least once each year. Solid gravel jetties on each side of the dredged channel seaward from the shore to about 500 feet might reduce the dredging requirements by as much as a factor of 10. If so, this amount of dredging might be possible with a backhoe from the ice. However, most coastal structures, including groins, jetties or dredged channels, can cause adjacent erosion. Erosion on the northeast side of the channel could be sufficiently extensive to require Mitigation. Dredge spoils might be a possible beach sediment source to nourish the eroded areas, While this report deals primarily with normal conditions, severe storms are also common on the north coast of Alaska, and it is possible that a single such storm could substantially fill the proposed channel. This could result in the need for additional dredging operations during the open-water period before barging activities could continue. Since except for a brief reconnaissance, this analysis was conducted without the benefit of on-site data collection, it is difficult to assess the quality of these estimates. Such an assessment would require an extensive field program which focuses on local conditions. It is suspected that these are reasonably accurate estimates, perhaps with an error on the high side for normal conditions. It is possible, however,that during an extreme year, these quantities could be as much as 2 or 3 times the estimate presented here. 2.0 INTRODUCTION ee EOE 2.1 PURPOSE A mining feasibility and marketing analysis is being conducted for a coal mining prospect southwest of Pt. Lay on the Chukchi Sea coast (Figure 1). The developers are considering dredging a channel to a depth of 13 feet (MSL) from a proposed barge-loading facilities on the northeast end of Omalik Lagoon offshore to the natural 13-foot depth. To maintain this depth, annual dredging is anticipated due to infilling from sediment transport. The purpose of this study is to estimate how much dredging might be necessary. 2.2 BACKGROUND The only known coastal studies at the present development site have been performed in support of the present project and consist of a bathymetric survey and a geotechnical drilling program. The bathymetric survey was conducted through the ice during 1985 (Arctec Alaska, 1985) and was extended to a depth of approximately 18 feet. The drilling and sampling program was also conducted through the ice during the spring of 1985. It provided standard geotechnical information including sediment size analysis. Nearby at Pt. Lay, a coastal study was conducted by personnel from Louisiana State University (Wiseman,et al, 1973). Although 40 miles to the north, wind, waves, tides, sediment transport, currents and water mass properties were either directly observed or estimated. Astronomical tides were found to be only a few inches, while meteorological tides were at times on the order of 3 feet. Open-water surface currents, measured with drogues, ranged between a few tenths to over 1.3 feet per second. Under-ice currents were no more than a tenth of a foot per second. These overall conditions are probably appropriate for the area studied in the present analysis. Although no wind records were presented in their report, the authors state that during one period of strong winds, wave heights were over 6 feet with periods over 5 seconds. During one 36-hour period, they estimated that sediment transport was about 10,000 M3 (about 13,000 yd3). This constitutes a transport rate of approximately 0.10 yd3/sec. 2.3 APPROACH 2.3.1 Coastal Reconnaissance and Site Inspection After three days in Barrow waiting for adequate weather conditions, an aircraft was chartered to fly over the site and, if possible, land for a brief inspection. A landing was made at an abandoned Dew Line site at Cape Lisburne approximately 12 miles to the southwest of the site of the proposed loading facilities. Winds were steady out of the east at over 30 knots. Although the winds were sufficiently strong to produce a severe wave activity on the beach, such was not observed. In fact, no breaking waves were observed. Two reasons accounted for this: the easterly direction provided very little fetch over which the waves could develop and a layer of mushy ice had already formed from the shoreline to a distance of several hundred feet offshore. This was thought to have been the initiation of the shorefast icing process but, it was learned, that this ice disappeared a few days later as rain and warming temperatures returned. Buoyant objects thrown a few feet offshore in this ice blanket. showed no discernible motion. Besides observing the nearshore conditions, the beach was examined briefly for indication features. The beach face was composed of coarse sand and fine gravel with almost no fine sands except near the base of 25-30 foot cliff that paralleled the shoreline. No strong evidence existed at Cape Lisburne that would suggest which was the major littoral transport in either direction. At this site and at the site for the proposed loading facilities, the beach » oriented approximately 60 degrees north of east. The orientation changes toward Pt. ay. WESTERN ARCTIC) f_ 4. COAL DEVELOPMENT PROJECT raonee TrANSPOFrt _ _STUDY AREA _ Study Area Northward and northeastward, the beach becomes more oriented northerly. In fact, the beach orientation crosses over to become oriented just a few degrees west of north near Pt. Lay. This variation in orientation is noteworthy because, due to the increase in southerly and southwesterly winds during the open-water period, transport should increase toward Pt. Lay as the beach assumes a more northerly orientation. As indicated by channel offset and spit and barrier island elongation to the east at Pt. Lay, this increase seems to occur. The evidence includes the orientation of spits and barrier islands seaward of Pt. Lay. To the south, however, the evidence is not as strong. At Omalik Lagoon, weak evidence exists to suggest transport toward Pt. Lay in that the outlet from the lagoon is positioned on its northeast side. Such often indicates net transport from the closed end (southwest, in this case) toward the open end (northeast) of the lagoon. However, the orientation of other stream mouths near the lagoon indicate transport in both directions and provide no real indication of the direction of long-term net transport. 2.3.2 Estimate of Sediment Transport Rates from Hindcast Wave Climate Several years of wind records were acquired while the Dew Line site at Cape Lisburne was in operation. Though located 12 miles to the southwest, these records should be representative of the proposed shoreside facilities site. Under a separate contract to the University of Alaska’s’s Arctic Environmental Information and Data Center, the Dew Line site records were compared to the much longer Pt. Lay wind record. In the opinion of the State Climatologist (Wise 1987, pc), the records were sufficiently similar to permit the use of the longer record. Since several years of wind speed and direction information have been published in the the Climatic Atlas (Brower, et al 1977), the Atlas was used as the primary source of wind information. : The wind summaries from the Atlas consisted of percent frequency of occurrence for winds within certain direction and speed ranges for each month (Table 1). Since waves are generated during the open-water period, the records only between July | and October 15 were used. Though wind data were published for each of the 8 compass octants, only southwest, west, northwest, and north were used. The Yeason for including only these winds was that the other 4 directions had offshore, rather than onshore components. Little or no wave activity would be generated at the site for offshore winds. Table 1 Percent frequency of winds at Pt. Lay, Alaska for selected directions WIND SPEED CLASS IN KNOTS DIRECTION | 7-11 | 11-17 28-34 | 34-41 SW 5% [4% JULY Ww 4 2 [ 1 | 04 | 03 NW 4 1 N 5 : SW 4 3 | 1 | 1 | 03 0.2% AUG W 3 1 {| 1 [1] 03 NW 3 1 0.2 N «4 sw 3 2 0.3 SEPT W 2 2 0.3 NW 2 1 of i | 04 | 03 a [sw 2 ft 2 tf | os | 02 ot [-_w [1 | 1 | 05 | 04 _| [aw 1 | 1 os | oa Souce: Modified from Brower, op cit The hindcasts were used in conjunction with a refraction analysis to produce nearshore wave conditions. These were used to calculate the longshore energy flux at a point where the waves break and to calculate the wave-induced bed velocities. 2.3.3 Sedimentation into a Dredged Channel A dredged barge channel will experience infilling near the shoreline primarily due to littoral drift and offshore due to wave-induced motion that is strong enough to initiate sediment motion. In addition to the wave-induced water motion offshore, there would likely be a general circulation due either to wind stress or thermal-haline circulation patterns. The direction of currents within the study area, can change with variations in a wind direction or large-scale circulation, and every few seconds during a wave cycle, While direction might be important in considering the effects of sediment control structures, it is not particularly important in determining the filling rate of a dredged channel which would entrap sediments coming from either direction. Large net transport quantities in either direction could indicate areas where dredged material might be placed Eg — contributing to the channel filling and where mitigation of beach erosion might e needed. Beach erosion may become important for the following reason. As with a solid causeway-type structure, a channel can effectively prohibit the transport of sediments. Until the channel becomes nearly filled, a sediment-laden longshore currents moving down the coast, could deposit a substantial portion of its sediments into the channel as it represents a type of barrier to the sediment transport. On the downstream side of the channel, littoral currents will accelerate and begin to pick up additional sediments resulting in some beach erosion. In the case of a solid structure, the sediment will be deposited on the upstream side; whereas with the channel, the sediment will be deposited directly into the channel. The rate of this deposition is a function of the local wave activity. The activity is quite different at the shoreline than seaward of the breaker zone. At the shore, sediment transport is primarily due to the sudden dissipation of potential and kinetic energy during wave breaking, while in the nearshore region, bottom currents generated by breaking waves are primarily responsible for transporting sediments. The extent of both of these processes were estimated using numerical models. The models were general in the sense that they used principles which could be applied on nearly any coastline, but they were specifically modified for this analysis and on this beach. As wave activity was considered totally responsible for sediment transport, the wave climate had to be accurately depicted. Ideally, this would be a result of long-term wave measurements. however, this was clearly not possible here and the waves were hindcast from existing wind records. This is a commonly accepted practice but the quality of the wave hindcast analysis is directly related to the quality of the wind records. Within the present analysis, no adjustment of the wind data was made with regard to its quality. However, the published winds were modified due to the type of statistic that they were likely to represent. The next section describes how the wind records were modified and how the techniques were used to develop transport estimates from those wind records and the local beach conditions. : 3.0 ANALYTICAL METHODS SS 3.1 WIND ANALYSIS The winds speeds used study were those published in the Climatic Atlas (Op cit) where the months of July, August, September, and October were used. Table | presents a modified version of the published winds for Pt. Lay. The entire months were used for July, August, and September, while only half of October was used. In the opinion of the State Climatologist, the Pt. Lay winds adequately represented the study site (Wise 1987, pc) and could therefore, be used for the present analysis. Winds used for the purpose of wave hiadcasting are tipically either measured at, or adjusted to, a 10-meter (approximately 33 feet) elevation. According to Wise (1987, pc), most of the winds published for Pt. Lay were measured at 38 feet. Such winds would tipically be reduced a few percent to account for the difference between 33 and 38 feet. Since the quality of the wind record is uncertain and the probable difference between winds at 33 and 38 feet is small, that reduction was not done for this analysis. Since waves are generated at sea, winds used in hindcasting them are typically assumed to be over-water winds. Over-water winds are up to 12 percent greater than their over-land values (for the same driving pressure differential) due to friction created by land and vegetation. Since wind speeds are generally measured on land, there is a commonly accepted procedure for converting land winds to their corresponding values over water. This procedure is a function of distance between the land-based recording station and the coast. Since that distance was very small in the present study, no such conversion was made. An adjustment was made, however, to account for the probability that the published wind speeds were statistically similar to 1-minute mean wind speeds. According to Wise (1987, pc), the winds were recorded as an observer viewed a moving dial responding to the varying wind speed and direction. No paper records of the instantaneous winds were produced. Such a technique apparently results in a value close to the 1-minute average. But waves do not respond to the relatively high variability generally associated with l-minute means and, for wave analysis, a value close to the l-hour mean is more typically used. Formulas exist for making such adjustments (Simiu and Scanlan, 1978; Durst, 1960), and these indicate that the ratio between the l-minute mean and the l-hour mean is about 1.24. That is, the 1-hour mean will be nearly equal to the l-minute mean divided by 1.24. The wind speeds presented in the Climatic Atlas (Op cit) were adjusted to account for this difference before they were used to hindcast the waves. The duration of the wind events, that is, the length of time that the winds occur, is important in wave hindcasting for two reasons. First, for waves to be in equilibrium with the existing winds, they require a sufficient fetch and wind duration. Either factor can limit wave growth. Secondly, wind duration will influence the amount of material transported -- the greater the wind duration, the more sediment will be transported. However, records of wind durations for the project site were not found in the literature and ,therefore, the average length fo wind occurences for various speeds is not known. Based on experience, 10 hours was considered the duration for each wind speed and direction considered. 3.2 WAVE ANALYSIS There are several techniques available to numerically generate wave parameters from wind information. Some of the techniques involve complex calculations and require sophisticated weather data. These usually produce wave energy spectra rather than discrete heights and periods. Less complex models do exist and have proved very useful for many years. The method selected for this analysis was produced by simplifying one of the complex energy techniques. It is presented in Chapter 3 of the Shore Protection Manual (US Army Corps of Engineers, 1984). Wave height and period are given by the following relationships: 2 A F 3 T=gu,¢o.2714)( 25) U4 7 | H = gU2(1.6x 10°) 2 CS and Where F is the fetch in feet, g is the gravitational constant (32.2 ft/sec?), and H and T are the significant wave height and period, respectively. Ug, is the wind stress factor which, in terms of the wind speed, U, in mph is: U,=0.589 U1-23 These formula produce wave heights and periods for deep-water conditions. Table 2 presents the calculated heights and periods for each of the wind speeds analyzed. Since the same fetch and duration were assumed for each direction, the estimated heights and periods varied only with wind speed. Table 2 Deep water wave heights in feet and periods in seconds for selected wind speeds WIND SPEED CLASS IN KNOTS Once the deep-water wave conditions were estimated, they were assumed to undergo modification due to bending and shoaling as the wave comes ashore. This is referred to as refraction and accounts for significant changes in both the height and direction of wave approach on the beach. Refraction is based on two principles: the first is the conservation of wave energy and the second is the irrotationality of wave number. The first states that as a wave shoals, the speed of energy propagation becomes less. This is compensated by an increase in the height of the wave. The second states that for a wave approaching the beach at an angle, its angle must change in response to a reduction in the wave speed. The refraction process was modeled using an explicit finite difference scheme which relied on the depth, wave height and period, and initial approach angle as primary input. To model this effect and the transport processes to be described next, the depth information had to be cast into a rectangular grid. This was a relatively simple task due to the almost rectangular survey grid provided by ARCTEC, Alaska (1985). Interpolation was necessary at only a few locations to produce a rectangular grid with a 500 foot ane between grid points. The area for which the grid was generated is shown in igure 1. The overall effect of refraction with an offshore bathymetry such as occurs in the project area is to first reduce the wave height soon after the wave "feels" the bottom and then to increase the height rather quickly, with continued shoaling, until breaking occurs. The wave also re-orients itself so that its angle of approach is more direct. The breaking wave characteristics are presented in Table 3. Table 3 Breaking wave heights in feet and angles in degrees for selected wind speeds and directions at the project site. a TS mse ee ne na so coal e281 [nw [1288 [240 9 [410 10] 558 12/722 13] 886 13, 3.3 SEDIMENT TRANSPORT ANALYSIS In this analysis, two modes of sediment transport were studied, namely, transport by breaking waves and transport by wave-induced bottom velocities. The first transports material along the beach as littoral transport or drift, and the second occurs in deeper water as non breaking waves generate bottom currents beyond the threshold of sediment motion. The littoral transport will be described first. 3.3.1 Littoral Transport The depth grid used as input to this analysis was briefly described in the previous section. It consisted of 9 rows and 17 columns, where the rows are parallel to the beach and the columns are perpendicular. Since the spacing between the rows and columns were each 500 feet, the grid extended from 4,000 feet offshore to the shoreline and a distance of 8,000 feet along the beach. Using this grid and accepted methods for estimating littoral transport quantities (described in greater detail in the Appendix), the average transport along the beach was determined. The procedure consisted of using the results of the wave prediction and refraction model to determine an average for the breaking wave height and angle. These were then used in the following formula to provide the transport estimate: Qu = 3.0x10°5(pg)(C,H?sinacosa), Where Q, is the transport volume in yd3/sec, c, is the group or energy velocity, p is the density of sea water, g is the gravitational constant, H is the wave height, and is the angle between the wave crest and the beach (see Figure 2). The subscript ’b’ refers to the breaking wave values. Once the transport was presented in yd3/sec, it had to be converted to transport for each month and finally for the entire open-water season. This was done by referring back to the published wind information. For each month, the percent frequency for each wind condition was also provided. These were then used to determine the amount of transport for each month and the total for the open-water period. The monthly subtotals and open-water totals are presented in Table 4. The transport direction can either be toward Pt. Lay (northeast) or away from Pt. Lay (southwest). Figure 3 presents the sum of the longshore transport quantities for these two directions. 3.3.2 Wave-Induced Transport A computer model was developed which determined the average wave induced transport for each row of the depth grid. The technique (described in greater detail in the Appendix) was developed by Madsen and Grant (1976) based on principles developed for steady flow by Einstein (1972). Jonsson (1966) developed an oscillatory analogy to the unidirectional friction factor which permited the use of earlier unidirectional models. The method estimated the transport quantities using the wave heights, period, and angle, a wave friction factor (f.),and the fall velocity (V,) of the sediment. UV... is the instantaneous horizontal particle velocity near the bottom, d is the sediment diameter and p is the oe The instantaneous wave-induced transport (Q.) parallel to the shore was estimated rom: BEACH ORTHOGONAL WAVE ant See TO WAVE CREST BREAK POINT “ BREAKER ZONE &-DEEP WATER WAVE ANGLE & -BREAKING WAVE ANGLE Definition Sketch of Wave ENVIRONMENTAL SCIENCE hopeeay Selon AND ENGINEERING, INC. 10 Transport Quantities LITTORAL TRANSPORT 40000 35000 30000 25000 20000 (cubic yards) 1SO000 10000 JOO © - AM i@s Eri) S| iiiEs 33724 July Aug Sept Oct Open—water Month QUANTITIES LEGEND d Towara Pt. Lay sd Away from Pt. Loy > Figure 3. Sum of littoral (longshore) transport directed toward and away from Pt. Lay, at the project site 11 fra Ueen ; : OF sov a{ Peal sina Where the only undefined parameter, s, is the specific gravity of the sediment (assumed to be 2.60 for silicious sand). The wave friction factor, fy, is dependent on the ratio of the horizontal distance that a water particle travels during a wave passage to the sediment diameter. The instantaneous transport was then integrated over a wave cycle to obtain an average value for the entire wave. This value was then multiplied by the duration over which those waves conditions occurred. Table 5 also presents the wave-induced transport volumes for the wind condition specified. Figure 4 presents the values in terms of direction relative to Pt. Lay. Table 4 Littoral transport quantities at the project site ( cubic yds per month) | WIND SPEED CLASS IN KNOTS | [omection [ru _[ur-i7_[ 17-22 | 2228 | ese | 3a | sw 288 | 1900 | 4418 | 4423 | 2702 | sury [ w_ [619 | 2599 | 3365 | 3736 | 5312 _| | P Nw azn [663 [992 | | [oon [sa [aae [353 [ 3400 i TOTAL FOR JULY: 40,631 | 2886 | auc [> ~w | 464 | 1300 [3365 | 9341 | 5312 5486 —————— TOTAL FOR AUGUST: 47,923 [sw] 167 _[ 963 | 213 [1769 | 2615 SEPT Pp Nw [208 [642 [1920 | 1069 | 3032_| Pn | 496 | anes | 227 [3329 YY TOTAL FOR SEPTEMBER: 35,905 [sw 56481 | 069 | sss | 1307_| 1394 ocr [-_w | _75_| «29_|_a14_| 1807 | SS PN 83592391665 _ —__ TOTAL FOR OCTOBER: 13834 {| TOTAL FOR YEAR: 138,293 | 12 TRANSPORT QUANTITIES (Cubic Yards) WAVE—INDUCED TRANS 13000 16200 14400 12600 10800 9000 7200 5400 5600 1300 oO Figure 4. Sum of wave-induced transport directed toward and away from Pt. Lay, at the project site AT PROJECT SITE WK 2 WWW \\ a: poe E JULY AUG SEPT OCT OPEN—WATER MONTH PORT QUANTITIES LEGEND EZ Zs “A Toward Pt. Lay r Sl Away from Pt. Lay » 3 Table 5 Wave induced transport quantities at the project site (cubic yds per month) WIND SPEED CLASS IN KNOTS DIRECTION | 7-11 SS CS a Lesa | tee es 13 | 413 | 1443 | 1686 | 2650 | _| 6 | 126 | 4s | | | | [0 [as [me [TT TOTAL FOR JULY: 13,720 ee ee 10 Tas [aris [2650] | 4__|_126 26 [408 [908 [a] 10 | wo [ia [iy [TT TOTAL FOR AUGUST: 21,097 2 a 6 | 400_| 698 | 1593 | 2560 |_| a 7 [3s [54 [162 [|_| The average was taken over the entire wave cycle even though the direction during half of the cycle was 180 degrees out-of-phase with the direction during the other half of the wave cycle. That is, during half of the cycle, the sediment is mcved in one direction and during the next half cycle, sediment is moved in the opposite direction. This appeared to be correct because it allowed for the fact that sediment would fill the channel regardless of the wave direction. Though not completely correct, velocities other than wave-induced were not used in this analysis. Since infilling would occur on both sides of the channel, the effect of an ambient current would essentially be nullified. The possible fallacy of this reasoning is that, since the transport is not a linear function of velocity, an exact balance between filling on one side of the channel during one half of the wave cycle would not by the same as filling on the other side during the next half cycle. The difference is unknown, however, and probably not substantial. 3.3.3 Summary of Transport Quantities Figure 5 combines the transport quantities which could fill the channel from both modes. This figure presents the cumulative rate beginning with the first open-water month. The total contribution from the littoral transport is just over 138,000 yd3/yr and from the wave-induced transport, 54,400 yd3/yr. 1% wn = = 3 sc = oO c> e zs Sa 2 = CUMULATIVE 220000 198000 7 176000 + 154000 t¢ 132000 7 110000 7 88000 7 66000 + Figure 5. Cumulative AT AUG OPEN-WATER MONTH SEPT OCT TRANSPORT QUANTITIES PROUECT Site LEGEND Sediment sediment quantities for littoral and wave- induced transport modes, 15 at the project site 4.0 DISCUSSION SSS The information presented in Figures 3 and 4 indicates that more sediment is being transported to the northeast than toward the southwest. The actual difference in the longshore transport rates between the southwest and northeast directions was 21,792 yd3/yr. This is not a particularly large value and applies to a normal year as represented by the published wind data. Anomalous wind patterns, which are not uncommon, could reverse the direction of the net discharge during some years. As an example of the magnitude of transport volumes that can be found elsewhere, a study of transport along a 70-mile length of beach between Capes Thompson and Krusenstern on the northwest Alaskan coast (Colonell and Jones, 1983) estimated net transport between 9,000 yd3/yr in one direction and 108,000 yd3/yr in the opposite direction. It is not uncommon for beaches in other parts of the United States to have net transport rates of several hundred thousand cubic yards per year. The relatively low value found for the project site is likely to explain why net transport direction is not strongly indicated by natural beach features as it is further to the north near Pt. Lay. But, conversely,it may be sufficient to explain why the outlet to Omalik Lagoon is located on its Pt. Lay side. Some of the assumptions and approximations used in this analysis and not already described merit further discussion. It was assumed that, in all cases, the wind events had a duration of 10 hours. This assumption appears unrealistic since it can be shown statistically that low wind speeds tend to have longer durations than high wind speeds. As it turns out, however, this relationship is integrated the analysis owing to the use of a constant fetch of 50 nautical miles. This fetch can become a limiting factor for winds greater than 11 knots. For example, for a 15-knot wind, the wave heights and periods stabilize after 7.5 hours. Similarly, for a 30-knot wind, stabilization occurs after 5.8 hours. Another point warranting closer examination is the grid spacing. A spacing of 500 feet was used for the analysis. This was somewhat coarse for determining the exact breaking wave condition, especially of the lower waves. In almost every case where the wind speed was equal to or less than about 14 knots, the model did not adequately allow the waves to break with correct heights and angles. For these wind conditions, the breaking height and angle were estimated from shallow water approximations after the wave hindcast and refraction model was run. The estimated values are probably close to the actual values. The wave induced transport quatities were totaled from the offshore grid boundary to the shoreline. In reality, however, the two most offshore grid points were below the maximum dredging depth of 13 feet (providing that allowances for a negative storm surge were already incorporated into the channel design). The error arising from this oversight was not large because the transport near these points are over an order of magnitude less than the transport at grid points closer to the shore. No consideration of the ambient currents was made. These currents could be important especially for the wave-induced transport mode. It was reasoned that the contribution that an ambient current might make in depositing greater sediment loads on one side of the channel would be negated on the other side. That is, on one side, it would permit sediment deposition for greater than half a wave cycle while on the other side, it would reduce the deposition duration by a similar amount. As pointed out in the previous section, annual sediment contribution to a dredged channel might be in excess of 190,000 yd3/yr. This amount would more than equal the volume of the channel. In addition, severe storms could transport quantities of sediment sufficient to require mid-season dredging. This has already been exemplified by Wiseman, et al (1973) where they estimated longshore transport of 13,000 yd? in just 36 hours near Pt. Lay. Sediment control structures might mitigate much of the transport problems. “16 Solid groins out to a distance of approximately 500 feet should eliminate most of the transport associated with breaking wave activity. Eventually, excavation along the groins would be necessary to prohibit material from entering the channel around their seaward tip. This excavation could probably be accomplished by land-based equipment such as backhoes or front-end loaders. Another remedial measure would be the use of a solid-fill causeway type of structure also out to a distance of approximately 500 feet. This would eliminate the need for a channel out to that distance. Sediment accumulation along the causeway would be removed as with the groins already described. In both cases, the excavated material could be used to mitigate any erosion which might occur. 17 5.0 REFERENCES eee aaa ARCTEC ALASKA, Inc. 1985. Western coal development project, phase II-task 5, Bathymetric survey report. Prepared for Alaska Native Foundation Brower, William A., Henry F. Diaz, Anton S. Prechtel, Harold Searby and James L. Wise. 1977. Climatic atlas of the outer continental shelf waters and coastal regions of Alaska. V. III Chukchi and Beaufort Seas, US Dept. of Interior, 439pp. Colonell, J. M. and D. F. Jones, 1983. Sediment Transport from Pt. Thompson to Cape Krusenstern, Woodward Clyde Consultants Rept to Cominco Alaska, Inc. Dusrt, C. & 1960. Wind speeds over short periods of time, Met. Mag., V. 89, No. 1056, pel. Einstein, H. A., 1972. A basic description of sediment transport on beaches, In: Meyer, R. E., Ed., Waves on beaches and resulting sediment transport, Academic Press, New York, 462pp. Jonsson, I. G., 1966. Wave boundary layers and friction factors, Proc. 10Th. Conf. Coastal Engr., ASCE, V. 1, pp. 127-148 Madsen, O. S. and William D. Grant, 1976. Sediment Transport in the coastal environment, Ralph ™M. Parson’s Laboratory for Water Resources and Hydrodynamics, Dept. of Civ. Engr., Massachusetts Institute of Technology, Rept. No. 209, 105pp. Simiu, E., and R. N. Scanlan, 1978. Wind effect on structures: An introduction to wind engineering,Wiley, New York, p. 62 U. S._Army, Corps of Engineers, 1984. Shore protection manual, V.1, U. S. Govt. Printing Office, Chapter’s 3 and 4. Wiseman, William J.,Jr.. J. M. Coleman, A. Gregory, S. A. Hsu, A. D. Short, J. N. Suhayda, C. D. Walters, Jr., and L. D. Wright, 1973. Alaskan arctic coastal processes and morphology, Coastal Studies Institute, Louisiana State University, Tech. Rept. No. 149, 17Ipp. Wise, James L., Alaska State Climatologist, 1987. Personal Communication. 18 6.0 APPENDIX 6.1 LITTORAL TRANSPORT According to the Shore Protection Manual, there are four methods to estimate the littoral transport at a specific location. The preferred method is to use estimates from nearby sites and apply local conditions. If this is not possible, the next best method is to estimate the net transport rates by estimating erosion or deposition from a series of charts, maps, or photographs over time. The most frequently used method, however, is to calculate transport rates based on beach and wave conditions. The wave conditions are either measured data or calculated from measured meteorological conditions. This is based on wave energy flux which in essence is the wave power. The forth method is by the use of empirical relationships between wave heights and transport rates. A combination of the wave power approach and and empirical have been used in this study. The average wave power (?) can be expressed as a function of the average wave energy (EF) and group velocity (C,) as: P=EC, If a is the angle between the wave crest and the shoreline, then the incoming energy flux per unit of beach length is: pgH? Pcosa= C,cosa Where p is the density, g is the gravitational constant, and H is the wave height. The component of this power in the longshore direction (?,)is: gH? P,=Pcosasina= C,cosasina Curve fitting of the data from several experimental programs has established the best relationship between the littoral transport and longshore power as: Q,=7500P, Where Q, is in yd3/sec. This relationship was used along with the frequency of wind occurrence to determine the net annual littoral transport. 6.2 WAVE-INDUCED TRANSPORT To determine the amount of material transported by wave action on the bottom, the unsteady bottom shear stress must be known. Jonsson (1966) used an approach analogous to determining an unsteady Shields Parameter. Madsen and Grant (1976), using experimental results from the University of California, Berkeley, related this parameter to volume transport. The model in this investigation used the following techniques. Madsen and Grant (1976) developed an expression between the instantaneous volume transport (Q.) and the instantaneous Shields Parameter (¥,.) as: Q,=40V ,d¥? Where V, is the particle’s fall velocity, and d is its diameter. By analogy with Shield’s development for steady flow, the Shields Parameter is expressed as: y t “ (s-1l)pgd ow 19 Where ¢ is the fluid density, s is the particle’s specific gravity, g is the gravitational constant, and +, is the instantaneous bottom shear stress. Jonsson expressed the shear stress as: 1 Tow 5fuP(U(t))?sgnU(t) Where /. is the unsteady, or wave, friction factor and U(t) is the horizontal water particle velocity near the bed, (U,.cosot),with the vertical brackets signifying "the magnitude of". The wave frequency, ¢, is equal to 27/T; T being the wave period. Combining all in a single expression for the instantaneous volume transport gives: 2\3 o,-40v ,a{ Leal) sina (s-l)gd Sina is used so that only the shore parallel component is considered. To obtain the total transport into the dredged channel, this function must be integrated twice: once over a wave cycle and again over the length of the channel. 20 Appendix H Hydrology Survey Report WESTERN ARCTIC COAL DEVELOPMENT PROJECT PHASE III HYDROLOGY SURVEY REPORT January 1988 Prepared for: Alaska Native Foundation 4101 University Drive Anchorage, Alaska 99508 Prepared by: Arctic Slope Consulting Engineers 6700 Arctic Spur Road Anchorage, Alaska 99518 TABLE OF CONTENTS 1. INTRODUCTION. ....... elie, of list fe [eal sei allie lie) oll saHlllaille | 1 TLDs PURPOSE oe\ it ellcot||e: ie: foll|sel|lits lle: (of: | wl lo |e) a! !|/'e |) || ey iteil||@ | 1 TY25||SQOPE | OF | WORK | ll! |l/e) fet sell| fon |!) f6!||tel||te |e) 204l| sill le [lel inl] sot |tas||l0 all Hilfe 2. METHODOLOGY ...... at | tol lint |lioe mel | smelt: INot “r| "os [tw fi] ell cool a tet || 2.1.. APPROACH AND OBJECTIVES . 2. 2 2 we ce ee ew aneee Z 2.2. DEFINITIONS 5 6s 6 ew we ee ew we 8 ew we 2 Sh! |\YBROWOGY: || |)-0)!:/e ls} ells) S| etol|e 2] w/t te; &||0|\6 |/6 asl cant) life (ie) ||| 3.2. FEVEAL REGIMEN . 0 ws ec eC 3 3.2. DRAINAGE BASINS . 2... 22 ee ee ee eee sissies 3 3.205. Kuchiak Creek... 2.2.2 e ee | wt |ls| |e le ||| 3.2.2 North Mormon Lake Creek ......-.. ‘4 3 Besse Mormon Lake Drainage Basin ........ 3 Su2ehs Omalik Lagoon Creek ........ Pllleliie ls 3 3.3. SURFACE WATERQUALITY 2. 0 eee De sei is 3.4. PRECIPITATION AND RUNOFF . 1... ...2.22206- + || 3 4. CONCLUSIONS AND RECOMMENDATIONS ... ~~... 2. sree 4 4.1. CONGELUSIONS .. 2. 2 2 ee see ct eeas sels ee | 4 4.2. RECOMMENDATIONS . 2... 2 we ee ee eee eee sli || 4 APPENDICES Appendix A: Water Quality Test Results Summary Appendix B: Stream Flow Calculations Appendix C: Stream Cross Sections and Stream Flow Gauging Field Notes Appendix D: Water Balance of Freshwater Lake LIST OF FIGURES 2-1 Baseline Hydrology Location Map 3-1 Drainage Basin Map 3-2 Lower Kuchiak Creek Cross Section No. 3-3 Lower Kuchiak Creek Cross Section No. 3-4 3-5 3-6 Wwnre Lower Kuchiak Creek Cross Section No. Upper Kuchiak Creek Cross Section Mormon Creek Cross Section LIST OF TABLES TABLE PAGE 3-1 Expected Runoff Water Quantity From The Annual Spring Fl00d.......ccccscccccccsccccsscscncs 3-6 3-2 Expected Runoff Water Quantity From The 10 yr., 24 hr. Precipitation Event............ ys sees cecccese 3-7 3-3 Expected Runoff Water Quantity From The 25 yr., 24 hr. Precipitation Event..........eeee as eilehel ete a lets eu 3-8 PRWWNYNMR RH Pee ree Pee tedis 1.2. INTRODUCTION PURPOSE The purpose of this study is to present a summary of baseline hydrology data on water quality and quantity within the study area for Phase III of the Western Arctic Coal Development Project (WACDP) . SCOPE OF WORK The goal of this study was to collect flow data, water samples for detailed laboratory analysis and take field measurements of applicable quality parameters from surface water bodies that may be affected by proposed mining operations. Flow data was collected from Mormon, North Mormon Lake, Kuchiak and Omalik Lagoon’ Creeks. Field measurements and jaboratory analysis of water samples were made from Mormon, North Mormon Lake and Kuchiak Creeks and from Mormon, North Mormon and South Lakes and Omalik Lagoon. All samples and field data were collected in late June, 1987, with laboratory analysis performed in early July, 1987. Zale METHODOLOGY APPROACH AND OBJECTIVES The field work for the WACDP baseline data hydrology survey was accomplished during June 23-30, 1987. The existing stream flows were gauged and the high’ water levels were determined along three streams by means of cross sections. Water quality field measurements and water samples for laboratory analysis were collected at eight locations. The water quality Measurements recorded in the field were temperature, pH and dissolved oxygen content in parts per million (ppm). The water samples collected in the field were shipped to Anchorage for laboratory analysis by Northern Testing Laboratories, Inc. The following field locations are indicated on Figure No. 2-1. Location No. 1: Lower Kuchiak Creek The existing stream flow was gauged on 6/25/87. Three cross sections were measured and referenced to the apparent high water mark. The stream gradient was measured to determine the past flood discharge rate. Water quality measurements were taken in the field and a water sample was collected for laboratory analysis. Stream cross-sections are shown in Figures 3-2, 3-3, and 3-4. Location No. 2: Upper Kuchiak Creek The existing stream flow was gauged on 6/26/87. Water quality Measurements were taken in the field and a water sample was collected for laboratory analysis. A stream cross-section is shown in Fig. 3-5. Location No. 3: North Mormon Lake Creek The existing stream flow was gauged on 6/25/87. Water quality measurements were taken in the field and a water sample was collected for laboratory analysis. Location No. 4: Omalik Lagoon Creek A cross section was measured and referenced to the apparent high water mark. The stream gradient was measured to determine past flood discharge rates. No stream flow was observed on 6/27/87. Location No. 5: Mormon Creek The existing stream flow was estimated on June 23, 26 and 29, 1987. A cross section was measured and referenced to the 2-1 Der apparent high water mark. The stream gradient was measured to determine the past flood discharge rate. Water quality Measurements were taken in the field and a water sample was collected for laboratory analysis. A stream cross-section is shown in Fig. 3-6. Location No. 6: Mormon Lake Water quality measurements were taken in the _ field on 6/24/87 and a water sample was collected for laboratory analysis. Location No. 7: Omalik Lagoon, and Location No. 8: Freshwater Lake Water quality measurements were taken in the’ field on 6/27/87 and a water sample was collected for laboratory analysis. Location No. 9: Mormon North Lake Water quality measurements were taken in the’ field on 6/28/87 and a water sample was collected for laboratory analysis. The results of the laboratory water quality analysis and the water quality measurements taken in the field are summarized in Appendix A. The stream flow rates for the observed high water Marks are calculated in Appendix B. The field Measurements of the stream cross sections, gradients and existing stream flow at the time of the survey are contained in Appendix C. DEFINITIONS Beaded Stream: A series of small pools connected by short water-courses. The pools result from the thawing of ground ice that commonly represents the interesections of ice wedges. Channel Flow: Movement of surface runoff in a _ long narrow troughlike depression bounded by banks or valley walls that slope toward the channel; Evapotyranspiration: Loss of water from a land area through transpiration of plants and evaporation from the soil. Also, the volume of water lost through evapotranspiration. Fluvial: Of or pertaining to a river or stream. Regimen: The flow characteristics of a stream; specif. the habits of an _ individual stream (including low flows and floods) Zo 2 Sheet Flow: Sub] imation: with respect to such quantities as velocity. The overland flow of water not concentrated into streams. The process by which a solid, such as ice and snow, vaporizes without passing through a liquid stage. Baseline Hydrology Data Collection Points Location Map i. & G END =@9 BASELINE HYDROLOGY DATA COLLECTION POINT June 23 - 30, 1987 WESTERN ARCTIC F< ope COAL DEVELOPMENT engines PROJECT BASELINE HYDROLOGY LOCATION MAP Prepared by Date: arctic slope | JAN.,1988 consulting Sick 332. HYDROLOGY FLUVIAL REGIMEN The streams in the study area are all located in permafrost terrain and have small drainage basins. The largest drainage basin is Kuchiak Creek with an area of 59 square miles. The smallest drainage basin is that of Mormon Lake to the west of the proposed mine site. This basin has an area of only 2 Square miles and includes the drainage area of Mormon Creek. The fluvial regimen of these streams is comparable to the larger arctic rivers of the Arctic Coastal Plain to the north and northeast, but of a much smaller scale. The streams in the study area have a_ period of flow lasting approximately four months from break-up in early to mid-May to freeze-up in mid- September. The stream flow starts at break-up with the spring flood which results from rapid melting of the winter snow pack. As with larger arctic rivers, the spring flooding event is a brief period which usually produces the highest stream flow rates of the season. Because the active layer of the soil is still frozen at this time, there is very little soil infiltration of the melt waters. The lakes in the = study area are still predominantly frozen during the spring flood. The water from the melting snow pack flows across and ponds on the lake ice with the excess water flowing down drainage. This results in JVittle or no flushing action of the lake water. The length and magnitude of the spring flooding is dependent on the amount of snow pack in the stream's drainage basin and the rate at which it melts. Typically, the spring flooding event is over within two weeks. After the spring flood, the source of the water in the streams is the thawing of residual snow drifts in the basin, summer rainfall and the contribution of soil moisture from the thawing of the seasonally active soil zone. As these streams are located in an area of continuous permafrost there is no contribution of groundwater to the stream flow. Unless there is adequate rainfall during the summer’ to maintain flow, all of the streams in the study area, including Kuchiak, will go dry. The only available water storage in the study area is contained in the lakes. DRAINAGE BASINS The four drainage basins that were studied in this survey are: Kuchiak Creek, North Mormon Lake Creek, Mormon Lake Drainage Basin and Omalik Lagoon Creek. These basins are shown in Figure 3-1. 3.2.1. Se1212- Kuchiak Creek Kuchiak Creek is the largest stream in the study area. It has its headwaters in the Amatusuk Hills to the southeast of the proposed mine site. It flows in a generally northward direction to the east of the mine site and then turns northwest into the Chukchi Sea. The length of the longest stream channel is 19.5 miles. The highest elevation in the drainage basin is approximately 1,600 ft. in the Amatusuk' Hills. The total area of the drainage basin is approximately 59 square miles. The Kuchiak Creek drainage basin is fed by surface run-off characterized by sheet flow, channel flow across the tundra and flow within structurally controlled channels in the upper reaches of the basin. The flow in the middle reach of the basin is channelized in predominantly beaded streams. The lower half of the basin is characterized by flow in well defined sand, gravel and boulder lined channels. The stream flow of Kuchiak Creek was measured at 20 cubic ft./sec. on June 25, 1987 at a _ location 3,700 ft. upstream from its mouth at the Chukchi Sea, see Fig. 2-1, Point #1. The calculated discharge for the high water marks observed at this location is 253 cubic ft./sec. assuming that this high water level was obtained without the influence of ice or snow dams in the channel. The bank-full discharge is calculated at 50 cubic ft./sec. This high water flow probably occurred during spring flooding. The stream of Kuchiak Creek was measured at 9 cubic ft./sec. on June 26, 1987 at a location 1.6 miles due east of Mormon VABM benchmark (see Fig. 2-1, Point #2). No reliable high water marks were observed with which to calculate a flood discharge rate. North Mormon Lake Creek North Mormon Lake Creek is a small beaded stream which flows from North Mormon Lake and the adjacent drained lake basins northwest for 2.6 miles to the Chukchi Sea. The total area of the drainage basin is 6 square miles. The existing flow of North Mormon Lake Creek was measured at 3 cubic ft./sec. on June 25, 1987 at its mouth at the Chukchi Sea. Most of this flow appeared to be the result of the melting of a 2,000 foot long snow drift located in the Channel adjacent to its mouth. No reliable high water Brae Sadese 3.2.4. marks were observed with which to calculate a flood discharge rate. Mormon Lake Drainage Basin Mormon Creek, which drains the area of the proposed mine site, is the best defined stream which flows into Mormon Lake. It has a drainage basin area of approximately 2 square miles. The stream has a gravel bed only where it has down-cut the sandstone beds along the north side of coal seam DFS-4, the western end of which is near Point 5 in Fig. 2-1. For the remainder of its course it is a wide, poorly defined Channel of bog grasses and low willows. The flow of Mormon Creek was estimated at 15 gallons per minute on June 23, and at 1 gallon’ per minute on June 26, 1987. All of the flow appeared to be the result of the melting of a large upstream snow drift. Mormon Creek appears to remain dry throughout the summer except after large storms, when flow is temporarily restored. The calculated flow at the apparent high water mark is 37 cubic ft./sec. The Mormon Lake watershed is the smallest drainage basin in the study area. The area of the Mormon Lake drainage basin including Mormon Creek is approximately 2.6 square miles. Mormon Lake is a small lake approximately 25 acres in size located at the northern end of an approximately 160 acre drained lake basin. When there is adequate precipitation, Mormon Jake drains to the south and west through a series of drained lake basins. Mormon Lake and its adjacent bog should adequately filter any suspended sediment that is not removed by the mine runoff settlement ponds. Omalik Lagoon Creek Omalik Lagoon Creek drains into the northeast end of Omalik Lagoon. It is the only channelized source of fresh water flowing into the lagoon. The drainage basin parallels the channel of Omalik Creek to the south and has a total area of 3.5 square miles. This drainage basin is characterized by poorly defined Channel flow across tundra in its upper reaches and sheet flow across a drained lake basin located 1,500 ft. east of Omalik Lagoon. Omalik Lagoon Creek is only truly channelized for the last 100 ft. of its course prior to its mouth at Omalik Lagoon. Here the stream bed is steep and grass-covered, with several deep plunge pools just as it enters the lagoon. 3 - 3 Kose 3.4. On June 27, 1987 there was no water flow in_ this stream. Although no reliable high water marks were observed, measurement of the cross section and gradient of the channelized stream section yielded a calculated maximum flow for a bank-full channel of 227 cubic ft./sec. Given the slope of this short channel segment, the existence of plunge pools, and a delta in Omalik Lagoon at the mouth of this stream it is likely that a high flow rate does periodically occur. However, it probably lasts for only a short period due to the limited size of the drainage basin and occurs only during the spring flood. The expected water quantity from the average annual spring flood is Calculated as 11,384,000 cubic feet (Table 3-1). This quantity of runoff would raise the level of Omalik Lagoon by approximately 0.6 feet. SURFACE WATER QUALITY The sampling of the surface waters of the study area in late June probably resulted in the best water quality test results that could be obtained for this area. In general, the water samples from both lakes and streams were slightly basic to neutral in pH and well-oxygenated. If water samples were to be taken in the late summer or early fall, the streams that were flowing in June would either be dry or flowing with the water from recent rains and probably have higher levels of total suspended solids. Water samples taken from the Jakes at this time might show a slight increase in acidity due to biological activity, with an accompanying increase in metal ion content. The water quality analysis results are presented in Appendix A. These results satisfy the minimum required testing parameters as listed in 11 AAC 90.049 for a surface coal mining permit application. PRECIPITATION AND RUNOFF The precipitation and runoff values for the study area were addressed in the Western Arctic Coal Development Project, Phase II, Technical Memorandum, Preliminary Mine Design, Arctic Slope Consulting Engineers & Pool Engineering, August 30, 1985. This report concluded that the average precipitation for the study area is 8 inches, with 3 inches of this total being derived from the average annual winter snowfall of 30 inches. The average daily potential evapotranspiration rate for the assumed 4 month thaw season equals 0.056 inches per day. The non- 3-4 snowfall precipitation estimated at 5 inches per year or 0.048 inches per day results in a net value less than the daily potential evapotranspiration rate. The sublimation value for the winter season is estimated at 1.25 inches. Predicted runoff water quantities are shown in Table 3.1 for annual spring flooding, Table 3-2 for the 10 year, 24 hour precipitation event, and Table 3-3 for the 25 year, 24 hour precipitation event. The runoff values were calculated from the Soil Conservation Service Method which yielded a 53% runoff value for the natural vegetation cover during the 10 year, 24 hour precipitation event and a 64% runoff value for the 25 year, 24 hour precipitation event. Using these values, the quantity of runoff expected from the average spring flood shown in Table 3-1 is equal to the runoff values calculated for the 25 year, 24 hour precipitation event shown in Table 3-3. TABLE 3-1 EXPECTED RUNOFF WATER QUANTITY FROM THE ANNUAL SPRING FLOOD DRAINAGE BASIN AREA IN SQ. MILES CUBIC FT. OF WATER ACRE FT. Kuchiak Ck. 59 191,896,000 4,400 N. Mormon L. Ck. 6 19,515,000 450 Mormon Ck. (1) 2 6,505,000 150 Mormon L. (2) 2.6 8,456,000 200 Omalik Lagoon Ck. 3.9 11,384,000 260 Assuming a 30 inch winter snowfall with a 3 inch water equivalent, a sublimation value of 1.25 inches per winter season and a 80% runoff value for the frozen soil yields a potential runoff quantity of 1.4 inches. The runoff quantities are equal to the expected 25 year, 24 hour precipitation event runoff values shown in Table 3-3. 1 The drainage area of Mormon Creek. 2 The drainage area of Mormon Lake, including Mormon Creek. TABLE 3-2 EXPECTED RUNOFF WATER QUANTITY FROM THE 10 YR., 24 HR. PRECIPITATION EVENT DRAINAGE BASIN AREA IN SQ. MILES CUBIC FT. OF WATER ACRE FT. Kuchiak Cr. 59 123, 362,000 2,800 N. Mormon L. Cr. 6 12,545,000 2,900 Mormon Cr. (1) 2 4,182,000 100 Mormon L. (2) 220) 5,436,000 120 Omalik Lagoon Cr. S20 7,318,000 170 Assuming a 1.7 inch precipitation event and a 53% runoff value which yields a potential runoff quantity of 0.9 inches. 1 The drainage area of Mormon Creek. 2 The drainage area of Mormon Lake, including Mormon Creek. TABLE 3-3 EXPECTED RUNOFF WATER QUANTITY FROM THE 25 YR., 24 HR. PRECIPITATION EVENT DRAINAGE BASIN AREA IN SQ. MILES CUBIC FT. OF WATER ACRE FT. Kuchiak Cr. 59 191,896,000 4,400 N. Mormon L. Cr. 6 19,515,000 450 Mormon Cr. (1) 2 6,505,000 150 Mormon L. (2) 2.6 8,456,000 200 Omalik Lagoon Cr. 329 11,384,000 260 Assuming a 2.2 inch precipitation event and a 64% runoff value which yields a potential runoff quantity of 1.4 inches. The runoff quantities are equal to the expected spring flood runoff values shown in Table 3-1. 1 The drainage area of Mormon Creek. 2 The drainage area of Mormon Lake, including Mormon Creek. 2 MILES ee "= 2 MILES BASEMAP FROM USGS POINT LAY QUADRANGLE (A-2, A-3,A-4) Q Drainage QD. Se BEE thr srgineer? ’ a ni DRAINAGE BASIN €\/O BASIN MAP Prepared by: ae vii ea consulting | engineers} Figure daa South Bank North Bank | | T | HIGH HIGH WATER MA, o a RELATIVE ELEVATION WATER LEVEL 6/25/87 RELATIVE ELEVATION o NOTES: 1) The distance to Cross-Section No. 2 is 150 ft. upstream from Cross-Section No. 1. 2) The assumed elevation of the creek water at this location is = 0.00 ft. 3) View is downstream. 4) The stream gradient at this location is 0.28 ft./mile (0.00005 ft./ft.) 5) Reference Point 1 On Fig. 3-1. Lower Kuchiak Creek Cross - Section cuctier Green CROSS-SECTION i Number 1 Horizontal Scale : |" = 20' Vertical Scale: |"= 5 Moras aan slope ae consulting South Bank North Bank HIGH HIGH WATER MAR LOW HIGH WATER MAR ee es WATER LEVEL 6/25/87 {TATU RELATIVE ELEVATION RELATIVE ELEVATION NOTES: ny} The distance to Cross-Section No. 3 is 225 ft. upstream from Cross-Section No.2. 2) The assumed elevation of the creek water at this location is = 0.00 ft. 3) View is downstream. 4) The stream gradient at this location is 0.28 ft./mile (0.00005 ft./ft.) arn WESTERN ARCTIC 5) Reference Point 1 On Fig. 3-1. ON er Lower Kuchiak Creek Cross - Section Pg CROSS-SECTION 2 Number 2 Horizontal Scale : |" = 20' Vertical Scale : |" = 5' Dee aan a consulting South Bank North Bank LOW HIGH WATER MAR eee a WATER LEVEL 6/25/87 RELATIVE ELEVATION z ° Ee < > w 4 w w > E < a w 4 NOTES: 1) The distance to Cross-Section No. 2 is 225 ft. 6) Reference Point 1 On Fig. 3-1. downstream from Cross-Section No. 3 2) The assumed elevation of the creek water at this location is = 0.00 ft. 3) No apparent High High Water mark was observed. 4) View is downstream. 5) The stream gradient at this location is WESTERN ARCTIC ; /mile (0.00005 ft./ft.) #1 siope COAL_ DEVELOPMENT 0.28 ft./mile (0.0 nie P ECT Lower Kuchiak Creek Cross - Section KUCHIAK CREEK CROSS-SECTION 3 Number 8 Horizontal Scale : |" = 20' Vertical Scale : |= 5) ce Nae dione consulting EAST BANK WEST BANK WATER LEVEL (6/26/87) RELATIVE ELEVATION RELATIVE ELEVATION \ oO a NOTES: 1) The assumed elevation of the creek water at this location is = 0.00 ft. 2) View is upstream. 3) The stream gradient at this location is 36.96 ft./mile (0.007ft./ft.) 4) Reference Point 2 On Fig. 3-1. Uoper Kuchiak eee arctic slope sonsulting PROJECT UPPER KUCHIAK Creek ae CROSS-SECTION Cross = Section ee 7 ‘arctic slope JAN.,1988 " oe Figure 3— Horizontal Scale: Vertical Scale: | engineers — East Bank HIGH HIGH WATER MARK RELATIVE ELEVATION RELATIVE ELEVATION ee NOTES: 1) View is downstream. 2) The stream gradient at this location is 211.9 ft./mile ( 0.04 ft./ft.) 3) Reference Point 5 on Figure 3-1. Mormon Greek Cross - Section Horizontal Scale: | =5 Vertical Scale: | WESTERN ARCTIC COAL_ DEVELOPMENT PROJECT arctic slope consulting engineers MORMON CREEK CROSS-SECTION Prepared by Date JAN.,1988 Figure 3-6 arctic slope consulting engineers 4.1. 4.2. CONCLUSIONS AND RECOMMENDATIONS CONCLUSIONS The conclusions about the fluvial regime of the study area, the level and occurrence of the peak and low stream flow rates and the seasonal variations of the surface water quality as stated in this report are consistent with the hydrology of the arctic environment. Based on the information gathered during this initial baseline hydrology survey, the proposed coal mining operation will probably have an_ insignificant impact on the water quality within the study area. RECOMMENDATIONS The surface coal mining permit application review by the federal, state and local regulatory agencies for the proposed mining operation, may require additional baseline field surveys in the study area to record the actual stream flow and water quality variations through-out’ the ice-free season. This would require additional field trips and water quality sampling and analysis. APPENDIX A WATER QUALITY TEST RESULTS SUMMARY MORMON CREEK MORMON LAKE FIG. 2-1 LOC. 6 ADEC LIMITS /DRINKING WATER. 18 AAC18.80.05 PARAMETER UNIT FIG. 2-1 LOC. 5 A070287-12 SAMPLE NO. SAMPLE DATE: 6/23/87 FIELD TESTS Water Temp. F 47 pH ---- 6.1 Dissolved Oxygen ppm O52 LAB TESTS Alkalinity as CaCo3 mg/1 25 Chloride mg/] 2.0 Sulfate mg/1 <1.0 Nitrate-N mg/1 <0.10 Ammonia-N mg/1 2 Total Phosphate-P mg/1 <0.1 Total Dissolved mg/1 44 Solids Total Suspended mg/1 32 Solids Turbidity NTU sell Antimony mg/1_ <0.003 Arsenic mg/1 <0.001 Barium mg/) <0.1 Cadmium mg/1 <0.005 Calcium mg/1 5.54 Chromium mg/1 <0.010 Copper mg/1 <0.02 Iron mg/1 era Lead mg/1 0.002 Magnesium mg/1 30) Manganese mg/1 0.06 Mercury mg/1 <0.0002 Nickel mg/1 <0.04 Potassium mg/1 0.61 Selenium mg/] <0.002 Sodium mg/1 1.4 Zinc mg/1 0.047 A070287-13 SAMPLE DATE: 6/24/87 Ono sie oOo a liehi« ornw rPOoOnNw <1 <0.1 10 30 23 <0.003 <0.001 0.2 <0.005 35.35 <0.010 <0.02 Tal 0.003 1.4 0.03 <0.0002 <0.04 0.67 <0.002 154 0.045 NORTH MORMON ADEC LIMITS PARAMETER SAMPLE NO. FIELD TESTS Water Temp. pH Dissolved Oxygen LAB TESTS Alkalinity as CaCo3 Chloride Sulfate Nitrate-N Ammonia-N Total Phosphate-P Total Dissolved Solids Total Suspended Solids Turbidity Antimony Arsenic Barium Cadmium Calcium Chromium Copper Iron Lead Magnes ium Manganese Mercury Nickel Potassium Selenium Sodium LAKE CREEK /DRINKING UNIT NORTH MORMON LAKE LOCs WATER. 18AAC FIG. 2-1 LOC. 9 FIG. 2-1 18.80.05 A070287-18 A070287-14 SAMPLE DATE: SAMPLE DATE: 6/28/87 6/25/87 fF 54 52 ---- del 6.9 ppm 9-6 8.7 mg/1 27 36 ----- mg/1 3.3 671 ween mg/]_ <1l.0 90 250 mg/1_ <0.10 <0.10 10 mg/1 1 SUCRE tasers mg/1 <0.1 ea mg/1 34 1400 500 mg/1 34 SA eae NTU 16 27 il mg/1_ <0.003 0.008 ----- mg/1 <0.001 0.015 0.05 mg/] = <0.1 <0.1 a mg/1_ <0.005 0.013 0.01 mg/1 7.97 20.6 = ----- mg/1 <0.010 <0.010 0.05 mg/1 0.05 0.04 1 mg/1 1.9 425 0.3 mg/1 <0.001 0.003 0.05 mg/1 ss ----- SS seen on mg/1 0.03 0.14 0.05 mg/1 <0.0002 <0.0002 0.002 mg/1_ <0.04 <0.04 = ----- mg/1 es 23.8 jj ---=- mg/1 <0.002 0.009 0.01 mg/1 2.85 207 250 mg/1 0.198 0.037 5 Zinc UPPER KUCHIAK CREEK LOC. 2 FIG. 2-1 LOWER KUCHIAK CREEK Loc. 1 FIG. 2-1 ADEC LIMITS /DRINKING WATER. 18 AAC18.80.05 A070287-16 SAMPLE DATE: 6-26-87 A070287-15 SAMPLE DATE: 6/25/87 FIELD TESTS Water Temp. pH Dissolved Oxygen LAB TESTS Alkalinity as CaCo3 Chloride Sulfate Nitrate-N Ammonia-N Total Phosphate-P Total Dissolved Solids Total Suspended Solids Turbidity Antimony Arsenic Barium Cadmium Calcium Chromium Copper Iron Lead Magnes ium Manganese Mercury Nickel Potassium Selenium Sodium Zinc mg/1 mg/1 mg/1 mg/1 mg/1 mg/1 mg/1 mg/1 NTU mg/1 mg/1 mg/1 mg/1 mg/] mg/1 mg/1 mg/1 mg/1 mg/1 mg/1 mg/1 mg/1 mg/1 mg/1 mg/1 mg/1 38 <1.0 <0.10 <0.1 40 22 1.7 <0.003 <0.001 <0.1 <0.006 12 <0.010 0.02 0.39 <0.001 4.2 0.01 <0.0002 <0.06 0.88 <0.002 Le 0.070 30 <1.0 <0.1 <0.1 42 34 4.9 <0.003 <0.001 <0.1 0.009 ll 0.010 0.04 0.62 <0.001 4.9 0.03 <0.0002 <0.04 de <0.002 4.56 05335 OMALIK LAGOON Gi) /(2=1) (LOC 7 FRESHWATER LAKE FIG. 2-1 LOC. 8 ADEC LIMITS /ORINKING WATER. 18AAC 18.80.05 A070287-17 SAMPLE DATE: 6/27/87 A070287-11 SAMPLE DATE: 6/27/87 FIELD TESTS Water Temp. pH Dissolved Oxygen LAB TESTS Alkalinity as CaCo3 Chloride Sulfate Nitrate-N Ammonia-N Total Phosphate-P Total Dissolved Solids Total Suspended Solids Turbidity Antimony Arsenic Barium Cadmium Calcium Chromium Copper Iron Lead Magnesium Manganese Mercury Nickel Potassium Selenium Sodium Zinc mg/1 mg/1 mg/1 mg/1 mg/1 mg/1 mg/1 mg/1 39 682 <0.10 <0.1 1440 38 15 0.009 0.015 0.6 <0.005 24.5 <0.010 <0.02 156 <0.007 52 0.07 <0.0002 <0.04 23.8 0.016 180 0.162 APPENDIX B STREAM FLOW CALCULATIONS The discharge rate for a stream at the observed high water mark was calculated from the field cross sections of the stream channel and the local stream gradient using the Manning Equation: V=1.49 R2/3 S1/2 where: V= velocity of the flow in n ft./sec. R= the hydraulic radius (the cross-section area divided by the wetted perimeter (WP) S= slope of the water surface n= the stream bed roughness factor and: Q=AV where: Q= flow rate in cubic ft./sec. A= the cross-section area in square ft. V= velocity in ft./sec. Numbers shown are for calculation consistency and are not a measure of the Measurement accuracy. LOCATION: Lower Kuchiak Creek F 2-1 Map Location No. 1 Calculated discharge at high water mark on tundra at cross section no. 1 excluding the channel area of existing stream flow on 6/25/87: V= 0.498 ft./sec. where: R= 3.10 Q= 233 cubic ft./sec. A= 465 square ft. = 0.00005 ft./ft. n= 0.04 WP= 150 ft. Calculated discharge for channel area of existing stream flow at cross section No. 1 on 6/25/87: V= 0.289 ft./sec. where: R= 1.15 Q= 20.2 cubic ft./sec. A= 70 square ft. S= 0.00005 ft./ft. n= 0.04 WP= 61 ft. The gauged existing stream flow at cross section No. 1 on 6/25/87 was 19.6 cubic ft./sec. Therefore, the calculated discharge of a snow and ice free channel to the observed high water mark is 253 cubic ft./sec. APPENDIX B LOCATION: Upper Kuchiak Creek Map Location No. 2 Inadequate field evidence to determine accurate high water level. The gauged existing stream flow at this location on 6/26/87 was 8.6 cubic ft./sec. LOCATION: North Mormon Lake Creek Map Location No. 3 Inadequate field evidence to determine accurate high water level. The gauged existing stream flow at this location on 6/25/87 was 3.2 cubic ft./sec. LOCATION: Omalik Lagoon Creek Map Location No. 4 Inadequate field evidence to determine accurate high water level. Calculated discharge for a bank full channel at cross-section. South channel: V= 6.4 ft./sec. where: R= 0.91 Q= 203 cubic ft./sec. = 31.8 square ft. = 0.042 n= 0.045 WP= 34.9 ft. North channel: V= 3.8 ft./sec. where: R= 0.42 Q= 24 cubic ft./sec. A= 6.3 square ft. S= 0.042 n= 0.045 WP= 14.9 ft. Combined bank full discharge= 227 cubic ft./sec. APPENDIX B LOCATION: Mormon Creek Map Location No. 5 Calculated discharge at high water mark at cross-section. V= 6.0 ft./sec. where: R= Q= 37.1 cubic ft./sec. = oooro square ft. u" ADoonr OBWP ft. LOCATION: DATE: NOTES: APPENDIX C Stream Flow Cross Sections and Stream Flow Gauging Field Notes Lower Kuchiak Creek cross section no. 1; south side. Map Location No. 1 6/25/87 Cross section from the south bank of the creek. There was no apparent high water mark on the south side of the creek at the location of this cross section. The reference elevation of the creek water at this location is = 0.00 ft. A reference point for this cross section and cross sections no. 2 & 3 of Lower Kuchiak Ck. is a spike located 112 ft. to the south of the creek in line with cross section no.1. The elevation of the spike above the water of the creek at cross section no. 1 is 10.30 ft. The distance to cross section no. 2 is 150 ft. upstream from cross section no. 1. LOCATION: Lower Kuchiak Creek cross section no. 1; north side. Map Location No. 1 DATE: 6/25/87 NOTES: Cross section from the north bank of the creek to the apparent highwater mark on the north side of the creek. The reference elevation of the creek water at this location is = 0.00 ft. B.S Hele eS: EL DIST. NOTES TE580) | 11680) | 21-10) || 0.70 1.00 11.80 9.40 2.40 10.00 11.80 9.60 2.20 20.00 11.80 7.80 4.00 30.00 11°80!) (7.200 4.80 40.00 apparent high water mark 11.80 4.30 7.50 50.00 11.80 2.60 9.20 70.00 LOCATION: DATE: NOTES: Lower Kuchiak Creek cross section no. 2; south side. Map Location No. 1 6/25/87 Cross section from the south bank of the creek. There was no apparent high water mark on the south side of the creek at the location of this cross section. The reference elevation of the creek water at this location is = 0.00 ft. The distance to cross section no. 3 is 225 ft. upstream from cross section no. 2 cross section No. 2 reference hub at dist. 104 ft. no elevation taken LOCATION: Lower Kuchiak Creek cross section no.2; north side Map Location No. 1 DATE: 6/25/87 NOTES: Cross section from the north bank of the creek to the apparent high water mark on the north side of the creek. The reference elevation of the creek water at this location is = 0.00 ft. Bess HSE F.S. EL DIST. NOTES 10.00 10.00 ----- 0.00 0.00 10.00 8.70 130 0.50 10.00 7.00 3.00 11.00 low high water mark 10.00 5.20 4.80 22.00 high high water mark 10.00 1.90 8-10) | | 3500 LOCATION: Lower Kuchiak Creek cross section no. 3; south side Map Location No. 1 DATE: 6/25/87 NOTES: Cross section from the south bank of the creek. There was no apparent high water mark on the south side of the creek at the location of this cross section. The reference elevation of the creek water at this location is = 0.00 ft. The distance to cross section no. 2 is 225 ft. downstream from cross section no. 3 10.00 1.50 8.50 67.00 reference hub for cross section No. 3 LOCATION: Lower Kuchiak Creek cross section no. 3; north side. Map Location No. 1 DATE: 6/25/87 NOTES: Cross section from the north bank of the creek to the apparent high water mark on the north side of the creek. The reference elevation of the creek water at this location is = 0.00 ft. 10.00 6.60 3.40 13.00 low high water mark no high high water mark observed LOCATION: Lower Kuchiak Creek cross sections. stream gradient. Map Location No. 1 DATE: 6/25/87 NOTES: Cross section of the stream gradient from cross section no. 3 (upstream) to cross section no. 1 (downstream). The reference elevation of the water at cross section no. 3 = 0.00 ft. 12265 12.65—_12.65:- 0.00 0.00 cross section no. 3 water elevation 12.65 12.66 -0.01 225.00 cross section no. 2 water elevation — 12.65 12.67 -0.02 375-00 cross section no. 1 water elevation Gradient is 0.42 ft. mile (0.00005 ft./ft.) LOCATION: Upper Kuchiak Creek cross section No. 1 Map Location No. 2 DATE: 6/26/87 ’ NOTES: Cross section from the west side of the creek to the east side of the creek. Cross section includes the channel bottom. The reference elevation of the creek water at this location is 0.00 ft. Base H.I Faas ELS DIST. NOTES 8.55 8.55 ----- ---- ---- 8.55 2240 =) 6515 0.00 reference hub on west side of ck. 8.55 S40 5615 6.00 8255 6.10 2.45 32.00 8.55 8°10) 05451-3800 edge of channel (dry) 8255 82555-0500 = 53.00 edge of water 8555 9.10 -0.55 66.50 edge of channel (bottom) 8.55 1230-1525) .08.00! top of stream bank 8555: 6. 20ee2 351. 72.00) 8.55 5-00 3-3'.55'=— 82.700 B55 8104-5 45)=-100-00 LOCATION: Upper Kuchiak Creek cross section. Stream gradient Map Location No. 2 DATE: 6/26/87 NOTES: The reference elevation of the creek water at the cross section location = 0.00 ft. Bis05 8355 9.20 -0.65 100.00 downstream from cross section 8.55 6355 0.00 0.00 at cross section B55 7.80 0.75 100.00 upstream from cross section Gradient is 36.96 ft./mile (0.007 ft./ft.) LOCATION: Lower Kuchiak Creek at cross section No. 1 Map Location No. 1 DATE: 6/25/87 NOTES: Distance is measured from the south bank of the creek DISTANCE (ft.)° WATER DEPTH (ft.) VELOCITY (cm./sec.) 0.0 0.0 0 10.0 0.5 0 15.0 0.6 0 20.0 0.5 5 25.0 0.7 5 30.0 1.0 10 35.0 116 13 40.0 1.8 14 45.0 2.0 10 50.0 1.9 12 55.0 138 4 60.0 1.6 4 61.0 --- -- edge of north ck. bank Cross section area = 70 square ft. Area Weighted Average velocity = 7.01 cm./sec. (0.23 ft./sec.) Discharge (Q)=19.6 cubic ft./sec. c - 10 LOCATION: Lower Kuchiak Creek at cross section No. 2 Map Location No. 1 DATE: 6/25/87 NOTES: Distance is measured from the south bank of the creek DISTANCE (ft.) WATER DEPTH (ft.) VELOCITY (cm./sec.) 0.0 0.0 0 - 3.0 0.5 3 5.0 057 5 10.0 0.8 6 1550) 0.9 9 20.0 1.0 10 25-0 12 5 30.0 1.3 9 35.0 12 6 40.0 Lo: 7 45.0 1.0 6 50.0 0.9 5 55.0 0.8 3 60.0 O23 0 edge of stream bank Cross section area = 58.5 square ft. Area Weighted Average velocity = 5.8 cm./sec. (0.19 ft./sec.) Discharge (Q)=12.0 cubic ft./sec. € = 8 LOCATION: | Lower Kuchiak Creek at cross section No. 3 Map Location No. 1 DATE: 6/25/87 NOTES: Distance is measured from the south bank of the creek DISTANCE (ft.) WATER DEPTH (ft.) > VELOCITY (cm./sec.) 0.0 0.0 0 1.0 -6 4 5.0 0.8 4 10.0 0.9 3 15.0 0.9 5 20.0 0.8 6 25.0 Lez 2 30.0 GS) 0 35.0 1.6 3 40.0 1.8 13 45.0 1.8 18 50.0 136 16 52-0 To 5 edge of ck. bank Cross section area = 72.5 square ft. Area Weighted Average velocity = 6.7 cm./sec. (0.22 ft./sec.) Discharge (Q)=17.3 cubic ft./sec. C - l2 LOCATION: Upper Kuchiak Creek at cross section No. 1 Map Location No. 2 DATE: 6/26/87 NOTES: Distance is measured from the west edge creek water 0 east bank of ck. Cross section area = 6.9 square ft. Area Weighted Average velocity = 30.5 cm./sec. (1.0 ft./sec.) Discharge (Q)=8.6 cubic ft./sec. Ce o13 LOCATION: Mormon Creek cross section No. l Map Location No. 5 DATE: 6/26/87 NOTES: At nick point at DFS-4 from west to the east side of the stream. Estimated flow on 6/23/87 is 15 gallons per minute Estimated flow on 6/26/87 is 1 gallon per minute 4.55 4.55 ---- ---- 0.00 4.55 8.80 -4.25 8.00 bed of creek 4.55 8.75 -4.20 11.00 bed of creek 4.55 7.70 -3.15 12.00 apparent high water mark c - 14 LOCATION: Mormon Creek cross section. Stream gradient Map Location No. 5 DATE: 6/26/87 NOTES: Elevation of small pools of water in the creek bed, the upstream pool elevation = 0.00 ft. isle, Take, ---- 0.00 0.00 upstream pool Tst2 10.13 -330% 75.00 downstream pool Stream gradient is 211.9 ft./mile (0.04 ft./ft.) G = 15 LOCATION: Mormon North Lake Creek at its mouth at the Chukchi Sea. Map Location No. 3 DATE: 6/25/87 NOTES: Surface velocity of the water was measured for a 10 ft. reach of uniform channel. Channel width = 10.0 ft. Channel depth = 0.15 ft. (uniform) Surface water velocity = 65 cm./sec. (2.13 ft./sec.) Flow rate is 3.2 cubic ft./sec. C - 16 ~ mr APPENDIX D WATER BALANCE OF FRESHWATER LAKE Freshwater Lake, Location No. 8 shown on Figure No. 2-1, is a possible source of fresh water for the camp facilities of the proposed coal mine. It is estimated as outlined below that approximately 500,000 gallons of water will be withdrawn from the lake on an annual basis to meet the needs of the camp. A conservative estimate gives the annual net water input of Freshwater Lake at approximately 1,833,000 gallons as outlined below. The withdrawal of 500,000 gallons of water per year from Freshwater Lake represents 27% of the lakes net water budget. This amount of water withdrawal will not have an adverse impact on the lake. The net annual water input of Freshwater Lake was calculated using the following factors: Lake surface area of 499,000 square feet (11.5 acres); Lake input drainage area of 2,091,000 square feet (48 acres), not including the lake surface area; Annual precipitation of 8 inches (5 inches from rain, 3 inches water equivalent from the winter snowpack) ; Winter snow sublimation value of 1.25 inches water equivalent; An average daily evapotranspiration value of 0.056 inches during a 120 day thaw season; and An infiltration and runoff surface retention value of the tundra at spring break-up of 20%, equaling a runoff factor of 80%. The annual net water input to the lake surface (based on its surface area only) is 8 inches minus 6.7 inches lost to evaporation during the thaw season and an additional 1.25 inches lost from winter sublimation of the smowpack. This equals a net annual input of approximately 16,000 gallons for only the surface area of the lake. The water input to the lake from the melting of the winter snowpack within the 48 acre drainage area (excluding the lake surface area) will contribute approximately 1,817,000 gallons of water. This does not include the input from summer rain within this drainage area. The minimum estimated net water input to Freshwater Lake is approximately 1,833,000 gallons a year. 30|000 E SZIJOOO E 32/000 E 33/000 E 34}000 E 35/000 E 36/000 E 37/000 E 381000 E 52,000 N 31,000 N —— 50,000 N APPROXIMATE SCALE: | inch = 300 feet ELEVATION DATUM: Mean Sea Level COORDINATE DATUM: Alaska State Plane Zone 7 add 5,500,000 to N coordinates 500,000 to E coordinates 49,000 N WESTERN ARCTIC COAL DEVELOPMENT PROJECT SURFACE TOPOGRAPHY MORMON WEST BLOCK Prepared by: Date 2 Denton Civil & Mineral 2-|-88 APPENDIX E