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Northwest Alaska Coal Project, Power Plant Evaluation, September 1991
NORTHWEST ALASKA COAL PROJECT SS. STRANDBERG Consulting Engineers, Inc. POWER PLANT °™ RECEIVED, EVALUATION FNAL) || REPORT £9 September, 1991 Prepared For: Prepared By: Arctic Slope Consulting Group, Inc. SFT, Inc. P.O. Box 650 6629 West Central Avenue Barrow, Alaska 99723 Toledo, Ohio 43617 ARCTIC SLOPE CONSULTING GROUP, INC. Engineers ¢ Architects ¢ Scientists * Surveyors TECHNICAL MEMORANDUM ON POWER PLANT EVALUATION FOR NORTHWEST ALASKA COAL PROJECT ENGINEERING FEASIBILITY STUDY SFT) SFT, Inc. 6629 West Central Avenue Toledo, Ohio 43617 (419) 843-8200 TABLE OF CONTENTS EXECUELV.E |SUMMATY/-1)o]oleie)elerllelenelelo}ohehelerele ells) steteloleteliclierol slelel efelelelelele TOM ENEHOAUCEON oo eloleielolels)lelelelel=lel/siieloo1 > enele! 5) ofeles) s]iaiielione te elevelisietelore 2.0 Technology Assessment.......eeeeeeccceoece sisleiel sores Helos ENETOAUCELONG els lelelelsleleleleleleie hele! s) vlelofelele ells) feleielerelohetens Plant Configuration.........-.sesces NEIDIO OOOO US aiete Environmental Issues... cece ceccccccscceseccce 2.1 Zire 4} 2.4 Available Boiler Technology..........sseeeee- shelere 2.5 Plant Size and Technology Selection.........-...- 2-6 CondenserS..cccccccccccscese elec © ercle erolallelelioneveje}ereliere Ze CONCIUS1 ONt\-poreielelsle/ eo eslelelele rere eltelolferel stiaiieley = sPelletelievehelo}eietete 3/0) | Equipment |Si:Z3Ng< «<1 </s\<\s/<1s\es/e/+/eleiele elelelels)e\e/< Motelcleleyele cloierere TENELOAUCT LON cieyole/ clo) otelolele/elolsicioleleleleloierelelelerelersisiorels|clevele NOME. coe ccrccccccccvccvvcccccccccceccece reese sces Kotzebue.......ceeee ellololois|e/eielolelchol ol siciietele lol sis) elierereie)lelelele REG) DOGI MINS ctoveis/e|0/e ole) ole) <)> iolelelieirevol niefeleicrel< cVellcoleleheilerelte Deadfall Syncline Coal Mine........cccccccccccece Conclusion rcislerelolcielolelieielspeieioletehereverele Morolololsiarerelolelcrele WWWWWw . . . . . . NU FWNH 4.0 Plant Description and Cost Estimate...... aralolelelevere elated PNCLOAUCEIION siejololeleleleloicicleseloiclelelelelelsielolelelelelehe/cielste)sielslie Descxri pci onyOLNCONcraccsss jellies clelcleleleleroleveisielelolelelere Plant |Stakfing.|.\.)< < cielsisicic « clslele es sleieic|s sicle/clele slelelei Arrangement DrawingS...ccccccccccccccccccscscccces Water Supply... cccccccccccccccccccccccccccsccces Sewer) Facility) (7) ).)c..cclsicleie «lo eleielele e}sicle coleleiicle.e ell oleie SCheduleciciccc > cleleloleielsicleleiele © /clcleiele/olsisie/e cle elsrels/elelelelole PPE ESP oe © © we ww NAW PWNHrH SOM CONCLUSIONS sloleleleretereiclsielelorelelelevolalelslelsisisiolsleisisiere slelehelielelelsietstie NNNNN ' WO PNR H vY BK TECHNICAL MEMORANDUM ON POWER PLANT EVALUATION FOR NORTHWEST ALASKA COAL PROJECT ENGINEERING FEASIBILITY STUDY EXECUTIVE SUMMARY A review has been made of the potential of utilizing Alaskan coal for generation of electrical power and district heating in northwest Alaska. The study has reviewed this potential at the City of Nome, the City of Kotzebue, the Red Dog Mine site and the Deadfall Syncline Mine site with transmission to Red Dog. A technology assessment has been performed which assumed use of a conventional Rankine cycle for power production. Results of this assessment indicate that the selection of spreader stoker steam generating equipment coupled with a conventional steam turbine-generator is the best choice. Should sulfur dioxide scrubbing be required at Nome and Kotzebue, consideration should be given to fluidized bed combustion technologies. Dry scrubbers have been selected at the mine sites. Selection of an air cooled condenser in lieu of a conventional condenser - cooling tower arrangement is based upon minimal water availability without significant performance degradation. A review of the present systems at Nome, Kotzebue, and Red Dog was performed. From that information, forecasts of load requirements through the year 2004 were made. Included in these forecasts was the first phase of district heating. In Nome, the first phase would displace 126,000 gallons of fuel oil a year and in Kotzebue, 214,000 gallons. Red Dog presently heats from waste heat produced by the diesel generators. On the basis of this review, the following sizing criteria was developed: 2 @ Nome: 10.5 MW electrical plus 5 million BTU/Hr district heating requiring 2 - 65,000 Lbs/Hr boilers, 28,100 tons per year of coal. e Kotzebue: 5.7 MW electrical plus 5.3 million BTU/Hr district heating requiring 2 - 40,000 Lbs/Hr boilers, 18,100 tons per year of coal. @ Red Dog Mine: 16.5 MW electrical plus 40 million BTU/Hr district heating requiring 2 - 120,000 Lb/Hr boilers, 87,000 tons per year of coal. @ Deadfall Syncline Mine: 22 MW electrical requiring 2 - 120,000 Lb/Hr boilers, 87,000 tons’ per year of coal. Estimates were prepared for each of the plant sites. Pricing was solicited from various vendors for major equipment. The remainder of the estimates were prepared by SFT, Inc. Following are the estimated prices for the plants including district heating at Nome, Kotzebue, and Red Dog, sulfur dioxide scrubbing at Red Dog and Deadfall Syncline, and a 90 mile transmission line in the Deadfall Syncline estimate: @ City of Kotzebue: $32,520,000 e® City of Nome: $39,120,000 @ Red Dog Mine: $61,490,000 @ Deadfall Syncline Mine: $70,130,000 It is estimated that the period of construction would be 24 months for Nome and Kotzebue, and 30 months for the Red Dog and Deadfall Syncline mine sites. aleiets Manpower requirements were reviewed. It is expected that these plants will require staffing of 22 persons total, for all shifts. iv 1.0 INTRODUCTION SFT, Inc. of Toledo, Ohio was retained by the Arctic Slope Consulting Group to develop information regarding the potential of burning Alaskan coal for power generation at various communities in northwest Alaska. This report presents the results of the study. The objective of the study is to develop sufficient information such that the Arctic Slope Consulting Group can make prudent decisions regarding the economic viability of use of coal as a fuel for power generation in northwest Alaska. The procedures used in performing the study follow: ake Review status of existing generation, transmission and distribution systems at Nome, Kotzebue, and Red Dog Mine. 2. Review environmental issues. 32 Review applicable power generation technology. 4. Forecast future system electrical demand. Sic Size first phase of district heating. 6. Determine optimum equipment sizing for Nome, Kotzebue, Red Dog Mine, and Deadfall Syncline Mine es Estimate construction costs for each of the four (4) potential power plant sites. 8. Prepare the report. The report is arranged as follows: 1. The report proper which presents the essential results of the study in the following sections: @ Section 2 describes the technology assessment. @ Section 3 determines proper equipment sizing. e Section 4 describes the plant descriptions and subsequent cost estimates. ® Final conclusions are presented in Section 5. 2. The Appendix which contains supporting documentation. — 2.0 TECHNOLOGY ASSESSMENT 2.1 Introduction SFT has reviewed the coal and ash analyses performed on the Deadfall Syncline coal by Commercial Testing and Engineering and by Idemutsi Kosan. Both these analyses indicate a reasonably good quality very low sulfur coal with a low ash content. The fuel appears to be similar to coals found in Utah and is classified as a high volatile bituminous coal. The ash analysis indicates a lignite-type ash classification, generally indicating a "younger" coal. Battelle, in a report dated March 16, 1989, reviewed the coal analyses and ran combustion tests in their facility. It was found that the coal burns well in both fluid bed combustors and in suspension. Mass burn, or stoker tests were not run. There were no problems with clinkering or slagging. Battelle ultimately recommended fluid bed combustion as the preferred technology and indicated that the coal is suitable for use in a suspension-fired furnace. Battelle, however, did not rule out burning this fuel on a stoker but did indicate that use of a stoker may result in clinker formation due to the low ash fusion temperature. SFT elected to review all technologies, particularly considering the fact that the combustion tests showed no evidence of clinkering or slagging. 2.2 Plant Configuration The requirements of this study are to review the available technologies assuming a conventional Rankine cycle, whereby steam is generated in a boiler by the combustion process, the steam then passing through a _ turbine-generator where electricity is generated and the steam then being condensed to water in a condenser unit and returned to the boiler to begin the process again. Steam turbine-generator technology does not vary in the size ranges being studied. There are several alternatives regarding boiler technology and condensers that need to be reviewed in order to make a proper selection. 2.3 Environmental Issues Today, technology selection for a project of this type is usually not only based on what is best based upon fuel, but is also based on what product can meet the environmental regulations in effect. Amendments to the Clean Air Act were promulgated into law in late October 1990. The amendments define the area for which the laws are applicable as the "States". States are defined as "State means one of the 48 contiguous states and the District of Columbia." It has, therefore, been determined that these amendments which include “acid rain" legislation do not apply to the State of Alaska. Discussions with the Alaskan Department of Environmental Conservation (DEC) indicate that the areas under consideration have achieved the National Ambient Air Quality Standards and that the areas are classified as Class II. Class II areas do not require any special consideration. It will be necessary to obtain a Permit to Install from DEC which generally takes 4 - 6 weeks. Should the facility generate relatively large amounts of regulated pollutants, a Prevention of Significant Deterioration (PSD) review would be required and Federal EPA review of the permit application would occur. A PSD permit will take more than a year to obtain according to DEC. Whenever a PSD review occurs, the facility plans must demonstrate meeting Best Available Control Technology (BACT). BACT requires a review of all similar installations and a determination of what is being done in those installations to reduce pollutants. PSD is triggered when emissions of any regulated pollutant exceed 250 tons per year for "grass roots" sites or the following increment above present levels (based upon actual emissions over the prior two (2) years) for modified existing sites: Increment Pollutant Tons/Yr Particulate 15 Nox 40 co 100 voc 40 so, 40 It is our opinion that we can conclude that these power plants being considered are not a modification to an existing plant but are indeed grass roots. Of course, in order to do so, it will be necessary to locate the new coal plants physically away from any existing plants. Based upon our review of potential sites, this is certainly feasible and probable. In order to avoid PSD review, it will be necessary to limit the operation of the equipment such that the 250 ton per year limit is not exceeded. This should not be a significant problem for the Nome and Kotzebue sites because the demand for electricity and district heating is seasonal during the day, or, in other words, the equipment does not have to operate at full capacity 24 hours per day, 365 days per year. The situation at the Red Dog Mine is potentially a bit different. While the heating load is seasonal, the electrical load is not, typical for any heavy industry. The installation at Red Dog (or at the coal mine with transmission to Red Dog) may require PSD review. A PSD review, as previously stated, will require that the site install Best Available Control Technology. In the case of the smaller units that would be located in Nome and Kotzebue, should they be subject to PSD review, this would require meeting an SO, emission standard of 1.2 Lbs/million BTU which can be met because of the sulfur content of the coal under consideration. Should SO, reduction be required under any new law, this can be accomplished by either use of an SO, scrubber or fluid bed technology. For the larger equipment to be located at Red Dog or the coal mine, 90% reduction of SO, would be required. A review of recent permits issued indicates that essentially all units installed in the capacity range being reviewed for Nome and Kotzebue are using low sulfur coal as BACT for emissions. 2.4 Available Boiler Technology The generally accepted means for combusting coal for power generation today considering the conventional Rankine cycle are fluid bed (both bubbling and circulating), pulverized firing and stoker firing. Each offers advantages and disadvantages. The fluid bed boiler industry in the U.S. has been an outgrowth of use of the technology in Europe. The technology was developed to be able to utilize the poor quality coals readily available in Europe. The U.S. industry accepted the technology generally out of frustration with poor operating characteristics of wet scrubbers and limited success with dry scrubbers; both for sulfur dioxide removal. It should be noted that minimal work was done in Europe on sulfur dioxide reduction in fluid bed units. Acceptance in the U.S. has been slow, with about 150 units sold in the past 7 - 10 years and approximately 50 in operation, the majority of the smaller units without SO, reduction. Present U.S. experience on fluid bed boilers has been poor to fair; with significant problems in the areas of fuel handling, erosion and other areas. It is expected that the next generation of fluid bed units will perform better. The advantages of using fluid bed boilers are as follows. The fluid bed has the capability of calcining limestone, whereupon the calcium oxide reacts with the sulfur dioxide being formed and becomes calcium sulfate, a solid. The solid can then be removed by conventional means. In addition, due to relatively low combustion temperatures, nitrous oxides, as well as slag are not formed. Typical nitrous oxide emissions are guaranteed to not exceed 0.4 Lbs. per million BTU input, which will meet the New Source Performance Standards. Properly designed fluid bed units have demonstrated an ability to handle various waste fuels, including wood, municipal refuse, agricultural wastes, tires and others. Disadvantages of fluid bed boiler include the following. The fluid bed is sensitive to fuel sizing. Large amounts of fines tend to increase carbon carryover and therefore reduce efficiency. Fluid bed units typically cannot turn down (reach low loads) due to the air requirements of keeping the bed fluidized and in addition, are slow following load swings. Fluid beds have relatively complex fuel and material feed systems which complicate operations. There is insufficient data available regarding reliability and maintenance costs in order to be able to accurately estimate life cycle costs. Fluid bed units have also shown themselves to be high auxiliary power users. A survey of several fluid bed boiler manufacturers in the U.S. indicates that generally, the size range being considered for Nome and Kotzebue is smaller than the majority of U.S. and European installations. Competitiveness, with other technologies, would be poor. There is one (1) manufacturer of bubbling fluid bed type units who claims competitiveness in the size range being considered for Nome and Kotzebue. This manufacturer has limited experience burning coal and limited experience with SO, reduction. However, should it be necessary to meet significant SO, reduction (90%+), all manufacturers will be examined further. Concerning Red Dog, however, which will require SO, reduction and is to be a larger installation than the villages, fluid bed technology is an option that should be considered to a greater degree than Nome and Kotzebue. Pulverized coal (PC) boilers have been in service in all types of plant for many years. Several thousand have been installed in the U.S. with several more thousand installed throughout the world. PC units are used in all major coal fired power generation facilities in the world. PC units can be found burning a variety of coals, from lignite to anthracite. PC units offer several advantages. A PC boiler will have an excellent load response with an acceptable turndown rate. While a PC boiler can burn a wide range of fuels, it must be designed for the types of fuels expected otherwise slagging and fouling will occur. PC units typically have high availability and are considered quite reliable and as indicated above, PC firing is a demonstrated technology. Certain disadvantages also exist with PC fired boilers. An auxiliary fuel, such as oil or gas, is required to start the unit. PC units generally have medium to high (but not as high as fluid beds) auxiliary power use. Generally, PC units get very expensive as size of the unit decreases. The PC unit generates more NOx than other technologies and does require auxiliary equipment in order to reduce SO,emissions. Typical NOx emissions are 0.6 Lbs. per million BTU input which will meet New Source Performance Standards. The manufacturers of pulverized coal units in the U.S. do not recommend this technology in smaller capacities. Small (under 100,000 pph or 10 MW) PC units are very difficult to find. Use of PC technology would be better suited at Red Dog than at Kotzebue or Nome. The third type of unit being reviewed is a stoker fired boiler. Stoker units have been in service for many years, being the oldest technology for coal burning. Stoker themselves, however, have seen significant improvements over the years. There are several thousand new as well as old stoker fired boilers throughout the U.S. as well as the world. Stoker units can be found burning a wide variety of fuels, including all types of coal, wood, refuse, waste materials, and others. This can be done as long as the stoker itself and the boiler are properly designed for the fuel to be encountered. The stoker unit can be considered to be reliable with very good availability. Stokers do have a reasonably good load response, somewhere between fluid beds and PC units. Stoker units are the simplest and most forgiving, of the three (3) technologies being reviewed, to operate. Generally, one can expect low maintenance costs and low auxiliary horsepower requirements on stoker fired boilers. Stoker units are to be considered demonstrated technology. Stoker units do generate less NOx than PC units. Typical NOx emissions are 0.5 Lbs. per million BTU input which will meet the New Source Performance Standards. Along with advantages of stoker boilers come’ some disadvantages. The major disadvantage of stoker units is that they are, like fluid bed units, sensitive to coal sizing. Generally, coal must be double screened to remove both large and small particles prior to burning in a stoker unit. Like the PC unit, there is no inherent capture of SO, and therefore, auxiliary equipment would be required for SO, reduction. All manufacturers surveyed indicated stoker firing would be the technology of choice for the scenarios being reviewed. While there is some concern regarding clinkering and slagging potential, proper design and selection of equipment would overcome these problems. The manufacturers indicated that the products would be highly competitive and relatively easy to install. In some instances, complete shop assembly could be accomplished. A table summarizing the three (3) technologies reviewed follows: BOILER TECHNOLOGY Stoker PC CFB NOx Generation Medium High Low Inherent SO, Yes Capture Auxiliary Power Low Medium High Usage Sensitivity to Yes No Yes Coal Size Complexity of Simple Average Complex Operation Experience in Yes Limited Limited Units less than 100,000 pph (0.5 Lb/MMBTU) | (0.6 Lb/MMBTU) | (0.4 Lb/MMBTU) Maintenance Low Medium High Cost Load Response Fair Good Poor Turndown Fair Good Fair Boiler 85% | 87% 85 - 86% Efficiency It should be noted that if lower NOx levels (below those shown in the table) are required due to local restrictions, a non- selective catalytic reduction system would be required. It has been assumed that this is not the case. 2.5 Plant Size and Technology Selection Plant electrical generation is to be detailed elsewhere in this report. A summary of the requirements is listed below on a location basis. Along with the requirements is a discussion of the technologies suitable for the size range and a recommendation of the best selection. The selection is generally based upon ability to meet environmental regulations, estimated installed cost, reliability, operational costs including performance ease of operations and size and weight. District heating requirements are to be detailed elsewhere in this report. As a summary, district heating requirements are based on a phased approach. Plant sizing requirements would increase dramatically if it were necessary to provide sufficient capability for an entire city such as Nome or Kotzebue. This large load would not match well with the present electric load, and in essence, the plants would become heating plant with electricity as a byproduct which, because there presently are no or minimal heating customers, may make financing difficult. 2.5.1 Nome The projected median electrical load growth for Nome shows a growth rate of 0.6% on energy and 0.5% on peak electrical demand after the acquisition of the gold mines’ electrical requirements. Looking at a 10 year window froma 1995 startup, it is expected that Nome will have an electrical peak of 9.55 MW and net generation requirements of 40,716 MWH in the year 2004. Regarding district heating, it is reasonable to assume a phased approach as will be discussed elsewhere. For purposes of equipment sizing, the first phase would be expected to displace approximately 125,900 gallons of oil per year. On the basis of the above, approximately 115,000 pounds of steam per hour would be required to meet the maximum electrical and district heating loads. In order to assure reasonable reliability, normally two (2) 55% capacity boilers would be recommended driving one (1) steam turbine. It is recommended that the primary technology be stoker firing, or more particularly, spreader stoker. Should SO, scrubbing be required, either a dry scrubber utilizing lime or a venturi scrubber utilizing alkali technology could be utilized. 2.5.2 Kotzebue Projected electrical load growth for Kotzebue indicates that by the year 2004, peak electrical requirements will be approximately 5.2 MW with net generation of 25,500 MWH. District heating would be phased as it would be at Nome. Presently, it is expected that the first phase would displace 214,000 gallons of oil per year. On the basis of the above, it is expected that approximately 70,000 pounds of steam per hour would be Zee LO required to meet the maximum electrical and district heating loads through the ten (10) year planning period ending in 2004. Again, in order to assure reasonable reliability, two (2) 55 percent capacity boilers would be recommended driving one (1) steam turbine. It is recommended that the primary technology be spreader stoker firing. However, because availability of water is a serious problem in Kotzebue, should SO, major reduction be required, fluid bed technology may be the only viable solution. Should process water become available, a stoker unit with either a dry or alkali scrubber would be preferred. 2.5.3 Red Dog A power plant located either at the Red Dog mine or at the coal mine with transmission to Red Dog would be required to meet all load requirements of the present diesel plant installed at the Red Dog facility. Present installed capacity at Red Dog is 25 MW of diesel generation and approximately 40 MMBTU/Hr of waste heat recovery. At times of high power use, no more than three (3) of the five (5) diesels are presently used, one (1) being held as backup and one (1) considered as under repair. It is expected that approximately 215,000 Lbs/Hr of steam generation will be required to meet peak load. PSD review will be required in this instance, and we can expect that 90% SO, reduction will be necessary. 2 It is recommended that the technology considered here be spreader stoker firing based upon two (2) 55% capacity boilers with SO, reduction by dry scrubber in order to be similar to Kotzebue and Nome such that spare parts and operator training would be simplified and based upon sufficient process water available in the area. Should process water not be available (25 - 35 gallons per minute), then circulating or bubbling fluid bed technology would be preferred. 2.6 Condensers There are several means for providing the cooling media necessary to remove heat from the low pressure steam exhausting from the turbine. Water and air, and in some instances a combination of both, are the mediums used for this purpose. Most conventional power generation plants utilize water as the cooling medium. The water circulates through tubes in a heat exchanger while the hotter steam circulates around the tubes. The steam is condensed and collected. The circulating water is either sent to a cooling tower where it is cooled and re- used or sent back to the source such as a river or large lake. Water loss is significant with a cooling tower and it must be made up by local sources. In the case of Nome, expected cooling tower losses would be approximately 600 gpm. In regard to Kotzebue, 300 gpm and Red Dog, 1,000 gpm. Another method of cooling is by the use of air. This would seem to be most appropriate for the climate conditions encountered in Northwest Alaska. The exhaust steam from the turbine flows through a series of finned tubes exposed to air. The air is forced around tubes by multispeed fans and cools and condenses the steam. There is no water loss and therefore 2a—eL2, no makeup water requirements. The only concern regarding air cooled condensers would be freezing during harsh weather, however, this can be avoided by proper design. Hot weather would degradate performance, which would not occur in Northwest Alaska. Generally, a rankine cycle power plant can improve cycle efficiency by lowering the pressure at the exhaust of the steam turbine. However, this exhaust pressure is a function of the temperature of the cooling media utilized to condense the steam; the lower the cooling media temperature, the lower the exhaust pressure and the cycle efficiency improves. A plant that has the capability of utilizing once through cooling by use of a river or large lake usually has a fairly constant cooling water temperature that typically does not exceed 70 F. A turbine backpressure range for this situation would be 1-1/2" Hg to 3" Hg. A plant that utilizes circulating cooling water where the water is subsequently cooled in a cooling tower, cool make-up added and then returned, generally has a turbine backpressure in the 2-1/2" - 4" Hg range. Plants that utilize air cooled condensers are affected much more by ambient temperatures. Utilizing the ambient temperatures expected at the sites under discussion, turbine backpressure will range from 2-1/2" to 5" Hg, with the higher backpressures occurring in the summer. Yearly average backpressure is expected to be 3-1/4" Hg. As can be seen, it is expected that use of an air cooled condenser will result in slight degradation of average yearly cycle efficiency. However, the significant losses will occur 2a lS in the summer, when the unit is lightly loaded, thereby mitigating the loss. Both air and water cooled systems utilize multiple fans, typically dual speed, to assist in control of backpressure. In addition, sections of an air cooled condenser or a cooling tower can be isolated in order to assure proper control can be Maintained under any climate condition. The air cooled condenser is more versatile in that it has several more fans than a cooling tower and therefore, is easier to control A condenser - cooling tower system would include the condenser, condenser foundations, hotwell, condensate pumps, circulating water piping, circulating water pumps, cooling tower, cooling tower foundation, cooling tower fans and controls. An air cooled condenser system would include the steam line to the condenser, condenser foundations, hotwell, condensate pumps, condenser, condenser fans and control. It is expected that the air cooled condenser system would be less costly on an installed basis. However, there would be slightly higher parasitic power use to the number of fans, thereby resulting in an increase in operating costs. Based on the above and the high cost of water, it is our recommendation to proceed on the basis of use of air cooled condensing at all plants. 2-7 Conclusion A review has been performed of technologies available for production of electricity and district heating utilizing a conventional Rankine cycle. Present environmental regulations 2—- 14 have a major impact on the technology selection. The recent Clean Air Act amendments do not apply to the State of Alaska. Various vendors have been surveyed and it has been determined that minimal experience exists regarding fluid bed boiler technology in this size range. Pulverized coal firing is a non-competitive technology in the boiler capacities required. All vendors who manufacture stoker fired boilers indicate that this is the technology most suited and most competitive in the capacities necessary for Nome and Kotzebue. SFT, assuming conservative boiler sizing and grate release rates, concurs. Should sulfur dioxide reduction be required, small dry scrubbers as well as alkali venturi scrubbers are available. It should be noted that it will be necessary to process the coal at the mine site prior to shipment. The processing for stoker units will involve crushing and double screening of coal to remove large pieces and small fines. The processing for fluid bed units, should they be selected, would involve crushing and single screening to remove small fines. Pulverized coal units would require no processing. The balance of plant equipment, including the turbine- generator would be of conventional design, with the exception of the condenser - cooling tower system. Rather then use of a water cooled condenser with circulating water then cooled in a cooling tower, it is recommended that an air cooled condenser be utilized. An air cooled condenser requires minimal makeup water as compared to a conventional condenser - cooling tower arrangement. Ziel 3.0 EQUIPMENT SIZING 3.1 Introduction Power plants of this nature typically take several years from initial conception to final commercial operation. Construction alone, from time of purchase of the major equipment such as boiler and turbine-generator to construction completion typically amounts to over 20 months. When considering the time required for review of the various studies and preliminary plans, as well as the time required for arrangement of financing, it is reasonable to assume that initial operation of the various plants under consideration will occur in 1995. Typically, it is prudent to incorporate into the design of major capital equipment the ability to meet present and future needs such that the needs can be met for a reasonable period, generally ten (10) years. For that reason, plant sizing should be based on meeting the electrical needs as forecast for the year 2004, including any known expansion and growth. District heating, in deference to the above, requires a different method of analysis. In order to provide equivalent heat from a central heating plant capable of meeting the district heating needs of an entire town would require a very large increase in the initial investment in capital equipment. For example, the City of Nome utilizes on the order of 2,000,000 gallons of fuel oil per year for heating. This is approximately 30,000 MMBTU per year of energy or an average of 34 million BTU per hour, which would be expected to peak at about 60 million BTU per hour. This is equivalent of being able to produce approximately 5,500 KW of electrical power, which amounts to, in essence, a 50% increase in plant size due Sie to district heating over the requirements of electrical production. To be considered is the fact that the residents must be convinced of the viability of district heating particularly in regard to reliability. Due to these reasons, most district heating systems have been based upon a phased approach, with the first phase typically including buildings and residences physically near the power plant and also possibly potential major users. Once reliability and decreased cost is demonstrated, additional phases are constructed. It is recommended that plant size be based upon a phased approach to district heating. Generally, rankine cycle equipment ranges in pressure and temperature of the steam produced. The actual choice of a pressure and temperature is dependent upon several factors. This includes such items as size, cost, complexity, and efficiency. While higher pressures and temperatures generally result ina better cycle efficiency, availability becomes more difficult and cost increases as does complexity. It is for these reasons that units under 50 MW in size typically do not exceed 1,250 psig and 950 F, units under 25 MW in size generally do not exceed 900 psig and 900 F and units 15 MW and under are usually either 600 psig, 750 F or 425 psig, 750 F. These generalizations should then be examined based upon the particular situation. One significant concern is boiler water quality. As boiler operating pressure increases, the requirements for higher quality also increase. There is a break point at 900 psig where units at or above this pressure typically require mixed B i=|2 bed demineralized quality water while units below this pressure utilize water quality associated with the simpler and less costly sodium zeolite system. Another concern is materials and associated labor. Temperatures exceeding 750 F require a piping material change to alloy. The higher the temperature, the more alloy used until stainless steels are reached. Higher alloy content piping and valving are more difficult to obtain, cost more and are much more difficult to weld, requiring heat soak periods and stress relief which in turn means better labor skills and more equipment. It is recommended that all units at all locations being examined be designed for production of steam at 600 psig and 750 F. The potential increase in cycle efficiency to increase pressure or temperature is outweighed by cost complexity and availability as described above. 3.2 Nome 3.2.1 Present System The City of Nome owns and operates its own electrical system under the auspices of the Nome Joint Utility System (NJUS). The NJUS operates two (2) power plants, one (1) located adjacent to the Snake River and west of town the second smaller plant located at Beltz High School which generally operates unattended. There are seven (7) diesel generator sets located at the main power plant as follows: GENERATOR SIZE (KW) General Motors GMD General Motors GMD Fairbanks Morse Cooper Bessemer Cooper Bessemer (3) 600 (each) Jacket cooling water is utilized to heat the City’s potable circulating water loop. The plant was built in the mid-1950s and has been added to throughout the intervening years. NJUS is in the process of installing a new 3,700 KW diesel generator to augment existing capacity and possibly retire some of the older units. The Beltz High School plant consists of a_ single unattended diesel generator set manufactured by Mitsubishi at 600 KW capacity. The heat rejected from this engine is utilized to heat the Beltz school. 3.2.2 Electrical Sizing Electrical load has grown steadily in Nome for many years. The past ten (10) years data is shown below and graphically in Figure 1. HISTORICAL ELECTRICAL LOAD - NOME RA ES ST NEE TE AIS YEAR ENERGY (KWH) DEMAND (KW) 1980 15,738,600 3,150 1981 16,254,600 3,180 1982 18,090,400 3,500 1983 19,257,300 3,600 1984 20,478,100 3,750 1985 21,818,000 3,950 1986 22,491,600 3,900 | 1987 22,748,500 4,050 24,056,200 27,459,400 The analysis of this data indicates an average energy growth rate of 6.4%, well above the U.S. norm. Nome’s electrical use peaks in winter. Also, there is a significant decrease in requirements in the summertime, a bit unusual as compared to most U.S. cities. Monthly generation for 1989 is shown in Figure 2. In the past few years, Nome has been assuming portions of the load of the various gold mining companies in the area, which has partially accounted for the high average growth rate of over 6%. Presently, the majority of the gold mining companies generation is by in-house diesels owned and operated by each of the mining companies. Based upon discussions with the NJUS management, it is reasonable to assume that the NJUS will serve the electrical needs of the gold mining companies within the next few years. Should the cost of NJUS generated electricity decrease due to use of coal as a fuel, then it becomes even more probable that the gold mining Yoads will be served by the NJUS. This conclusion has been supported at length in a recent report outlined "Nome Electrical Load Forecast" dated October 26, 1990. This report does predict load growth for Nome on the basis of non-mining generation, mining generation, and a combined total. Sufficient work was done studying the demographics of the area such that a conclusion was reached that shows three (3) cases, a low forecast, a mid-forecast, and high forecast. The report indicates” that there is a 50% probability that the mid-forecast will indeed become the actual load. The three (3) forecasts are shown below for reference. It should be noted that the growth rate decreases significantly, to 0.6% on energy and 0.5% on demand, after the acquisition of the gold mine company’s load. ART ROR IO eR CALETA ANN AA ie NR a aN MINING + NON-MINING LOAD GROWTH EAE A ST TAR A Year Low Mid High (MWH) 1995 28,534 37,005 56,194 1996 28,694 37,715 56,408 1997 28,759 38,301 56,773 1998 29,084 38,812 57,143 1999 29,389 39,273 58,866 2000 29,837 39,742 60,046 2001 29,868 39,763 60,888 2002 30,081 39,991 61,352 2003 30,337 40,278 61,994 2004 30,701 40,716 62,975 It is our belief that the mid-forecast does represent a reasonable expectation of the Nome load requirements in the future. It would, therefore, be recommend that the electric plant output be sized for 40,716 MWH with a peak load of 9.55 MW as predicted for the year 2004. 3.2.3 District Heating Presently, the NJUS does recover heat from diesel jacket water and heats the City’s circulating water loop. In addition, the Beltz High School installation also recovers heat from diesel jacket water in order to heat the school. There is no other district heating or supplemental heating from power plant operations. All other heating in Nome is done with diesel fuel in local heaters amounting to over 2,000,000 gallons per year of use or 300,000 million BTU per year. Since this equates to approximately 5,500 KW or 58% of the electrical requirements, it seems prudent to size the district heating to meet the requirements of Nome in a phased approach. The first phase would show the feasibility as well as the cost saving of the system. The first phase, therefore, should be well planned and should service major heat users near the power plant and be capable of future expansion. Proposed, therefore, is sizing such that the following Bering Street buildings would be serviced. Bonanza Auto Hanson Trading Company Police/Fire Station Public Works Garage Lutheran Church Professional Building N.S.H.C. Hospital Community Health Services Hospital Warehouse The above buildings require 125,900 gallons of fuel oil, per year or 17,626 million BTU per year. Peak hourly requirements amount to approximately 5 million BTU per hour including losses which is what the district heating system would be required to produce. It is not expected that the heating load for these buildings will vary over the next fifteen (15) years. Domestic water heating is expected to continue by use of stack heat recovery or condenser heat recovery adding an additional 10,640 million BTU per year or 1.2 million BTU per hour to the above figures. Future phases would continue on a route on the north side of Nome to include the Community Center, apartment building and elementary school as well as a route along Front Street in order to service the commercial establishments and businesses located there. In addition, other phases would be intended to service the various residences throughout Nome. The district heating system design would be similar to that proposed in various other studies and reports on this subject, the latest being the "Nome Waste Heat Recovery Report and Concept Design" as prepared by Fryer/Pressley Engineering, Inc. , 3.2.4 Summary On the basis of the above information, it is necessary for the coal fired power plant to produce a peak electrical load of 9.55 MW (winter load) which could be coincident with a peak district heating load of 5 million BTU per hour. Production of a net 9.55 MW would require a fuel input of approximately 135 million BTU per hour. Projected demand, electrical consumption, and coal use is shown in the following table. PROJECTED ELECTRICAL AND COAL USE CITY OF NOME Coal Use (Tons/Yr) The district heating energy requirement, which would be serviced from a turbine extraction, would improve the overall cycle efficiency due to less steam flow to the condenser. Therefore, while we would normally expect to provide fuel energy to the boiler higher than the district heating load to account for losses, we do not need to due to the cycle efficiency gains. It is recommended that the Nome coal fired power plant be sized such that total maximum fuel input be 140 million BTU per hour. This is equivalent to a _ boiler(s) 3 - 10 Sid producing 115,000 pounds per hour (pph) of steam and a steam turbine-generator capable of generating 10.5 MW gross electrical generation. A cycle diagram is shown in Figure 5. Kotzebue 3.3.1 Present System The Kotzebue Electric Association (KEA) provides electrical service to the area at the tip of the Baldwin Peninsula. This fully encompasses the City of Kotzebue. The KEA is a Rural Electric Administration (REA) cooperative not subject to the administration of the municipal government as is Nome. The KEA operates one (1) power plant located within the confines if the City of Kotzebue. There are five (5) diesel generators and one (1) combustion turbine-generator located at the plant as follows: KW Generator Size ; 4 a White Superior (2) 500 (each) General Motors GMD 2,500 General Motors GMD 1,700 Caterpillar 1S 5 ye Solar (combustion turbine) 900 » & Tec |] 4 While several waste heat recovery system have been designed and installed in Kotzebue, presently, minimal waste heat recovery from the equipment at the power plant is occurring. SE eel: Electrical load growth in Kotzebue has been fairly steady over the past ten (10) years. The data is shown below and in Figure 3. HISTORICAL ELECTRICAL LOAD - KOTZEBUE (ee ree on pint ae reenact eta eee YEAR ENERGY (KWH) DEMAND (KW) Ce NO 1980 10,626,900 2,105 se 1981 11,530,600 2,150 1982 12,249,300 2,240 1983 13,668,400 2,668 1984 14,703,000 2,662 1985 15,999,200 2,665 1986 16,101,400 3,005 1987 16,222,900 3,455 1988 16,235,000 3,005 1989 16,981,000 3,425 se The average energy growth rate over the past ten (10) years is 5.4% which is also well above the U.S. norm for the same period. Kotzebue, like Nome, has its electrical peak in the winter, with significant decreases during the summertime. Monthly generation for 1989 is shown in Figure 4. 3) 12 Recent projections performed by KEA (Power Requirements Study - March 1989) indicates that a growth rate of 2.7% in electrical use is expected through the year 1997. The reason the growth rate is less than the historical growth is that it is expected that both small and large commercial use will not increase significantly over the planning period. This is evidenced by the past five (5) year’s data which shows a growth rate significantly below the ten (10) year average. It is, therefore, reasonable to assume that the growth rate as predicted in the Power Requirement Study is acceptable and can be extrapolated through the year 2004 even though the study only predicted growth through 1999. On that basis, plant capability should be 26,345,000 KWH per year with a peak of 5,200 KW. 3.3.2 District Heating Presently, the KEA does minimal heat recovery from power plant operations but does intend on reactivating a heating system which will assist in heating domestic potable water in the wintertime. All heating in Kotzebue is done with diesel fuel in local heaters amounts to well over 1,000,000 gallons per year of fuel use. As previously stated, a district heating system should be designed such that a phased approach is taken in order to prove feasibility and reliability and also not have a major impact on the capital costs of the power plant project. It is recommended that the system be sized to meet the needs of major users near the power plant and also be sized such that expansion can occur in the future. Stes Proposed, therefore, is sizing such that the following buildings would be serviced: New Hospital A.C. Company Store KIC Apartments Senior Center Public Works Water Treatment The above buildings and water system require 214,200 gallons of fuel oil per year or 29,988 million BTU per year. Peak hourly requirements are 5.3 million BTU per hour. The water system would not be able to be heated from stack or condenser waste heat because the water treatment plant is located far from the proposed coal fired power plant location. Future phases would include a southerly loop to incorporate the NANA Museum, KIC apartment building and various airport buildings. Northerly phases would incorporate the various schools, armory, recreation center, buildings on Shore Avenue and ultimately residences. The district heating system design would be similar to that proposed in various other studies and reports, the latest being "Kotzebue Waste Heat Recovery Report and Concept Design" as prepared by Fryer/Pressley Engineering, Inc. 3.3.3 Summary Based upon the above information, the proposed coal fired power plant would need to produce a peak electrical load of 5,200 KW which could be coincident with the peak district heating load of 5.3 million BTU per hour. As 3 - 14 previously indicated, district heating energy would improve overall cycle efficiency by reducing losses from the condenser. It is recommended that the Kotzebue coal fired facility be sized such that total maximum fuel input be 88 million BTU per hour. This is equivalent to a steam production of 70,000 pph and a steam turbine-generator producing 5.7 MW gross electrical generation. Projected demand, electrical consumption, and coal use is shown in the following table. PROJECTED ELECTRICAL AND COAL USE CITY OF KOTZEBUE Coal Use (Tons/Yr) A cycle diagram is shown in Figure 6. 3.4 Red Dog Mine The present installed capacity at the Red Dog Mine is 25 MW of diesel generation, made up of five (5) Wartsila 5 MW diesel generators. Significant waste heat is recovered from jacket water, turbocharge cooling, and exhaust gases amounting to 40 million BTU per hour. Generally, the electric load at Red Dog does not exceed 9 MW, but when full production is reached, 12 - 15 MW will be required. It is not expected that this will change through the planning period; the year 2004. This is equivalent to boiler production of 215,000 pph of steam which will meet the heating and electrical load needs and a steam turbine-generator capable of generating 16.5 MW gross electrical generation. This would require approximately 65,000 tons per year of 12,000 BTU coal. A cycle diagram is shown in Figure 7. 3.5 Deadfall Syncline Coal Mine Another possible power plant location would be at the Deadfall Syncline coal mine site. This plant would generate sufficient electricity to service the Red Dog Mine at its maximum requirements of 15 MW. Transmission from the Syncline to Red Dog would be by 138 KV overhead transmission line. Preliminary routing indicates that approximately 85 miles of line would be required. Generation would occur at voltage of 13.8 KV (which is typical for this size of generator), be stepped up to 138 KV for 3 = 16 transmission and then be stepped down at the Red Dog site to the voltages required for plant operation. The losses associated with the transformation and transmission are expected to be approximately 500 KW. Therefore, boiler production would be 220,000 pph of steam with electrical production of 22 MW assuming that Red Dog converts to electrical heating. Boiler production would be 170,000 pph of steam and with 17 MW of electrical production should Red Dog convert to some other method of heating. The larger unit would require approximately 87,000 tons per year of coal and the smaller unit approximately 65,000 ton per year. A cycle diagram is shown in Figure 8. 3.6 Conclusion Based upon various projections of growth, it is recommended that the coal fired power plants be sized to produce the following: @ Nome: 10,500 KW gross plus 5 million BTU per hour district heating energy. @ Kotzebue: 5,700 KW gross plus 5.3 million BTU per hour of district heating energy. @ Red Dog Mine: 16,500 KW gross plus 40 million BTU per hour of district heating energy. @ Deadfall Syncline Mine: 22,000 KW gross including sufficient electrical production for plant heating. Seana, mre ses =< 30000000 25000000 20000000 15000000 10000000 1980 1981 1982 NOME HISTOR LILCTMC LOND OLMAND 1983 1964 198s = | —s | ENERGY 1986 1967 1968 1989 6000 5500 5000 4500 p 4000 3500 3000 Pigure 1989 CLMETATON-NOME 3100 4000 2900 3500 2700 0) C N 3000 ‘ E 2500 h R r N ) Y 2300 2500 | M 2100 ENERGY K W 2000 W H 1900 1500 1700 1500 1000 JAN FEB MAR APR MAY JUN JUL AUG SEP ocT NOV DEC Figure 2 perneiet — peren Sena ‘ - a KOIZILUE ISTOMC LECTIUCAL LOM) 17000000 3600 3400 166000000 CNERGY 3200 [ 18000000 N UD C 3ooo [ R 14000000 M CG A 2800 : N 13000000 0 K 2600 W K W H 12000000 2400 11000000 2200 10000000 2000 1980 1981 19862 1983 1964 1965 1986 1987 1988 1989 Pigure 3 LIED CEMELATION-KOIIT 2000 2600 1900 2400 1800 OCMAND 2200 £ 1700 NN é ~x 2000 M 1600 A R =. N © 1500 yen o 1so0 () K yy 1400 1600 W H 1300 = “— ———__ nervy 1400 1200 1200 1100 1000 1000 JAN FED MAR APR MAY JUN JUL AUG SEP ocT NOV DEC Figure 4 BOILER BLOWDOWN HIGH PRESSURE HEATER GENERATOR FROM = ir] - nw > wn oO = e < uj ee EXCHANGER AIR COOLED CONDENSER (=) U OW PRESSURE HEATER BOILER FEED PUMP 51Alo4-09-91{ LA LL a Av zi ry D = Ni ARCTIC SLOPE CONSULTING GR SIGNATURE Se ee a ce ae eee ea aed IE lo SFT, Inc, connot be copled or reproduced | CH’ KOt Vfe (04-09-91 CYCLE DIAGRAM without the exprese written permission of fcu'xo: RY [0 -09- SFT, ne. aren pect WIZO= RED DOG MINE SCALE! PROJ. /CONTRACT NU.T ORAWING NO. SFT, Inc. Sail GFT NONE 9058-00-00 | 905800-MRP-001 = Sh GENERATOR - A og ze © ow te HEAT EXCHANGER BOILER CONDENSER BLOWDOWN BOILER FEED PUMP ARCTIC SLOPE CONSULTING GROUP NOTICE! The drowing ond oll Information con- tolned thereon le confidentiot ond proprietory FIGURE 5 to SFT. Ine. connot be copled or reproduced jen‘xor Jp —|04-09-91 CYCLE DIAGRAM Seer Ae exprese written permission of feu’xo: RY [04-09-97] : 5 [are"0: PRE_|O4-09=91] SFT, Inc. Consulting Engineers GFT ORANING NO. ny 905800-MRP-002 A SCALE? PROS. /CONTHACT HO. NONE 9058-00-00 Pe S908 nO. ut GENERATOR ROM DISTRICT HEATING SYSTEM HEAT EXCHANGER TO DISTRICT HEATING SYSTEM BOILER CONDENSER BLOWDOWN BOILER FEED PUMP ARCTIC SLOPE CONSULTING GROUP NOTICE! The drowing ond oll Intormotion con- toined thereon Is confidentiot ond proprietory to SFT, Inc. It connot be copled of reproduced without the express written permission of SFT, inc, SFT, Inc. Consulting Engineers GFT) FIGURE 6 CYCLE DIAGRAM -KOTZEBUEs ALASKA PROJ. CONTRACT NO. 9058-00-00 SCALE: NONE DRAWING NO. 905800-MRP-003 r 4.0 PLANT DESCRIPTION AND COST ESTIMATE 4.1 Introduction In accordance with the recommendations of this report, the plants for Nome, Kotzebue, Red Dog Mine, and the Deadfall Syncline Mine cost estimates have been prepared on the basis of installing spreader stoker fired boilers with associated equipment required for a complete power plant. Arrangement drawings were prepared for the Nome and Kotzebue plants and site plans for the Red Dog Mine and Deadfall Syncline Mines as listed in paragraph 4.4. The cost estimate results for each plant are tabulated and shown on separate pages in this section. In order to complete the cost estimates, pricing was obtained from various vendors for major equipment including boilers, turbine-generators, air cooled condensers, and feed pumps. The remainder of equipment costs were based on recent experience and adjusted as required for the plant requirements. Construction costs including materials and labor costs were estimated on the basis of the drawings prepared for the four (4) plants. Freight costs to Seattle and from Seattle to the Alaskan ports have been included. 4.2 Description of Contracts 4.2.1 General Each of the line items listed on the cost estimate is generally considered to be one (1) contract. Certain of them are on a delivered and erected basis and others are for equipment only delivered to nearest Alaskan port. In general, the contents of each plant is the same except Warn! for capacity and size of equipment required to meet the plant output as recommended in this report. 4.2.2 Steam Generators The steam generator contracts for each plant include two (2) stoker fired boilers with furnaces, superheaters, economizers, attemperator, coal feeders, forced draft fans, induced draft fans, flues, ducts, one (1) stack, sootblowers, boiler support steel, baghouse, refractory, insulation and lagging. In addition, a cost for the dry scrubbers have been added to the Red Dog and Deadfall Syncline Mine installations. Each of the steam generators would be sized to produce 55% of the total steam requirements of the plant at the pressure and temperature conditions recommended in this report. The size of the steam generators for the Kotzebue plant would allow complete shop assembly while the others can be partially assembled in the shop, shipped to Seattle, then assembled into larger modules for shipment to the appropriate Alaskan port by barge. The amount of assembly would be limited to the weight capacity of lift equipment at the Alaskan port and any clearance limits. The intent is that this contract scope be on a delivered and erected basis to provide for a single responsibility to meet the guarantee which would be written into the contract. Budget prices were obtained for the equipment from the following: Foster Wheeler Energy Corporation @ Babcock & Wilcox Company e Energy Products of Idaho e Tampella Keeler 4.2.3 Turbine-Generators One (1) turbine-generator would be installed with a capacity rating as recommended for the plants. The cost is based on a condensing type turbine with a controlled extraction point for process steam and supply to the deaerators. The generator would be a _ synchronous machine. Accessories include one (1) turbine-generator combined control and lubrication oil system, speed reducing gear, supervisory controls, instrumentation, and baseplates. The estimated costs include installation of the equipment. Budget prices for the equipment were obtained from the following: @ Turbodyne @ Elliott Company @ General Electric Company 4.2.4 Deaerator/Feedwater Heaters The cost estimate is for the equipment delivered to the port. Construction of this equipment is included in the piping and mechanical contract. The budget cost was obtained from Cochrane Environmental Systems. The deaerator is required for removing air from the water and also heats the water. All the plants would have a deaerator and the plant at the Red Dog Mine and Deadfall Syncline Mine would have additional feedwater heaters as indicated on the flow diagrams. 4.2.5 Boiler Feed Pumps Three (3) boiler feed pumps, two (2) motor driven and one (1) steam driven, with drives and shipping costs to Alaska port are included in the estimate. Budget prices were obtained from Goulds, Inc. Installation cost is included in the piping and mechanical contracts. These pumps are required for supplying water to the boiler at the pressures needed. 4.2.6 Air Cooled Condenser The estimated cost includes the air cooled condenser, delivered and installed, with a galvanized steel support structure, fan with drive and geared speed reduction, condenser isolation valve and other accessories. Budget prices were obtained from the following: @ GEA Power Cooling Systems, Inc. @ Zurn Balcke-Durr, Inc. Areionl, Water Treatment The estimated cost includes a sodium zeolite water treatment system delivered and installed. This equipment is required to provide water to the boilers at the quality required for the design pressure of the system. 42.8 Instruments and Controls The estimated cost is based on a microprocessor based system delivered to the Alaskan port. It would control the two (2) stoker fired boilers, district heating (where applicable) and the balance of plant auxiliaries. Installation is included in the contracts for mechanical and electrical work. A budget price was obtained from Bailey Controls for system. 4.2.9 Ash Handling The estimated cost includes the necessary equipment delivered to Alaska for installation by the mechanical contractor. The system would be a pneumatic type with mechanical exhauster, air filtering equipment, transport pipe, air intakes, bottom ash crushers, ash silo and rotary unloader. It would be designed to collect ash at the various boiler and baghouse hopper discharges and transport the ash to the silo. It is expected that the silo storage would be for about two (2) days. MTrucks would be required to take the ash from the silo to the City landfills or the mines for disposal. Ae 2:0 Coal Handling The cost for the coal handling system includes the equipment delivered and erected at the plant. Each system will require a coal crusher, magnetic separator, controls, conveyor with motor drives,. and equipment structural supports. The arrangement drawings indicate an indoor storage facility in which coal would be dumped from truck. An operator with a front end loader would load coal into a hopper from where it would be conveyed to the power house coal bunker. 4.2.11 Site Preparation and Substructure This contract includes labor and materials for the site preparation and substructure installation. 4.2.12 Structural Steel and Building Enclosures Costs for all structural steel materials and labor required for platforms, building support, walls, roofing, hoppers, coal silos, and miscellaneous steel are included in this estimate. Boiler support steel was included in the steam generator estimate. 4.2.13 Building and Site Finishes This contract estimate includes all costs for materials and labor required for concrete floors, partitions for offices and rooms, underground sewer and water lines to site boundary lines and roads located within the plant boundary. 4.2.14 Piping and Mechanical Equipment All materials and labor required for the installation of steam, water, and air piping to the boiler and plant auxiliaries would be included in this contract. This contract would also include’ the supply and/or installation of mechanical equipment not included in the other contracts. 4.2.15 Major Electrical Equipment This cost estimate is for the transformers, switchgear, and motor control centers that are shown in the single line diagrams prepared for each of the plants and listed under paragraph 4.4. Cost includes the shipment and delivery to the Alaskan port. Installation costs are in the station wiring estimate. 4.2.16 Painting The contract would be for the finish painting of shop primed coated surfaces including structural steel, platforms, uninsulated piping, rooms, and touch up of shop finished equipment. 4.2.17 District Heating District heating is for the Nome, Kotzebue, and Red Dog Mine plants and hot water heating of the coal storage buildings. All materials, heat exchangers, and miscellaneous equipment costs are included on a delivered and installed basis. ieele Overhead Circuits This estimate is for the finishing of all materials and labor required for delivery and installation of the transmission lines between the Deadfall Syncline Mine power plant and the Red Dog Mine. Certain design assumptions were to use H-frame wood pole structures, span lengths of 500 feet, foundations of direct embedment type and a transmission line length of 92 miles. Wood poles for cost estimate included 75 foot Class 1 Douglas Fir. 4.2.19 Total Project Costs A 15% engineering and contingency cost has been added to the total construction costs and 7% escalation has been assumed to provide for 1992 and 1993 cost increases. 4.3 Plant Staffing The power plants would require a full time, 24-hour per day staffing. Three (3) daily shifts, one of eight (8) hours each plus a rotating shift for weekends, requiring a total of four (4) shifts is proposed. This will account for continuous staffing, with allowances for sickness and vacations. The plant would have to be staffed with the following operating personnel as a minimun. Plant Superintendent: Responsible for overall management of the plant, shift and maintenance scheduling, ordering of fuel and supplies, hiring of personnel, record keeping, etc. Usually this position is held by a person with at least ten (10) years of power plant operating experience and preferably some formal college training. Power Plant Operator: Responsible for the day to day control and operation of the equipment within the power plant. This position is held by a person with at least five (5) years of heavy equipment operating experience. Familiarity with a power plant would be helpful. Reports to the Plant Superintendent. Assistant Operator: Responsible for removal of ash from the system and the receipt of coal and filling of coal bunkers. Assisted as necessary by the power plant operator. This position is held by a person who has familiarity with mechanical and electrical equipment. Reports to the Plant Superintendent. Laborers: Responsible to assist all others within the plant as necessary. General cleaning and stocking of supplies. No experience is required and reports to the power Plant Superintendent. The plant would also require certain maintenance personnel although it is expected that major maintenance would be performed on a contracted basis by an outside company. Maintenance personnel would include: Mechanical Maintenance: Responsible for oiling and greasing, minor valve repair, minor equipment repair and non-code welding. A person with experience in heavy equipment maintenance would be required. Reports to the power Plant Superintendent. Electrical Maintenance: Responsible for minor repair to electrical devices within the plant. Also responsible for tuning and calibration of instruments and controls, assisted by mechanical maintenance. This position requires a person with experience in maintenance of electrical devices and instrument and control calibration and repair. Reports to the power Plant Superintendent. In addition to the above, a clerk would be required. The clerk’s responsibilities would include bookkeeping, payroll and general typing. A person with three (3) to five (5) years bookkeeping/typing experience would suffice. Typical shift operation would be: Days: Evenings: 7:00 a.m. to 3:30 p.m. 3:00 p.m. to 11:30 p.m. Nights: 11:00 p.m. to 7:30 a.m. Overall plant staffing would be as follows: Number Required Number of Total Number Title Plant Superintendent Shift Operator Assistant Operator Laborers Mechanical Maintenance Electrical Maintenance Clerk Subtotal per Shift Shifts Required aE Days Only uk 2 All 8 2 All 8 1 Days Only aL 2 Days Only 2 1 Days Only Z 1 Days Only z 22 4.4 Arrangement Drawings Arrangement drawings, site Plans, and electrical single line diagrams have been prepared and used as a basis for the cost estimating. These drawings are located in the Appendix of this report with numbers and titles as follows: Drawing No. 905800-MPR-005 905800-MPR-006 905800-MPR-007 905800-MPR-008 905800-MPR-009 905800-MPR-010 905800-ERP-001 905800-ERP-002 905800-ERP-003 905800-ERP-004 4.5 Water Supply Rev. Rev. Rev. Rev. Rev. Rev. Rev. Rev. Rev. Rev. Title Site Plan - 10.5 MW Plant - Nome, Alaska General Arrangement - 10.5 MW Plant - Nome, Alaska Site Plan - 5.7 MW Plant - Kotzebue, Alaska General Arrangement - 5.7 MW Plant - Kotzebue, Alaska Site Plan - 16.5 MW Plant - Red Dog Mine, Alaska Site Plan - 17.5 MW Plant - Deadfall Syncline Mine, Alaska Single Line Diagram - Kotzebue, Alaska Generation Single Line Diagram - Nome, Alaska Generation Single Line Diagram - Red Dog Mine, Alaska Generation Single Line Diagram - Deadfall Syncline Mine Generation It has been assumed that City water supply will be made available to the Nome and Kotzebue plants and that the Red Dog and Syncline Mines water supply will be adequate for the boilers. After the boilers are filled with water and are operating, approximately 5% makeup water will be required for ay ell ed blowdown and miscellaneous uses. In addition, water for the dry scrubbers will be required for the Red Dog Mine and Deadfall Syncline Mine plants. On this basis, the following approximate quantities would be required: e Kotzebue 7 gpm @ Nome 12 gpm @® Red Dog Mine 55 gpm @ Syncline Mine 55 gpm 4.6 Sewer Facility It is assumed that the boiler drains blowdown and wastewater can be discharged into the City sewer systems for the Nome and Kotzebue plants. Sewer facilities for the mine plants would also have to be made available for the plant discharges. 4.7 Schedule The critical path item for power plant construction is normally the procurement, fabrication, shipment, and construction of the steam generating equipment. The steam generator manufacturers have quoted 10 to 12 months for shipment to Seattle while the turbine-generator vendors have quoted 65 weeks. An additional 4 to 6 weeks will be required for shipment to the Alaskan port. Shipments from Seattle to Alaska have to be accomplished between May and September. It will take approximately 12 to 18 months for installation of the equipment, piping, and wiring depending on manpower availability and climate conditions. In regard to the transmission line, it is assumed that this would be started and built in the same period of time. A a2 FS ESE TASES 5.7 MW POWER PLANT CITY OF KOTZEBUE COST ESTIMATE SRT C0 i Le A Re i RNR ae a UR LETTER TR Steam Generators $ 3,740,000 Turbine-Generator 2,380,000 Deaerator 60,000 Boiler Feed Pumps 160,000 Air Cooled Condenser 1,460,000 Water Treatment 50,000 Instruments and Controls 1,200,000 Ash Handling 620,000 Coal Handling 1,220,000 Site Preparation and Substructure 2,370,000 Structural Steel and Building Enclosure 4,460,000 Building and Site Finishes 1,100,000 Piping and Mechanical Equipment 2,600,000 Major Electrical Equipment 570,000 Station Wiring 2,420,000 Painting 30,000 District Heating 1,990,000 Total Construction $26,430,000 Engineering and Contingency 3,960,000 Escalation 2,130,000 Total Project $32,520,000 ALS (A TT eT NT a 10.5 MW POWER PLANT CITY OF NOME COST ESTIMATE SST NG TR Se Ge ES Steam Generators S$ 4,430,000 Turbine-Generator 3,120,000 Deaerator 70,000 Boiler Feed Pumps 170,000 Air Cooled Condenser 2,190,000 Water Treatment 60,000 Instruments and Controls 1,250,000 Ash Handling 620,000 Coal Handling 1,080,000 Site Preparation and Substructure 2,790,000 Structural Steel and Building Enclosure 5,160,000 Building and Site Finishes 1,100,000 Piping and Mechanical Equipment 2,690,000 Major Electrical Equipment 500,000 Station Wiring 2,400,000 Painting 50,000 District Heating 4,200,000 Total Construction $31,880,000 Engineering and Contingency 4,780,000 Escalation 2,560,000 Total Project $39,120,000 4 - 14 (FeO CY RTA A NMR tN SE SEY OR 16.5 MW POWER PLANT RED DOG MINE COST ESTIMATE i a Ae SR RA CPI Steam Generators Ses 7/5 0/1000 Turbine-Generator 4,900,000 Deaerator 150,000 Boiler Feed Pumps 250,000 Air Cooled Condenser 3,010,000 Water Treatment 80,000 Instruments and Controls 1,500,000 Ash Handling 700,000 Coal Handling 1,400,000 Site Preparation and Substructure 5,800,000 Structural Steel and Building Enclosure 8,330,000 Building and Site Finishes 1,270,000 Piping and Mechanical Equipment 3,820,000 Major Electrical Equipment 900,000 Station Wiring 2,860,000 Painting 80,000 District Heating 1,170,000 Total Construction $ 49,970,000 Engineering and Contingency 7,500,000 Escalation 4,020,000 Total Project $ 61,490,000 4- 15 yorttwccs EN AEA SEPT E S E 22 MW POWER PLANT DEADFALL SYNCLINE COAL MINE COST ESTIMATE | EE aa AIRE CT a Sn AIT Steam Generators Sus; Turbine-Generator 5, Deaerator Boiler Feed Pumps Air Cooled Condenser Sy Water Treatment Instruments and Controls iy Ash Handling Coal Handling 1, Site Preparation and Substructure l, Structural Steel and Building Enclosure 4, Building and Site Finishes lv Piping and Mechanical Equipment 37 Major Electrical Equipment 1, Station Wiring Si Painting Overhead Circuits 14, Total Construction S156), Engineering and Contingency 8, Escalation 4, Total Project $ 70, Ao 750,000 060,000 150,000 250,000 080,000 80,000 500,000 700,000 400,000 790,000 000,000 270,000 590,000 930,000 510,000 80,000 850,000 990,000 550,000 590,000 130,000 pewees 5.0 CONCLUSIONS On the basis of use of a conventional Rankine cycle for power generation, a technology assessment was performed based upon the potential of utilizing Alaskan coal for power generation. Technology selection is based primarily on the environmental requirements and that the Clean Air Act amendments of 1990 do not apply to Alaska. Review of environmental aspects indicate that there is minimal potential for sulfur dioxide scrubbing requirements at Nome and Kotzebue. The mine sites will require scrubbing. Other environmental requirements can be met with proper equipment selection. Review of the fuel indicates that essentially any coal burning technology would be suitable. This includes stoker firing, pulverized coal firing, fluid bed firing. The least costly method is stoker firing. If scrubbing is required at Nome and Kotzebue, consideration should be given to fluid bed boilers. Stoker firing provides good reliability and simple operation. Review of various methods for the condensing portion of the cycle has resulted in the selection of air cooled condensers. The primary reason is the shortage of water in the areas of study. Projections of Nome plant loads indicate a need to meet an electrical load of 9.5 MW and 40,716 MWH in the year 2004. This would require 28,100 tons of coal per year. A first phase of district heating would displace approximately 126,000 gallons of fuel oil on a year basis and additional phases can be added as required. At Kotzebue, it is estimated that electrical needs will be 5.2 MW and 26,345 MWH in the year 2004, requiring 18,100 tons of coal yearly. The first phase of district heating would displace 214,000 gallons of fuel oil a year. Placing a power plant at the Red Dog Mine would require a need to meet maximum plant load which is estimated to be 15 MW plus heating requirements of the plant. Should the power plant be placed at the Deadfall Syncline Mine, with transmission to Red Dog, an additional 500 KW is required due to line losses plus additional electrical generation for heating of the Red Dog Mine, assumed to be converted to electric heat. This would require approximately 22 MW of electrical production. Either plant requires 87,000 tons of coal per year. Estimates have been prepared for each of the four (4) potential power plant sites. Total costs for each of the sites is as follows, including escalation through 1993: @ City of Kotzebue, 5.7 MW Plant $32,520,000 @ City of Nome, 10.5 MW Plant $39,120,000 @ Red Dog Mine, 16.5 MW Plant $61,490,000 @ Deadfall Syncline Mine, 22 MW Plant $70,130,000 The estimates have been prepared based upon solicitation of quotations for major pieces of equipment. Other portions of the estimate were developed by SFT, Inc. based upon prior experience and the arrangement drawings prepared for each of the plants. Plant construction scheduling is based primarily upon the procurement, fabrication, shipment, and construction of the boilers. It is estimated that the overall construction schedule will be 24 - 30 months, the shorter schedule applying to two (2) smaller plants and the longer schedule applying to the mine sites. = we Kee. Plant staffing has also been determined. It will be necessary to have 22 persons on staff to operate the plant during all shifts. APPENDIX SS cron XO i aaa a A HEE fn CH ( , Pet Vy VN TT . / f ee TE Obst on --4 r fo HH ly lool ¥ LIL. Sil | Pe est rl tu F aes 7 4g (yy \uy , we PLAN VIEW Sawer © ARCTIC SLOPE CONSULTING GROUP é pensar ARCTIC SLOPE CONSULTING GROUP sastarion cr) ARCTIC SLOPE CONSULTING GROUP a. Sates = ea ge ic ooo nnn [go Peg Fee a Sree oe] fea eats Poot] [es PLAN. - , 2UUTH ruanr L 20UTH ra anon GEN. GEN. GEN. GEN. SIRSTATION. FOR. NO.8 NO.7 HOUSE NO.6 NO.9 NO.3 BOOKW 1135KW SERVICE 2500KW 1700KW 12.47/4. 16xy 3O00KVA 12-47KV 42004 BUS 12.47/74. 16KV SOOOKVA 4.16KV FOR. NO.1 NO.2 NO.4 12.47/4.16KV AN ALTERNATE ARRANGEMENT WOULD BE TO HAVE 4.16KV BUS 5 THE NEW GENERATOR RATED 12.47KV WHICH WOULD 4.16KV/480V 5.7MW LEGEND EXISTING ——— PROPOSED mi fc : TURBINE AUX. ue NOTICE! The rowing ond of Information sen omic reza a tained thereon le confidential ond propristery PSteced te SFT, ing, R sonnet be copies or reproduaes | CH’ KEY Smtewrend {4-8-9 without the express written permission of ONN9OSBOON\EMO) BASE SCALE: * TWO (2) 4.16KV CIRCUITS CONNECTED TO NOME'S DISTRIBUTION SYSTEM OR DEDICATED CIRCUITS TO NOME’S EXISTING POWER PLANT. | ‘ | | 4.16KV BUS | 4. 16KV/480V | 5. 7MW 480V SWGR. BUS | LARGE 480V AUX. COAL_HDLG. M.C.C. BOILER AUX. M.C.C. TURBINE AUX. M.C.C. ARCTIC SLOPE CONSULTING GROUP “Torysiont—- NOTICE: Tnia crowing ona off Informotion con- teined thereon is confidentio! ond proprietory SFT, inc. it conmet be copied or reproduced Rout the express written permission of = Ty ime. SINGLE LINE DIAGRAM errepaee0 08-21 NOME ALASKA GENERATION fereoeJ¥—&404-0B-31 PROJ./CONTRACT NO.| ORAWING NO. 3058-00-00 905800-ERP—-002 D\SOS800\EMOS _ L SFT, Inc. Consulting Engineers f : 1 1 ' ' L G {ov GEN. FUTURE NO.1 NO.2 GEN. NO.3 SMW SMW SMW LEGEND —— EXISTING PROPOSED 4.16KV» 3000A» 250MVA BUS 4.16KV BUS 4.16 AUX. Ay a Beg eet oo aaa ae bdab ak _ 13.8/4.16KV 12/16/20MVA FOR. STATION FOR. FDR. GROUNDING SERVICE TRANSFORMER 16.5MW 4. 16KV/480V METS 480V SWGR. BUS \ wet r LARGE 480V AUX. re) COAL HOLG. M.C.C. mf BOILER AUX. wee a to''arr. wes NR connet be soplen wr renreauacs [Ot Koy seterent]04 Ot witneut the express written permission of re Led O09 -RED DOG MINE GENERATION alien [are 0k xB RKO 9 ; oe _| PROJ. /CONTRACT NO. ORAWING NO. GFD 3058-00-00 | 905800-ERP-003 DiyS05800\E MOR BASE SCALE: a