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The geothermal potential of Clarke Lake and Milo gas fields in northeast British Columbia Arianpoo, Nastaran 2009

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  THE GEOTHERMAL POTENTIAL OF CLARKE LAKE AND MILO GAS FIELDS IN NORTHEAST BRITISH COLUMBIA by Nastaran Arianpoo A THESIS SUBMITTED IN PARTIAL FULFILMENT OF THE REQUIRMENT FOR THE DEGREE OF  MASTER OF APPLIED SCIENCE  in The Faculty of Graduate Studies  (Mining Engineering)  THE UNIVERSITY OF BRITISH COLUMBIA (Vancouver)  August 2009  © Nastaran Arianpoo, 2009  ii Abstract The increasing consumption of energy and its side-effects on the environment are driving an international effort to enhance the use of more environmentally-friendly energy resources such as geothermal energy which this research addresses. The work has involved an analysis of data provided by the B.C. Ministry of Energy, Mines and Petroleum Resources collected from oil and gas wells drilled in the Northeast region of British Columbia for the purpose of evaluating the potential to exploit geothermal energy in the region. The study area was narrowed to two gas fields near Fort Nelson – Clarke Lake and Milo. The objectives of the project have been 1. to investigate the geothermal potential of the area; and, 2. to examine if non-geothermal wells could be used to recover geothermal energy; Using data gathered from the gas well log records, temperature gradient and heat flow maps were successfully generated for the study area using ArcGIS. A preliminary reservoir assessment has been done based on these maps. The results show the region has notably high potential for a deep geothermal project using Enhanced Geothermal System (EGS) methodologies to produce significant amounts of electrical energy for a very long time in a sustainable fashion. It is recommended that additional exploration and exploitation drilling should be done at Clarke Lake to verify the conclusions and strengthen the assumptions about suitable local rock permeability and fluid availability at depth. With respect to geothermal energy production from spent oil and gas wells, there is currently insufficient temperature and fluid flow to either recover heat for a district heating system in the nearby community of Fort Nelson or to generate electricity using a Binary Cycle process. The quantity of heat is too low to be an economically viable  iii investment while the temperature is too low at the current gas plants to technically generate power. The research has demonstrated that data from drilled oil and gas wells when studied can be used with confidence to evaluate the geothermal potential of a region and should be applied to other locations in British Columbia and elsewhere to produce similar temperature gradient and heat flow maps.    iv Table of Contents  Abstract ............................................................................................................................ii Table of Contents ............................................................................................................iv List of Tables .................................................................................................................. vii List of Figures ................................................................................................................ viii List of Nomenclature ....................................................................................................... x List of Symbols ............................................................................................................... xii List of Units ................................................................................................................... xiii Acknowledgments ..........................................................................................................xv 1 Introduction ........................................................................................................ 1 1.1 Problem Statement and Justification ............................................................... 1 1.2 Objectives ....................................................................................................... 2 1.3 Thesis Outline ................................................................................................. 3 2 Geothermal Energy ............................................................................................ 4 2.1 Direct Use ....................................................................................................... 6 2.2 Electricity Generation ...................................................................................... 9 2.3 Enhanced Geothermal Systems (EGS) ........................................................ 15 2.4 Case Studies ................................................................................................ 16 2.4.1 Chena Geothermal Project ........................................................................... 17 2.4.2 The Soultz-Sous-Forets Geothermal Project ............................................. 19 2.5 Geothermal Energy: Advantages and Disadvantages .................................. 23 2.6 Comparison of Geothermal Energy with other Renewable Energies ............ 25 2.7 Geothermal Energy Status in Canada .......................................................... 28 3 Area of Study ................................................................................................... 30 3.1 Fort Nelson ................................................................................................... 32  v 4 Methods and Procedures ................................................................................. 34 4.1 Data Assembling ........................................................................................... 36 4.2 Geophysical Techniques ............................................................................... 36 4.2.1 Thermal Methods .......................................................................................... 37 4.3 Geographical Information System (GIS) ....................................................... 39 4.3.1 ArcGIS Software ........................................................................................... 39 4.3.2 Inverse Distance Weighted Method (IDW) .................................................... 42 5 Results ............................................................................................................. 43 5.1 Temperature Gradient Map ........................................................................... 43 5.2 Estimated Temperature Maps at Different Depths ........................................ 46 5.3 Heat Flow Map .............................................................................................. 50 5.3.1 Thermal Conductivity .................................................................................... 50 5.3.2 Heat Flow ...................................................................................................... 52 5.4 Geothermometry ........................................................................................... 54 6 Discussion ........................................................................................................ 59 6.1 Clarke Lake Temperature Gradient Map ....................................................... 59 6.2 Recovery of Geothermal Energy from Existing Gas Wells ............................ 61 6.2.1 Clarke Lake Central Facilities (CLK LK Central) ........................................... 64 6.2.2 Archer Central Facilities............................................................................. 68 6.2.3 Possible Applications .................................................................................... 69 6.3 Hydrothermal Reservoir ................................................................................ 71 6.4 EGS Technology ........................................................................................... 73 6.4.1 Resource Assessment .................................................................................. 74 6.4.2 Managing the Resource............................................................................. 82  vi 6.5 Clarke Lake vs. Milo ...................................................................................... 83 7 Conclusion ....................................................................................................... 86 8 Recommendations ........................................................................................... 88 References .................................................................................................................... 89 Appendix 1 – Data from the Wells ................................................................................. 96 Appendix 2 – Average Water Flow Rate from Producing Wells .................................. 100 Appendix 3 – Cash Flow Analysis of a District Heating System at Clarke Lake .......... 102 Appendix 4 – Estimated Temperature Maps - Reservoir Assessment ........................ 103 Appendix 5 – Cash Flow Analysis of a Managed Resource Strategy at Clarke Lake .. 105 Appendix 6 – Idealized Drilling Pattern........................................................................ 107    vii List of Tables Table 2-1: Leading direct-use countries –in 2005. .......................................................... 7 Table 2-2: Summary of various World geothermal direct use applications in 2005. ........ 8 Table 2-3: World installed geothermal power capacity (MW), 1950-2007 ..................... 14 Table 2-4- General economic information about the Soultz geothermal project ............ 22 Table 2-5- Investment information about the Soultz geothermal project. ...................... 23 Table 2-6- Status of electricity production from renewable energy sources .................. 26 Table 2-7- Status of direct heat production from renewable energy sources ................ 27 Table 2-8- Technical potential of renewable energy sources ........................................ 27 Table 2-9- Geothermal energy status in Canada in 2005. ............................................. 29 Table 3-1: History of Fort Nelson electric power supply ................................................ 32 Table 5-1: Clarke Lake- geothermometry data and results. .......................................... 55 Table 5-2: Milo- geothermometry calculation ................................................................ 57 Table 6-1: SCADA snapshot, CLK LK Central, NE B.C................................................. 65 Table 6-2: The average of water flow rate connected to CLK LK Central, NE B.C. ....... 67 Table 6-3: SCADA snapshot, Archer Central Facilities, NE B.C. .................................. 68 Table 6-4: Average water flow rate from producing gas wells ....................................... 69 Table 6-5: Preliminary reservoir assessment, Clarke Lake gas field, B.C., Canada ..... 78 Table 6-6: Preliminary reservoir assessment, Milo gas field, B.C., Canada .................. 79 Table 6-7: EGS project, Clarke Lake, B.C. vs. Paralana, South Australia ..................... 82 Table 6-8: Comparison of Clarke Lake and Milo geothermal potential. ......................... 84    viii List of Figures Figure 2-1: Ring of fire ..................................................................................................... 5 Figure 2-2: Geothermal temperature intervals ................................................................. 6 Figure 2-3: Worldwide installed capacity of direct geothermal use in 2005. .................... 8 Figure 2-4: Flash steam power plant ............................................................................. 10 Figure 2-5: Dry steam power plant ................................................................................ 11 Figure 2-6: Binary cycle power plant ............................................................................. 12 Figure 2-7: Worldwide installed geothermal power capacity, 1950-2007 ...................... 13 Figure 2-8: Hot Dry Rock (HDR) system ....................................................................... 15 Figure 2-9: Geothermal site of Soultz, France - highest thermal ................................... 20 Figure 2-10: Temperature gradient, Soultz project, France ........................................... 21 Figure 3-1: Peace area- northeast British Columbia, Canada ....................................... 31 Figure 3-2: Possible load growth scenarios for Fort Nelson .......................................... 33 Figure 4-1: Thesis methodology .................................................................................... 35 Figure 4-2: Graphic information linked to an attribute table (descriptive information) .... 40 Figure 4-3: Representation of different types of layers in a GIS system ....................... 41 Figure 5-1: Distribution model of temperature gradient (°C/km), Clarke Lake ............... 44 Figure 5-2: Distribution model of temperature gradient (°C/km),Milo ............................ 45 Figure 5-3: Estimated temperature at 1000m, Clarke Lake gas field, B.C., Canada ..... 46 Figure 5-4: Estimated temperature at 1500m, Clarke Lake gas field, B.C., Canada ..... 47 Figure 5-5: Estimated temperature at 2000m, Clarke Lake gas field, B.C., Canada ..... 47 Figure 5-6: Estimated temperature at 2500m, Clarke Lake, B.C., Canada ................... 48 Figure 5-7: Estimated temperature at 1000m, Milo gas field, B.C., Canada .................. 48 Figure 5-8: Estimated temperature at 1500m, Milo gas field, B.C., Canada .................. 49 Figure 5-9: Estimated temperature at 2000m, Milo gas field, B.C., Canada .................. 49 Figure 5-10: Estimated temperature at 2500m, Milo gas field, B.C., Canada ................ 50 Figure 5-11: Buckinghorse formation-94J, north-eastern B.C., Canada ........................ 51 Figure 5-12: Distribution of heat flow (mW/m2), Clarke Lake gas field, B.C., Canada .. 52 Figure 5-13: Distribution of heat flow (mW/m2), Milo gas field, B.C., Canada ............... 53  ix Figure 5-14: Fournier Na/K geothermometry equation .................................................. 55 Figure 5-15: Comparison of estimated temperature by geothermometry, CLK LK ........ 56 Figure 5-16: Comparison of estimated temperature by geothermometry, Milo. ............. 58 Figure 6-1: Slave Point reef edge, Clarke Lake gas field, B.C., Canada ....................... 60 Figure 6-2: Water production in WCSB, ........................................................................ 62 Figure 6-3: Central facilities at Clarke Lake gas field, B.C., Canada ............................. 63 Figure 6-4: Meter-Run building, Clarke Lake gas field, NE B.C., Canada ..................... 66 Figure 6-5: Buried pipeline temperature loss versus flow rate (after Ryan, 1981) ......... 71 Figure 6-6:  Temperature zones at depth 4.5 km- Clarke Lake ..................................... 75 Figure 6-7: Quantity of heat capacity with depth at Clarke Lake. .................................. 76 Figure 6-8: Quality of heat capacity with depth, Clarke Lake ........................................ 76 Figure 6-9: An increasing trend of temperature with depth, Clarke Lake gas field, ....... 85 Figure 6-10: An increasing trend of temperature with depth, Milo gas field. .................. 85    x List of Nomenclature AC: Asbestos-cement AESO: Alberta Electric System Operator BC-MEMPR: BC Ministry of Energy, Mines and Petroleum Resources BHT: Bottom-hole Temperature CLK LK Central: Clarke Lake Central Facilities DI: Ductile Iron DOE: U.S Department Of Energy EGS: Enhanced Geothermal System or/and Engineering Geothermal System ERDA: U.S Energy Research and Development Administration FNG station: Fort Nelson Generating Station FRP: Fibreglass Reinforced Plastic GES: Geothermal Energy System GHGs: Greenhouse Gases GIS: Geographical Information System HDR: Hot Dry Rock HDRec: Hot Dry Rock economics IDW: Inverse Distance Weighted NE B.C.: northeast British Columbia ORC: Organic Rankine Cycle PVC: Polyvinyl Chloride S: Steel SCADA: Supervisory Control and Data Acquisition  xi TVD: True Vertical Depth MD: Measured depth UTC: United Technologies Corporation WCSB: Western Canadian Sedimentary Basin    xii List of Symbols ∆Q: Heat flow (kW or joule/s) K: Thermal conductivity (W/m°C) A: Area (m2) (T: Temperature gradient (°C/km). T: temperature (°C or K) m: water mass Cp: specific heat capacity ∆T: Temperature difference (°C or K)   xiii List of Units EJ: Exajoule gpm: gallons per minute GWh/yr: Gigawatt hour per year GWh: Gigawatt hour K: Kelvin _ temperature unit kg/m3: kilogram per cubic meter kJ/kg.K: kilo Joule per kilogram per Kelvin kWe: kilowatt electrical energy km: kilometre km2:  Square kilometre kPa: kilo Pascal L/s: litter per second m: meter m2:  Square meter mg/L: milligram per litter MW: Megawatt MWt: Megawatt thermal energy mWe: milliwatt electrical energy mWt: milliwatt thermal energy mW/m2: milliwatt per square meter PJ: Petajoule t: temperature  xiv TWh: Terawatt hour W/m°C: watt per meter per Celsius W/m.K: Watt per meter per Kelvin €: Euros €/kWh: Euros per killowatt hour €/kWe: Euros per kilowatt electrical energy °C: Celsius _ temperature unit ₵/kWh: cent per kilowatt hour $: dollar $/kW: dollar per kilowatt °C/km: Celsius per kilometre        xv Acknowledgments I would like to acknowledge those who provided financial, technical and personal support throughout my study. I would like to thank BC Ministry of Energy, Mines, and Petroleum Resources (especially Mr. Warren Walsh and Mrs. Cassandra Lee), Canadian Geothermal Energy Association (especially Craig Dunn), and MITACS. Further in appreciation of scholarship award, I would like to acknowledge the trust of International Partial Tuition Scholarship at UBC. The project required significant technical input, and in this I would like to acknowledge Dr. John A. Meech and Dr. Mory Ghomshei for their invaluable mentoring and technical input in this study as well as providing a great deal of assistance and support when it was needed, for spending many hours discussing the progress of the project and report writing, assistance where their expertise was required and reviewing the many revisions of this work. Thanks are due to Mr. Nevin Weist, a Reservoir Engineer for Petro-Canada Oil and Gas looking after the Clarke Lake Field for providing precise data from the site. Last but not least, thanks to my dearest parents, my charming sister, and my kind brother in law who always are there when I need them, for their patience and encouragement. Without them, I would never have gotten this far.       1 1 Introduction Population and industrial growth are major factors behind the increasingly higher demand for different types of energy in the world today. As energy consumption has increased, significant side-effect problems have been created that Society must deal with if the climate and environment that we know today is to be sustained. Combustion of the current important energy sources (coal, oil, and natural gas) emits greenhouse gases (GHGs) into the atmosphere. Climate change (global warming) and microclimatic effects on weather, nature, and human health are driving an international effort to replace these polluting energy sources with more environmentally-friendly resources such as geothermal, biomass, wind, wave, and solar energies. From among these clean renewable resources, this thesis will address geothermal energy – specifically the generation of such energy in the northeastern region of the province of British Columbia in Canada. 1.1 Problem Statement and Justification The aim of this research is to examine the potential for geothermal energy resources to be brought on-stream from a region in British Columbia that would not normally be considered viable for this type of energy – northeast B.C. Early work by Garland and Lennox (1962) and Anglin and Beck (1965) discovered a large thermal anomaly in the Western Canadian Sedimentary Basin extending from the Rocky Mountain foothills in the west to the edge of the Canadian Shield in the east and from northeastern B.C. to Norman Wells in the north. In later studies, Majorowicz and Jessop (1981; 2005) and Majorowicz (1996) showed the existence of high heat flows in northeast B.C. and northwest Alberta, but temperature gradient and heat flow maps were not created. To constrain the study location, other factors related to successful geothermal development were taken into account: proximity to demand and the availability of power distribution facilities narrowed the study to wells near communities  2 and transmission lines. With these criteria in mind, the Clarke Lake and Milo gas fields located near Fort Nelson in northeast B.C. were selected for analysis. The aims of the study were to address two main subjects as following: 1. To investigate if geothermal energy potential exists in the area; 2. To investigate the possibility of using hot water ascending to surface within producing gas wells as a geothermal energy source since this would reduce or eliminate drilling costs associated with conventional geothermal energy exploration and development.  1.2 Objectives The main objective of this thesis is to determine if geothermal energy potential exists in the study area by producing temperature gradient maps from the existing oil and gas well data. Geothermal maps of B.C. (Geological Survey of Canada & Ministry of Energy, Mines and Petroleum Resources, 1991) provide information about hot springs and heat flow data from boreholes drilled for the purpose of geothermal exploration. Until now, few studies have included oil and gas well data. B.C. government databases containing information from over 20,000 oil and gas wells in northeastern B.C. were obtained. The data proved suitable to screen thermal and geological information to create temperature gradient maps and perform a preliminary evaluation of geothermal potential at both Clarke Lake and Milo gas fields. The evaluation was extended to establish a preliminary economic assessment of an Enhanced Geothermal System at Clarke Lake. The second objective of the study was to determine if it was possible to use already drilled gas wells to extract geothermal energy. Since the hot water beneath the gas reservoir ascends to surface during exploitation, it was considered that an opportunity might exist to use it for direct heat use or power generation. Both Clarke Lake and Milo  3 gas fields can be categorized as moderate-temperature geothermal reservoirs potentially suitable for generation of electricity using Binary Cycle technology. This goal involved assembling and analyzing data from wellhead records on water flow rate, water chemistry, fluid thermal data, pipeline distribution networks, nearby sizable communities (demand), and infrastructure facilities (electrical distribution). 1.3 Thesis Outline Chapter Two provides a background review of geothermal energy applications. It presents two case studies, discusses the advantages and disadvantages of GES, compares renewable energies, and gives the status of GES in Canada. Chapter Three describes the study area consisting of two gas fields, Clarke Lake and Milo, located in north-east B.C. The reasons for choosing this region relate to the existence of prior studies and data, the close proximity to demand, and the presence of a nearby power distribution system. Chapter Four describes the methods and procedures used. To establish regional ground temperature profiles, estimates of temperature gradient, thermal conductivity of bedrock in the area, and regional heat flow conditions have been made. Chapter Five brings together the project outcomes. The main products of this work include temperature gradient and heat flow maps produced using the ArcGIS software product. These maps are essential tools for preliminary assessment of the reservoir potential for geothermal purposes. Two possible outcomes are presented in Chapter Six – an analysis of geothermal energy potential in the area and the possibility of using existing gas wells to extract geothermal energy. Chapter Seven concludes the thesis by listing the key results while Chapter Eight presents recommendations for future work. The Appendices contains all data and analysis details used in this study.  4 2 Geothermal Energy The term "geothermal" derives from the Greek words, geo meaning earth and thermal meaning heat. The main purpose of a geothermal energy system (GES) is to use the heat within the earth as a source of energy. Geothermal energy is an enormous base- load source of heat and power which is clean, reliable, and locally-available here in British Columbia. Volcanoes, hot springs, geysers, and other geothermal phenomena have led mankind to the fact that interior parts of the Earth are hot. However the first documented understanding that the Earth's temperature increases with depth dates back to the sixteenth century when underground mines began to be dug to depths of several hundred meters. In 1740, the first interior temperature measurements were taken in a mine near Belfort, France (Dickson & Fanelli, 2005, c2003). Geothermal reservoirs are formed when rising hot water or steam is trapped in permeable and porous rocks under a layer of impermeable rock. A geothermal reservoir is defined by the existence of adequate temperature, rock permeability, and fluid (steam or water) as a heat carrier. Studies (Duchane, 1996; Fridleifsson, 1996) show that the temperature of the Earth‟s crust changes on average of about 20 to 30°C for each kilometer beneath the surface. Geothermal anomalies (or reservoirs) are regions in which the rate of change in the temperature with the depth (temperature gradient) is higher than this average (Dickson & Fanelli, 2005, c2003). Such anomalies are mainly found along the tectonic plate boundaries characterized by young volcanism, seismic activity, and magmatic activity (Dickson & Fanelli, 2005, c2003; Fridleifsson, 1996; Gupta & Roy, 2007).  Many of the world's earthquakes and volcanic eruptions occur along a zone called the Pacific Ring of Fire along the coastline of the Pacific Ocean (Figure 2-1) (Decker & Decker, c1998).  Large sections of this rim consist of continuous series of volcanic arcs, plate movements, and oceanic trenches that provide significant geothermal anomalies in coastal regions of the Pacific Ocean.  5  Figure 2-1: Ring of fire (U.S. Geological Survey, 2005) Exploitation methods differ for different reservoirs depending on resource temperature and other variables. In addition to direct heat use, it is possible to convert some of the heat into electricity. There is no distinct boundary between the ranges of the quality characteristics known as low, moderate and high temperature with significant overlap existing between the adjacent terms (Figure 2-2). The thermal quality boundary for any particular site is, in fact, controlled by economic and technological factors. From ancient times, hot waters from geothermal reservoirs that reach the surface have been used for bathing, cooking, and agricultural support. It is unclear when the first direct use of geothermal heat took place, but numerous examples of First Nations and Aboriginal Peoples exploiting these resources exist in their culture. The first attempt to generate electricity occurred in Italy in 1904, when Prince Piero G. Conti built a small geothermal generation plant that lit 4 light bulbs (Armstead, c1983).  6  Figure 2-2: Geothermal temperature intervals (After Meech and Ghomshei, 2007) 2.1 Direct Use With direct use, the hot fluid extracted from a reservoir is used directly for heating and cooling without converting to another type of energy such as electricity. Low to medium temperature (~50-150°C) fluids can be used for direct use applications. Below about 30°C, a heat pump1 can be used to boost the temperature for heating use. Due to the availability of shallow low-temperature ground water almost everywhere in the world, geothermal heat pump technology is more widely used than the other forms of geothermal energy (Dickson & Fanelli, 2005).  Direct use of geothermal energy and low- temperature heat pump technologies provide heat for industrial, residential, and commercial use such as space heating, greenhouse heating, aquaculture pond heating, agricultural drying, bathing and swimming, etc. In 2005 (Lund, Freeston, & Boyd, 2005) the estimated worldwide capacity of direct geothermal use amounted to 28,268 MWt with an annual geothermal energy production of 76,698 GWh/yr indicating a capacity  1  A heat pump is a compression/decompression device used to extract heat from fluid at a relatively low temperature and transfer it to a second fluid at a higher temperature (example: a refrigerator).  7 factor of around 31%. In fact, the true capacity factor of direct use geothermal energy is of the order of 90% suggesting that 3 times this amount of energy could be made available from existing installations if convenient and steady nearby demand existed. The above data are from 72 countries as collected by the World Geothermal Congresses of 1995 (Freeston, 1996), 2000 (Lund & Freeston, 2001) and 2005 (Lund, 2005). The leading countries exploiting direct use are listed in Table 2-1. Note that the top-ten countries are responsible for nearly 75% of the total reported for all countries. Table 2-1: Leading direct-use countries –in 2005. Country Direct-use (GWh/yr) Installed Capacity (MWt) Capacity Factor Principal Use China 12,605 3,687 0.39 Bathing Sweden 10,000 3,840 0.30 Heat Pumps United States 8,678 7,817 0.13 Heat Pumps Turkey 6,900 1,495 0.53 Bathing/Heating Iceland 6,806 1,844 0.42 District Heating Japan 2,862 822 0.40 Bathing Italy 2,098 607 0.39 Bathing/Spas Hungary 2,206 694 0.36 Bathing/Spas New Zealand 1,968 308 0.73 Industrial Brazil 1,840 360 0.58 Bathing/Spas Source:  (Lund, 2005)  The required temperature for space heating is generally below 80°C and above 50°C, while temperatures as low as 4°C can be used with heat pumps to provide sufficient temperature for heat use (Figure 2-2). Figure 2-3 shows the major direct-use applications. Heat pump technology dominates these applications with 32% of the total  8 installed capacity. Balneology and space heating are second and third respectively with 30% and 20%.  Figure 2-3: Worldwide installed capacity of direct geothermal use in 2005. (Lund, 2005) Table 2-2: Summary of various World geothermal direct use applications in 2005. Application Capacity (MWt) Energy utilization (GWh/yr) Capacity Factor Geothermal heat pump 15,384 24,308 0.18 Space heating   4,366 15,350 0.40 Greenhouse heating   1,404   5,740 0.47 Aquaculture pond heating      616   3,050 0.57 Agriculture drying      157      559 0.41 Industrial uses      484   3,019 0.71 Bathing and swimming   5,401 23,062 0.49 Cooling/Snow melting      371      565 0.18 Others        86   1,045 0.39 TOTAL 28,268 76,698 0.58 Source: (Lund, 2005)  9 To better compare the various direct use applications, the amount of energy used should be considered as well as the installed capacity. The capacity factor indicates the ratio of energy production to the maximum possible annual production. Table 2-2 shows this capacity factor. Higher factors indicate more continuous use of the energy. As can be seen, geothermal heat pump applications have the highest installed capacity, but the lowest capacity factor mainly because of their seasonal use dependency. 2.2 Electricity Generation There are three kinds of geothermal power plants used to convert heat energy from a hydrothermal fluid into electricity:  Dry steam,  Flash steam, and  Binary cycle. The method chosen depends on two criteria: the reservoir temperature and the type of the geothermal fluid (either water or steam). A vapour is required to run turbines in all types of power plants. Flash steam and dry steam technologies are reserved for high- temperature reservoirs (more than ~180°C), while the binary cycle method is used with those reservoirs that possess a moderate-temperature (the current lowest temperature exploited  is about 74°C) (Armstead, c1983; Dickson & Fanelli, 2005, c2003). With Flash steam technology (Figure 2-4), high pressure hot water (brine) is allowed to flow in a controlled fashion to surface where the pressure is suddenly reduced. Consequently part of the fluid flashes to steam which then runs the steam turbine. The remaining geothermal water is pumped back to the reservoir, generally after water treatment to deal with metallic precipitates. The Coso geothermal field, located in east central California, is an example of a flash steam operation (Monastero, 2002).  10 Dry steam reservoirs are dominated with dry saturated steam at pressures well above atmospheric. The steam from the reservoir ascends to the surface through a production well and is routed directly through a turbine unit to generate electricity (Figure 2-5). The Geysers region, north of San Francisco, California is an example of a dry steam generation operation (Barton, 1973).  Figure 2-4: Flash steam power plant (After DOE, 2009; Idaho National Laboratory, 2009) When the temperature of the geothermal fluid is below its boiling point, the required vapour can be obtained by evaporating a second fluid with a lower boiling point. This is known as a binary-cycle power plant. In this method, heat from the geothermal fluid (water) is used to vaporize the second fluid. Hot geothermal water passes through a heat exchanger in one direction with the secondary fluid flowing in the opposite direction in a separate loop.  11  Figure 2-5: Dry steam power plant (After DOE, 2009; Idaho National Laboratory, 2009) The heat extracted in the heat exchanger converts the second fluid to a vapour. The vapour then drives a gas turbine (Figure 2-6); the condensed fluid is returned to the heat exchanger in a closed loop fashion. The geothermal water is reinjected into the reservoir. Since the processes are all closed-loop, no fluids or pollutants are emitted. As well, the geothermal water is never exposed to the generating turbine or associated equipment. The most important issue is the amount of electrical energy that can be generated from the reservoir water. Examples of binary cycle power plants are the Chena Hot Springs Resort in Alaska (Erkan et al., 2008b) and the Casa Diablo geothermal field in California (Spielman, 1990).  12   Figure 2-6: Binary cycle power plant (After DOE, 2009; Idaho National Laboratory, 2009) The first geothermal power plant was a dry-steam operation installed with a capacity of 250 kWe at Larderella, Italy, 1913 (Armstead, c1983). In 2007, the world installed geothermal power capacity was more than 9,960 MWe. Figure 2-7 shows the increasing rate of geothermal power installation from 1950 to 2007 (Dorn, 2009). While the rate of increase is impressive at about 3-4% annually since 1990, in comparison with other alternative sources of energy, geothermal power generation plays a small role in the world energy market.     13 The total geothermal power generation reported for 24 countries was 8,933 MWe in 2005 (Table 2-3).This amount is equal to 10 to 15 nuclear or large thermal-coal power stations (Heinloth, 2006). The top five countries generating geothermal electricity in 2005 are USA, Philippines, Mexico, Indonesia, and Italy (Dorn, 2009; Heinloth, 2006).  Figure 2-7: Worldwide installed geothermal power capacity, 1950-2007 (Earth Policy Institute, 2008)    14 Table 2-3: World installed geothermal power capacity (MW), 1950-2007 Country 1995 2000 2005 2007 1 Australia 0.2 0.2 0.2 0.2 Austria 0.0 0.0 1.1 1.1 China 28.8 29.2 27.8 27.8 Costa Rica 55.0 142.5 163.0 162.5 El Salvador 105.0 161.0 151.0 204.2 Ethiopia 0.0 7.3 7.3 7.3 France 4.2 4.2 14.7 14.7 Germany 0.0 0.0 0.2 8.4 Guatemala 33.4 33.4 33.0 53.0 Iceland 50.0 170.0 202.0 421.2 Indonesia 309.8 589.5 797.0 992.0 Italy 631.7 785.0 791.0 810.5 Japan 413.7 546.9 535.0 535.2 Kenya 45.0 45.0 129.0 128.8 Mexico 753.0 755.0 953.0 953.0 New Zealand 286.0 437.0 435.0 471.6 Nicaragua 70.0 70.0 77.0 87.4 Papua New Guinea 0.0 0.0 6.0 56.0 Philippines 1,227.0 1,909.0 1,930.0 1,969.7 Portugal 5.0 16.0 16.0 23.0 Russia 11.0 23.0 79.0 79.0 Thailand 0.3 0.3 0.3 0.3 Turkey 20.4 20.4 20.0 38.0 United States 2,816.7 2,228.0 2,564.0 2,923.5 World Total 6,866.1 7,972.9 8,932.6 9,968.4 1 Estimate. Source: Compiled by Earth Policy Institute (www.earth- policy.org/Updates/2008/Update74_data.htm) with 1995 from International Geothermal Association, "Installed Generating Capacity," at http://iga.igg.cnr.it/geoworld/geoworld.php?sub=elAgen, updated 29 July 2008; 2000, 2005, and 2007 from Ruggero Bertani, "World Geothermal Generation in 2007," GHC Bulletin, September 2007, p.9; 2007 U.S. data from Geothermal Energy Association, Update on US Geothermal Power Production and Development (Washington, DC: 16 January 2008).  15 2.3 Enhanced Geothermal Systems (EGS) Conventional geothermal reservoirs are associated with a resource that contains natural hydrothermal fluid (mostly steam and water) to carry heat from permeable rock to the Earth‟s surface.  Occurrences of such hydrothermal systems are mainly restricted to the tectonic plate boundaries which limit the technology on geographical-basis. Enhanced geothermal systems (EGS) are a new development in geothermal energy technology that has been applied to resources where heat is available in relatively impermeable rock without or with non-economic amounts of fluid available to transport the heat to surface (Gupta & Roy, 2007). This technology is also known as Hot Dry Rock (HDR) or/and Engineering Geothermal Systems (EGS). U.S Energy Research and Development Administration (ERDA) have defined this kind of reservoir as follows: “Heat stored in rocks within 10 km of the Earth’s Surface from which the energy cannot be economically produced by natural hot water or steam”   Figure 2-8: Hot Dry Rock (HDR) system (International Geothermal Association: Dikson & Fanelli, 2009)  16 In reality, to qualify as an EGS reservoir, exploitation must be "engineered" to create permeability and/or introduce "borrowed" fluid. As such these systems are often called Engineered Geothermal Systems (EGS) (Figure 2-8). The heat source is typically deep and water must be injected into the reservoir from another source to transport the heat. In this technology, rock permeability is enhanced by injecting high pressure cold water down an injection well to create new fractures or enlarge existing ones. The artificial fracture system acts as a heat exchanger by allowing water to circulate between an injection well and the production wells (Duchane, 1996; Gupta & Roy, 2007). Operation is relatively straight-forward. The high pressure water is pumped into the resource. Hydraulic pressure is applied to keeps the rock joints open and force the water to circulate through the previously impermeable reservoir (Duchane, 1996). With EGS, the heat source is typically much deeper than conventional GES – as much as 6km. Water is injected through one well and the permeability of the reservoir is enhanced through hydraulic stimulation (pulsing). For instance, the Paralana geothermal project in Australia has drilled two wells to 3.6 and 4.0 km for production and injection respectively. The reservoir covers 500 km2 of very-hot granite rocks. The artificial fracture system between the wells is essentially an underground heat exchanger. At least a 260 MW power plant is expected to be developed and a demonstration project of a 7.5 MWe power plant will come on-stream by the end of 2009 to supply local demand near Adelaide. It is estimated that the funds to drill each well is about $10 million U.S. (Goldstein et al., 2008; Grant et al., 2008; Petratherm Limited, 2009). 2.4 Case Studies Over the last few decades, generating electricity from the earth's heat has made significant progress. The most remarkable areas include power generation from medium temperature reservoirs and development of EGS technology. This section addresses two successful projects of these types in Chena, Alaska, and Soultz, France.  17 The Chena project is referenced as the lowest-temperature commercial geothermal power plant in the world while the importance of the Soultz project lies in paving the way to examine new methods for EGS. 2.4.1 Chena Geothermal Project The Chena project is the lowest-temperature commercial geothermal power plant in the world (Holdmann & List, 2007). Chena Hot Springs is located about 97 km east- northeast of Fairbanks, Alaska. The Chena Hot Springs Resort consists of residential and tourist houses, a greenhouse, a restaurant, an ice museum, and a hotel (Aurora Ice Museum) - all of which are supplied with geothermal energy (Chena Hot Spring Resort, 2007b). A binary cycle power plant was installed in 2006. At the site, geothermal waters are used to produce energy for heating in the winter and cooling for the ice museum in the summer (Chena Hot Spring Resort, 2007a). The Chena Hot Springs community is located in a semi-remote area in Alaska confronted with many infrastructure challenges. Located 53 km from the nearest power grid, all electricity was previously generated using a diesel generator. The high cost of electricity at 30¢/kWh motivated the development of an alternative approach. Chena Hot Springs entered into a partnership with United Technologies Corporation (UTC) in October 2004. UTC had already developed a new 200 kW power generation system to recover industrial waste heat. UTC was interested in operating its system at a geothermal resource as a sideline opportunity to their normal market (Kontoleontos et al., 2007). To meet the demand for electricity and heat at Chena, two 200 kW power plants were required. UTC conducted two important studies before designing the system:  First, they examined the capacity of the Chena geothermal resource to generate electrical energy. This capacity was needed to compare with the cost of diesel-generated electricity or installing a 53 km transmission line to join the Fairbanks power grid;  18  The second study determined the relationship between shallow and deep geothermal reservoirs in the region in order to site the production and injection wells. According to these studies, Chena Hot Springs reservoir is able to sustainably generate 5MW of electricity – well above the required capacity of 400 kW. The decision was made to drill the production and injection wells at opposite ends of the site – a distance of 914 m – to minimize reservoir cooling. The greatest challenge in designing the Chena power plant was the low temperature of the reservoir. The original UTC power generation system was designed to produce electricity from industrial waste gases at 260 to 540 °C. The power module is actually a simple chiller in which hot water feeds the evaporator and cold water feeds the condenser. To solve the problem of low input temperature, UTC designed a new binary cycle system using a working fluid with a lower boiling point. The working fluid was changed from the common refrigerant R245fa to R134a which has a more suitable boiling point for a low temperature resource. The lower price of R134a also helped reduce capital costs. UTC‟s binary cycle power plant can generate electricity from any heat source with at least a 55°C temperature difference between the heat source and sink (Chena Power Company, 2007). The first Chena binary power plant (200 kW) came online in late July 2006 with the lowest input temperature (74°C) anywhere in the world. A second 200 kW power plant started-up in December 2006. The cooling system for the first binary power plant uses cold water while the second unit uses a dual air/water system. The higher efficiency of an air-cooling system during the winter increased net power generation to 220 kW for the second unit. Indeed, the project viability actually depends on the cold weather at Chena in comparison to other locations. The Carnot efficiency of the binary power cycle in Chena is about 8% which is high because of the availability of an inexpensive (essentially free) cooling source (Erkan et al., 2008a).  19 Chena uses geothermal energy to heat 44 buildings in the community as well as two 560 m2 greenhouses and to cool the Aurora Ice Museum in the summer. The unique refrigeration system saves Chena about $190 per day and the greenhouses produce fresh food year round at almost no energy cost (Moins, 2008). The power plant was completed at close to its estimated budget. Total project capital cost was $2 million drive from a grant from the Alaska Energy Authority, a loan from the Alaska Industrial Development and Export Authority, and an investment by the Chena Hot Springs Resort owners and by K&K Recycling. To reduce the overall cost, UTC, in cooperation with its sister division, Carrier, reversed a Carrier chiller component into a binary cycle system. Using off-the-shelf equipment in designing the power plant reduced the total installation cost from an original estimate of $3,000/kW to a final real cost of $1,300/kW. The particular achievement of the Chena geothermal power plant is the operation of the project in a feasible financial, environmental, and socially-acceptable way. A payback period of 4 years is projected (Chena Power Company, 2007). In 2006 (late July to December), the first power plant operated for 3,000 hours, generating 578,550 kWh of electricity replacing 44,500 gallons of diesel fuel. It is estimated that after installing the second 200 kW power plant in 2007; the project generated 3 million kWh and displaced 224,000 gallons of diesel to save the community about $550,000 per year. Generating clean electricity thus reduced the local cost of power from 30¢ per kWh to below 6¢ per kWh (Holdmann & List, 2007). In 2007, the Chena geothermal power plant was able to produce more electricity than needed onsite. Since Chena is not connected to the state power grid which would have allowed power sales throughout the state of Alaska, the town is considering a new project to make hydrogen by electrolysis for use as a "green" transportation fuel. 2.4.2 The Soultz-Sous-Forets Geothermal Project The Soultz project is an example of a successful Enhanced Geothermal project. The Soultz-Sous-Forets site is located in Alsace, France within the extensive thermal anomaly of the Rhine Graben (Figure 2-9).  20  Figure 2-9: Geothermal site of Soultz, France - highest thermal area is shown in grey (Cuenot et al., 2008) The project is supported by the Commission of the European Communities and coordinated by the European Hot Dry Rock (HDR) Energy Program with the main purpose to develop a deep heat exchanger to generate electricity. This project is the most successful Enhanced Geothermal project in Europe. The average heat flow within the Rhine Graben area is about 80 mW/m2 which extends to 140 mW/m2 at the Soultz site. A high temperature gradient (Figure 2-10) of 100°C/km has been measured at shallow depths down to 1000m in the Rhine Graben area, but below this depth, down to 2500m, in the bedrock, the gradient drops to 15°C/km. A temperature gradient of 30°C/km has been measured for depths between 2500 to 5000 m (Berard & Cornet, 2003; Cuenot et al., 2008). The project began in 1997 with two wells drilled to 3,590 and 3,876 m. Well-testing showed water could be circulated at 25 L/s between the two wells. High fracture-density and permeability in the granite bedrock makes this circulation possible. The bottom-hole temperature was 150 °C.  21  Figure 2-10: Temperature gradient, Soultz project, France (Cuenot et al., 2008) Geothermometry (the science of using fluid geochemistry to estimate the origin temperature of a reservoir at depth) estimated a higher temperature than those measured in the geothermal fluid mainly since the water cools as it ascends from such depths. In 1999, one of the wells was extended to 5,000 m where the BHT was estimated at 200°C. In 2001, two more wells were drilled to 5000 m resulting in one injection well and two production wells (Cuenot et al., 2008; Elsass et al., 1995). Since 2008, the Soultz geothermal project has followed two operational plans. One involved installing a 1.5MWe binary power plant. The power plant runs off geothermal water from one well to test the sustainability of long-term production with a production test plan on the second well to prepare for additional power generation units. This additional geothermal water will allow well one or two more ORC units will be added to achieve a capacity of over 6MWe (Cuenot et al., 2008; European deep geothermal energy project, 2008).  22 The economics of the Soultz geothermal project from the beginning of commercial power production to the end of the project life-time (20 years) has been modeled using a program called HDRec developed specifically for geothermal project cost-benefit analysis. The program combines economic aspects with reservoir characteristics (thermal and hydrological factors) and technical parameters involving with power plant installation. This program helps study ways to optimize the economic aspects with respect to varying technical factors. The following parameters were used to estimate the final result (Heidinger et al., 2006):  Investment and operation costs  Revenues gained from electricity sales  Reduction in income ensuing from decreasing reservoir temperatures  Maintenance or refurbishment costs during production  Cost of dismantling the system when exploitation ends Economic information about the costs and investments at the Soultz-Sous-Forests geothermal project are summarized in Table 2-4 and Table 2-5. All costs are reported in 2005 Euros (€). The important and significant results of the HDR system with a 20-year production lifetime are shown in Table 2-5. The financial parameters refer to the beginning of commercial energy production. Table 2-4- General economic information about the Soultz geothermal project General information 2005 Data Specific investment costs of the fluid circulation pumps 1720 €/kW Specific investment in the power station 1.5 million €/MWe Annual maintenance cost – HDR plant (% of investment) 5% Selling price of the produced electricity (German market) 0.15 €/kWh Bond and equity interest rate 4% Fraction of capital in bonds 50% Fixed stimulation costs 0.55 million € Source: (Heidinger et al., 2006)  23 Table 2-5- Investment information about the Soultz geothermal project. Item Data Exploration cost 1.85 million € Drilling three boreholes cost 18.20 million € Stimulation cost 0.55 million € Pump costs 2.75 million € Power Plant (7.1 MWe) costs 11.10 million € Total investment in the HDR system 34.50 million € Replacement costs (pumps) 11.00 million € Annual operating costs 1.74 million € Temperature drawdown 199–152 °C Total annual energy produced 764 GWh Net Present Value of investment @ i=4.0% 7.50 million € Levelized total life cycle costs 0.136 €/kWh Source: (Heidinger et al., 2006) 2.5 Geothermal Energy: Advantages and Disadvantages As with all types of energy sources, besides many advantages, geothermal energy also has certain disadvantages – many of which can usually be prevented using more modern technologies (Brophy, 1997).  Some of the advantages of geothermal energy include (Armstead, c1983; Gupta & Roy, 2007):  Zero to only a small amount of gas emissions to the atmosphere since there is no fuel combustion;  Conservation of nonrenewable fossil fuels and reduction in carbon dioxide emissions to the atmosphere;  24  Elimination of fuel transportation costs since the plant is located right on top of the resource (water or steam reservoirs). This is most significant for countries that are not producers of oil and gas;  Reliable source of energy- designed to work 24 hours - 365 days a year;  Land requirements for a geothermal power plant are much smaller than that for oil, gas, coal or nuclear, hence a smaller footprint on the environment;  Tax incentives - some countries, such as the US, provide tax incentives and reduced environmental regulations for clean energy (The White House, 2009). Some of the disadvantages of generating electricity from geothermal energy are as follows (Armstead, c1983; Brophy, 1997; Dickson & Fanelli, 2005, c2003):  Finding a site to build the power station. Most geothermal zones are in active tectonic areas which are risky places for long-term geotechnical stability;  In some cases, if the production of steam or hot-water is not properly managed, the reservoir may run out of steam or fluid in less than a decade;  Hazardous gases may be associated with the resource;  Effects on the surrounding environment may be severe - physical effect of fluid withdrawal, thermal effects, chemical pollution, biological effects, and noise related to drilling and production facilities;  In some EGS projects, if enhancement of fractures is not properly managed, the process can cause earthquakes (up to 3.0 on the Richter scale).  25 2.6 Comparison of Geothermal Energy with other Renewable Energies The data presented in this section were screened from „the World Energy Assessment Report prepared by UNDP, UN–DESA and the World Energy Council (2000) published by the United Nations Commission on Sustainable Development. Current energy sources can be split into three categories - fossil fuels, renewable resources, and nuclear resources (Demirbas, 2000). Renewable energy sources, also known as alternative energy, can provide clean energy with zero or near zero emissions of greenhouse gases and air pollution. Biomass, hydropower, geothermal, wind, solar, and tidal belong to these types. In the case of biomass, despite the combustion of carbon, emissions are viewed as being carbon-neutral since the source of the biomass is quickly regenerated by photosynthesis from the atmosphere. Table 2-6 shows that the total worldwide electricity production from renewable energy sources in 1998 was about 2,826 TWh (UNDP, UN–DESA and the World Energy Council, 2000). Hydroelectricity predominated in 1998 at 92% of the total with the remaining types being biomass at 5.7%, geothermal at 1.6%, and wind at 0.6%, solar at 0.05%, and tidal at 0.02%. Energy production costs are lowest for hydro and geothermal and highest for solar and wind. However these latter two types each show a 30% increase in annual installed capacity over the period 1995- 2000. The rate of increase for hydro, biomass and geothermal ranges from 2 to 4% (Fridleifsson, 2001). The table also shows geothermal electrical generation can have a capacity factor as high as 90%, with current and future energy cost comparable to that of hydro and biomass (Turkenburg, 2000).  26 Table 2-6- Status of electricity production from renewable energy sources  Energy production 1998 (TWh(e)) Capacity factor (%) Current energy cost (US₵/kWh) Potential future energy cost (US₵/kWh) Turnkey investment cost (US₵/kWh) Hydroelectricity 2600 20-70 2-10 2-8 1000-4000 Biomass 160 25-80 5-15 4-10 900-3000 Geothermal 46 45-90 2-10 1-8 800-3000 Wind 18 20-30 5-13 3-10 1100-1700 Solar Photovoltaic 0.5 8-20 25-125 5-25 5000-10000 Thermal  1 20-35 12-18 4-10 3000-4000 Tidal 0.6 20-30 8-15 8-15 1700-2500 Total 2826.1 Source: (Turkenburg, 2000; UNDP, UN–DESA and the World Energy Council, 2000)  Data on direct heat production from renewable energy are given in Table 2-7. Biomass dominates here at 93% of the total followed by geothermal at 5% and solar at 2%. As with electricity, solar heat systems have the lowest capacity factor and highest energy costs.  27 Table 2-7- Status of direct heat production from renewable energy sources  Energy production In 1998 (TWh(e)) Capacity factor (%) Current energy cost (US₵/kWh) Potential future energy cost (US₵/kWh) Turnkey investment cost (US₵/kWh) Biomass >700 25-80 1-5 1-5 250-750 Geothermal 40 20-70 0.5-5 0.5-5 200-2000 Solar heat low temp. 14 8-20 3-20 2-10 500-1700 Source: (Turkenburg, 2000; UNDP, UN–DESA and the World Energy Council, 2000)  In comparison with other renewable sources of energy, geothermal has the potential to generate twice as much energy as all other renewables combined (Table 2-8). Table 2-8- Technical potential of renewable energy sources  EJ per year Hydropower      50 Biomass    276 Solar  1,575 Wind     640 Geothermal 5,000 Source: (World Energy Assessment (WEA), 2000)  It is expected that the share of renewable energy sources in the world energy market may increase to as much as 80% and certainly as much as 30% by 2100. The relative  28 position of geothermal energy in this total contribution will depend on the efforts of the geothermal communities and the currently leading countries (Fridleifsson, 2001). 2.7 Geothermal Energy Status in Canada Canadian resources include all types of geothermal energy from high to low temperature. Geothermal energy plays a small role in the Canadian energy market – only through direct-use heating applications. Currently there are no geothermal power plants in Canada despite the presence of high temperature resources associated with the Pacific Ring of Fire (Ghomshei et al., 2005). Use is predominately in the area of low- temperature heat pump technologies which is considered the fastest growing alternative energy in almost all Canadian provinces (Ghomshei et al., 2005). The geothermal heat pump market shows an annual growth rate between 10-15% since 2000 with a total of 600 million kWh(t) leading to an annual reduction of about 200,000 tonnes of greenhouse gas emissions (Ghomshei et al., 2005). Hot springs and abandoned mines such as Springhill, Nova Scotia (Ghomshei & Meech, 2005) are also used as geothermal reservoirs in Canada. More than 150 hot springs are reported in Canada with temperature up to 80°C. Over 70% of these resorts are located in British Columbia, the remainder being in Yukon, North West Territories, (NWT) and Alberta (Ghomshei & Sadlier-Brown, 1996).The total direct use capacity of these developed hot-spring resorts including pools and space heating is estimated to be 10-15 MWt (Ghomshei et al., 2005). Jessop (1995) estimated 11 MWt of installed capacity for heat extracted from abandoned mines for commercial and residential uses. In 2005, the total amount of direct use was 461 MWt (Table 2-9) – about 1.6% of total worldwide capacity (Lund et al., 2005; Lund, 2005).  Note that the capacity factor for this energy is extremely low relative to electricity production.   29 Table 2-9- Geothermal energy status in Canada in 2005.  Capacity (MWt) Energy utilization (GWh/yr) Capacity Factor Canada 461 707.3 0.18 Worldwide 28,268 75,942.8 0.31 Source: (Lund et al., 2005; Lund, 2005)  The majority of high-temperature geothermal sites are located in the western part of Canada, (British Columbia and Yukon) (Ghomshei et al., 2005; Jessop et al., 1991). Studies by Jessop et al., 1991) indicate the potential for the Atlantic Provinces to produce power using hot dry rock technology. Currently known high temperature geothermal resources in British Columbia have the potential to generate at least 1,500 MW commercial power (Ghomshei et al., 2005) although more recent estimates suggest double this level. The first attempts to extract geothermal energy in Canada go back to 1973 following the first major oil crisis. Exploration activities conducted by BCHydro indicated several interesting anomalies such as Mt. Meager and Mt. Caley (Ghomshei et al., 2004) located in the Garibaldi and Pemberton Ranges. But as oil prices stabilized in the early 1980s essentially all geothermal exploration activities stopped in 1985. So, it is clear that geothermal power generation does not yet make even a small contribution to the Canadian energy market despite the presence of high temperature resources in the west. Low energy prices in B.C. for natural gas and hydropower together with a lack of government incentives have frustrated many attempts to invigorate this field over the past quarter of a century. However, in recent times, increasing energy prices and rising efforts to reduce greenhouse gas emissions may be "turning the tide" back to this resource.  30 3 Area of Study The study described in this thesis takes place at the Clarke Lake and Milo gas fields located south of Fort Nelson in northeast British Columbia. These two gas fields were chosen based on four essential criteria: prior studies in the area in question, accessibility to data from existing wells, nearby infrastructure facilities, and proximity to demand (Fort Nelson). Studies by Jessop et al (1991) on Canadian geothermal resources show high-enthalpy hydrothermal resources located in British Columbia and Yukon – Canada coastal zones within the Pacific Ring of Fire. Further studies in the Western Canadian Sedimentary Basin (WCSB) (Anglin & Beck, 1965; Garland & Lennox, 1962) indicate the existence of a large thermal anomaly in the Peace area in B.C. Later work (Majorowicz & Jessop, 1981; Majorowicz, 1996) reported high ground heat flow in north-eastern BC and north- western Alberta from an analysis of about 120 deep shut-in wells and 20 producing wells. The results showed a heat flow of up to 99 mW/m2 in the northern part of the region – about 4 times background heat flow. Jessop et al (1991) estimated the extractable geothermal energy from deep-circulating water in the WCSB to be in excess of the total Canada‟s conventional oil and gas resources (Ghomshei et al., 2005). There are more than 20,000 drilled oil and gas wells in British Columbia, mostly within the WCSB in the Peace area (Figure 3-1). With this preponderance of wells in the area, there is an opportunity to gain useful information for geothermal purposes by analyzing the recorded borehole logs of the wells. However the well data are not available for all these wells in the Peace Area. Viability of a geothermal project depends on three factors; reservoir status, proximity to demand, and availability of power distribution utilities. In the current study, availability of suitable and consistent information on gas wells in the area was also important.  31  Figure 3-1: Peace area- northeast British Columbia, Canada Another limitation is that the existing electric power transmission grids do not cover all of NE BC. Sites with the best opportunity, because of their respective location relative to a required demand, are those areas next to Fort Nelson and Fort St John due to population size and the proximity to a local electric power transmission system. Fort Nelson and Fort St John are located in the northern and southern areas of the region respectively (Figure 3-1). The BC electrical power grid supplies Fort St John, while Fort Nelson electricity is provided by the power output of the Fort Nelson Generating Station and the backup supply from the Alberta electric power grid. Although considerable numbers of wells do exist in the region around Fort St. John, the data relevant to this work was unavailable. As well, the proximity of the fields to a demand site (Fort. St. John) was significantly greater than 10 km. So, data for the Fort St. John area was not analysed in this study. A study by Majorowicz & Jessop in 1981 demonstrated the highest heat flow values in the northeast of the region, so the community chosen for evaluation was Fort Nelson.  32 The two gas fields with useful data included Clarke Lake and Milo. There are two central facilities within the Clarke Lake gas field used to separate the extracted natural gas and water. Both facilities are connected to the B.C. Hydro power grid. According to the above criteria, Clarke Lake and Milo gas fields were chosen because of their proximity to a sizable community (demand), availability of well record data, and the necessary power lines (B.C. Hydro and Alberta power grids). Clarke Lake is the most interesting area due to a higher concentration of wells. In total, there are more than 70 currently producing gas wells in this field. 3.1 Fort Nelson Fort Nelson is located approximately 11 km from the Clarke Lake central gas-facilities. According to the 2006 census, there are 1,705 dwellings in Fort Nelson. The population was estimated at 4,660 people in 2008 (BC Stats, 2009). The city is not part of BC Hydro‟s integrated system with the Fort Nelson Generating Station (FNG) rated at 40 MW of power using natural gas-fired steam turbines. Table 3-1 shows the history of the Fort Nelson power supply system from 1991. Table 3-1: History of Fort Nelson electric power supply Before 1991 Diesel generating station 1991 Transmission line to Alberta 1999 Fort Nelson 40MW gas-fired generating station (supply) 2000 Decommissioned diesel generating station, Firm back up supply from Alberta 2007/2008 Load in the Fort Nelson area increased by more than 50% (now about 40MW-demand) Source: (Rich & Maiangowi, 2008)  Industrial and population growth are projected to increase demand by 50% by 2010. BC Hydro predicts the potential load to grow to as much as 300 MW (Rich & Maiangowi,  33 2008). BC Hydro considers three main load growth scenarios based on possible fuel- switching and new industrial activities. Figure 3-2 shows the probable demand scenarios for Fort Nelson over the next 20 years.  Figure 3-2: Possible load growth scenarios for Fort Nelson Source: (BC hydro, 2008) BC Hydro has identified the following options to meet this growth demand at 2007:  Local generation options o Expand the current FNG station o Investigate clean or renewable local energy sources  Transmission options o Connect Fort Nelson to the BC Hydro grid o Increase the supply from Alberta Finding a proper geothermal reservoir as a renewable, reliable, clean, and local source of energy might be able to supply heat and electricity for communities such as Fort Nelson and may also contribute to “carbon- offsets” for the production of oil and gas resources in the region.  34 4 Methods and Procedures There are various types of exploration techniques to assess the geothermal potential of an area in question. These include geochemical techniques (geothermometry), geophysical techniques (thermal methods, electrical resistivity methods, electromagnetic method, seismic methods, gravity and magnetic methods), and airborne surveys (aeromagnetic investigations, remote-sensing techniques, infrared radiation and atmospheric transmission windows, etc.) (Gupta & Roy, 2007). The method used in this study is based on thermal methods from geophysical exploration techniques that involve an investigation of local temperature gradients and heat flows. The main achievement of this project is the development of a temperature- gradient model and the creation of heat-flow maps for Clarke Lake and Milo. These were built on the basis of data collected from producing gas wells in the region. Data from the available documents included information on location, bottom hole temperature (BHT), pressure, and depth for 54 gas wells within the Clarke Lake field with an additional 16 gas wells at Milo. The data collected from these wells were originally compiled for non-geothermal purposes. As such, the first task was to screen the databases for appropriate information for geothermal purposes. The information selected from the well documents included bottom-hole temperature (BHT), depth, bottom-hole diameter, water flow rate, and water chemistry. ArcGIS was used in this study to virtually assemble and analyze the available geothermal information. ArcGIS is map-producing and analysis software that allows users to manage and maintain large amounts of spatial and vector data. The method chosen to interpolate the data was the Inverse Distance Weighted method (IDW) (see section 4.3.2). With this method, the influence of a measured value on an unmeasured neighboring point diminishes with distance. Figure 4.1 illustrates the thesis methodology.  35  Figure 4-1: Thesis methodology Assembling available data from producing gas wells Data management Screening proper data for geothermal purposes Converting the data into a GIS format Analysing and interpolating geothermal information from the wells to the area in question Visualizing data through producing maps with GIS Investigating the regional geothermal potential Interpreting data from maps Fluid information  Thermal information  Prior geological studies  Assembling all available data Integrating and interpreting all data  36 4.1 Data Assembling The first step was to screen the appropriate information for geothermal purposes from the pool of existing databases. The BC Ministry of Energy, Mines and Petroleum Resources (BC-MEMPR) had gathered the majority of well information from different BC oil and gas companies. This information was accumulated into two relevant oil and gas field programs: GeoScout and AccuMap. The data included general information and drilling information as well as the entire geological and technical test work performed on each well. Some of the most fundamental geothermal information selected from the pool of data included bottom-hole temperature (BHT), depth, bottom-hole diameter, water flow rate, and water chemistry. All data collected from BC-MEMPR was in image format which had to be converted into digital format in order to be accessible. After studying the data, a chart was made using the necessary geothermal information from the producing wells. After filtering out logs with unusual or incomplete information, 54 producing wells in Clarke Lake and 16 in Milo remained in the chart (see Appendix 1). 4.2 Geophysical Techniques Geophysical techniques are exploration methods (geochemical techniques, geophysical techniques, and airborne surveys) to delineate deep subsurface features that do not require drilling.  With geophysical techniques, important issues such as the source of heat, areal extension of the reservoir, zones of fluid up-flow, rock permeability, and reservoir assessment as well as structural features must be addressed (Gupta & Roy, 2007). The information provided helps us to understand fluid movements through withdrawal and re-injection processes during exploration and for reservoir management for sustainable production. Geophysics has been used to investigate physical properties of geothermal reservoirs such as temperature, resistivity, density, porosity, magnetic susceptibility, and seismic velocity. They can be applied to shallow or deep geothermal  37 reservoirs, hydrothermal or enhanced systems.  Understanding the physical properties of a reservoir will control exploitation decisions such as siting drill-hole locations. 4.2.1 Thermal Methods Thermal exploration methods are applied to assess the size and potential of a geothermal reservoir (Armstead, c1983; Gupta & Roy, 2007). Temperature gradient measurements (the rate of change in temperature with depth) and heat flow (the rate of heat transfer through the rock) are done in all geothermal exploration activities as key criteria to select drilling sites. With these criteria in mind, the most economically attractive geothermal areas are those that possess temperature gradients and heat flows higher than the global average. The most common thermal methods include temperature probe surveys, temperature gradient surveys, and heat flow investigations. Other methods use thermal conductivity measurements as well as measurements on rock fragments and unconsolidated sediments. This study uses temperature gradient and heat flow surveys for both Clarke Lake and Milo gas fields with the approach of gaining data by analyzing recorded oil and gas borehole logs (bottom-hole temperature and well depth). Temperature Gradient Surveys Temperature gradient surveys provide basic subsurface thermal information (Armstead, c1983; Gupta & Roy, 2007). The ratio of temperature difference to measured depth difference represents a temperature gradient. Because of variable conductivity, faults, rock types, etc., a linear pattern cannot always be applied to the temperature gradient. For instance, in sedimentary rocks, decreasing porosity with depth increases thermal conductivity, but decreases the temperature gradient. Data available from oil and gas borehole logs were used to assemble regional thermal information for both Clarke Lake and Milo gas fields. Using the bottom-hole temperature  38 and depth data from each well to compute the regional temperature gradient is how we applied the thermal method in this study. Since the well data was gathered from different companies, under different conditions and at a variety of depths, it is vital to convert the information into a new dataset appropriate to interpolate across the area of interest. For example, the bottom-hole temperature (BHT) came from wells of variable depth. By adjusting the BHT using the average temperature gradient, this parameter could be normalized to a constant depth for each well in the study (see Appendix 1). Heat Flow Investigations Geothermal gradient surveys are often sufficient to address a geothermal area in general (Gupta & Roy, 2007), however, to better understand the subsurface thermal system; a heat flow investigation should also be used. Heat flow is a function of temperature gradient and thermal conductivity. Temperature is considered a property of matter, while heat is the energy flowing through the mass as a result of a temperature difference either within the mass itself or between the mass and its surrounding environment. Heat energy transfers from a high temperature area to a low one. How heat is conducted within the subsurface body is described by Fourier‟s equation: ∆Q = - K A     Eq. 4-1. ∆Q is the amount of heat transferred per unit time (in kW or joule/s), K is the thermal conductivity of the rock (W/m°C), A is the area (m2) and  is the temperature gradient (°C/km). According to this equation, the first step to create a heat flow map is to conduct a temperature gradient survey and measure the thermal conductivity of the region.  39 4.3 Geographical Information System (GIS) The method to assemble, analyze and interpolate data from the wells is to place the data into a Geographical Information System (GIS). Geographical information plays an important role in virtually all decisions being made; in choosing sites, in targeting market segments, in planning distribution networks, and in redrawing country boundaries, etc. (ESRI, 2008b).The term „Geographic Information System (GIS)‟ has been gaining in use around the world. GIS is a technical tool to capture, store, integrate, check, manipulate, analyse and display data related to locations on the Earth's surface (GIS Lounge, 2008; Stanford University, 2006).  GIS is computer software linking two basic questions: where things are (geographic information) and what things are (descriptive information) (ESRI, 2008a). Various definitions have been put forward by different authorities – two of the more common ones are as follows: “A geographic information system (GIS) is a computer-based tool for mapping and analyzing things that exist and events that happen on earth. GIS technology integrates common database operations such as query and statistical analysis with the unique visualization and geographic analysis benefits offered by maps.” (ESRI, 2009) “GIS is an integrated system of computer hardware, software, and trained personnel linking topographic, demographic, utility, facility, image and other data sources that are geographically referenced.” (NASA, 2009)  4.3.1 ArcGIS Software ArcGIS is the GIS software used in this study. The main concept of a GIS program is to use data related to positions on the Earth and overlay the datasets to obtain a new insight to make a wiser decision. Coupled with each layer is an attribute table that contain additional information about map features (ESRI, 2009; Stanford University,  40 2006). For instance, Figure 4-2 shows the bottom-hole locations of producing gas wells in northeast BC, Canada and how their geographic position is linked to the descriptive information in the attribute table.  Figure 4-2: Graphic information linked to an attribute table (descriptive information) As the picture illustrates, additional data such as coordinate position of each well, total vertical depth (TVD), bottom hole temperature (BHT), etc. can be found in the attribute table for the specific layer that represent the producing gas wells. The attribute tables allow users to create new datasets based on existing data and adding it into the maps. There are two graphical model types in ArcGIS; raster and vector. A raster is composed of a grid of individual pixels for different sub-sets of data while vector data can be stored as line length and orientation–a much more compact method (Figure 4-3). Despite this advantage, the raster method was selected since the regional earth crust has a continuous geological structure and so, thermal data from the wells can be interpolated  41 over the area of study to more-easily create a raster map. Additional vector information such as electric power line positions can also be added to the database.  Figure 4-3: Representation of different types of layers in a GIS system The real power of GIS programs are in applying spatial and statistical methods to analyze geographic and attribute data to prepare a new set of derivative, interpolated, and/or prioritized information. The „ArcGIS Spatial Analyst‟ toolbox provides many different raster interpolation programs such as Inverse Distance Weighted (IDW), Kriging, Natural Neighbor, Spline, Topo, and Trend. The first two are the most common tools used for geothermal/geological purposes. A deterministic interpolation is used in the IDW method based on surrounding measured values and their distance from unmeasured points. With Kriging, similar to IDW, predicted values for unmeasured points depend on influences from surrounding measured values. The difference lies in the calculation method. Kriging is based on a statistical interpolation model with the ability to predict a value for an unmeasured point based on probability theory. Kriging appears to be a more powerful interpolation tool than does IDW when the number of measured points distributed across the entire area of interest is sufficient. The number of measured points affects the accuracy of a predicted value. In this study, the number  42 of wells and their distribution were not considered enough for Kriging. So the method chosen to interpolate the well data was IDW. 4.3.2 Inverse Distance Weighted Method (IDW) IDW is a commonly-used method to interpolate data from scattered points. In this method, the influence of a measured value on an unmeasured neighboring point diminishes with distance. With IDW, the effect of each measured point on the predicted cell value is determined by a linearly-weighted method. Thus, the influence of nearby points is greater than that of distant points. In the IDW method, the maximum and minimum values are chosen from the measured points. A general form of the IDW interpolating function was defined by Sheppard, (1968) to estimate an unmeasured value „u‟ for a given point „x‟ is:         u x =  ωk x uk N k=0  ωk(x) N k=0                         Eq. 4-2. where:            ωk(x)= 1 d x,xk p              Eq. 4-3. In this function, x refers to an interpolated point (unknown), xk is a neighboring measured point (known), d is the distance between the known point xk and unknown point x, N is the number of measured (known) points used in the interpolation, and p, called the power parameter, is a positive real number. The weights of the measured values decrease rapidly as distance increases. The value of p determines how fast the weight value decreases with distance. If p = 0, there is no decrease with distance. For  0 < p < 1, the resulting map has more detail, but the surface is rough and contains sharp peaks among the measured points. For p > 1, the maps become much smoother. A value of p = 2 is most commonly used in map-making and so, that is what we used.   43 5 Results 5.1 Temperature Gradient Map In a GIS system, some layers serve as base-data. BC-MEMPR prepared the primary base-data layer of the study containing the locations of the more than 20,000 wells in north-east BC. After screening the wells at Clarke Lake and Milo gas fields from the base map, the database table (attribute table) containing descriptive information was created. The attribute table contained the data necessary for map-making and future geothermal energy potential analysis. The temperature gradient map was then created using this database. The temperature gradient (T) represents the rate of change in temperature with depth. The map also embodies the regional subsurface thermal conditions of the Earth‟s crust. In this case, the ratio of bottom-hole temperature (BHT) to depth provides a reliable average value for the temperature gradient of each well. To account for seasonal effects on surface temperature, the temperature gradient was adjusted to 100m below surface where the temperature is roughly stable (~9ºC) year-round: T(°C/km)= (BHT-9) Well depth-100                    Eq. 5-1. The temperature gradient values calculated from the wells were interpolated into the surrounding area. The temperature gradient map for Clarke Lake is shown in Figure 5-1. As the map indicates, the temperature gradient ranges from 33-65 °C/km with an average value of 54 ºC/km - more than twice the average continental value. Those zones with a lower temperature gradient extend from south-central into the central part of the field.   44  Figure 5-1: Distribution model of temperature gradient (°C/km), Clarke Lake gas field, B.C., Canada As can be seen, the majority of the Clarke Lake field is located within a temperature gradient range of 53-59ºC/km - two to three times greater than the Earth‟s crust average value (20-30ºC/km). Figure 5-2 is the temperature gradient map for Milo gas field. As the map shows, high temperature gradients are features of the north-central part of the field. The majority of the area has a gradient ranging from 46 to 52°C/km with an average of 47 ºC/km. In comparison with the average temperature gradient of the continental Earth‟s crust (20- 30 ºC/km), both Clarke Lake and Milo exhibit high gradients. The average temperature gradients mean that for each kilometre in depth, the temperature changes by about 54ºC at Clarke Lake and 47ºC at Milo.  45  Figure 5-2: Distribution model of temperature gradient (°C/km), Milo gas field, B.C., Canada The temperature gradient maps point out the power of GIS to analyze individual data taking an integrated approach. Temperature gradient maps can be used to determine the geothermal energy potential in different parts of the area in question. The higher temperature gradient identifies a higher potential for geothermal extraction. These areas can be readily screened from the maps. Temperature gradient maps as primary exploratory tools can narrow operations such as exploratory drilling to those areas with the highest geothermal potential, and so, exploration costs are decreased. These maps can be readily updated through the accessibility of all databases used to produce the maps in ArcGIS.    46 5.2 Estimated Temperature Maps at Different Depths Based on these temperature gradient maps, the subsurface temperature at different depths can be estimated. Creating estimated temperature maps can be a valuable tool for deep geothermal projects within the area in question. Using the two created maps (Figure 5-1and Figure 5-2); an estimate of the average temperature versus depth was prepared for both areas at depths of 1000m, 1500m, 2000m, and 2500m. These maps are shown in the following diagrams for both Clarke Lake and Milo. These maps can be used to conduct a preliminary assess of the heat capacity of the reservoirs. The map applications will be discussed in the next Chapter.   Figure 5-3: Estimated temperature at 1000m, Clarke Lake gas field, B.C., Canada  47  Figure 5-4: Estimated temperature at 1500m, Clarke Lake gas field, B.C., Canada  Figure 5-5: Estimated temperature at 2000m, Clarke Lake gas field, B.C., Canada  48  Figure 5-6: Estimated temperature at 2500m, Clarke Lake, B.C., Canada  Figure 5-7: Estimated temperature at 1000m, Milo gas field, B.C., Canada  49  Figure 5-8: Estimated temperature at 1500m, Milo gas field, B.C., Canada  Figure 5-9: Estimated temperature at 2000m, Milo gas field, B.C., Canada  50  Figure 5-10: Estimated temperature at 2500m, Milo gas field, B.C., Canada 5.3 Heat Flow Map Heat flow rate is the amount of energy (heat) transferred per unit of time (in W or J/s). According to the Fourier Equation (Section, there is a positive relationship between heat flow, temperature gradient, and thermal conductivity. Consequently, to measure the regional heat flow, an estimation of the thermal conductivity of the bedrock in the Clarke Lake and Milo was needed. The following sections address how the regional thermal conductivity was estimated for the area in question and then the creation of heat flow maps based on the temperature gradient maps. 5.3.1 Thermal Conductivity Thermal conductivity is defined as the ability of rock to conduct heat. To estimate the thermal conductivity, the bedrock geology of the region was needed. The major formation at Clarke Lake and Milo bedrock consists of the „Buckinghorse Formation‟  51 which contains dark-grey marine shale, siltstone, sideritic-, and marine-sandstone (Figure 5-11). The remainder is covered by the „Sikanni Formation‟ composed of fine- grained grey sandstone, siltstone, and shale. In work done by Majorowicz et al. in 2004 using regional bedrock geology maps, a range of 1.2 to 2.4 W/m.K was estimated for the entire north-east BC.  Figure 5-11: Buckinghorse formation-94J, north-eastern B.C., Canada This range is on the low side for Clarke Lake and Milo since siltstone (2.26 W/m.K) and marina sandstone (3.0 W/mK) (Côté & Konrad, 2005) are predominant in both fields. As a result, we chose to use a value of 2.25 W/m.K to create a suitable heat flow map. More exploration studies are required to more accurately evaluate regional thermal conductivity of Clarke Lake and Milo fields. CP (regional) = 2.25 W/m.K  52 5.3.2 Heat Flow Studies by Majorowicz (1996) and Majorowicz, et al. (2005) showed a large anomalous heat flow in the Western Canadian Sedimentary Basin in north-east BC. Based on data from the temperature gradient maps and assumed thermal conductivity, we have prepared heat flow maps both gas fields. According to these maps, the average heat flow is computed to be 121 mW/m2 and 106 mW/m2 at Clarke Lake and Milo respectively. The lowest heat flow obtained at Clarke Lake was 75 mW/m2 while the highest was 147 mW/m2. At Milo the heat flow was less variable with well values ranging from 84 to 122 mW/m2.  Figure 5-12: Distribution of heat flow (mW/m2), Clarke Lake gas field, B.C., Canada  53  Figure 5-13: Distribution of heat flow (mW/m2), Milo gas field, B.C., Canada According to the latest global compilation of heat flow data, the average global continental heat flow is 65 mW/m2 (Pollack, Hunter, & Johnson, 1993). Heat flow values above 80-100 mW/m2 presume an anomalous sub-surface (Jessop et al., 2005). So both Clark Lake and Milo gas fields are classified as ones with high geothermal potential. The heat flow maps results confirm a considerable amount of heat flow in the region.  Figure 5-12 and Figure 5-13 illustrate the distribution of heat flow in the areas of study. However, uncertainties about arbitrary thermal conductivity indicate the need for more specific measurement studies.   54 5.4 Geothermometry Geological differences in the rocks surrounding geothermal fields are reflected in the chemistry of the geothermal fluids. Exploration techniques based on using the composition of geothermal fluid discharged to the surface to collect information about deep geothermal reservoirs have been applied for about 20 years throughout the world. Most techniques rely on distribution of chemical solutes, isotopes, and gas composition of geothermal fluids (geochemistry). The temperature of a geothermal reservoir can be estimated by geothermometry to establish the potential error of direct measurements. This calculation is based on water- rock reactions as a function of temperature. In other words, the amount of water-soluble species derived from minerals depends on the reservoir temperature. The method assumes equilibrium conditions exist between the rock and the reservoir fluid. Geothermometers are chosen from the minerals with an ability to preserve their absolute or relative concentrations almost unaffected by physical and chemical processes within the ascending geothermal fluids. The sensitivity of the chosen minerals/species to temperature variations and their ability to preserve their concentration when the geothermal fluids are cooled down by ascending to the surface and/or sampling processes is important. The most reliable Solute Geothermometry equations are based on dissolved silica content and the ratio of Na/K. Since Si assays were not given for our fluid samples, the ratio of Na/K was chosen for further use. The water chemistry data was available for only 7 wells at Clarke Lake and 8 at Milo. Fournier (1979) has derived the most widely-used Na/K geothermometry equation to estimate the underground temperature as follows (Figure 5-14): t(℃)= 1217 log Na K  +1.483 -273.15                                                        Eq. 5-2  55 Figure 5-14: Fournier Na/K geothermometry equation  Table 5-1: Clarke Lake- geothermometry data and results. No. Well Licence K (mg/L) Na (mg/L) Na/K BHT (°C) t geothermometry (°C) 1 17878 121 428 3.54 108 326 2 16622 20 1300 65.00 110 96 3 14245 65 383 5.89 110 267 4 11322 9.5 486 51.16 106 108 5 10637 4.6 23 5.00 108 285 6 08778 10.2 91 8.89 113 227 7 08151 20 129 6.45 115 258   56  Figure 5-15: Comparison of estimated temperature by geothermometry with measured BHT, Clarke Lake In Figure 5-15, the measured and estimated temperatures for the Clarke Lake wells are compared. Except for two wells, there is a significant over-estimate of the BHT compared to the measured level. Ignoring these two wells, the average estimated geothermometry temperature is ~250˚C. Three hypotheses can be put forward to support this significantly higher temperature estimate: 1. It is probable that the geothermal fluid ascends or circulates from a deeper level than that of the bottom-hole position of each well. As a result, the actual temperature of the geothermal fluid is closer to the geothermometry temperature (~250˚C). Hence, geothermometry indicates the water source is deeper than the bottom-hole elevation.  2. The measured BHTs of the wells are all about 100˚C which is the boiling point of water. Part of the difference between recorded and calculated BHT may be due to the sudden release in pressure within the reservoir by the well as it  57 entered the underground formation. This would cause the geothermal fluid to boil and the bottom-hole temperature would then drop to 100˚C from the actual temperature.  3. A third possibility may be the time at which the BHT was measured. During drilling, mud is injected into the drill stem to decrease friction and retrieve rock cuttings. Hence, the temperature of the geothermal fluid decreases temporarily. If the BHT is measured immediately after drilling, it will not show the correct temperature of the geothermal fluid which is actually higher. Table 5-2: Milo- geothermometry calculation No. Well Licence K (mg/L) Na (mg/L) Na/K BHT (°C) tgeothermometry (°C) 1 14663 107 728 13.9 135 190 2 14587 3.8 58 16.0 139 180 3 14584 172 2357 5.80 136 269 4 13616 850 138 0.48 126 773 5 12866 499 166 0.54 133 729 6 12639 0.3 42 30.0 125 138 7 09227 891 17,500 8.88 102 227 8 07830 2520 18,900 2.80 118 357  The temperatures estimated by the Na/K geothermometry equations for the Milo gas field are shown at Table 5-2. The measured and estimated temperatures of Milo are compared in Figure 5-16. Ignoring the outliers (wells 13616 and 12866), the estimated temperatures by Na/K geothermometry show higher temperatures than measured.  58  Figure 5-16: Comparison of estimated temperature by geothermometry with measured BHT at the Milo gas field. Since accuracy of geothermometry severely depends on water sampling processes, certainly, more precise water analysis tests are needed. We hypothesize the origin of geothermal fluid at depth may significantly possess a higher temperature than that measured. However, since the reliability of the data collected from the recorded borehole logs is questionable, a definite conclusion cannot be made based on geothermometry calculations. This however, warrants further research.       59 6 Discussion The temperature gradient maps in conjunction with the fluid data collected from the wells and data from regional geology surveys (Lonnee & Machel, 2006a) present two possible options to extract geothermal energy from the Clarke Lake and Milo gas fields:  EGS technology: Drilling to the deep hot-temperature zones;  Hydrothermal system (GES): Using a shallower medium-temperature geothermal reservoir The following sections discuss both of these scenarios, but before this discussion, the reasons behind some geothermal anomalous observed on the Clarke Lake temperature gradient map are presented. After discussing all possible geothermal scenarios at Clarke Lake and Milo, the two fields are compared to find the best candidate for further study. 6.1 Clarke Lake Temperature Gradient Map Since the bedrock is consistent throughout the Clarke Lake gas field, the temperature gradient distribution in the map should be continuous. As shown in Figure 6-1, there are some anomalous points in the map that show a lower temperature gradient comparing to their surrounding points. This inconsistency may be due to differences in “time-after- drilling” that the BHT measurement was taken. If a measurement is taken immediately or shortly after drilling, it may not represent the true formation temperature (considering the cooling effect of the drilling fluids). However, due to the nature of ground heat flow, sharp differences between nearby wells may indicate the existence of subsurface fracture joints or other geological differences.  60  Figure 6-1: Slave Point reef edge and the approximate limit of pervasive dolomitization, Clarke Lake gas field, B.C., Canada  Geological studies by Lonnee & Machel, (2006a) in the Slave Point Formation (where the Clarke Lake gas pool is located) indicated high-temperature matrix dolomitization in the area. Figure 6-1 shows that lower gradient zones are located within the region of dolomitized carbonates of the Slave Point Reef edge as estimated by that study. Thermal conductivity is a function of geology. Geological alteration which increases thermal conductivity will decrease the temperature gradient of the area (Gupta & Roy, 2007). Dolomite and dolostone possess high thermal conductivities of 5.5 W/m.K and 3.8 W/m.K respectively which is double that of the estimated regional thermal conductivity (Jessop et al., 2005). The lower temperature gradients in the south and central zones of the field may be the result of thermal conductivity differences. More studies are needed to corroborate this assumption.   Unusually Low Temperature gradient  61 6.2 Recovery of Geothermal Energy from Existing Gas Wells Geothermal energy production requires extensive up-front costs mainly because of drilling, so the use of the existing gas wells for geothermal energy production purposes can reduce the capital cost of a geothermal project depending on supply and demand. Well-depth, bottom-hole temperature, water flow-rate, and well status (diameter, casing, condition, etc.) are among the most important criteria to choose appropriate wells for geothermal purposes. As well, the growing cost of water handling as a waste product from the oil and gas business might economically justify this study. To the oil industry, producing hot water is a nuisance. It is difficult to handle, costs money to pump, and must be re-injected at additional costs. Figure 6-2 shows the increasing rate of the water production in WCSB from 1957 to 2007. The term “water cut” (WTR Cut) refers to the ratio of water produced to the volume of total fluid produced from a well.  As the diagram shows the growing trend of water cut has decreased oil and gas productions in WCSB. The high cost of water handling and associated difficulties are major reasons that wells are shut down.  62  Figure 6-2: Water production in WCSB, (from Craig Dunn, 2007) To investigate if the wells are appropriate for geothermal purposes, the amount of water flow rate and wellhead temperature is needed. The total energy flux can then be calculated to determine possible heat distribution and electrical generating capacities. Energy flux represents the rate of energy transfer through the wells. The amount of heat energy that can be released from the water is calculated from the second law of thermodynamics: ∆Q= m × Cp× ∆T               Eq. 6-1. where Q is the heat energy from the water, m is the water flow rate, Cp is the specific heat capacity of the water, and ∆T is the temperature difference between the in-coming and returning-water.  63  Figure 6-3: Central facilities at Clarke Lake gas field, B.C., Canada There are two central facilities (Clarke Lake and Archer Central Facilities) within the Clarke Lake gas field used to segregate extracted gas and water. 46 wells are connected by pipeline to the Clarke Lake Central Facilities (CLK) while 12 producing wells feed the Archer Central Facilities.  The dry raw gases produced from both facilities then feed the Westcoast Fort Nelson Plant where the gas is prepared for transmission to market. Figure 6-3 shows the Clarke Lake facilities and the gas-gathering system. Clarke Lake Central Facilities Archer Central Facilities Westcoast Ft. Nelson Plant  64 6.2.1 Clarke Lake Central Facilities (CLK LK Central) This section integrates the temperature and water flow rate information from MEMPR (2008) and from personal communications with Mr. Nevin Weist, a Reservoir Engineer for Petro-Canada Oil and Gas looking after the Clarke Lake Field. Clarke Lake central facilities (CLK LK Central) (Figure 6-3) are located in the north part of the gas field; the wells are connected by two non-insulated underground pipelines to the CLK LK Central. Table 6-1 shows SCADA (Supervisory Control and Data Acquisition) snapshots of the operating conditions of the CLK LK Central wells. The table illustrates wellhead pressures, temperatures and production rate (water+ gas) data. Note the wells produce both water and gas in two phase flow down a common pipeline. According to the SCADA snapshots, there is a range of wellhead temperature recorded for the wells. According to personal communication with Weist N. (2009), the wells with higher water to gas ratio tend to have higher temperatures as a result of the higher heat content of water relative to gas. Various factors control the water/gas ratio from each well; the most important being size of the aquifer, gas production rate, initial reservoir pressure, and permeability of the formation (Al-Hashim, 1988). Studies performed by Johnstone (1982) on Clarke Lake wells noted an average water wellhead temperature of 82˚C in 1982.  As a result of a greatly reduced flow rate since 1982, the average wellhead temperature has come down for the majority of the producing wells in the region. Although there are still some wells where the temperature exceeds 82 °C, most of these are connected to the CLK LK North part of the plant.   65 Table 6-1: SCADA snapshot, CLK LK Central, NE B.C. Source: Weist, N. (2009)   Wells code Surface temp. (°C) Surface pressure (kPag) Fluid flow (water+gas)E3m3/d CLK LK Central- North Part c-88-L 14.97 2567 0.825 a-92-I 92.87 2507 30.46 a-10-D 86.16 2585 23.57 b-8-D 71.29 2778 118 a-65-L 67.49 2853 0 d-96-L 75.07 2704 12.12 b-72-L 83.43 2873 100.2 b-97-L 68.19 2643 23.17 a-77-L 88.74 2633 57.99 d-72-L 62.37 2832 37.16 b-75-F 83.81 3379 100.9 c-14-F 83.18 3825 78.67 a-56-B 0 0 0 CLK LK Central  - South Part a-94-I 56.62 2532 49.53 a-94-I 84.29 2419 26.66 a-52-J 4 2.527 0 a-A53-J 4.7 15.16 0 a-56-J 28.07 3961 25.17 a-53-J 40.47 2923 48.83 d-31-K 0 0 0 d-27-J 15.84 4217 12.62 b-46-J 17.22 3997 0 c-43-J 31.37 2912 0 a-51-J 13.26 2840 8.337 b-70-I 3.25 2821 0 c-78-I 36.41 2731 166.2 c-87-I 13.38 2639 7.66 c-73-I 79.84 2603 113.2 b-57-I 9.22 2970 2.507 b-18-I 43.76 2965 72.55 c-20-I 73.4 2945 58.92 b-22-J 51.41 2934 21.46 d-21-J 36.86 2887 22.52 c-29-I 25.57 2956 27.41 b-48-I 53.41 2905 43.84   66 The temperatures recorded by the SCADA snapshots are taken at Meter Run buildings at each wellhead which are 20-30 m from the wellhead. As such the readings are probably lower than the actual wellhead values during the winter. The piping is bare steel above the ground from the wellhead to the meter run building before going underground to the gas gathering pipeline and so heat losses are high (Figure 6-4).  Figure 6-4: Meter-Run building, Clarke Lake gas field, NE B.C., Canada With the current gas gathering system, all the extracted water-gas from the wells comes together at one location. Attempting to isolate the production from wells with high temperature fluid is impractical. As well, the non-insulated underground pipelines significantly accelerate the decline in fluid temperature during transmission.  67 To separate water from gas, the Clarke Lake Central Facilities consist of a two phase inlet separator, a compressor and cooler and a dehydrator. The gas-water inlet temperature varies from 47-57 °C with a pressure range of 2,200- 2,500 kPa. The water at almost the same temperature (40-50 °C) is then injected back to the reservoir through a disposal well called b-69-L. The average water flow rate from current producing gas wells are given in Table 6-2. The data show that water flow rates have increased somewhat from 2006 to 2008. Since wells with high water flow rate are being closed, the water volume trend shows a decline at the end of 2008 and beginning of 2009. Overall, from 2006 to 2009, the average flow rate has varied between 2,500 and 4,000 m3/d (Appendix 2). Table 6-2: The average of water flow rate from producing gas wells connected to CLK LK Central, NE B.C. Average: 2008 2007 2006 m 3 /d 3644 3242 3023 L/s 42.1 37.5 34.9 Source: (Weist, 2009)  These measurements likely reflect a minimum water flow rate due to a large number of wells being shut-down periodically (average of two months/year). Currently, of the roughly 46 wells that are connected to the Clarke Lake Central Facilities only 24-26 wells are still producing. The separated water after CLK LK Central has a temperature range between 40- 50 °C. According to the above water flow rate data, a range of 35- 42 L/s is typical.   68 6.2.2 Archer Central Facilities The temperature and water flow rate data in this section are provided from personal communication with the reservoir engineer of Petro-Canada Oil and Gas (Wiest, 2009) who is in charge of the Clarke Lake gas field. There are currently 12 producing gas wells that feed the Archer Central Facilities. The facilities consist of similar equipment such as inlet separator, compressor and cooler and dehydrator. The SCADA snapshot of operating condition is shown in Table 6-3. Wellhead temperature, pressure, and production (gas+ water) rate are illustrated in these SCADA snapshots. Table 6-3: SCADA snapshot, Archer Central Facilities, NE B.C. Source: Weist, N. (2009) Wells code Surface temp. (°C) Surface pressure (kPag) Fluid flow (water+gas)E3m3/d c-54-F 81.16 3855 80.54 c-52-F 90.36 3670 58.5 d-66-G 88.64 3087 94.27 a-54-G 58.18 2689 21.21 a-51-G 2.73 2732 0 c-58-H 22.18 6250 32.35 c-69-H 57.38 5991 106.4 d-72-G 14.27 2852 0 c-A76-H 44.71 3190 55.74 a-81-G 17.01 2946 24.62 a-83-G 69.98 5878 83.78 a-92-G 47.03 3005 8.56  Similar to CLK LK Central, the fluid temperatures were measured 20-30 m from the wellhead and the same non-insulated underground pipeline approach is used to connect the wells to the Archer Central Facilities. The separated water from the Archer inlet separator is injected back to the reservoir through two disposal wells (a-65-G, d-74- G).  69 The average water flow rate to the injection wells is shown in Table 6-4. Similar to that of Clarke Lake, the water flow rate has increased from 2006 to 2008. The total water flow rate from Archer was about 15 L/s in 2008 (see Appendix 2).  Table 6-4: Average water flow rate from producing gas wells connected to the Archer Central Facilities, NE B.C.  Average: 2008 2007 2006 Well No. d-74-G M 3 /d 683.64 615.67 549.96 L/s 7.9 7.1 6.4 Well No. a-65-G m 3 /d 596 546 545 L/s 6.9 6.3 6.3 Source: (Weist, 2009)  6.2.3 Possible Applications The beneficial amount of energy flux that can be extracted from the geothermal water depends on economic and technical factors, and the type of demand. As mentioned in Chapter 2, a temperature of at least 74 °C is required to generate geothermal electricity using a Binary Cycle power plant. With the current non-insulated gas/water gathering pipelines that mix all high and low temperature production together (from 15- 92 °C), using this hot water from CLK LK Central and Archer Central Facilities to generate electricity is not feasible with present technology. The alternative would be direct geothermal heating and/or the use of heat pumps. Low to medium temperature (~50-150°C) geothermal fluids can be used for direct use applications while temperatures below this range are typically upgraded using heat pump technology. In supplying heat, the proximity to demand is an important factor because of heat lost during pumping between the field and demand location. The CLK  70 LK Central and Archer Central Facilities are located about 11 and 17 km respectively from Fort Nelson. As such, using heat pumps represents the only practical application. The fluid would be transmitted through the pipeline from the field to Fort Nelson. Several factors must be considered to design the pipeline: these include dissolved chemicals in the fluid, pipe material, pipe diameter, installation method, head loss, temperature, heat loss, and insulation requirements. Choosing a suitable pipe material depends on durability, fluid temperature, and dissolved chemical constituents. Potential materials are asbestos-cement (AC), ductile iron (DI), steel (S), polyvinyl chloride (PVC), and fiberglass reinforced plastic (FRP). There are two installation methods; buried or above-ground. A buried pipe system is more common with the advantage of security from intentional or accidental damage as well as providing natural insulation. The main disadvantages are cost and poor accessibility for maintenance. A major concern with the pipeline is the heat and pressure loss. The temperature difference between fluid in the pipe and ambient air or soil drives heat loss, but water flow rate also plays a major role. Because of the cold climate, the pipeline should be buried. Figure 24 (after Ryan, 1981) shows that for a 76°C inlet temperature and a flow rate above 20 L/s, the temperature will drop by ~0.36°C/km for a 154-mm diameter, insulated pipe (46-mm insulation, PVC jacket, FRP carrier pipe). This would give a drop of 4°C for 11 km and 6°C for 17km. Therefore, in downtown Fort Nelson, the temperature would be ~34-46 °C for Clarke Lake water and ~30-40 °C for the Archer Central Facility waters.  71  Figure 6-5: Buried pipeline temperature loss versus flow rate (after Ryan, 1981) One or more pumps distributed across a number of pumping stations can be used to maintain pressure. Assuming a pipe diameter of 8-in, the construction (material and installation) cost for 11km will be about $5.74million. If the project serves 300 users, the Internal Rate of Return (IRR) would be 5% which is too low to justify district heating. The preliminary assessment can be viewed in Appendix 3. Low water flow, inadequate temperature, and demand distance mean that water from the Clarke Lake gas field is not a practical proposition to supply heat to the city of Fort Nelson. 6.3 Hydrothermal Reservoir The measured temperature and water flow rate after CLK LK Central and Archer Central Facilities are inadequate to generate electricity. To generate a greater amount of electricity, drilling specifically for geothermal purposes must be considered. Gas and water production from Clarke Lake are from dolomitized carbonates of the Middle Devonian Slave Point Formation (Johnstone, 1982; Lonnee & Machel, 2006a).  72 At Clarke Lake, the Slave Point Formation begins at depths of about 2000 m (Lonnee & Machel, 2006b). Early studies indicated that a halite brine aquifer within the Clarke Lake field mixes with meteoric fluid recharge from the Rocky Mountains. Geological studies on high-temperature matrix dolomitization in the Slave Point Formation specifically at Clarke Lake show that the temperature of origin fluid may range from 140- 200 ºC at depth. This range of temperature is sufficient for Binary Cycle and potentially hot enough for a Flash Steam power plant. Dolomitized sections typically provide adequate porosity and permeability for water mobility at depth (Johnstone, 1982). If a geothermal project at a depth similar to that of the gas wells is selected for further study, a Binary Cycle power plant could certainly be used to generate power. In Section 5.4 of the thesis, geothermometry calculations considered the possibility of a high-temperature geothermal fluid (about 250 ºC) at some depth below the average bottom hole location but connected thereto. Because of the small number of wells with available water chemistry data (only 7) and the unknown sampling circumstances of each data set, the results should be considered hypothetical. Despite this, there is literature evidence (Lonnee & Machel, 2006a) to support this possibility. Further studies should determine the exact status of underground water at Clarke Lake and Milo with respect to water volume, pressure, and chemistry. These data are needed to determine the actual energy flux available in the reservoir, the optimal water flow rate to extract energy, the preferred geothermal well diameter, and also to investigate whether the aquifer is truly of an economic size with respect to fluid availability and permeability. A deeper reservoir is recharged by a larger catchment area. Further drilling and investigations should be done at Clarke Lake and Milo. Due to the potential demand for both geothermal heat and electricity in the area, additional heat recovery following power generation may contribute to the economics of the project.  73 6.4 EGS Technology The average measured temperature gradients for Clarke Lake and Milo are 54 ºC/km and 47 ºC/km respectively. These levels suggest a significant potential for commercial geothermal power generation. The average depth of the existing gas wells at Clarke Lake and Milo are 1,946m and 2,519m respectively containing groundwater with an average bottom-hole temperature of 110 ºC. With deeper geothermal drilling (3,500 to 4,500 m), it is possible that a flash steam plant could generate a larger amount of power from depths where the temperature is above 200 ºC. The potential is likely comparable to the Soultz-Sous- Forets Enhanced Geothermal Project (Cuenot et al., 2008). However, due to the higher average temperature gradients at Clarke Lake and Milo (54 ºC/km and 47 ºC/km respectively) than at Soultz, drilling for enhanced geothermal generation will be less expensive. For example, to reach a temperature of 200 ºC, the well depth is estimated as 4.2 km at Milo and 3.7 km at Clarke Lake compared to 5.0 km at Soultz. Further studies are required to delineate other factors such as the existence of an economic quantity of hot fluid and adequate permeability at deep levels. Enhancing the reservoir quality (creating artificial permeability and/or injecting working fluid) may be required. The feasibility of a geothermal project depends on both economic and technical justifications. Some of the important decision-making factors include proximity to a demand-centre and proximity to electric power transmission facilities, as well as thermal energy content of the reservoir. The proximity of the study area to power lines (B.C. Hydro integrated system and Alberta electric system operator (AESO)) enhances the economics of a geothermal power project in the region. A high-temperature geothermal reservoir can provide both heat and electricity for nearby communities (such as Fort Nelson) and industries. Complementary studies are required in order to validate the thermal energy content of the reservoir at deep levels. Such additional studies are outside the scope of this study,  74 however the temperature gradient maps can be applied for preliminary assessment of the reservoir. The aim of the following section is to conduct this exercise. 6.4.1 Resource Assessment Based on the Clarke Lake and Milo temperature gradient maps (Figure 5-1 and Figure 5-2), ArcGIS can be used to estimate the subsurface temperature at any point in the field at a given depth. To assess the total heat capacity of a geothermal reservoir, the following basic assumptions are considered:  Required temperature: above 200°C (adequate for flash steam power);  Production well depth: 3.5 km to 4.5 km (based on current drilling technology and average regional temperature gradient required to achieve 200 °C with current data). Each map was sub-divided into different temperature contour intervals of 10°C. Those zones with temperatures above 200°C increase in size with depth as would be expected. Of course, additional drilling is necessary to confirm this trend. If we consider that each contour zone extends over a depth of 100m, the size of the reservoir between 3.5 km to 4.5 km at temperatures above 200°C can be estimated. The following assumptions are used to calculate the total heat capacity of the region:  In-situ rock density (ρ) ranges between 2300 to 2700 (kg/m3) (the average for sediment and sandstone rocks);  Specific heat capacity is 0.92 kJ/kg.K (typical dolomite rock and sandstone);  Heat energy available in each zone is a function of resource temperature change over time, rock mass, and the specific heat capacity (∆Q= m × Cp × ∆T or ∆Q= (ρ × V) × Cp × ∆T);  Each zone above 200°C that is affected by a drilled well will be operated such that at the end of the energy extraction period (20-40 years), the affected area  75 cools down to 200°C – following which the well be allowed to rest for a time sufficient to restore the original zonal temperature (from 40 to 100 years).  The volume of regions with increasing temperature from 200 to 290°C (the highest temperature estimated at Clarke Lake) is measured on an areal basis for temperature ranges of 10 °C and then summed. The total heat capacity of each level of the reservoir is: ∆Q total= ( mi 290 i=200 ×(Ti – 200))× Cp   Eq. 6-1. The preliminary heat capacity estimation in this study is limited by the following parameters:  A temperature resolution of 10 °C is coarse and the estimate would likely improve for a range of 1°C (Figure 6-6);  A depth of 100m per level is also coarse and improvement would occur if 10m depths were used.  The geothermal regions are calculated only to the boundaries of the gas field leases.  Figure 6-6:  Temperature zones at depth 4.5 km- Clarke Lake  76  Figure 6-7: Quantity of heat capacity with depth at Clarke Lake.   Figure 6-8: Quality of heat capacity with depth, Clarke Lake  0 500 1000 1500 2000 2500 3000 3500 4000 4 H e a t C a p a c it y  ( P J ) Depth (km) Density 2300 kg/m3 Density 2700 kg/m3 190 200 210 220 230 240 250 260 270 3.5 3.6 3.7 3.8 3.9 4 4.1 4.2 4.3 4.4 4.5 A v e ra g e  W e ig h te d  t e m p . (° C ) Depth (km)  77 Table 6-5 shows the preliminary reservoir assessment for Clarke Lake. The heat energy of the zones which will cool down to 200 °C following the extraction period is estimated at 22,114 to 25,667 PJ. Figure 6-7 and Figure 6-8 show that both the quality and quantity of the heat energy in the reservoir increases as deeper levels are penetrated. For comparison purposes, a similar calculation was done for the Milo gas field. However, as can be seen in Table 6-6, both the resource heat content and its quality are significantly lower at Milo than Clarke Lake and the resource must be drilled to a greater depth. Appendix 4 contains estimated temperature maps at depths of 3500m, 4000m, and 4500m which were used to assess the reservoir.  78 Table 6-5: Preliminary reservoir assessment, Clarke Lake gas field, B.C., Canada   Area (km 2 ) Heat Capacity (PJ) Depth (km) Temp. Range 200- 210°C 210- 220°C 220- 230°C 230- 240°C 240- 250°C 250- 260°C 260- 270°C 270- 280°C 280- 290°C Total area (km 2 ) Density 2300 kg/m3 Density 2700 kg/m3 3.5 116-228 8 238 6 0 0 0 0 0 0 252 796 934 3.6 119-235 7 239 7 0 0 0 0 0 0 253 803 943 3.7 123-241 2 23 227 2 0 0 0 0 0 254 1291 1515 3.8 126-248 1 6 104 149 1 0 0 0 0 261 1683 1683 3.9 129-254 1 5 104 153 1 0 0 0 0 264 1710 2007 4 133-261 0.5 2 14 204 35 1 0 0 0 257 1937 2273 4.1 136-267 0.5 1 5 59 197 4 1 0 0 268 2403 2821 4.2 139-274 0.5 1 6 51 208 5 1 0 0 272.5 2466 2894 4.3 143-280 0 0.6 1 10 101 147 2 0.5 0 262.1 2789 3274 4.4 146-287 0 0 0 4 21 157 76 1 0.5 259.5 3127 3671 4.5 149-293 0 0 0 3 20 157 76 1 0.5 257.5 3110 3651          Sum (PJ)  22114 25667     79 Table 6-6: Preliminary reservoir assessment, Milo gas field, B.C., Canada     Area (km^2) Energy (PJ) Depth (km) Temp. Range °C 200-210 °C 210-220 °C 220-230 °C Total area km 2  Density 2300 kg/m3 Density 2700 kg/m3 4 173-213 0 0 0 0 0 0 4.1 178-218 200 0 0 200 212 248 4.2 178-218 75 130 0 205 492 578 4.3 182-223 83 125 0 208 485 569 4.4 186-228 34 76 144 254 1039 1220 4.5 190-234 42 86 148 276 1100 1292    Sum (PJ)  3327 3906  80 The energy at Clarke Lake is calculated over a large area (about 280 km2) and the amount of this energy that can be extracted for conversion into electricity depends on technical, economic, and design factors including rock mass permeability and the availability of fluids at depth. It is considered reasonable to assume that only 10% of the total estimated heat energy within Clarke Lake is extractable (about 2,200-2,500 PJ). To determine the quantity of electricity that can be derived from this thermal resource, we can apply the Carnot efficiency calculation. The following assumptions are used to calculate the power plant efficiency: Hot water source temperature: 215 °C (based on reservoir temperature) Cold water source temperature (condenser): 40 °C Average t hot = 273.15+ 215°C =488.15 K Average t condenser = 273.15+ 40 °C = 313.15 K µ = (t hot - t condenser)/ t hot = ((488.15-313.15)/488.15) × 100= 36% The theoretical Carnot efficiency of 36% is unrealistically high as it does not account for other losses and efficiency factors. Therefore a more conservative approach is taken and the extractable heat to electricity is considered to be 10% since a variety of technical and environmental constraints will not allow all the extracted heat to be converted into electricity. By assuming a power plant lifetime of 25 years, there is the possibility to develop a power plant with a capacity of 280 - 325 MW over the production period. A summary of this calculation is as follows:       81  The total heat capacity over 280 km2 (cooled down to 200°C):                                                  22,114 to 25,667 PJ      (79.0 to 91.7 PJ/km2)   Extractable heat from the reservoir (10% of the total heat capacity): (22,114 to 25,667 PJ) ×10% = 2,211.4 to 2,566.7 PJ   Extractable heat for each production year: (2,211.4 to 2,566.7 PJ)/ 25 = 88.5 to 102.7 PJ/year = (24.6 to 28.5) × 106 MWh/year   Sustainable power plant capacity: ((24.6 to 28.5 × 106 MWh/year) × 10%) / (365 × 24 h/year) ≈ 280 to 325 MWe   Annual Electricity Generated: ((280 to 325 MW) x 365 x 24 x 0.8) = 1,962,240 to 2,277,600 MWh Assumption:  Production lifetime: 25 years Assumption:  Heat to electricity conversion: 10% Assumption:  Power plant capacity factor: 80% Assumption:  10% of resource can be extracted  82 To further demonstrate the potential of the Clarke Lake reservoir to generate electricity, the study area is compared to the Petratherm project located in Paralana, Southern Australia with almost identical conditions (Table 6-7). Resource modeling at Paralana suggests that a 1-km-thick block with a surface area of 20 km2 at an average temperature of 200°C could support power generation of 520 MWe over 25 years (Goldstein et al., 2008; Grant et al., 2008; Petratherm Limited, 2009). Table 6-7: EGS project, Clarke Lake, B.C. vs. Paralana, South Australia  Paralana Clarke Lake Expected depth of temp. above 200 °C 3.6 km 3.7 km Geology Sedimentary and Granite rocks Sedimentary rocks Extractable energy assumption 2,273 PJ 2,211 - 2,567 PJ Potential power plant capacity 520 MWe 280 - 325 MWe Planned power plant capacity 260 MWe 250 MWe Assessment area 500 km2 280 km2 Average geothermal gradient 50 °C/km 54 °C/km Production well depth 3.6 km 4.0 km est. Injection well depth  4 km 4.5 km est. Source: Petratherm Limited, 2009 6.4.2 Managing the Resource The thermal analysis of the resource at Clarke Lake indicates a sustainable heat conversion to electrical capacity between 280 to 325 MW. In order to understand how this resource should be exploited over time, it is necessary to generate a scenario of how the resource should be drilled.  83 The potential electrical generating capacity of a well at Clarke Lake is estimated to be about 10 MW or less (see Appendix 6). Assuming this level is achievable, the suggested resource plan is for an eventual plant capacity of 250 MW by initially drilling 5 production wells and 2 reinjection wells and then adding an additional 5 production wells every 5 years with a similar number of reinjection wells. By continuing this for 25 years, the generating capacity will grow from an initial 50 MW to 250 MW in line with the previously calculated sustainable resource capacity. At that time the initial 5 wells can be closed down to allow the resource to recover its lost heat. Appendix 5 contains a cash flow analysis of what such a schedule will cost in terms of capital and operating and maintenance. Assuming an 80% capacity factor, the initial annual electricity generation will be 350,400 MWh growing to 1,752,000 MWh in years 21 through 25 and forever thereafter. All wells will be managed such that the extraction of energy will only reduce the temperature of any zone to 200 °C over a 25-year period of operation. The after-tax Internal Rate of Return (IRR) for this investment schedule is estimated at 12.6% which is a reasonable return on investment for this type of energy resource and for this “order of magnitude” calculation. The resource can be sustained for many years if it is exploited at this rate. 6.5 Clarke Lake vs. Milo Figure 6-9 and Figure 6-10 illustrate an increasing trend of temperature with depth in both the Clarke Lake and Milo gas fields. As depicted, the Clarke Lake potential to generate electricity using binary power plant is higher than Milo with the lower depth and the higher temperature. The water data was not available for Milo, but according to the average temperature gradient, the required depth to obtain temperatures suitable for a Binary Cycle power plant is less for Clarke Lake as compared to Milo (Table 6-8)   84 Table 6-8: Comparison of Clarke Lake and Milo geothermal potential.  Clarke Lake Milo Number of wells 54 16 Temperature Gradient 54 ºC/km 47 ºC/km Binary Cycle Power Depth Temperature  1500 m  2000m 74-165 ºC 74-133 ºC EGS technology temp. >200 ºC: Depth Estimated  heat capacity Estimated power plant capacity  3.7 km 22,000-25,000 PJ 280-325 MWe 4.2 km 3,300-3,900 PJ 33-39 MWe  In the case of a deep geothermal project (EGS), Clarke Lake shows an estimated power plant capacity 6 times greater than Milo and at a shallower depth (see Appendix 5 for comparison maps). According to these results, Clarke Lake is the better candidate for further geothermal studies.   85         Figure 6-9: An increasing trend of temperature with depth, Clarke Lake gas field,        Figure 6-10: An increasing trend of temperature with depth, Milo gas field.  Binary Cycle potential Binary Cycle potential  86 7 Conclusion This study was initiated to prepare a database to indicate the potential to extract geothermal energy technically and economically from existing oil and gas wells at Clarke Lake and Milo gas fields in northeast British Columbia. The following set of conclusions can be derived from this work:  A. Generating data from oil and gas wells: 1.  The results of this study demonstrate that useful geothermal data can be gathered from existing oil and gas well logs in northeast British Columbia and that this approach may prove usefully applied in other regions (Fort St. John for example). 2 .  The data collected has proven successful in generating useful temperature gradient and heat flow maps for two oil and gas fields - Clarke Lake and Milo. These maps demonstrate that a potentially-exploitable geothermal resource exists at Clarke Lake. 3 .  The study demonstrates the utility of GIS software to present and analyze geological data relevant to geothermal energy exploitation.  B. Exploitation of geothermal energy from existing oil and gas wells: 4.  The analysis shows that with the current gas/water gathering system, generating electricity from water ascending to surface through operating gas wells is not practical. 5 .  Although adequate temperature and water flow exists to service a district heating system; the distance of 11-17 km to Fort Nelson from the gas plant facilities is too great to economically justify the investment.  87 6 .  Data from this research and past work show that the origin of underground water may have adequate temperature for a Binary Cycle power plant and potentially sufficient to supply a Flash Steam power plant. More study is needed to assess the possible hydrothermal reservoirs beneath the Clarke Lake field. More detailed economic and technical analyses are needed to justify such a project. 7 .  Due to the cold climate in north-east B.C., there is a potential demand for both geothermal heat and electricity in the area. Additional heat recovery following power generation may improve the economic viability of the project.  C. Exploitation of the known resource at Clarke Lake: 8.  The study has verified that a geothermal anomaly exist beneath the Clarke Lake gas field that can be economically and technically exploited in a sustainable fashion by drilling to 3.5 to 4.5 km. 9 .  The preliminary reservoir assessment in this study demonstrates that there is a possibility to operate a 280 to 235 MW power plant over a 25 year period in a sustainable and economic manner.         88 8 Recommendations Further work in the following areas would be beneficial:  1 .  An opportunity exists to gain useful geothermal data through the analysis of oil and gas borehole log records. A database with information from other oil and gas wells should be processed using the same methods presented in this study to produce similar maps for all of northeast B.C., thereby avoiding expensive exploratory drilling costs. Fort St. John is a suggested location to replicate the methods developed in this study.  2 .  The work suggests with good reliability that exploration/exploitation drilling should be done to verify the conclusions made about the geothermal anomaly and to obtain information about permeability and fluid availability at depth.  3 .  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Landolt-börnstein - group VIII advanced materials and technologies (pp. 493-548) Springer Berlin Heidelberg. doi:10.1007/b83039  93 Holdmann, G., & List, K. (2007). The Chena Hot Springs 400kW geothermal power plant: Experience gained during the first year of operation. Geothermal Resources Council Transactions, 31 Idaho National Laboratory. (2009). Geothermal energy. Retrieved Jan/09, 2009, from www.inl.gov/ International Geothermal Association: Dikson, M.H, & Fanelli, M. (2009). What is geothermal energy? Retrieved 07/01, 2009, from http://www.geothermal- energy.org/geo/geoenergy.php Jessop, A. (1995). Geothermal energy from old mines at Springhill. Geoworld, Proceedings of World Geothermal Congress, 463-468. Jessop, A., Ghomshei, M., & Drury, M. (1991). Geothermal Energy in Canada. Geothermics, 20(5-6), 369-385. Jessop, A.M., Lane, L.S., & Majorowicz, J.A. (2005). Regional heat flow pattern and lithospheric geotherms in northeastern British Columbia and adjacent Northwest Territories, Canada. Bulletin of Canadian Petroleum Geology, 53-1, 51-66. Johnstone, M. C. (1982). Study on the feasibility of using middle Devonian formation water from Clarke Lake gas field, N.E. British Columbia, as a geothermal energy resource No. 11698) Ministry of Energy, Mines and Petroleum Resources. Kontoleontos, E., Mendrinos, D., & Karytsas, C. (2007). Optimized geothermal binary power cycles. Proceedings of the ENGINE Mid-Term Conference. Potsdam, Germany, 9–12. Lonnee, J., & Machel, H.G. (2006a). Pervasive dolomitization with subsequent hydrothermal alteration in the Clarke Lake gas field, middle Devonian slave point formation, British Columbia, Canada. AAPG Bulletin, 90, 1739-1762. Lonnee, J., & Machel, H.G. (2006b). Mixing of halite brines with meteoric water in the Clarke Lake gas field, Canada. J. Geochemical Exploration, 89(1-3), 243-246.  94 Lund, J.W., & Freeston, D.H. (2001). World-wide direct uses of geothermal energy 2000. Geothermics, 30, 29-68. Lund, J.W. (2005). Worldwide utilization of geothermal energy - 2005. Geothermal Resources Council 2005 Annual Meeting, Sep 25-29, 831-836. Lund, J.W., Freeston, D.H., & Boyd, T.L. (2005). Direct application of geothermal energy: 2005 worldwide review. Geothermics, 34(6), 691-727. Majorowicz, J.A. (1996). Anomalous heat flow regime in the western margin of the North American Craton, Canada. Journal of Geodynamics, 21(2), 123-140. Majorowicz, J.A., & Jessop, A.M. (1981). Regional heat flow patterns in the western Canadian sedimentary basin. Tectonophysics, 74(3-4), 209-238. Meech, J.A and Ghomshei, M.M. (2004). Geothermal Energy Research and Use in Canada. Green Power in Canada Workshop Series: Pollution-Probe, 5, Vancouver, B.C., April 3, 2004, pp.10. Moins, J. (2008). Alaska resort pioneers revolutionary hydrothermal power. Retrieved 09/17, 2008, from http://www.ecogeek.org/geothermal-power/1353 Monastero, F.C. (2002). Model for success. Bulletin. Geothermal Resources Council, 31(5), 188-195. NASA: LaRC GIS. (2009). Geographic information system.www.larc.nasa.gov Petratherm Limited. (2009). Paralana project description. Retrieved 07/01, 2009, from http://www.petratherm.com.au/projects/paralana.htm Pollack, H.N., Hunter, S.J., & Johnson, J.R. (1993). Heat flow from the earth's interior: Analysis of the global data set. Review of Geophysics, 31, 267-280. Rich, J., & Maiangowi, Y. (2008). Fort Nelson resource plan. Retrieved 01/04, 2009, from http://www.bchydro.com  95 Spielman, P. (1990). Design and operation of a data gathering system for the Casa Diablo geothermal reservoir. 1990 International Symposium on Geothermal Energy, Aug 20-24, 14 451-456. Stanford University: Libraries and academic information resources. (2006). Geographical information system (GIS). Retrieved 11/26, 2008, from http://www- sul.stanford.edu/depts/gis/whatgis.html Turkenburg, W.C. (2000). Current status and potential future costs of renewable energy technologies, Table 7.25. World Energy Assessment Report, prepared by UNDP, UN–DESA and the World Energy Council. New York: United Nations. U.S. Geological Survey. (2005). Understanding plate motions. Retrieved 06/15, 2009, from http://pubs.usgs.gov/gip/dynamic/fire.html UNDP, UN–DESA and the World Energy Council. (2000). WEA. World Energy Assessment Report. New York: United Nations. Weist, N. (2009). Water volume from the gas wells at Clarke Lake gas field - personal communication. World Energy Assessment (WEA). (2000). Energy and the challenge of sustainability. New York: UNDP, UN–DESA and the World Energy Council United Nation Development Programme. Worldwatch Institute. (2004). Signposts 2004. Retrieved 05/18, 2009, from www.worldwatch.org/  96 Appendix 1 – Data from the Wells Clarke Lake Gas Field:     Depth (m) No. Licence Well Status Owner TVD MD ∆T(°C /km) BHT(°C) 1 17878 Gas Petro Canada 1948.51 1950 54 108.2 2 16622 Gas Petro Canada 1962.3 2084 54 109.5 3 16358 Gas Petro Canada 1934 2450 54 108.6 4 15212 Gas Petro Canada 2016.4 2057 53 110 5 14252 Gas Petro Canada 1995 _ 53 110 6 14245 Gas Petro Canada 2000 _ 53 110 7 13413 Gas Petro Canada 1979 1979 55 112 8 11322 Gas Petro Canada 1940 1978 53 106.2 9 11136 Gas Petro Canada 1904 2096 55 108 10 10637 Gas Petro Canada 1904.4 1910.6 55 108 11 10346 Gas Petro Canada 1973 2220 46 95 12 10070 Gas Petro Canada 1924.6 2127 54 108 13 10063 Gas Petro Canada 1911 2116 54 106 14 09539 Gas Petro Canada 1960 1963 55 112 15 08778 Gas Petro Canada 1839.5 1866 59 112 16 08226 Gas Petro Canada 1962.46 2036 55 112 17 08151 Gas Petro Canada 1922.3 2136.5 56 110.3 18 07566 Gas Petro Canada 1930 _ 34 72 19 07371 Gas Petro Canada 1973 1973 56 114.75 20 05358 Gas Petro Canada 2033 2266 52 108.9 21 04803 Gas Petro Canada 1945 _ 53 107.2 22 04543 Gas Petro Canada 1858.1 _ 57 110 23 04167 Gas Petro Canada 1920.5 _ 57 113 24 04116 Gas Petro Canada 1917.19 _ 60 118 25 04004 Gas Petro Canada 1906.3 _ 55 108.3 26 03961 Gas Petro Canada 1902 2318 57 111.1 27 03517 Gas Petro Canada 1913 _ 58 113.3  97      Depth (m) No. Licence Well Status Owner TVD MD ∆T(°C /Km) BHT(°C) 28 03452 Gas Petro Canada 1986 _ 54 111.59 29 03378 Gas Petro Canada 1915.45 _ 57 112.79 30 03361 Gas Petro Canada 2030 _ 56 117.5 31 03228 Gas Petro Canada 1986.4 _ 65 132 32 03104 Gas Petro Canada 1946 2275.4 53 107 33 03011 Gas Petro Canada 1947.37 _ 53 107 34 02776 Gas Pacific Petroleum Ltd 1836.5 _ 55 104 35 02540 Gas Pacific Petroleum Ltd 1913.5 _ 56 111 36 02509 Gas Petro Canada 1922.37 _ 56 111.1 37 02316 Gas Pacific Petroleum Ltd 1954.9 _ 53 107 38 02310 Gas Petro Canada 1970.5 _ 55 112.5 39 02249 Gas Petro Canada 1961.39 _ 53 108 40 02239 Gas Pacific Petroleum Ltd 1938.2 _ 54 109 41 02176 Gas Coop. Energy Dev. Corp. 1958.64 _ 34 72 42 02162 Gas Petro Canada 1832.4 2186.9 57 107.7 43 02107 Gas Pacific Petroleum Ltd 1967.5 _ 54 109 44 01966 Gas Petro Canada 1835 1945 55 104 45 01932 Pacific Petroleum Ltd 1988.6 _ 54 111 46 01796 Gas Petro Canada 1906.5 2500 51 102 47 01578 Gas Petro Canada 2033.9 2081.7 56 117 48 01554 Gas Petro Canada 1947.7 _ 56 112 49 01528 Gas Pacific Petroleum Ltd 2004 2043 33 72 50 01274 Gas Pacific Petroleum Ltd 1963.22 _ 55 112.2 51 00856 Gas Pacific Petroleum Ltd 1954.38 _ 53 106.7  98     Depth (m) No. Licence Well Status Owner TVD MD ∆T (°C/Km) BHT(°C) 52 00688 Gas Pacific Petroleum Ltd 1918.9 _ 53 106.1 53 00585 Gas Petro Canada 1996.44 _ 52 107.8 54 00505 Gas Pacific Petroleum Ltd 1991.26 _ 53 110 55 00503 Gas - Abandoned Petro Canada 2026.92 2087.9 53 111 56 00344 Gas  1962.3 _ 56 113.33 Average    1945.91 2105.8 54 107.9 Max    2033.9 2500 65 132 Min    1832.4 1866 33 72    99 Milo Gas Field:     Depth (m) Numbers Licence Well Status Owner TVD MD ∆T(°C / Km) BHT (°C) 1 14788 Gas Crown 2569.5 2650 50 132.49 2 14664 Gas Petro Canada 2841.9 2961 37 111 3 14663 Gas Petro Canada 2801 2965 47 135 4 14587 Gas Marathon Canada Ltd 3131 3631 43 139 5 14585 Gas Marathon Canada Ltd 2844.7 3007 46 134 6 14584 Gas Marathon Canada Ltd 3103 3625 42 136 7 14333 Gas Tikal Resources Corporation 2295 2295 51 120 8 13616 Gas Progress Energy Ltd 2378 2550 51 126 9 12866 Gas Progress Energy Ltd 2389 2405 54 132.85 10 12668 Gas Purcell Energy 2293.9 2725 45 107.85 11 12639 Gas Progress Energy Ltd. 2287.5 2364 53 125 12 09227 Gas Talisman Energy Inc. 2089 2166 47 102 13 08369 Gas AMERADA HESS Canada Ltd 2460 2510 50 126.15 14 07830 Gas AMERADA HESS Canada Ltd 2165 2202 53 118 15 05921 Gas Gulf Canada Resources 2438  41 105 16 01297 Gas Pacific Petroleum Ltd 2225  44 103 Average      47 122 max      54 139 min      37 102  100 Appendix 2 – Average Water Flow Rate from Producing Wells Clarke Lake Central:   0 500 1000 1500 2000 2500 3000 3500 4000 4500 Jan. Feb. Mar. Apr. May Jun. Jul. Aug. Sep. Oct. Nov. Dec. m 3 /d  101 Archer Central Facilities:   Archer Central Facilities:  Jan. Feb . Mar . Apr. May Jun. Jul. Aug . Sep . Oct. Nov . Dec . m3/d(2009) 757. 812. 751. 814. m3/d(2008) 634. 590. 697. 608. 552. 625. 659. 676. 801. 789. 774. 744. m3/d(2007) 444. 466. 411. 465. 1241 687. 749. 608. 491. 590. 615. 616. m3/d(2006) 552. 552. 533. 584. 623. 649. 616. 341. 610. 547. 478. 508. 0.00 200.00 400.00 600.00 800.00 1000.00 1200.00 1400.00 m 3 /d d-74-G Injection Well Jan. Feb. Mar. Apr. May Jun. Jul. Aug. Sep. Oct. Nov. Dec. m3/d(2009) 579. 565. 516. 543. m3/d(2008) 603. 570. 642. 565. 567. 520. 434. 604. 687. 659. 630. 658. 612. m3/d(2007) 285. 438. 391. 677. 639. 610. 574. 633. 562. 548. 588. 603. m3/d(2006) 612. 622. 588. 522. 548. 597. 529. 245. 464. 521. 663. 626. 0.00 100.00 200.00 300.00 400.00 500.00 600.00 700.00 800.00 m 3 /d a-65-G Injection Well  102  Appendix 3 – Cash Flow Analysis of a District Heating System at Clarke Lake Assumptions: Pipeline diameter: 8in                                                                          O & M factor: 0.1 Pipeline length: ~ 35km (25km delivery+10 km distribution)               Taxes rate: 50% Average of Canadian energy consumption: 148 GJ/year                    Users number: 300 Construction and Material costs: ~ $ 50/Linear foot Average of heating price per GJ: ~ $ 9.40  Year  0 1 2 3 4 5 6 7 8 9 10 Cap cost $5,741,450 O& M costs/year  $50,000 $50,000 $50,000 $50,000 $50,000 $50,000 $50,000 $50,000 $50,000 $50,000 Revenue  $417,360 $417,360 $417,360 $417,360 $417,360 $417,360 $417,360 $417,360 $417,360 $417,360 Operating profit  $367,360 $367,360 $367,360 $367,360 $367,360 $367,360 $367,360 $367,360 $367,360 $367,360 taxes  $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Depreciation  $367,360 $367,360 $367,360 $367,360 $367,360 $367,360 $367,360 $367,360 $367,360 $367,360 Depreciation Fund $5,741,450 $5,374,090 $5,006,730 $4,639,370 $4,272,010 $3,904,650 $3,537,290 $3,169,930 $2,802,570 $2,435,210 $2,067,850 Cash flow - $5,741,450 $734,720 $734,720 $734,720 $734,720 $734,720 $734,720 $734,720 $734,720 $734,720 $734,720  Calculated IRR after taxes = 5%  103 Appendix 4 – Estimated Temperature Maps - Reservoir Assessment   Clarke Lake Milo  104   Milo Milo Clarke Lake Clarke Lake  105 Appendix 5 – Cash Flow Analysis of a Managed Resource Strategy at Clarke Lake Assumptions  Capital Cost per production well = $20million This includes all distribution piping as well as drilling one reinjection well for every two production wells  Capital Cost of Generation Plant per production well = $20million This includes all generation plant facilities and any power lines required to take the electricity to the grid  Electrical Capacity MW/well = 10 Capacity Factor = 0.85 Price of Electricity = $100/MWh Income Tax Rate = 50% Additional wells per cycle = 5 Annual decline in well capacity = 1%   Operating and Maintenance Cost = 10% of current plant capital  Tax Rate = 50% Operating and Maintenance Costs = 10% of current capital Depreciation = accelerated  106   Year 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25    No. of Wells = 5  10  15  20  25  25      Capacity MW 0.0 50.0 49.5 49.0 48.5 48.0 97.5 96.6 95.6 94.7 93.7 142.8 141.3 139.9 138.5 137.1 185.8 183.9 182.1 180.3 178.5 226.7 224.4 222.2 219.9 217.7 MWh x1000 0.0 372.3 368.6 364.9 361.2 357.6 726.4 719.1 711.9 704.8 697.7 1063.1 1052.4 1041.9 1031.5 1021.2 1383.3 1369.4 1355.7 1342.2 1328.7 1687.8 1670.9 1654.2 1637.6 1621.3     Revenue $M 0.0 37.2 36.9 36.5 36.1 35.8 72.6 71.9 71.2 70.5 69.8 106.3 105.2 104.2 103.2 102.1 138.3 136.9 135.6 134.2 132.9 168.8 167.1 165.4 163.8 162.1       Cap Costs $M 100.0     100.0     100.0     100.0     100.0     100.0     Power Plant  $M 100.0  100.0  100.0  100.0  100.0  100.0     O&M Costs  $M - 20.0 20.0 20.0 20.0 20.0 40.0 40.0 40.0 40.0 40.0 60.0 60.0 60.0 60.0 60.0 80.0 80.0 80.0 80.0 80.0 100.0 100.0 100.0 100.0 100.0     Op. Prof it     $M - 17.2 16.9 16.5 16.1 15.8 32.6 31.9 31.2 30.5 29.8 46.3 45.2 44.2 43.1 42.1 58.3 56.9 55.6 54.2 52.9 68.8 67.1 65.4 63.8 62.1 Taxes $M - 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 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 1.2 31.1 Depreciation  $M - 17.2 16.9 16.5 16.1 15.8 32.6 31.9 31.2 30.5 29.8 46.3 45.2 44.2 43.1 42.1 58.3 56.9 55.6 54.2 52.9 68.8 67.1 65.4 61.3 0.0 Depreciation Fund 200.0 182.8 165.9 149.4 133.3 317.5 284.9 253 221.8 191.3 361.6 315.2 270.0 225.8 182.7 340.5 282.2 225.3 169.7 115.5 262.6 193.8 126.8 61.3 0.0 200.0       Ann. Cash Flow $M -200 34.5 33.7 33.0 32.2 - 168.5 65.3 63.8 62.4 61.0 - 140.5 92.6 90.5 88.4 86.3 - 115.8 116.7 113.9 111.1 108.4 -94.3 137.6 134.2 130.8 123.9 - 168.9       NPV @ 0%  $M 832.3       NPV @ 7%  $M 173.1  IRR % 13.04   107 Appendix 6 – Idealized Drilling Pattern     Production wells 1 km2 1 km2 1 km2 1 km2 1 km2 1 km2 1 km2 1 km2 1 km2 1 km2 1 km2 1 km2 1 km2 1 km2 1 km2 1 km2 Reinjection wells 1 km 1 km 1 km 1 km  1 km2  square sequence of 5 production and 2 reinjection wells (continuing for 25 year)  Each one km2 is able to produce ~7MWe (according to heat capacity estimation for 280 km2 in Section 6.4.1 if there is sufficient fluid and permeability) Initial well pattern Second set of wells  108 Although each km2 is rated at 10 MW capacity, there will be about a 30% loss from temperature drop coming to surface, and other production losses. So each km2 will generate only about 7.14 MW So with the above 5 production well / 2 reinjection well pattern, a total of 50 MW will be sustained. With an 80% capacity factor the following production sequence will be sustained over the first 50 years of production assuming a 25-year rest period is suffiicent to restore the initial temperature to each set of 5 wells. Year Production Wells Rated Capacity MW Electricity MWh Production Area km2 Rest Area km2 Total Area km2 0 5 50 351,350 7 - 7 5 10 100 702,700 14 - 14 10 15 150 1,054,050 21 - 21 15 20 200 1,405,400 28 - 28 20 25 250 1,756,750 35 - 35 25 25 250 1,756,750 35 7 42 30 25 250 1,756,750 35 14 49 35 25 250 1,756,750 35 21 56 40 25 250 1,756,750 35 28 63 45 25 250 1,756,750 35 35 70 50 to 100 25 250 1,756,750 35 35 70  So only about 25% extraction of the total resource occurs with this pattern and schedule. The ratio of production years to "at rest" years could be as high as 1.0 (25 years at rest) or as low as 0.625 (40 years at rest) on many factors that influence resource recovery.


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