Design of Geothermal District Heating and Cooling System for the

Background

Energy production and consumption have evolved significantly from early civilizations, which relied on sunlight for fire and wood for cooking and heating Since the industrial revolution, fossil fuels have dominated global energy production, accounting for the majority of energy consumption In 2017, the United States consumed 103.1 EJ (97.7 quadrillion Btu) of primary energy, with 80% sourced from fossil fuels such as petroleum, coal, and natural gas The remaining 20% was derived from nuclear energy (9%) and renewable resources (11%).

Figure 1.1: U.S energy consumption based on energy source [1]

Fossil fuels significantly affect the environment, as their electricity production releases carbon dioxide and other greenhouse gases (GHGs) The ongoing rise in atmospheric carbon dioxide levels contributes to global temperature increases and extreme weather events, such as polar ice melting, flooding, and droughts These climate changes pose serious risks to human health and the ecological and physical environments.

2 balance energy production, energy consumption, and their environmental impact to develop a sustainable energy system; therefore, attention has been shifted towards investing and developing renewable energy

Figure 1.2: Global CO 2 atmospheric concentration [2]

Between 2004 and 2015, investment in renewable energy surged by approximately 600%, with solar and wind receiving the majority of funding Despite their growth, these energy sources face challenges due to their intermittent availability and the high costs associated with energy storage In contrast, geothermal energy offers a consistent, reliable, and easily scalable solution, providing a substantial energy output As of 2007, geothermal energy accounted for about 0.5% of the total energy demand in the United States.

2018, constitutes only 2% of the total renewable energy consumption in the U.S [7]

Figure 1.3: Global investment in renewable energy technologies [3].

Geothermal Energy as a Renewable Energy Source

Geothermal energy, derived from the Greek words for earth and heat, is a renewable resource continuously generated beneath the Earth's surface Historically utilized by Native American cultures, the Chinese, and the Romans for various heating and bathing purposes, geothermal energy has evolved in the past century to provide steam and hot water for residential heating and electricity generation Today, its applications are categorized into three main areas: electricity generation in power plants, direct-use systems, and geothermal heat pumps In power generation, high-temperature geothermal fluids drive turbines to produce electricity, while direct utilization encompasses district heating, agricultural applications, aquaculture, industrial processes, and heat pumps The potential for direct-use geothermal energy in the U.S is significant, with extensive documentation on its applications in district heating.

The geothermal temperatures (< 150°C) required for direct-use are generally lower than those of electricity generation (>150°C) Fox et al [16] carried out a detailed study of the U.S yearly

Energy consumption varies with utilization temperature, with approximately 25% of the total primary energy demands in the U.S used for thermal applications below 120°C Currently, fossil fuel combustion meets these low-temperature needs, despite the high combustion temperatures that lead to exergy losses A significant portion of energy required for space and water heating is supplied by oil and natural gas, which results in inefficiencies In contrast, geothermal energy presents a sustainable solution for providing thermal energy with minimal exergy losses Additionally, geothermal direct-use offers more efficient energy utilization, eliminating the thermodynamic inefficiencies associated with converting thermal energy into electricity.

Figure 1.4: Thermal energy use temperature distribution from 0 to 260°C [16]

Currently, most U.S geothermal power plants and direct-use applications are installed in California, Nevada, and Idaho where there exists high geothermal temperature gradients and

Recent research from Southern Methodist University has revealed that temperatures beneath West Virginia are significantly higher than earlier estimates reported by MIT in "The Future of Geothermal Energy." This high-temperature zone spans from north-central West Virginia (Monongalia County) to southeastern West Virginia (Greenbrier County) According to the Low-Temperature Geothermal Play Fairway Analysis in the Appalachian region, the elevated temperatures in Morgantown are adequate to support commercial geothermal systems for direct-use applications.

Figure 1.5: The updated heat flow map of the conterminous United States [19], the circle represents West Virginia

The Tuscarora Reservoir is an optimal location for geothermal development due to its estimated adequate temperature and geofluid flow rate, which are essential in reducing the costs associated with geothermal system development.

The "Marcellus Shale Energy and Environment Laboratory (MSEEL)" project, led by West Virginia University and funded by the Office of Fossil Energy, has successfully gathered new geothermal gradient data using a downhole fiber optic cable This research indicates that the background geothermal temperatures in the Morgantown area reach 167-170°F (75-77°C) at a depth of 7,500 feet (2,286 m) Extrapolating these findings suggests that the temperature of the Tuscarora formation at 10,000 feet will be around 211°F (~100°C), highlighting the potential for geothermal energy development in the region.

Significant porosity and permeability in the area, indicated by resistivity logs and gas production history, suggest strong geothermal potential For deep direct-use geothermal development to be economically viable, it is essential to have available thermal demand and suitable surface distribution infrastructure The geothermal market in Morgantown primarily targets the commercial and residential sectors of the West Virginia University (WVU) campus, which spans 1,892 acres and includes 245 buildings, serving approximately 30,000 faculty, staff, and students Thus, the WVU campus presents a promising opportunity with its substantial surface demand and potential subsurface viability for geothermal resources.

Objectives and Approach

The project aimed to assess the feasibility of implementing a geothermal district heating and cooling (GDHC) system at West Virginia University (WVU) in Morgantown, WV, to replace the existing coal-fired steam system that currently serves over 30,000 students, faculty, and staff across more than 1,800 acres and 245 buildings The current steam supply is managed by Morgantown Energy Associates (MEA), a coal-based facility This initiative is part of a sustainability plan overseen by the Office of Sustainability and the WVU Energy Institute, which seeks to transition to a reliable and clean energy source for central steam generation, with geothermal energy identified as a promising alternative.

WVU's heating and cooling system stands out for its year-round steam usage, providing heat in winter and absorption cooling in summer Implementing geothermal heating would enable continuous operation of the deep direct-use (DDU) system, significantly reducing the levelized cost of heat (LCOH) by spreading costs over the entire year This initiative would serve as the first demonstration of a geothermal system's practical feasibility and effectiveness in the eastern United States.

The specific objectives of this study:

1 Objective 1: Characterize energy demand for the WVU campus The year-round energy consumption data of the WVU campus is collected to characterize the energy demand

2 Objective 2: Evaluate existing campus district heating system retrofit capability

3 Objective 3: Design a geothermal surface plant and pipeline distribution using Aspen simulators

4 Objective 4: Perform an economic analysis to estimate the levelized cost of heat (LCOH) using GEOPHIRES (GEOthermal energy for Production of Heat and electricity (“IR”) Economically Simulated) [22]

The feasibility of the hybrid GDHC system at WVU was determined by comparing costs and benefits with the existing MEA coal-fired steam-based system.

Thesis Structure

This article explores the geothermal energy system in the U.S., beginning with an overview of the development of the Ground Source District Heating and Cooling (GDHC) system and existing district heating and cooling systems at West Virginia University (WVU) Chapter 3 details the collection of data on temperature, pressure, and flow rates from current facilities, alongside an analysis of new equipment and distribution pipelines needed for the coal-fired steam-based system Chapter 4 outlines the simulation setup for the geothermal surface plant and distribution pipelines, utilizing data from Chapter 3 for HYSYS simulations, and discusses methodologies such as Aspen Exchanger Design and Rating (EDR) and Aspen Capital Cost Estimator (ACCE) In Chapter 5, HYSYS simulation results inform the rigorous design of geothermal heat exchangers, while Aspen ACCE estimates the costs associated with surface plant equipment and distribution pipelines Chapter 6 evaluates the project's economics using GEOPHIRES software, assessing the feasibility of the hybrid GDHC system at WVU through the levelized cost of heat (LCOH) and comparing it to a natural gas boiler system Finally, Chapter 7 outlines future directions and recommendations for further research.

Development of Geothermal District Heating and cooling (GDHC) System in US

The first geothermal district heating system (GDHS) in the U.S was established in Boise, Idaho, during the winter of 1890, utilizing two wells that provided geothermal hot water at 77°C A network of wooden pipelines was constructed to deliver this hot water to various buildings, enabling Boise Water Works to offer both space heating and drinking water to its customers To date, approximately 22 GDHS have been developed across the U.S., predominantly in the western states Despite the significant time since the inception of the first geothermal system, the growth of GDHS in the U.S has been relatively slow compared to Europe and countries like Iceland, where geothermal energy meets over 90% of space heating demands.

Figure 2.1: The locations of geothermal district heating system in US [27]

Geothermal district heating and cooling systems in the U.S remain underdeveloped, despite their significant potential to provide clean energy and reduce fossil fuel emissions Key barriers to the advancement of geothermal energy include technical challenges, economic constraints, and regulatory policies Research conducted by Thorsteinsson utilized logistic regression analysis to highlight these issues at the state level.

Funding and design challenges are the primary factors affecting the successful development of geothermal district heating and cooling (GDHC) systems in the U.S The establishment of these systems demands substantial initial investments for geothermal drilling and exploration, coupled with inherent risks associated with drilling geothermal wells Beyond drilling costs, additional financial burdens arise from surface plant equipment, scaling and corrosion issues, and the necessary pipeline infrastructure Therefore, a thorough analysis of the district heating and cooling system design at West Virginia University (WVU) is essential to facilitate the successful implementation of a GDHC system.

Surface Plant Development

Integrating a geothermal surface plant into existing district heating and cooling (DHC) systems can be achieved by retrofitting them to create a geothermal district heating and cooling (GDHC) system The geothermal heating system serves as the primary heat source in GDHC but can be supplemented with other energy forms for enhanced efficiency Depending on the production temperatures of the geothermal fluid, a hybrid DHC system incorporating a heat pump and/or conventional boiler may be advantageous For instance, in some district heating setups, geothermal energy fulfills the base-load energy demand, while a boiler caters to peak-load requirements during winter.

In situations where geothermal energy alone cannot fulfill district heating demands, a hybrid GDHC system can be implemented, utilizing fossil fuels like natural gas or biomass boilers to supplement heat requirements Additionally, the efficiency of geothermal energy can be enhanced through heat cascading, where lower-temperature spent geothermal fluid is repurposed for applications such as greenhouse and swimming pool heating Furthermore, the integration of heat pump systems can significantly improve the overall performance of geothermal energy utilization in district heating and cooling systems.

Overview of district heating and cooling (DHC) system at WVU

Existing Heating and Cooling System at WVU

WVU's existing District Heating and Cooling (DHC) system operates on a steam-based model, utilizing steam to heat water that is then circulated throughout campus buildings for both heating and domestic use Additionally, various equipment, including absorption cooling towers and autoclaves, depend on steam for their functionality Ruby Memorial Hospital notably requires a substantial steam supply not only for building heating but also for essential medical operations.

Proposed Heating and Cooling System at WVU

The geofluid produced from the well is insufficient to meet the campus steam demand, as it consists of hot water with temperatures below 100°C Transitioning from a steam-based system to a hot water system is deemed uneconomical and complex To effectively utilize the existing campus heating and cooling infrastructure, a hybrid geothermal-natural gas system has been proposed to deliver steam under the required conditions This system involves preheating condensate water with geothermal fluid, which is then heated to steam conditions using a natural gas boiler Key components of the hybrid geothermal district heating and cooling (GDHC) system include a centralized geothermal heat exchanger, a heat pump system to enhance geothermal extraction, a natural gas boiler for steam production, a condensate receiver tank, condensate pumps, and retrofitted pipeline networks for transporting secondary fluid to existing pipelines.

The Research Study Workflow

The design of the proposed hybrid district heating and cooling (DHC) system at West Virginia University (WVU) utilized reservoir parameters, including geofluid temperature, alongside data from the existing steam-based system, which included temperature, pressure, and flow rate Two scenarios for the hybrid DHC systems were developed based on the collected data Standard district heating equipment and pipeline distribution networks were selected for simulation using the Aspen simulator (HYSYS), which facilitated the design of surface plant facilities Additionally, detailed equipment design, including the sizing and rating of heat exchangers, was executed in Aspen EDR, allowing for a comprehensive analysis of the capital costs associated with the equipment.

In Aspen ACCE, 11 pipelines were evaluated for two scenarios, with the total capital costs of equipment and pipelines being critical for the economic analysis of hybrid systems in GEOPHIRES The feasibility of the hybrid geothermal-natural gas systems was assessed by comparing their Levelized Cost of Heat (LCOH) to that of the existing coal-fired steam-based system A summary of the project workflow is illustrated in Figure 2.2.

Figure 2.2: A schematic of the workflow for the design and economic analysis of a hybrid GDHC system at WVU

Characterization of Existing Infrastructure and Evaluation of Existing Campus District Heating (DH) System Retrofit Capability

Objective 1: Characterization of Existing Infrastructure

The year-round energy consumption data for WVU campus buildings was collected to analyze energy demand MEA currently supplies steam to five main distribution points across three campuses: Downtown, Evansdale, and Health Sciences These distribution points deliver steam directly to individual buildings To monitor this process, flow meter servers were installed at the distribution points to record steam temperature, pressure, flow rate, and return condensate flow rate and temperature over a one-year period.

The steam to the campus is distributed through the following five distribution points:

1 Medical Center: Health Sciences campus and Ruby Memorial Hospital

3 Evansdale: Engineering and Agriculture buildings

4 Life Sciences: Life Sciences building

5 Downtown: Majority of the campus buildings in downtown area.

Objective 1: Results and Discussion

The current District Heating System (DHS) supplies steam to 245 buildings from a centralized coal-fired surface plant managed by MEA Energy characterization across the three campuses relies on flow metering data, which is logged every five minutes and downloaded monthly to a local computer This data, including steam flow rates, temperatures, and pressures, is crucial for analyzing energy consumption at each campus For instance, Figure 3.1 illustrates the steam temperature, pressure, and flow rate recorded at the Medical Center meter point for the Health Sciences campus in June 2019.

The annual campus steam consumption for 2017-2018 highlights that the Medical Center, Evansdale, and Downtown meter points are the primary contributors to steam demand Notably, steam usage peaks in January and reaches its lowest point in June.

Figure 3.1: WVU steam data for (a) temperature (°F) (b) pressure (psig) (c) flow rate (PPH) for Health Sciences campus (Medical Center meter point) for June 2019

Figure 3.2: Annual WVU campus steam consumption data for the current DHC system at WVU (2017-

Objective 2: Evaluate Existing Campus District Heating (DH) System Retrofit

The proposed hybrid GDHC system involves evaluating the retrofit capability of existing pipeline distribution networks and DHC equipment across WVU campuses The design will utilize the current building infrastructure while incorporating essential new equipment at the centralized surface plant, including a heat exchanger, natural gas boiler, heat pump, and condensate receiver tank for collecting return condensate from five distribution points Additionally, new steam and condensate pipelines will be established to transport steam and condensate from the central plant to the existing distribution system.

Objective 2: Results and Discussion

The essential equipment needed to fulfill campus steam requirements has been identified, alongside the current steam supply pipeline networks from MEA to individual distribution points, as illustrated in Figure 3.3 This figure provides detailed information on pipe lengths, diameters, and the locations of five distribution points The reported pipe lengths are equivalent lengths, which consider factors such as bends, valves, and obstructions within the distribution piping system.

Figure 3.3: One-line drawing of MEA’s pipelines with distribution meter points along with linear pipe distances and pipe sizes

134.38 PSIG 385.98°F Life Sciences MEA Main

505 ft 1996 ft 3945 ft 701 ft 4596 ft

Design a Surface Plant and Pipeline Distribution Using Aspen Simulators

Proposed Hybrid Geothermal-Natural Gas System Design

The campus currently relies on a steam-based heating and cooling system, but the geofluid from the well is inadequate as it produces hot water below 100°C, failing to meet steam demands This steam is essential for heating water circulated in buildings and for operating equipment such as absorption cooling towers, autoclaves, and Ruby Memorial Hospital's medical facilities To address this issue, a hybrid geothermal-natural gas boiler system has been proposed for WVU, utilizing geothermal fluid to preheat water before a natural gas boiler further heats it to generate steam at the necessary conditions.

The surface plant components of the proposed hybrid district heating system at WVU include a geothermal heat exchanger, a natural gas boiler, a condensate receiver tank, and pumping and distribution pipeline units Figure 4.1 illustrates the closed-loop configuration and highlights the key components of this system.

The surface plant components are categorized into two main units: heat production and heat distribution The heat production unit comprises a centralized heat exchanger, a condensate receiver tank, and a natural gas boiler, while the heat distribution unit includes fluid distribution lines and associated pumping systems for steam and condensate Hot geothermal fluid (GEO-IN) from the production well is directed to the geothermal plate heat exchanger (PHE), where it transfers heat to the condensate (CLD-IN) before the spent geothermal fluid (GEO-OUT) is reinjected into the reservoir The PHE serves to isolate the geothermal fluid from the district heating network, preventing scaling and corrosion in the distribution pipelines Additionally, the natural gas boiler heats the water to steam at the required conditions, and the condensate tank collects returns from the distribution lines, which consist of a network of steam and condensate pipelines.

16 respectively To improve heat utilization of the proposed hybrid geothermal-natural gas boiler system, heat pump system is integrated into the surface plant components in Figure 4.1

Figure 4.1: Schematic of the proposed hybrid geothermal-natural gas boiler systems for West Virginia University

The proposed hybrid geothermal-natural gas boiler system incorporates a heat pump to enhance heat utilization by extracting heat from low-temperature condensate return, maximizing geothermal energy extraction The heat pump utilizes low-temperature water from the campus distribution loop, allowing the working fluid to evaporate and absorb heat before the condensate is directed back to the geothermal PHE The compressor then increases the pressure of the working fluid, which is subsequently condensed at high temperature and pressure in the condenser, rejecting the absorbed heat to further elevate the temperature of the geothermally preheated water before it is sent to the boiler.

Figure 4.2: Schematic of the proposed hybrid geothermal-natural gas boiler system improvised with heat pump system for West Virginia University

The heat pump system pressurizes high-temperature hot water with a pump before sending it to a natural gas-fired boiler for additional heating to produce steam This steam, either superheated or saturated, is distributed to individual buildings at WVU for domestic heating and cooling As the steam condenses within the buildings, the resulting condensate is returned to distribution points through a network of pipelines This condensate is then transported back to the centralized surface plant for reuse by the heat exchanger, with a condensate receiver tank collecting the return for recirculation A system of condensate pumps facilitates the movement of condensate back to the central plant site.

The design of the proposed hybrid district heating and cooling (GDHC) system is centered around the location of the geothermal well (HSC) and the steam demand at West Virginia University Two distinct design scenarios were evaluated for the implementation of this system on the WVU campus.

The article discusses the supply of steam to the entire West Virginia University (WVU) campus through two scenarios: Scenario 1A and Scenario 1B In Scenario 1A, a single boiler (Boiler1) delivers high-pressure steam at 18.25 bar (250 psig) and 260°C (500°F) to the entire campus Conversely, Scenario 1B utilizes Boiler1 alongside a compressor, where Boiler1 supplies superheated steam at 14.5 bar (195.6 psig) and 200°C (392°F) to the campus, while the compressor specifically provides superheated steam at 18.25 bar and 260°C to the Life Sciences meter point.

Scenario 2 outlines the supply of steam to the Health Sciences Medical Center and Evansdale campuses, consisting of two distinct cases: Case 2A and Case 2B In Case 2A, a single boiler, Boiler1, delivers saturated steam at a pressure of 12.5 bar (166.6 psig) to both the Health Sciences and Evansdale meter points Conversely, Case 2B incorporates two boilers; Boiler1 continues to supply saturated steam at 12.5 bar (166.6 psig) to the Health Sciences and Evansdale meter points, while Boiler2 provides low pressure saturated steam at 2.75 bar (25.2 psig) to the Towers meter point.

Figure 4.3: The aerial view of the proposed geothermal well site location at Health Sciences

Geothermal Heat Exchanger Unit

The aim of this study was to design a geothermal plate heat exchanger (PHE) capable of processing hot geothermal fluid at rates of 15.2 kg/s for Scenario 1 and 10.2 kg/s for Scenario 2, specifically to heat condensate water The use of a PHE was chosen due to its effectiveness in isolating corrosive and fouling geothermal fluids, making it a preferred option over shell and tube heat exchangers (STHE) due to its superior ease of cleaning and maintenance in various geothermal applications.

To simulate the Plate Heat Exchanger (PHE), the "Simple End Point" heat exchanger model in HYSYS was utilized for initial simulations For a comprehensive design addressing fouling and pressure drop constraints, process data was exported to Aspen EDR, as detailed in Chapter 5 The PHE is constructed from stainless steel SS-304 for its corrosion resistance In four cases analyzed, Aspen EDR provided critical design parameters, including the heat transfer area, tube passes, number of tubes, tube arrangement, TEMA shell types, and estimated pressure drops Additionally, carbon steel was selected for the construction of the Shell and Tube Heat Exchanger (STHE) to withstand the high-temperature flue gas inlet.

5) is then used to determine the range of values for the allowable pressure drops for the hot and cold streams which was estimated as 0.02 bar The estimated pressure drop is used in rigorous design of the PHE

Geothermal fluid contains various dissolved chemicals that can be corrosive to construction materials, with its chemical composition largely influenced by the geochemistry of the geothermal reservoir For this study, geothermal fluid was modeled as pure water using HYSYS, as the built-in fluid property correlations in GEOPHIRES for density, heat capacity, viscosity, and vapor pressure are based on this assumption To address geothermal fouling in heat exchangers, a typical fouling resistance of 0.0007 ft²-h-°F/BTU was utilized.

In the meticulous design of the heat exchanger, 20 references from the literature were utilized The condensate fluid fouling resistance was determined to be 0.0001 ft²-h-°F/BTU, based on the assumption that the condensate consists of soft water.

Fired heater simulation in HYSYS

The three major sections of the fired heater available in HYSYS (AspenTech) are:

• Radiant Section: consists of a firebox which transfers heat to the heater tubes mainly by radiation from high-temperature flue gas;

• Convection Section: consists of a bank of tubes which receives heat from the hot flue gases, primarily by convection; and

• Economizer: used to heat the water fed to the boiler Economizer is primarily used to recover heat from the boiler flue gases to increase boiler efficiency

In a steady state, the HYSYS fired heater lacks convection and economizer sections, and is designed with appropriate size, material, and heat of combustion This simulation focuses on performing basic mass and energy balances to determine boiler heat duty, air-fuel flow rates, and the necessary steam outlet temperature and pressure, whether saturated or super-heated These parameters are essential for obtaining boiler costs from vendors and estimating costs in Aspen ACCE.

A fired heater comprises four essential components: the fire box, burner, convection coil, and stack In HYSYS steady state simulations, only the radiative section is active, omitting the burner, convection coils, and stack, and no significant modifications are made for these simulations Although vacuum or negative pressure conditions are not present, combustion of air and natural gas occurs at near atmospheric pressure, approximately 0.8 bar To minimize utility costs, the fired heater operates at an efficiency of 85%, ensuring that 85% of the heat is absorbed in the radiant section, while 15% is lost to the exiting flue gas The efficiency of the radiant section is defined as the ratio of heat supplied to the process fluid compared to the total heat supplied to both the process fluid and the flue gas exiting the stack The stack features a cylindrical brick shell design.

The flue gas is transported to the atmosphere without a stack section, meaning no damper is used to regulate its flow or control draft in the fired heater during steady-state simulations Instead, draft—whether forced, induced, or natural—is simulated using an air blower in HYSYS to provide combustion air to the burner and to counteract the pressure drop Although a natural gas preheater is not directly available in HYSYS, it is effectively simulated with a shell and tube heat exchanger that utilizes exiting flue gas from the fired heater to preheat the industrial natural gas before it enters the combustion section of the fired heater.

The performance of fired heaters is influenced by several factors, including burner capacity, air leakage, negative pressure, economic considerations, and safety, which are not accounted for in steady-state simulations It is assumed that the flue gas temperature reaches approximately 385°C, a level deemed sufficiently high to avoid condensation at the dew point.

The goal of this study was to simulate a natural gas boiler for the West Virginia University (WVU) campus district heat supply The preheated water from the geothermal heat exchanger (GEO-HEX) had a pressure of 1 bar However, both Scenario 1 and Scenario 2 simulations of the fired heater necessitate a higher steam supply pressure to fulfill the steam demands at distribution points.

To achieve optimal steam conditions at distribution points, high-temperature hot water, preheated geothermally, is pumped into the fired heater with a pump (PUMP-1), while natural gas combustion in the burner supplies the additional heat needed for producing superheated and saturated steam The generated steam is then distributed to various campuses through a network of insulated underground pipelines extending from the centralized surface plant at the well location.

Figure 4.4: Boiler unit and other combustion components simulated in HYSYS

In Figure 4.4, the fuel preheater (NG-PREHEATER) heats natural gas to approximately 65°C before it is combusted in the boiler, while the air blower (AIR-BLOWER) supplies air to the combustion chamber This optimal temperature is crucial for ensuring complete combustion of the natural gas.

As shown in Figure 4.4, inlet and outlets streams to the fired heater are:

• PUMP-OUT: geothermal-heat pump preheated water,

• HP-STEAM: saturated or superheated steam produced from combustion of natural gas in the fired heater,

• Natural Gas and Air-1 (fuel inlets): a mixture of air (dry air) and natural gas, and

• Flue Gas1: Fired heater flue gas exhaust

The major assumptions and conditions used in fired heater simulation:

• Fired Heater: Firebox efficiency was fixed at 85% and the adjust logical operator in

HYSYS was used to perform optimization at steady state in order to meet steam requirements at the distribution points

The air-fuel mixture for natural gas combustion consists of 79% nitrogen and 21% oxygen, while natural gas is primarily composed of 95% methane, 2.5% ethane, and 2.5% propane To achieve complete combustion in the firebox heater, dry air is supplied at 10% above the stoichiometric requirement at 25°C The natural gas is delivered at an industrial pressure of 4.81 bar and a temperature of 15°C, as per current data from WVU Facilities Management The combustion process occurs under atmospheric conditions, necessitating a reduction in natural gas pressure via a valve A blower is utilized to introduce air into the combustion burner, and a fuel preheater raises the temperature of the natural gas to ensure firebox efficiency of 85%.

• Air Blower: Air blower was used to compress and push air into the combustion chamber of the boiler unit at 0.8 bar

Air and natural gas inlet temperature and pressure for all the boiler units simulated in Aspen HYSYS are summarized in Table 4-1

Table 4-1: Air and fuel inlet conditions for fired heater simulation in HYSYS

Fired Heater Input Air Natural Gas

To enhance the efficiency of the fired heater from 80% to the desired 85%, a fuel preheater unit was implemented to optimize the inlet natural gas flow into the boiler's combustion chamber By adjusting the natural gas flow rate using an operator in HYSYS, the system was fine-tuned to ensure the steam produced met the required temperature while maintaining the flue gas temperature above 384°C This optimization process channels flue gas (Flue Gas1) to improve the overall performance of the boiler unit.

The flue gas from the boiler is directed to the heat exchanger (NG-PREHEATER) to preheat the natural gas before it enters the boiler unit A steam-to-hot-water exchanger (STHE) is utilized to achieve the necessary inlet temperature for the natural gas, optimizing boiler performance In the HYSYS simulation of the simple heat exchanger, the pressure drop was considered negligible.

Distribution Piping System

In geothermal district heating systems, it is crucial to implement an efficient piping system along with proper insulation to reduce heat losses The distribution pipeline networks transport steam from the surface plant facility to multiple distribution points, with five points in Scenario 1 and three in Scenario 2 To assess the total cost of the pipeline distribution networks necessary for meeting the heating and cooling demands at West Virginia University (WVU), the expenses associated with the pipelines delivering steam to various WVU campuses were estimated using Aspen ACCE.

4.4.1 The major assumptions and conditions used in distribution pipeline simulation for the entire campus include:

The geothermal well is strategically located near the HSC campus, utilizing the existing steam pipeline network for efficient steam distribution To enhance connectivity, new pipelines have been installed to link the geothermal well at HSC with the established MEA steam and condensate pipelines.

• One new steam pipeline o HSCLOT81: transports steam from boiler outlet to the main MEA pipeline that connects to existing MEA pipeline at the Medical Center meter point

Two new condensate pipelines have been established to enhance efficiency in condensate transport The first, Cond-HSCLOT81PIPE-1, is designed to carry condensate returns from Evansdale and Downtown to the condensate receiver tank at the central plant site via the main MEA line The second pipeline, Cond-HSCLOT81PIPE-2, facilitates the transport of HSC condensate returns from the main MEA line to the same condensate receiver tank at the central plant site.

Fuel pipelines are essential for supplying natural gas to the boiler for combustion The NG-PIPE system efficiently transports natural gas from an industrial delivery location directly to the boiler unit at the central plant site.

• Aspen ACCE was used to evaluate pipeline cost for:

The natural gas pipeline simulation utilized carbon steel, while an alloy of carbon steel and chromium was employed for steam and condensate pipelines to mitigate corrosion The insulation type used for the pipes was polyurethane, and the pipelines were fully buried.

The analysis is based on several key assumptions, including the absence of heat loss through distribution pipelines (Q=0), a pipe surface roughness of 0.00015 ft (the default value from AspenTech), and a simulation to assess choke flow conditions across all pipelines Additionally, the pipe schedule is designated as #80, and there is an anticipated water loss of 10% between the steam and condensate lines.

The relocation of the surface plant from the MEA site to HSC necessitated an assessment of elevation changes along the main Personal Rapid Transport (PRT) route for five distribution points Elevation change refers to the difference in height between any two meter points, which was determined using Google Maps to identify significant elevation variations These elevation changes were incorporated into the pipeline segments for HYSYS simulations, as detailed in Table 4-2, which outlines the elevation and corresponding pressure changes along the pipeline segments used in the HYSYS pipeline simulation.

Table 4-2: The elevation changes used in pipeline simulations in HYSYS

Map Location Pipeline Name Elevation

PRT-BEECHURST to PRT MEA Cond-DTN-LFS2 -111.00 -3.32

PRT MEA to PRT Ag SC Cond-DTN-LFS 124.00 3.71

PRT Ag SC to PRT TOWERS Cond-AGDTN -26.00 -0.78

PRT TOWERS to PRT MED CENTER Cond-AGDTNTWRDTN 99.00 2.96

PRT-MEDCENTER to CENTRAL PLANT Cond-HSCLOT81PIPE-1 35.00 1.05

Figures 4.5 and 4.6 illustrate the steam distribution from the boiler outlet, where steam is channeled into the new HSCLOT81 pipeline, linking the centralized surface facility to existing MEA pipelines At the HSCLOT81 exit, the steam is divided into two streams: one directed to the Medical Center meter point (MED-MTPT) and the other routed to the main MEA steam pipeline at HSC for distribution to other campuses In Scenario 1, the existing MEA steam pipelines include AGTWRDTN, TWR-PIPE, AG-DTN, AG-PIPE, DTN-LFSC, DTN-LFSC2, LFS-PIPE, and DTN-PIPE, while Scenario 2 features a different set of pipelines: AGTWR, TWR-PIPE, AG-MEA, and AG-PIPE.

Figure 4.5: The schematic of the steam line simulated for Scenario 1 (Case 1A & Case 1B) pipeline distribution system

Figure 4.6: The schematic of steam line simulated for Scenario 2 (Case 2A & Case 2B) pipeline distribution system

The condensate pressure at distribution points remains uncertain; however, WVU Facilities Management estimates it to be around 3.1 bar (30 psig) when leaving individual buildings With an assumed pressure drop of 10 psig between buildings and the meter point, the returning condensate pressure at the meter point is estimated to be 2.4 bar (20 psig) A HYSYS simulation was conducted using this initial pressure for two scenarios, while ensuring that the total water loss between the steam supply and condensate return lines was limited to approximately 10% Consequently, 90% of the supplied steam was successfully returned as condensate, with the 10% makeup water compensating for losses in the closed-loop system.

Figure 4.7 and Figure 4.8 show the schematic of the condensate pipeline distribution system at WVU For Scenario 1 as represented in Figure 4.7, the condensate return was transported from the

In both scenarios, condensate is transported from five distribution points back to a centralized surface facility using existing MEA condensate pipelines, including cond-LFS-PIPE, cond-DTN-PIPE, and others For Scenario 2, the return process involves three distribution points utilizing similar pipelines Additionally, two new condensate pipelines, cond-HSCLOT81PIPE-1 and cond-HSCLOT81PIPE-2, were introduced at HSC to support both scenarios.

In the heat production unit, the condensate lines delivered returning water at temperatures of 65.59°C and 65.58°C These streams were mixed with 10% makeup water at 15°C, flowing at rates of 1.52 kg/s for Scenario 1 and 1.02 kg/s for Scenario 2, before entering the condensate receiver tank The resulting mixture from the tank reached temperatures of 48.79°C in Scenario 1 and 50.43°C in Scenario 2, and was subsequently sent back to the GEO-HEX system, completing the closed-loop configuration It is important to note that the condensate tank was considered uninsulated, and the residence time of the condensate within the tank was deemed negligible.

Figure 4.7: The schematic of the condensate line for Scenario 1 (Case 1A & Case 1B) pipeline distribution system

Figure 4.8: The schematic of the condensate line for Scenario 2 (Case 2A & Case 2B) pipeline distribution system.

Heat Pump System

A heat pump is a device designed to transfer heat energy from a low-temperature source to a high-temperature sink When its operation is reversed, it functions as a cooling or refrigeration system The key distinction between a heat pump and a refrigeration cycle is that a heat pump aims to deliver heat to a hot reservoir, while a vapor-compression refrigeration cycle focuses on removing heat from a low-temperature area.

A heat pump system consists of four main components: the condenser, compressor, evaporator, and expansion valve The refrigerant circulates through these components in a continuous loop The cycle starts in the evaporator, where the refrigerant evaporates by absorbing heat from a low-temperature source The compressor then increases the refrigerant's pressure before it enters the condenser, where it releases heat to a high-temperature sink After this, the refrigerant passes through the expansion valve, reducing its pressure and temperature, before returning to the evaporator to repeat the cycle.

Efficiency of a heat pump system is expressed by its Coefficient of Performance (COP) [52] The

The Coefficient of Performance (COP) is determined by the ratio of heat expelled by the condenser (qc) to the work input (W) required by the compressor A higher COP indicates greater efficiency in a heat pump system.

𝑊 (4.1) where W is the electric power input into the compressor, and q c is the heat delivered or rejected by the condenser The range of COP is usually between 4-6

Figure 4.9: A simplified diagram of a heat pump system [56]

The efficiency and performance of a heat pump are significantly influenced by the choice of working fluid, as well as the temperature difference between the heat source and heat sink Selecting the appropriate refrigerant is crucial for optimizing the operation of heat pump systems Common natural working fluids include carbon dioxide (CO2), ammonia (NH3), water, and hydrocarbons Various simulations have been conducted to evaluate different working fluids and heat pump configurations documented in existing literature, highlighting the importance of fluid properties in system performance.

31 the heat pump simulated conditions were evaluated to come up with the best scenario for the WVU campus

Assumptions used in heat pump simulation

• Compressor efficiency (adiabatic): 75% (AspenTech default value)

• There is no pressure drop across the heat exchanger

CO2 has a maximum heat source temperature limit of 37°C for inlet water, while the heat source at WVU reaches approximately 65°C In contrast, ammonia (NH3) can effectively operate within an inlet temperature range of 50-65°C Additionally, NH3 is known for its high efficiency, resulting in superior coefficient of performance (COP) compared to CO2.

In a recent simulation using HYSYS, NH3 was selected as the preferred natural refrigerant due to its ability to operate within the temperature limits required for the heat pump system at WVU, achieving a higher temperature of 90°C with an improved coefficient of performance (COP) However, it is crucial to implement safety measures to mitigate the toxicity of NH3 and prevent potential performance issues arising from refrigerant leaks.

Results and Discussion

Geothermal Heat Exchanger Unit Results and Discussion

HYSYS simulations results obtained from simple exchanger design are shown in Table 5-1Error!

The design process for geothermal and condensate fluids involved a thorough analysis using Aspen EDR, which determined the necessary size of the centralized plate heat exchanger for both Scenario 1 and Scenario 2 heat loads After simulating the plate heat exchanger in HYSYS, a detailed configuration design was conducted in Aspen EDR, leading to an evaluation of the centralized plate heat exchanger's costs in Aspen ACCE The subsequent cost findings for both scenarios are outlined in the following sections.

Table 5-1: The results of HYSYS simulation of geothermal plate heat exchanger (PHE)

GEO (Hot Side) COND (Cold Side) GEO (Hot Side) COND (Cold Side)

IN OUT IN OUT IN OUT IN OUT

The cost of a centralized heat exchanger for a geothermal district heating and cooling system has been calculated, requiring a plate heat exchanger (PHE) area of 303.3 m² to transfer approximately 1.67 MW of heat from geothermal fluid to condensate water, with both fluids flowing at a rate of 15.2 kg/s The overall heat transfer coefficient of 1,103 W/m²-K is within acceptable limits for PHEs The geometry configuration and inlet/outlet temperatures for the geothermal fluid and condensate water are detailed in Table 5-1, while Table 5-2 presents the rigorous PHE design results obtained from Aspen EDR The estimated cost for the heat exchanger, based on the area calculated in EDR, is $221,600 according to Aspen ACCE.

Figure 5.1: Details of the geometry obtained for Scenario 1 from rigorous heat exchanger design in EDR

Table 5-2: Results of rigorous design of plate heat exchanger (PHE) in EDR for Scenario 1

In Scenario 2, for a geothermal hot water flow rate of 10.2 kg/s flowing counter-currently with condensate water flow rate (10.2 kg/s), a PHE area of 170.10 m 2 is required to transfer about 1.05

The geothermal fluid generates approximately $172,400 MW of heat for the condensate water, with an overall heat transfer coefficient of around 1,103 W/m²-K, which is considered acceptable for plate heat exchangers The findings of the detailed plate heat exchanger design conducted in Aspen EDR are summarized in Table 5-3.

Table 5-3: Results of rigorous design of plate heat exchanger (PHE) in EDR for Scenario 2

Figure 5.2 below summarizes Scenario 2 PHE geometry obtained from rigorous heat exchanger design together with given inlet and outlet temperatures for the geothermal fluid and condensate water

Figure 5.2: Details of the geometry obtained for Scenario 2 from rigorous heat exchanger design in EDR.

Geothermal Contribution to the Heating and Cooling System at WVU Results and

Scenario 1 which supply the entire campus steam was further subdivided into two design schemes- Case 1A and 1B Case 1A, a boiler ( Q BOILER1 ) provides high pressure steam at 18.25 bar and 260°C to the main distribution center while depending on the monthly steam demand, the heat exchanger extracted the required heat from the geofluid (Q GEO ) flowing at a rate of 15.2 kg/s and for all 12 months the secondary fluid temperature is preheated by 26.21°C (from 48.79°C to 75°C)

The geothermal contribution to the proposed hybrid Ground-Source District Heating and Cooling (GDHC) system was evaluated in two scenarios: first, for a hybrid system without a heat pump, and second, for a hybrid system that incorporates a heat pump, as detailed in Equations 5.1 and 5.2.

For the two instances considered, the geothermal contributions to the district heating and cooling at WVU are calculated as follows:

The equation Q GEO + Q BOILER + Q HEATPUMP (5.2) illustrates the geothermal contributions to a hybrid Ground-Source District Heating and Cooling (GDHC) system The percentage of geothermal energy utilized solely from geothermal sources is represented as % GEO ONLY, while % GEO HP indicates the geothermal contributions to the enhanced hybrid system Understanding these parameters is essential for optimizing energy efficiency in hybrid heating systems.

Q HEATPUMP are the amount of heat contributed to the proposed hybrid GDHC system at WVU by the geothermal, natural gas boiler and heat pump respectively

In Case 1A, the hybrid geothermal contributions are analyzed with and without a heat pump system, as shown in Tables 5-4 and 5.5 The reservoir returning temperature (T h, out) is adjusted based on the monthly secondary fluid flow rate, reflecting steam demand, and the heat extracted by both the geothermal system and the heat pump is assessed over a year The geothermal contribution to the campus heating and cooling system is approximately 2.30% without a heat pump and increases to about 4.10% with the heat pump in operation Notably, the heat pump alone contributes around 1.80% to the enhanced Case 1A, improving geothermal efficiency by extracting additional heat from the condensate return and reducing the geothermal re-injection temperature.

The results from Case 1A, simulated in HYSYS, demonstrate the geothermal contribution to a hybrid geothermal system without a heat pump, achieving superheated steam at 18.25 bar and 260°C This was accomplished with a geothermal fluid flow rate of 15.2 kg/s while varying the monthly steam flow rate.

The results from Case 1A, simulated in HYSYS, demonstrate the geothermal contribution to an enhanced hybrid geothermal system utilizing a heat pump (%GEO HP) for generating superheated steam at 18.25 bar and 260°C This simulation is based on a geothermal fluid flow rate of 15.2 kg/s, with variations in the monthly steam flow rate.

Case 1B, on the other hand, has one boiler ( Q BOILER1 ) where the condensate preheated by geothermal fluid was further heated to superheated steam at 14.5 bar by boiler ( Q BOILER1 ) to supply

Superheated steam is delivered directly to the Health Sciences Medical Center and the Downtown campuses, where it is further compressed to 18.25 bar for the Life Sciences distribution point The geothermal flow rate of 15.2 kg/s preheats the secondary fluid by 26.21°C, increasing its temperature from 48.79°C to 75°C This geothermal fluid contributes approximately 2.40% to the hybrid heating and cooling system However, after enhancements to the hybrid system using a heat pump, the geothermal contribution rises to about 4.39%.

Table 5-6 presents the results for Case 1B, simulated in HYSYS, demonstrating the geothermal contribution to a hybrid geothermal system without a heat pump This system produces superheated steam at 14.25 bar and 200°C for the Med Center, Towers, Evansdale, and Downtown meter points, while generating superheated steam at 18.25 bar and 260°C for the Life Sciences meter point, utilizing a geothermal fluid flow rate of 15.2 kg/s.

Table 5-7 presents the simulation results from HYSYS for Case 1B, highlighting the geothermal contribution to an enhanced hybrid geothermal system This system utilizes a heat pump to generate superheated steam at 14.25 bar and 200°C for the Med-Center, Towers, Evansdale, and Downtown meter points Additionally, a compressor produces superheated steam at 18.25 bar and 260°C for the Life Sciences meter point, with a geothermal fluid flow rate of 15.2 kg/s.

Scenario 2 features two design schemes, Case 2A and 2B, supplying steam exclusively to the Health Sciences and Evansdale meter points In Case 2A, a centralized boiler system delivers saturated steam at 12.5 bar to the Towers, Evansdale, and Medical Center meter points With a geothermal flow rate of 10.2 kg/s and a secondary fluid temperature increase of 30.5°C, geothermal energy contributes 2.42% to the hybrid system, as detailed in Table 5-8, where the heat extracted from geothermal fluid and reservoir returning temperature vary with monthly steam demand Additionally, a heat pump enhances the system by raising the preheated water temperature from 75°C to 90°C, resulting in an increased geothermal contribution of 4.05% to the hybrid system, as indicated in Table 5-9.

In Case 2A, HYSYS simulations reveal the geothermal contribution to a hybrid geothermal system without a heat pump, achieving superheated steam production at 12.5 bar This process utilizes a geothermal fluid flow rate of 10.2 kg/s, highlighting the system's efficiency in harnessing geothermal energy.

Table 5-9 presents the results for Case 2A, which was simulated in HYSYS to analyze the geothermal contribution to an enhanced hybrid geothermal system utilizing a heat pump This system is designed to generate superheated steam at a pressure of 12.5 bar, employing a geothermal fluid flow rate of 10.2 kg/s.

Case 2B features a centralized geothermal heat exchanger equipped with two boilers The first boiler (Q BOILER1) generates saturated steam at 12.5 bar for the Evansdale and Medical Center meter points, while the second boiler (Q BOILER2) produces saturated steam at 2.75 bar specifically for the Towers meter point.

Towers operate efficiently with steam supplied at low-pressure conditions With a geothermal flow rate of 10.2 kg/s, the secondary fluid is preheated from 48.79°C to 75°C, resulting in a geothermal contribution of approximately 2.43% to the hybrid system without a heat pump, and about 4.05% when a heat pump is integrated.

In Case 2B, the geothermal contribution to a hybrid geothermal system without a heat pump is analyzed, showcasing the performance of two boilers The first boiler generates saturated steam at 12.5 bar for the Evansdale and Medical Center meter points, while the second boiler produces low-pressure steam at 2.75 bar for Towers, utilizing a geothermal fluid flow rate of 10.2 kg/s.

Boiler Unit: Fired Heater Results and Discussion

HYSYS simulation results of a fired heater for Scenario 1 (Case 1A and Case 1B) and Scenario 2 (Case 2A and Case 2B) are shown in Table 5-12 and Table 5-13

Table 5-12: The data obtained from HYSYS simulation of natural gas fuel preheater for Scenario 1

Natural Gas Input Case 1A Case 1B

IN OUT IN OUT IN OUT IN OUT

Table 5-13: The data obtained from HYSYS simulation of natural gas fuel preheater for Scenario 2

Natural Gas Input Case 2A Case 2B

IN OUT IN OUT IN OUT IN OUT

Table 5-14 illustrates the energy requirements for two cases of superheated steam supply on campus In Case 1A, approximately 0.95 kg/s of natural gas is needed to generate superheated steam at 100°C, while Case 1B requires about 0.90 kg/s of natural gas for steam at 200°C The table also details the inlet hot water conditions, outlet high-pressure steam conditions for Boiler 1, and the characteristics of the exiting flue gas, including temperature, pressure, and flow rate for both cases.

Table 5-14 presents the inlet hot water, flue gas, and high-pressure steam outlet conditions for natural gas combustion, simulated in HYSYS for Cases 1A and 1B These results were obtained at a consistent boiler efficiency of η% and a fixed hot water inlet temperature of 90°C, corresponding to a specific natural gas flow rate.

Hot water inlet HP-Steam Natural Gas Flue Gas1 Case

The Downtown campus requires two types of steam supply: saturated steam at approximately 10 bar for the Downtown meter point and superheated steam at around 18.25 bar for the Life Science meter point To accommodate these pressure needs, the inlet pressure for Boiler1 at HSC is adjusted to about P.5 bar, allowing high-pressure steam to be delivered to the Downtown meter point at 10.22 bar Additionally, a reciprocating compressor is utilized to meet the Life Science meter point's pressure requirement of P.25 bar The compressor operates with an assumed adiabatic efficiency of 75%, as per AspenTech's default settings For the generation of superheated steam at Downtown, key parameters such as an actual steam flow rate of 371.9 m³/h, compressor power of 87.28 kW, and specific inlet and outlet pressures were analyzed using Aspen ACCE to estimate the compressor cost effectively.

Scenario 2 Fired Heater: In Case 2A which supplies saturated steam to the Health Sciences and

At Evansdale campuses, a steam production requirement of approximately 0.60 kg/s is necessary for medium pressure steam at 12.5 bar, while Case 2B indicates a need for 0.56 kg/s of natural gas to generate medium pressure steam (P.5 bar) for both Health Sciences and Evansdale campuses Additionally, a natural gas flow rate of 0.04 kg/s is essential for low pressure steam (P=2.75) at the Towers meter point The inlet hot water conditions, outlet steam conditions for Boiler1 in Case 2A, and for both Boiler1 and Boiler2 in Case 2B, along with the exiting flue gas conditions, including temperature, pressure, and flow rate, are detailed in Table 5-15.

In Table 5-15, the inlet conditions for hot water, flue gas, and high-pressure steam outlet during natural gas combustion are simulated in HYSYS for Case 2A and Case 2B These simulations are conducted at a consistent boiler efficiency of η% and a fixed hot water inlet temperature of 90°C, corresponding to a specific natural gas flow rate.

Hot water inlet Sat Steam Natural Gas Flue Gas1

The costs associated with the natural gas preheater are assessed using Aspen ACCE, following the simulation of the Shell and Tube Heat Exchanger (STHE) in Aspen HYSYS and detailed design in Aspen EDR The financial outcomes for Scenario 1 and Scenario 2 are discussed in the subsequent paragraphs.

The cost of heat exchangers is evaluated for shell-and-tube heat exchangers (STHE) utilized in fuel preheater simulations In Scenario 1, the required STHE areas are approximately 71.70 m² for Case 1A and 69.90 m² for Case 1B, enabling the transfer of around 106.60 kW and 101.80 kW of heat energy, respectively, from flue gas to preheat natural gas to a temperature of 65°C In Scenario 2, an STHE area of about 42.40 m² is needed to transfer approximately 64 kW and 62.50 kW of heat from hot flue gas, achieving the same natural gas outlet temperature of 65°C for both Case 2A and Case 2B Detailed results of the rigorous STHE design are presented in Table 5.16.

In Aspen EDR, the meticulously designed areas of the Shell and Tube Heat Exchanger (STHE) are utilized in Aspen ACCE to calculate the heat exchanger costs For Scenario 1, the estimated cost is $0.1 million, while Scenario 2 shows a reduced cost of $0.08 million.

Table 5-16: Results of rigorous design in EDR and Aspen ACCE estimation for the natural gas preheater (shell and tube heat exchanger) for Scenario 1 and Scenario 2

Case Case 1A Case 1B Case 2A Case 2B

Parameter Value Value Value Value

Ammonia (NH 3 ) Heat Pump System

The integration of a heat pump system into the hybrid Ground-Source District Heating and Cooling (GDHC) system allows for the reinjection of geothermal fluid at reduced temperatures of 53.83°C and 55.56°C for Scenario 1 and Scenario 2, respectively This heat pump system enhances geothermal energy utilization by extracting additional heat from the returning condensate that enters the Plate Heat Exchanger (PHE) As illustrated in Figure 5.3, the cycle initiates with ammonia (NH3) at 45.60°C vaporizing within the evaporator, drawing heat from the low-temperature returning condensate stream The resulting lower-temperature condensate is then directed back to the centralized geothermal PHE through the outlet stream GEOHEX-CLDRETURN.

Figure 5.3: The proposed heat pump configuration using ammonia as a working fluid

The evaporator outlet (NH3EVAP-OUT) feeds into the compressor, where ammonia (NH3) is compressed to a high temperature of 166.6°C and a pressure of 54 bar The high-temperature NH3 exits the compressor (COMPR-OUT) and enters the condenser, where it is cooled to 92.69°C while rejecting heat to geothermally preheated water, raising its temperature from 75°C to 90°C The heated water is then directed to a natural gas boiler to generate saturated and superheated steam for Scenario 1 and Scenario 2, respectively The condenser outlet (CONDESR-OUT) is routed to an expansion valve to reduce the NH3 pressure, allowing the low-pressure NH3 to return to the evaporator and restart the cycle The heat pump cycle and the pressure-enthalpy (p-h) diagram for the ammonia heat pump, simulated in HYSYS, are illustrated in Figures 5.3 and 5.4.

Figure 5.4: Pressure-enthalpy (p-h) diagram of the ammonia heat pump simulated in HYSYS The major components for the heat pump simulated are represented by compressor (1-2), condenser (2-3), expansion valve (3-4) and evaporator (4-1)

The coefficient of performance (COP) of the heat pump was evaluated for Scenario 1 and Scenario 2, calculated as the ratio of heat rejected by the condenser to the compressor work input The results for Case 1A, Case 1B, Case 2A, and Case 2B are summarized in Table 5-17.

Table 5-17: Results of the coefficient of performance for Scenario 1 and Scenario 2

The calculated Coefficient of Performance (COP) for Scenario 1 is 4.49, while Scenario 2 has a COP of 3.02 Despite the work input to the compressor being consistent across all cases due to the uniform flow rate and temperature of the NH3 entering from the evaporator, the heat rejected by the condenser varies between the two scenarios This difference arises from the distinct flow rates of the heat-absorbing fluid, which is geothermally preheated water, leading to the differing COP values.

Vendors Quote for Heat Pump and Boiler

Quotes for the boiler unit and heat pump system were generated using HYSYS simulations, with vendor quotes reflecting specific process conditions such as steam flow rate and design parameters like design pressure These details are summarized in Tables 5-18 and 5-19 for the respective systems.

5.5.1 Boiler Vendor’s Quote from Johnston Boiler Company (JBC):

Table 5-18 below presents the operating pressure (psig), rated capacity (hp), and steam flow rate (lbs/hr) of dry saturated steam at the required pressure for Scenario 1 and Scenario 2, as simulated in HYSYS.

Table 5-18: Vendor’s quote obtained from Johnston Boiler Company (JBC) for Scenario 1 and Scenario

Steam flow rate (lbs/hr)

At a design pressure of 300 psig, Scenario 1 boiler, rated at 2,000 hp and 8.69 kg/s (69,000 lbs/hr), necessitates two units to satisfy the existing steam flow rate of approximately 15.2 kg/s (120,636.9 lbs/hr).

The 200# boiler is designed for a pressure of 200 psig and has a nominal capacity of 2,200 hp, equating to 9.45 kg/s (75,900 lbs/hr) To satisfy the current steam flow rate requirement of approximately 10.2 kg/s (80,953.74 lbs/hr) at WVU, two of these boilers would be necessary.

In Scenario 1 (Case 1A and Case 1B), the vendor's quote only covers saturated dry steam conditions and does not include the costs for the superheating necessary to achieve superheated steam conditions Conversely, Scenario 2 specifically requires saturated steam conditions.

5.5.2 Heat Pump Vendor’s Quote from Mayekawa Company:

Table 5.19 presents the vendor quotes for heat pumps simulated in HYSYS for Scenario 1 and Scenario 2, sourced from the Mayekawa Company These quotes were specifically derived from the use of NH3 as the working fluid.

Table 5-19: High temperature heat pump package performance obtained from Mayekawa Company

Hot water flow rate (gpm)

Table 5.19 presents vendor costs for two NH3 heat pump packages from Mayekawa Company tailored for WVU's rated process conditions Both options are comparable in design, size, and weight; however, Option #1 features a 4-cylinder high-pressure reciprocating compressor, achieving a hot flow rate of approximately 48.51 kg/s (770 gpm), while Option #2 employs a 6-cylinder compressor for a higher flow rate of 71.82 kg/s (1,140 gpm) Given that WVU's maximum flow requirements are 15.2 kg/s for Scenario 1 and 10.2 kg/s for Scenario 2, Option #1 is chosen to meet the necessary heat pump capacity for both scenarios The operating conditions from the vendor quote were analyzed against HYSYS simulation results from Chapter 4, revealing that the coefficient of performance (COP) for the vendor's quote is 6.18, surpassing the 4.49 and 3.02 COPs achieved in HYSYS for Scenarios 1 and 2, respectively, as shown in Table 5.20.

Table 5-20 compares the ammonia heat pump parameters from Mayekawa Company with those simulated in HYSYS for Scenario 1 and Scenario 2 The red section highlights the heat pump system conditions derived from the HYSYS simulation, providing a clear overview of the performance metrics and operational efficiencies of both systems.

IN OUT IN OUT IN OUT IN OUT

*N/A not applicable as only vendor’s quote was used.

HYSYS Pipeline Distribution System Simulations Results and Discussion

Pressure losses in the pipeline were analyzed for two scenarios: the entire campus and the Medical Center, Towers, and Evansdale, as illustrated in Figure 5.5 The findings indicate that the pressure drop in the proposed piping system is influenced by factors such as steam flow rate, pipe length, and pipe diameter in both scenarios.

Figure 5.5: Schematic of the proposed steam pipeline distribution from geothermal well site location to the five meters across the entire WVU campus

5.6.1 Pressure losses across steam line:

In Case 1A and Case 1B, the pressure drop is most significant in the 4,596 ft long, 10 in diameter pipeline (BD), as detailed in Table 5.21 This is due to the extensive distance the steam must travel from the Med-center to the Tower meter point In contrast, the pressure losses in the other pipelines are notably lower when compared to the longest pipeline (BD).

Table 5-21: Pressure drop across the steam pipelines for Scenario 2 (Case 1A and Case 1B) Red section represents new pipelines and black section represents existing MEA pipelines

Flow rates (kg/s) ΔP (psi) Case 1A Case 2A

In Scenario 2 (Case 2A and Case 2B), pressure losses in the pipeline distribution system are influenced by factors such as pipe length, diameter, and steam flow rate, as detailed in Table 5.22 Notably, Pipeline BD experiences the highest pressure drop in this scenario Additionally, the newly introduced Towers pipeline (NEW-TWR) exhibits a significant pressure drop of 5.19 psi, attributed to the separate pipeline in scenario 2B that transports low-pressure steam from the secondary boiler to the Towers meter point.

Table 5-22: Pressure drop across steam pipelines for Scenario 2 (Case 2A and Case 2B) Red section represents new pipelines and black section represents existing MEA pipelines

5.6.2 Pressure losses across condensate line:

The pressure losses in the condensate pipelines for both scenarios—entire campus and the Medical Center, Towers, and Evansdale—are influenced by factors such as condensate flow rate, pipe length, and diameter, as detailed in Table 5-23 In Scenario 1, the pressure drop is notably higher in three specific pipelines: from the downtown meter point (cond-DTN-LFS2F) to the downtown MEA point (cond-DTN-LFSS), and from the MEA meter point to the Evansdale meter point (AGTWRDTND) These increased pressure losses are attributed to the longer lengths of these pipelines.

Table 5-23: Pressure drop across condensate pipelines for Scenario 1 Red section represents new pipelines and black section represents existing MEA pipelines

In Scenario 2 (Case 2A and Case 2B), pressure losses are influenced by factors such as pipe length, diameter, and condensate flow rate, as detailed in Table 5.24 Notably, Pipeline BD, with the longest length of 4,596 feet, experiences the highest pressure drop of 42.76 psi in this scenario Additionally, the pressure drop in the newly introduced Towers pipeline (NEW-TWR) is significant at 5.19 psi, attributed to Scenario 2B's separate pipeline that transports low-pressure steam from the secondary boiler to the Towers meter point.

Table 5-24: Pressure drop across condensate pipelines for Scenario 2 Red section represents new pipelines and black section represents existing MEA pipelines

Aspen ACCE Pipeline Cost Results and Discussion

5.7.1 Scenario 1 Pipeline Cost from ACCE:

The evaluation of pipe costs for the campus distribution networks was conducted using Aspen ACCE, focusing on both pipe length and diameter for existing and new pipelines A comparison of the costs for the new steam and condensate pipelines (highlighted in red) against the existing pipelines (shown in black) is presented in Table 5-25 below.

Table 5-25: The result of the pipeline simulated in HYSYS for the steam and condensate pipelines Red section represents new pipelines and black section represents existing MEA pipelines

DE 199 TWR-PIPE 4 0.01 Cond-TWR-

DF 701 AG-DTN 12 0.30 Cond-AG-

FG 616 AG-PIPE 8 0.01 Cond-AG-

FH 3,945 DTN-LFSC 12 1.7 Cond-DTN-

HI 1,996 DTN-LFSC2 8 33 Cond-DTN-

JK 701 LFS-PIPE 6 0.08 Cond-LFS-

JL 505 DTN-PIPE 8 0.08 Cond-DTN-

From the table, the cost of the new steam pipeline to be added to the existing MEA line is about

The total estimated cost for purchasing and installing the insulated pipe segmented for the retrofitted pipeline system at WVU is approximately $1.04 million, which includes $0.72 million for the existing pipeline and $0.33 million for the new condensate pipeline in Scenario 1 (Case 1A and Case 1B).

A pipeline segment was modeled in HYSYS to transport the natural gas necessary for boiler operation, with an estimated length of 3,000 ft provided by the WVU Facilities Management Team This pipeline is essential for supplying natural gas for combustion in the boiler The required pipe diameter for transporting natural gas in Scenario 1, encompassing Case 1A and Case 1B, was determined through HYSYS simulation based on the fired heater air-fuel flow rate The cost of the natural gas pipeline for Scenario 1 is estimated at $0.18 million, which remains consistent for both Case 1A and Case 1B.

5.7.2 Scenario 2 Pipeline Cost from ACCE:

Pipe length and pipe diameter used for steam and condensate pipeline networks simulation in HYSYS as in section 5.6 Here, the corresponding pipe costs for distribution networks were

The costs of the new steam and condensate pipelines, as evaluated in Aspen ACCE, were compared to the existing pipelines, with the findings detailed in Tables 5-26 and 5-27.

Table 5-26: The result of Case 2A pipeline simulated in HYSYS for the steam and condensate pipelines Red section represents new pipelines and black section represents existing MEA pipelines

DE 199 TWR-PIPE 4 0.01 Cond-TWR-

DF 701 AG-DTN 12 0.30 Cond-AG-

FG 616 AG-PIPE 8 0.10 Cond-AG-

Table 5-27: The result of Case 2B pipeline simulated in HYSYS for the steam and condensate pipelines Red section represents new pipelines and black section represents existing MEA pipelines

DE 199 TWR-PIPE 4 0.01 Cond-TWR-

DF 701 AG-DTN 12 0.30 Cond-AG-

FG 616 AG-PIPE 8 0.10 Cond-AG-

In Case 2A, the addition of a new steam pipeline to the existing MEA line is projected to cost approximately $0.72 million, while the new condensate pipeline is estimated at $0.33 million In contrast, Case 2B reveals a total cost of $1.42 million for steam and condensate pipelines, which includes the new tower pipeline costing about $0.71 million, alongside the condensate pipeline remaining at $0.33 million.

In Case 2A, a new segmented pipeline was simulated in HYSYS to transport the natural gas needed for boiler operation, as detailed in Table 5.28 This pipeline supplies fuel for combustion in the boiler Conversely, Case 2B involved the simulation of two additional pipelines, each designated for Boiler1 and Boiler2, facilitating the combustion of natural gas in both boilers Consistent with Scenario 1, a pipeline length of 3,000 ft was utilized, as indicated by the WVU Facilities Management Team The required pipe diameter for transporting natural gas was determined based on the air-fuel flow rates obtained from HYSYS simulations in Chapter 4 Additionally, the Aspen ACCE costs associated with the new natural gas pipelines are discussed.

Table 5-28: The result of the pipeline simulated in HYSYS for the natural gas pipelines

Pipe name Pipe length (ft) Diameter (in) Direct cost (M$)

Case 2A Case 2B Case 2A Case 2B Case 2A Case 2B

The total estimated cost for new hot water, condensate, and natural gas pipelines in Cases 1A, 1B, and 2A is approximately $1.22 million In contrast, the total cost, including the new Towers pipeline for Case 2B, is estimated to be around $2.01 million.

Aspen ACCE Results for Condensate and Hot Water Pump Costs

5.8.1 Scenario 1 Condensate and Hot Water Pump Costs

The pumping capacity for hot water and condensate pumps, along with the steam mass flow rate and pressure head derived from HYSYS simulations, were utilized as inputs in Aspen ACCE to estimate the total capital cost of the pumping system, as detailed in Table 5.29 below.

Table 5-29 presents the estimated costs of Aspen ACCE pumps for both hot water and condensate in Scenario 1 (Case 1A and Case 1B), highlighting the expenses associated with supplying hot water to the boiler unit and transporting condensate to the centralized surface plant for reuse in the geothermal heat exchanger system.

At a geothermal preheated water outlet flow rate of 15.2 kg/s, the estimated total pumping cost for the Case 1A hot water and condensate pumps servicing the entire campus is $0.28 million.

59 cost for pumping system in Case 1B is $0.28 M One hot water pump and a total of six condensate pumps were required for Case 1A and Case 2B GDHC steam distribution system at WVU

5.8.2 Scenario 2 Condensate and Hot Water Pumps Costs

The hot water and condensate pumps' pumping capacity, along with the steam mass flow rate and pressure head derived from HYSYS simulations, were utilized in Aspen ACCE to estimate the total capital cost of the pumping system, as detailed in Table 5.30 below.

Table 5-30 presents the cost estimates for the Aspen ACCE pumps in Scenario 2, specifically for hot water and condensate pumps These pumps are essential for supplying hot water to the boiler unit and transporting condensate to the centralized surface plant for reuse in the geothermal heat exchanger The highlighted red section indicates the necessary hot water pump for the new Tower pipelines.

In Scenario 2, the total pumping cost for hot water and condensate pipelines at a geothermal PHE preheated water outlet flow rate of 10.2 kg/s is estimated at $211,300 for Case 2A, while Case 2B incurs a higher cost of $249,300 due to the necessity of an additional hot water pump to supply low-pressure hot water to Boiler2 Case 2A requires one hot water pump, whereas Case 2B necessitates two Additionally, both cases require a total of four condensate pumps.

Aspen ACCE results for Condensate Receiver Tank Cost

The required volume of the uninsulated condensate tank for two scenarios was calculated by converting the steam flow rates of 225,000 lb./hr for the entire campus and 145,000 lb./hr for the Evansdale and Health Sciences campuses into equivalent water volume This calculation assumed that the hot water flow rate is half the hourly evaporation rate of steam in the boiler and that an additional tank volume of approximately one-twelfth of the steam flow rate is necessary for operational buffer space The final tank volumes derived for both scenarios were then utilized to estimate the cost of the condensate tank, as detailed in Table 5-31.

Table 5-31: The results of the cost of the condensate receiver tanks estimated for Scenario 1 and Scenario

Scenario Equipment Type Parameter Parameter Value Cost (M$)

Scenario 1 Condensate Receiver Tank Volume (m 3 ) 62.10 0.27

Scenario 2 Condensate Receiver Tank Volume (m 3 ) 40.00 0.23

Surface Plant Equipment Utility and Miscellaneous Costs

The estimated annual utility costs for natural gas and electricity consumption in the boiler and pumping units of surface plants are calculated based on an operating year of 8,760 hours Current rates provided by WVU Facilities Management indicate electricity costs at $0.067 per kWh and natural gas at $4.12 per 1,000 cubic feet.

The estimated utility costs for pumping hot water into the boiler unit and transporting condensate back to the central surface plant facility at HSC were calculated using pump power (kW), an efficiency rate of 80%, and the unit cost of electricity The annual pumping utility costs for both scenario 1 and scenario 2 are detailed in Tables 5.32 and 5.33, respectively.

Table 5-32: The result of the utility cost estimated for pumping system at an electricity rate of $0.067/kWh for Scenario 1

The total utility cost for Case 1A ($30,644) is higher than Case 1B ($25,171) because the total pumping requirement for Case 1A (41.77 kW) is larger than Case 1B (34.31 kW)

In Scenario 2, the estimated utility cost for the pumping system is calculated at an electricity rate of $0.067 per kWh, with the additional pumps needed for the new Towers steam pipeline highlighted in red.

Cond-PUMP-TWR 1.40 1.75 1,020.51 1.40 1.75 1,020.51 Cond-PUMP-

Similarly, the total utility cost for Case 2A ($13,386.10) is higher than Case 2B ($12,690.16) because the total pumping requirement for Case 2A (18.25 kW) is larger than Case 2B (17.30 kW)

For Scenario 1 Case 1B, the compressor power (kW) and efficiency were used to estimate the annual utility cost for the compressor at about $68,301 as represented in Table 5.34 below

Table 5-34: The result of the utility cost estimated for the compressor at an electricity rate of $0.067/kWh

The annual utility cost for the air blower in the boiler unit was calculated based on its power consumption (kW) and an efficiency rate of 75% By applying the unit cost of electricity, the estimated annual pumping utility costs for both scenarios (Case 1A and Case 1B) were determined.

2 (Case 2A and Case 2B) are summarized in Table 5.35 below

Table 5-35: The result of the utility cost estimated for the air blower at an electricity rate of $0.067/kWh

5.10.4 Natural Gas Boiler Utility Cost

The annual utility cost for operating the natural gas boiler is calculated based on a natural gas purchase rate of $3.68 per gigajoule, reflecting the price in dollars per thousand cubic feet.

The annual natural gas utility cost at WVU was calculated using a unit cost of $4.12 per 1000 ft³, along with boiler heat duty (kW) and an efficiency of 85% For Scenario 1, the costs were $5.37 million for Case 1A and $5.13 million for Case 1B In Scenario 2, the costs were $3.22 million for Case 2A and $3.42 million for Case 2B.

Table 5-36: Scenario 1 and Scenario 2 results of the utility cost estimated for natural gas supply at a rate of $4.12/1000 ft 3

Scenario 1 and Scenario 2 annual heat pump utility cost for power (221.3 kW) and efficiency (75%) is estimated as $0.17 M

Perform an Economic Analysis to Estimate the Levelized Cost of Heat (LCOH) Using GEOPHIRES

Economic Evaluation

An economic evaluation of the proposed hybrid geothermal district heating and cooling (GDHC) system at West Virginia University (WVU) was conducted using GEOPHIRES software, which specializes in techno-economic analysis of geothermal energy systems The primary goal of this evaluation is to assess the economic feasibility of the hybrid GDHC system by comparing its costs and benefits to those of the existing coal-fired steam-based system To facilitate this comparison, the levelized cost of heat (LCOH) was calculated in GEOPHIRES, utilizing various parameters essential for determining the overall economic performance of the hybrid system.

• The amount of heat produced over the project lifetime (30 years)

• The capital cost of investment and

To calculate LCOH, GEOPHIRES has built-in correlations to estimate the capital cost of investment and O&M costs [45]

The capital cost of investment (C cap ) is calculated as the sum of:

• Well drilling and completion cost (C well )

• Surface plant equipment and distribution costs (C surf )

The sum of these costs (Ccap) are summarized as follows:

The surface plant cost model in GEOPHIRES is limited to basic cost calculations and cannot provide detailed estimates for the major components of surface plant equipment and distribution pipeline costs (Csurf) Consequently, simulations and designs for basic surface plant equipment and distribution networks were conducted using Aspen Plus, Aspen HYSYS, and Aspen Exchanger Design and Rating (EDR) The costs for various components in these surface plant designs were estimated with the Aspen Economic Analyzer, including the Aspen Capital Cost Estimator (ACCE) Additionally, specific equipment costs, such as those for natural gas boilers and heat pump systems, were sourced directly from vendors.

Similarly, the annual plant operating and maintenance costs (C O&M, plant ) are calculated as the sum of:

• Make-up water costs (C O&M, water )

• Surface plant utilities and natural gas costs (C U&NG, surf)

The sum of these costs (C O&M, plant ) are summarized as follows:

The geothermal reservoir's water loss is considered negligible, leading to the assumption that annual expenses for make-up water are zero for the GDHC system at WVU.

This article discusses the design of a hybrid geothermal-natural gas boiler district heating and cooling system for West Virginia University (WVU) The GEOPHIRES V2.0 python code, initially capable of simulating and calculating the Levelized Cost of Heat (LCOH) solely for geothermal systems, was modified to accommodate the hybrid system Key parameters were incorporated into the LCOH calculation to enhance the accuracy of the simulation for the combined heating and cooling system.

The boiler heat duty is derived from Aspen simulators, while the total annual natural gas utility cost is determined by the annual fuel flow rate necessary for steam production Additionally, the utility costs for the pump, compressor, and air blower are calculated based on the average electricity rate at the WVU campus, which is $0.067 per kWh.

6.1.2 Levelized Cost of Heat (LCOH) Model

Currently, there are three economic models available in GEOPHIRES to calculate LCOH These models are:

1 Fixed charge rate (FCR) model

2 Standard levelized cost (SLC) model

3 BICYCLE levelized life cycle cost model

The BICYCLE levelized cost model is recognized as the most robust and comprehensive economic model for evaluating the feasibility of the GDHC system at WVU It incorporates critical factors such as inflation rates, tax rates, and tax credits, making it a realistic assessment tool By assuming that the GDHC system is financed through a combination of debt (bonds) and equity, the model enables variations in the ratio of these financing methods to effectively model the Levelized Cost of Heat (LCOH).

$/MMBTU is calculated as follows:

The net present value (NPV) is calculated using the inflation rate (i inf), the average return on investment (i ′), the nominal thermal output (W t) in kilowatts thermal (kWth), and the operational lifespan of the plant, which is 30 years.

Levelized Cost of Heat (LCOH) Calculations

The levelized cost of heat estimates presented here are primarily derived from the current district heating and cooling system at West Virginia University (WVU), potentially overlooking other significant features that may be unique to this context.

The Levelized Cost of Heat (LCOH) is influenced by various factors, including drilling costs, geothermal gradient, operating hours, energy utilization factors, flow rates per well, and surface plant operation and maintenance costs Additionally, the plant's lifetime, discount rates, economic risks, and regional considerations, such as existing infrastructure, play a significant role in determining LCOH It is important to note that the LCOH calculations do not account for subsidies, tax incentives, or CO2 credits Therefore, any comparisons of LCOH must consider these factors, as geothermal resources are geographically localized.

Total Surface Plant and Capital Cost for Scenario 1 and Scenario 2

GEOPHIRES does not include built-in correlations for calculating surface plant costs, necessitating the use of Aspen ACCE to obtain the costs of major surface plant equipment for Scenario 1 (Case 1A and Case 1B) and Scenario 2 (Case 2A and Case 2B) The direct costs for geothermal surface plant equipment, which includes items such as plate heat exchangers, fuel preheaters, pumps, and retrofitted pipelines, are detailed in Table 6-1, alongside vendor quotes for the boiler and heat pump system Indirect costs, encompassing construction expenses, contingencies, contractor fees, and engineering costs, are estimated at 35% of the total direct and indirect costs, resulting in total surface plant indirect costs accounting for 54% of the direct costs The combination of direct and indirect costs forms the fixed capital investment, which is equivalent to total module costs The overall capital investment comprises both fixed capital investment and working capital, with the latter estimated to be 20% of the total capital investment required to initiate and maintain the hybrid surface plant's operations.

Working capital is determined as 25% of the total fixed capital investment, which includes all direct and indirect costs The overall project costs, detailed in Table 6-1, encompass utility expenses for the pumping system, compressor, natural gas, and air blower, along with the capital costs for surface plant facilities Additionally, the annual operation and maintenance (O&M) costs for the surface plant equipment are projected to be 20% of the total surface plant cost and are expected to increase in proportion to the size of the equipment.

Table 6-1 presents the Aspen ACCE results, vendor quotes, and utility costs for surface plant equipment in two scenarios: Scenario 1, which delivers superheated steam to the entire campus, and Scenario 2, which provides saturated steam specifically to the Health Sciences and Evansdale campuses, including Towers and Evansdale.

Scenario 1 and Scenario 2 Total Project Cost Summary (M$) Equipment type Case 1A Case 1B Case 2A Case 2B

Total Surface Plant Direct Costs 4.38 4.96 4.09 5.80

Total Surface Plant Indirect Costs 2.37 2.68 2.21 3.13

Case 1A features a centralized surface facility that includes a heat exchanger, boiler, heat pump system, and condensate receiver tank, all situated at HSC This setup incurs a lower total capital cost, although it results in slightly higher annual utility expenses compared to Case 1B, which involves the additional cost of a compressor.

In Scenario 2, Case 2A presents a more favorable option compared to Case 2B, as it has a lower total capital cost and utility cost, with Case 2A costing $3.67 million per year versus Case 2B's $3.86 million per year Consequently, designing a centralized surface facility for Case 2A is the preferred choice due to its overall cost-effectiveness.

The evaluation of the Natural Gas Fired Boiler (NGFB) system for steam production at WVU focuses on total surface plant capital costs, utility expenses, and the Levelized Cost of Heat (LCOH) This assessment excludes geothermal components such as the geothermal PHE and heat pump costs from the surface plant equipment and distribution pipeline networks for the GDHCS system Since the LCOH calculation in GEOPHIRES software is tailored for geothermal systems, the LCOH for the NGFB system is manually computed in Microsoft Excel using the BICYCLE economic model.

Table 6-2 presents the Aspen ACCE results for natural gas boilers, detailing vendor quotes and utility costs associated with surface plant equipment This data is categorized into two scenarios: Scenario 1, which provides superheated steam to the entire campus, and Scenario 2, which supplies saturated steam specifically to the Health Sciences and Evansdale campuses, including Towers and Evansdale.

Scenario 1 and Scenario 2 Total Project Cost Summary (M$) Equipment type Case 1A Case 1B Case 2A Case 2B

Retrofitted Steam Pipeline 0.72 0.72 0.72 1.42 Retrofitted Condensate Pipeline 0.33 0.33 0.33 0.33

Total Surface Plant Direct Costs 4.23 4.74 3.37 4.49

Total Surface Plant Indirect Costs 2.29 2.56 1.82 2.43

Economic Analysis in GEOPHIRES

6.4.1 Economic Analysis of Scenario 1 and Scenario 2 with Existing MEA Distribution

Economic Analysis of Scenario 1 and Scenario 2 with Purchase of Distribution Pipelines 76

The heating and cooling distribution system at West Virginia University (WVU) is currently managed by MEA Upon the expiration of their existing contract, WVU may either acquire or receive the MEA distribution pipeline as a donation To address potential uncertainties regarding the distribution system, the Levelized Cost of Heating (LCOH) is calculated based on estimated pipeline costs provided by WVU Facilities Management.

• Additional capital cost of $15 M if existing distribution pipelines are purchased from MEA by WVU

• Additional capital cost of $25 M if a new set of pipelines are purchased and installed for the WVU campus

In both Scenario 1 and Scenario 2, as illustrated in Tables 6-1 and 6-2, the levelized cost of hydrogen (LCOH) significantly escalates with rising capital costs for both default and NNE well costs, particularly when new distribution pipelines are procured or installed by WVU Specifically, for the NNE well cost, the levelized cost ranges from $8.50 to $12.45 per MMBTU for vertical well configurations, and from $8.72 to $12.89 for other setups.

The levelized cost of energy for vertical wells ranges from approximately $9.08 to $13.38 per MMBTU, while for horizontal wells, it varies between $9.47 and $14.08 per MMBTU, based on the default well costs provided in GEOPHIRES.

Figure 6.1: Scenario 1 (Case 1A and Case 1B) and Scenario 2 (Case 2A and Case 2B) LCOH values simulated in GEOPHIRES for NNE well at additional capital costs of $15M and $25M

Figure 6.2: Scenario 1 (Case 1A and Case 1B) and Scenario 2 (Case 2A and Case 2B) values simulated in GEOPHIRES for default (DF) well at additional capital costs of $15M and $25M

In the simulations conducted in GEOPHIRES, Case 1A exhibited the lowest levelized cost of hydrogen (LCOH), while Case 2B showed the highest LCOH Overall, the LCOH values for Cases 1A, 1B, 2A, and 2B associated with horizontal wells were found to be higher than those for vertical wells.

However, the levelized cost of heat (LCOH) for natural gas-fired boiler without geothermal, as shown in Table 4-1, ranges from 5.65 to 7.46 $/MMBTU

Table 6-7: The results of excel LCOH calculation for NGFB using BICYCLE economic model for Scenario 1 and Scenario 2

Parameters Case 1A Case 1B Case 2A Case 2B

The economic analysis indicates that the Levelized Cost of Hydrogen (LCOH) ranges identified in this study are lower than typical values found in existing literature This suggests that the proposed hybrid Ground-Source District Heating and Cooling (GDHC) system can be feasibly developed for West Virginia University (WVU), provided that the existing pipelines are donated by the Mountain Energy Association (MEA) In contrast, the LCOH values derived from the Natural Gas-Fired Boiler (NGFB) system, which does not utilize geothermal energy, are significantly lower than those of the proposed hybrid GDHC system.

Fuel Price Analysis for Case 1A

The future price of fuel significantly influences the Levelized Cost of Heat (LCOH) and the economic viability of the project Due to the uncertainty surrounding natural gas prices, an analysis for Case 1A was conducted to identify the natural gas price at which the proposed hybrid Ground Source District Heating and Cooling (GDHC) system becomes more cost-effective than the Natural Gas Fired Boiler (NGFB) Currently, the natural gas price supplied to West Virginia University (WVU) is $4.12 per 1000 cubic feet The LCOH values for varying natural gas prices in the proposed hybrid system are compared to those of the NGFB system, as detailed in Table 6-8.

Table 6-8: The LCOH results of the proposed hybrid GDHC system compared with NGFB system at different natural gas prices for Case 1A

The economic viability of the proposed hybrid GDHC system is contingent upon natural gas prices, with $15.00 per 1000 ft³ being the critical threshold When prices fall below this level, the hybrid system cannot compete with the more affordable NGFB, making it a less attractive option Conversely, if natural gas prices exceed $15.00 per 1000 ft³, the hybrid GDHC system becomes increasingly appealing, as its Levelized Cost of Heat (LCOH) is significantly lower than that of NGFB.

Conclusions and Recommendations for the Future Work

WVU's Morgantown campus, home to over 30,000 students and approximately 245 buildings spread across 1,892 acres, presents a significant opportunity for year-round geothermal energy utilization The presence of a hot spot beneath the Tuscarora Sandstone enhances its potential, making it an ideal site in the eastern United States for developing a geothermal direct-use heating and cooling system.

The project aimed to assess the feasibility of developing a geothermal district heating and cooling (GDHC) system for the West Virginia University (WVU) campus in Morgantown It involved evaluating the current district heating and cooling (DHC) system and proposing a combination of the existing DHC with a geothermal system to supply steam across various campuses Due to the geofluid from the well not meeting the campus steam demand at temperatures below 100°C, the study explored the integration of low-temperature geothermal energy with a natural gas boiler Utilizing Aspen simulators, a design for the geothermal surface plant was created, leading to the development of a hybrid GDHC system that incorporates a natural gas-fired boiler This innovative hybrid geothermal-natural gas district heating and cooling system is proposed as a replacement for the existing coal-fired steam-based system at WVU.

This study aimed to enhance the hybrid Ground-Source District Heating and Cooling (GDHC) system by integrating a heat pump, as the geothermal contribution was initially low By increasing the secondary fluid temperature from 75°C to 90°C, the performance of the hybrid system improved significantly, maximizing geothermal energy utilization and reducing the levelized cost of heat (LCOH) The results indicated that the geothermal contribution to the heating and cooling system at WVU increased from 2.30-2.43% to 4.05-4.39% with the upgraded hybrid GDHC system.

The total capital costs for two scenarios were assessed using Aspen ACCE, incorporating surface plant equipment and distribution expenses to calculate the Levelized Cost of Heat (LCOH) in GEOPHIRES Following the determination of surface plant capital costs, the BICYCLE model was employed to evaluate LCOH at West Virginia University (WVU) The viability of the Ground-Source District Heating and Cooling (GDHC) system was analyzed by comparing the costs of the proposed hybrid GDHC system against the existing MEA coal-fired steam-based system.

WVU currently incurs a cost of $15/MMBTU for steam supplies from MEA Previous research by Nandanwar et al estimated the Levelized Cost of Heat (LCOH) for the WVU campus at $11.73/MMBTU This study identified LCOH ranges of $7.55 to $10.90/MMBTU for vertical well configurations and $7.77 to $11.60/MMBTU for horizontal wells, utilizing the existing pipeline distribution system The proposed hybrid Ground Source District Heating and Cooling (GDHC) system shows that horizontal well costs are higher primarily due to well drilling expenses, which significantly influence geothermal project costs Consequently, the vertical well configuration offers a cost advantage due to lower drilling costs Additionally, assessments of potential capital costs for new pipeline installations—$15 million for purchasing or $25 million for installing—indicate that if existing pipelines are not available from MEA, the resulting LCOH would range from $8.50 to $12.89/MMBTU, which remains lower than the LCOH values of $16 to $17.

$/MMBTU reported in the literature [41], [52], [64]

The proposed hybrid GDCH system for the WVU campus is advantageous, as its levelized cost of heat (LCOH) for both scenarios is lower than the current steam supply cost of $15/MMBTU from MEA In comparison, the LCOH for a natural gas-fired boiler system, without geothermal, ranges from $5.65 to $7.46/MMBTU at the current natural gas price of $4.02/1000ft³ However, if natural gas prices exceed $15.00/1000ft³, the LCOH for the proposed hybrid system becomes more cost-effective than that of the natural gas-fired boiler system.

A summary of the major contributions from this study include:

• Characterization of current campus steam data at WVU and the data obtained are used in surface plant design

• Evaluation of the existing district heating system for the proposed new steam generation system

• Two design scenarios were investigated based on campus steam data and master campus district heating and cooling system drawings provided by WVU Facilities Management

• Rigorous design of the surface plant equipment in Aspen EDR including plate heat exchangers and shell and tube heat exchangers for fuel preheater

• Improvement of the two hybrid scenarios was further investigated to extract more heat from secondary fluid using heat pump in order to lower the LCOH at WVU

• Surfaced plant capital costs are calculated in Aspen ACCE

• Determined the total surface plant costs (capital cost, utility cost, and O&M costs) for the project

• The GEOPHIRES code written in Python was modified for the proposed hybrid system

The primary input for determining the Levelized Cost of Heat (LCOH) for the proposed hybrid Ground Source District Heating and Cooling (GDHC) system was derived from data obtained through surface plant design in Aspen simulators and reservoir output parameters from reservoir simulations, which were then fed into the modified GEOPHIRES model.

• GEOPHIRES simulation results show that the two scenarios investigated require a capital investment of about 16.72 to 27.93 $M for the vertical well configuration and a 21.21 to 34.95 $M for the horizontal well configuration

The study concludes that the proposed hybrid GDHC system for WVU offers a competitive and cost-effective alternative to the existing MEA coal-fired steam system While it currently cannot match the economic viability of the NGFB system due to natural gas prices, future projections indicate that the hybrid system would become more economical if natural gas prices exceed $15.00 per 1,000 ft³ Additionally, the hybrid GDHC system presents significant environmental benefits by reducing fossil fuel consumption on the WVU campus.

7.2 Recommendations for the Future Work

An assessment is needed to evaluate the feasibility of converting the existing steam-based heating system to a hot water-based system This analysis aims to compare the proposed hybrid geothermal-natural gas system with the DDU system design, which would supply hot water for campus heating and cooling Preliminary projections suggest that transitioning from the steam system to a hot water system may not be cost-effective To confirm or refute this assumption, it is essential to analyze WVU's steam data to determine the viability of a geothermal hot water system that could meet all heating and cooling needs for the campus.

To achieve this objective, the following steps needs to be considered:

The article outlines the essential background information necessary for converting the existing steam system to a hot water system on the WVU campus It includes an analysis of the campus's hot water demand and usage, the current conditions of the central plant, and the proportion of total steam that can be effectively converted to hot water This comprehensive assessment is crucial for ensuring a successful transition and optimizing energy efficiency.

• Challenges of converting existing steam-based system to hot water system

• Some equipment replacements for the proposed hot water system design

• Centralized surface plant facility design with the appropriate temperature and pressure should be considered for the hot water system design

• New distribution piping networks should be considered for the campus pipelines as higher hot water flow rates would be required to meet campus heating and cooling demand

An efficient hot water system should incorporate essential components such as a heat exchanger, heat pump system, new pipeline networks, circulatory and condensate pumps, tanks, and a dedicated boiler for steam requirements This system must operate independently from the existing district heating and cooling (DHC) distribution system To achieve optimal performance, the piping system should be designed to minimize heat, temperature, and pressure losses by modeling the pipeline diameters according to the desired hot water flow rate Hot water must be circulated through the campus loop at fixed temperature and pressure by a circulatory pump, ensuring effective distribution Given that the geothermal well is located within 5 km, heat losses are expected to be minimal, with temperature drops along the pipeline kept well below 5°C.

The evaluation of surface plant capital costs, including equipment and piping, should be conducted using 84 simulators, specifically Aspen Plus and HYSYS An estimation of the total capital cost for the hot water system is essential Additionally, the Levelized Cost of Heat (LCOH) from the proposed hot water system must be compared with that of the hybrid Ground-Source District Heating and Cooling (GDHC) system presented in this study To assess feasibility, a comparison of costs and benefits between the hot water system and the existing MEA coal-fired steam-based system is necessary.

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