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Feasibility Report of Fortissat Community Minewater Geothermal Energy District Heating Network

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Executive Summary

Introduction

This report presents the findings of the feasibility assessment for a potential minewater geothermal energy system in the vicinity of the James Hutton Institute's (JHI) Hartwood Home Farm, North Lanarkshire. The study area extends 5km from the site centre, which is roughly equivalent to the Fortissat ward of North Lanarkshire, and includes the settlements of Hartwood, Allanton, Shotts and Salsburgh.

The Fortissat Minewater Geothermal proposal is one of four projects awarded funding from the Scottish Government's Geothermal Energy Challenge Fund (GECF), for the 'Catalyst Stage' which covers initial strategy development and feasibility work. These projects have been funded to explore the potential of Scotland's geothermal resource to meet the energy needs of local communities.

Project Aims

The aim of this project has been to assess the feasibility and define the initial strategy to develop Scotland's first minewater geothermal scheme in a rural area with social deprivation. While focused on the specifics of the location, the project is conceived as a readily replicable and fully operational mine-water geothermal district heating system demonstrator project that would act as proof of concept for Scotland-wide duplication.

The project also addresses the complex technical and stakeholder management issues associated with development of a community district heating system within a varied portfolio of existing accommodation held under mixed tenure rather than a new build housing scenario. North Lanarkshire Council is engaged in the project and actively investigating all options for improving housing energy efficiency, reducing heating costs, and reducing carbon from heat in their Council homes.

Site and Study Area

The "site", for the purposes of the feasibility study and as the focus for defining locations for key infrastructure elements (such as production well, energy centre and reinjection well / passive treatment systems), has been Hartwood Home Farm, reflecting the role of JHI as the grantee. However, as the understanding of the geothermal resource developed, and the potential for Council owned properties to form the basis for the heat market, further engagement with North Lanarkshire Council (NLC) as project partner enabled the potential for alternative locations for site infrastructure within land in the ownership of NLC to be investigated as options. This has established the former Kingshill Colliery No. 1, now the designated Kingshill Local Nature Reserve (LNR) / Kingshill Wetlands and Plantations Site of Importance for Nature Conservation (SINC), as a potential site.

Geothermal Supply

The minewater geothermal resource mapping has identified the worked coal seams of the Kingshill Colliery as by far the largest geothermal resource in the area of interest and has been the main focus of this study, following a geothermal systems option appraisal which considered the various mine systems in the study area. Kingshill Colliery is one of Scotland's largest historical mine systems and the mine seams (primarily comprising the Wilsontown Main (WNMA) and Woodmuir Smithy (WRSM) seams) partly underlie the southern area of the James Hutton Institute's Hartwood Home Research Farm, and extend southwards under the village of Allanton. The former Kingshill Colliery No. 1 site lies to the south of Allanton, and is in the ownership of North Lanarkshire Council. Following its decommissioning, reclamation works included forestry planting, the creation of grassland habitat, lagoon reclamation and surface water drainage improvements. It is now designated as a Site of Importance for Nature Conservation, and a Local Nature Reserve. However, the drainage maintenance presents an ongoing financial burden to the Council, and minewater resurgence issues continue to affect homes in Allanton. The development of a geothermal minewater system in this location therefore simultaneously presents environmental constraints and benefits which need to be addressed as the project progresses. The estimates of the geothermal potential in the WRSM and WNMA, subject to the uncertainties implicit in a desk-based assessment, represent 258 years of heat extraction at a rate of 0.63 MegaWatts (MW), or 71 years of heat extraction at a rate of 2.3 MW.

Two preferred options have been identified for the geothermal supply in two locations, and with alternative methods for discharging the minewater. The 'preferred' option locates the production well at or in the vicinity of the Kingshill shaft to the south of Allanton, and proposes a passive treatment system to treat the minewater at surface prior to discharge to an existing watercourse. This option is preferred due to its potential to mitigate existing minewater resurgence issues affecting the village of Allanton, both by properly treating the minewater, and by locally lowering the water table. The 'alternative' option proposes a geothermal doublet system, with a production well and injection well(s) located on Hartwood Home Farm.

District Heating Network

In parallel with the geothermal system options appraisal, an appraisal of the district heating network (DHN) design options and associated heat market has been undertaken. The initial focus for assessing the energy needs of local communities in the area encompassed the town of Shotts, the villages of Hartwood, Allanton and Salsburgh, and residential and non-residential development within the area, roughly equivalent to the Fortissat Ward of North Lanarkshire. The feasibility study identified constraints and opportunities in relation to using the available geothermal energy to provide heat in this area, to inform the identification of potentially viable heat networks. Balancing the risks and opportunities, a medium term potential has been identified which connects Allanton and Hartwood to a DHN. This DHN is scaled to enable the primary heat source for the energy centre to come from the geothermal minewater, pumped from a single production well.

The estimated minewater temperature of 18 °C necessitates a heat pump based system. Heat is extracted from the minewater using a heat pump and upgraded to the required network flow temperature. The heat pump model has been developed to take account of the diversified demand profile, with a gas boiler providing system top-up and back-up.

As the financial analysis indicates marginal difference between a high temperature and low temperature network (due to the higher capital costs of the low temperature system being offset by the lower operating costs for a network of this size) and the low temperature network has a Co-efficient of Performance (COP) above 2.9 to make it eligible for the Renewable Heat Incentive (RHI), a low temperature network of 75/45 flow and return temperatures is proposed.

There is a longer term potential to extend the network to Shotts. While this is an economically attractive heat market for district heating, the heat demand would require more than one production well and reinjection well(s) and/or alternative sources of energy for the DHN, and consequently is identified as a longer term opportunity once the initial network is operational and the geothermal resource is better understood.

Due to the separation distance, a DHN in Salsburgh would be more effective as a standalone system, and an alternative energy source would be required as there is not a viable minewater geothermal resource in the vicinity of Salsburgh.

Development Options

The Development Options integrate the geothermal system design options appraisal and district heating network (DHN) design options appraisal. Two alternative design options are presented, taking into account all subsurface and surface factors considered.

Option 1 consists of a single production well and passive minewater treatment facility. The identified location for the production well is south of Allanton near or even at the Kingshill Mineshaft No.1. Pumping minewater in this vicinity offers the highest potential for lowering the local water table and reducing or preventing the minewater resurgence issues which affect this area and the village of Allanton which is downslope from there. It also allows the polishing wetlands to be located in an area already providing this facility, and contribute to the objectives of the Local Nature Reserve and Site of Importance for Nature Conservation. Minewater would be pumped from the WRSM seam at a depth of c. 340 m below surface level. This option has been modelled with three DHN designs - networks A, B and C - to assess the impact of the heat network's scale on the financial performance of the project.

Figure ES.1: Illustrative diagram of passive minewater treatment facility.

Figure ES.1: Illustrative diagram of passive minewater treatment facility.

Option 2 consists of a production well and two injection wells, with no passive minewater treatment. The geothermal system and heat centre components of this option are contained entirely within the JHI Hartwood Home Farm land boundary. This option produces and injects minewater from the WRSM seam at a depth of ca. 380 m below surface level. The heat centre in this option is situated between Allanton and Hartwood, so only network C, the largest DHN, has been modelled.

Figure ES.2: Illustrative diagram of doublet system with production and injection well(s).

Figure ES.2: Illustrative diagram of doublet system with production and injection well(s).  

The advantages and disadvantages of the two options - one proposing a passive treatment system, and the other proposing reinjection (with alternative locations for the production wells) - are compiled to compare the options. The options are also subject to a risk assessment, and opportunities from this project are identified.

The geothermal minewater DHN for Allanton and Hartwood has been calculated to offset 782 tonnes of CO2/year based on the 2015 UK electricity mix. However, it should be noted that this figure is based on displacing gas consumption, and the homes in Hartwood are off gas-grid, many using oil. Displacing this fuel source would further reduce carbon emissions.

Delivery Model

The feasibility study has considered the potential business models and legal structures currently deployed for DHN in the UK, and potential Energy Services Company (ESCO) structures for the Fortissat Minewater Geothermal project, and how these might evolve over the lifetime of the development. A preliminary financial model has been prepared to assess the commercial viability of the development options, and the results are summarised.

There are a number of different factors that need to be taken into consideration in selecting a preferred structure to deliver and run the project. These include, but are not necessarily limited to:

  • The preferred technical scenario;
  • The delivery structure;
  • The procurement strategy;
  • The Council's strategic priorities for the project;
  • The willingness of the Council to work with a joint venture partner(s) or to enter long term supply contracts with a 3rd party;
  • Longer term transition and exit strategy (if any);
  • Tax considerations;
  • EU State Aid considerations.

To provide a reference point for these factors, a review of existing heat networks has been undertaken, and a comparison undertaken of the advantages and disadvantages of the different commercial structures available. For the purposes of the preliminary financial model we have assumed that the project is delivered using a company limited by shares.

A key work stream during the next phase of the project will be to identify the preferred structure for the project. It should be noted that North Lanarkshire Council is currently considering the most appropriate business model for the development of a community heating network at high-rise flats in Motherwell. During our discussion with the Council there is the potential that the same operating model may be applicable for the Fortissat geothermal project. Using the same model may result in some cost savings but care will need to be taken in determining whether the model will require adjustment for a rural DHN connected to a geothermal project and dealing with both privately owned and social housing.

A financial model has been built to describe and evaluate the first 40 years of the project life as per the DECC Heat Network Project Metric Template. The financial model has intentionally been designed to be flexible and adaptable so that it can be used throughout the development process, including for the ultimate financing of the project construction. The structure of the financial model allows additional functionality to be added easily as the project continues to take shape.

The financial model evaluates multiple scenarios based around a heating network that comprises:

  • A minewater production well;
  • A heat exchanger and clean source loop pipe to capture heat at the production wellhead;
  • An energy centre that captures heat from the minewater;
  • A back-up gas boiler;
  • A district heating network comprising pipework and pumps;
  • Housing stock upgrades comprising energy efficiency improvements and a domestic heat interface unit replacing gas boilers; and
  • Two options for minewater disposal: either injection wells back into the mine; or a surface passive water treatment plant.

Construction is assumed to take 20 months, with the system becoming operational by 1 April 2021. Ongoing operating expenditure includes plant and well maintenance, electricity consumption, treatment of waste water and gas consumption for the back-up boiler.

The following preferred design options have been considered:

Table ES.1: District Heating Network Options

Design option

Description

1A

700 kW heat pump, 173 council houses and 155 private houses, low temperature DHN, passive treatment facility [Allanton only]

1B

1 MW heat pump, 197 council houses, 240 private houses, low temperature DHN, 1 school, passive treatment facility [Allanton only]

1C

2 MW heat pump, 201 council houses, 415 private houses, low temperature DHN, 1 school, passive treatment facility [Allanton and Hartwood]

2

2 MW heat pump, 201 council houses, 415 private houses, low temperature DHN, 1 school, injection wells [Allanton and Hartwood]

The model assumes that approximately 60% of the project capital expenditure is financed via a debt facility with a 20 year term (straight line amortisation) at an interest rate of 3.5% per annum. This is clearly not realistic for a commercial loan facility: the implicit assumption is that, as a demonstrator project with potentially wide applications throughout Scotland, the Fortissat project will attract preferential financing terms and/or an element of grant funding.

The following table summarises the capital and operating expenditure assumptions that have been used in the preliminary financial model. The development is still at an early stage and the detailed design process has not yet begun. Some of the costs may change substantially as the project progresses and as additional studies are undertaken. Where significant uncertainty exists we have intentionally used conservative estimates.

Table ES.2: CAPEX and OPEX figures as input to the financial model, for Options 1A, 1B, 1C and 2 low Temp.

Option 1a

700 kW Pump

Low Temp (75°C)

Small Network

Option 1b

1 MW Pump

Low Temp (75°C)

Medium Network

Option 1c

2 MW Pump

Low Temp (75°C)

Large Network

Option 2

2 MW Pump

Low Temp (75°C)

Small Network

Capex (£ real)

Production well(s)

460,000

460,000

460,000

500,000

Energy centre

2,730,823

3,995,080

6,781,253

6,976,623

Gas grid connection

21,566

21,566

21,566

122,366

Electricity grid connection

245,750

245,750

245,750

331,000

Heating sytem upgrades

590,400

786,600

1,108,800

1,108,800

Fabric energy efficiency measures

29,450

45,600

78,850

78,850

Passive treatment system

1,200,000

1,200,000

1,200,000

-

Injection wells

-

-

-

1,000,000

Injection well downhole pumps

-

-

-

15,000

Total capex (£ real)

5,277,990

6,754,597

9,896,220

10,132,640

Opex (£ real per annum)

Operating expenditure

74,278

96,799

167,227

182,867

Employee costs

17,500

17,500

35,000

35,000

Passive treatment system

30,000

30,000

30,000

-

Total opex (£ real per annum)

121,778

144,299

232,227

217,867

The majority of the costs increase as the network size increases. The exceptions are the production wells, gas and electrical grid connections, and the cost of the passive treatment system.

It should be noted that the CAPEX and OPEX estimates above do not include the costs of administration, billing, etc. These depend upon the ESCO structure which is selected and will therefore need to be defined more fully at the next stage of the project.

The revenue is composed of two elements: heat sales to customers and income from the Renewable Heat Incentive.

A heat network is fundamentally different to the gas or electricity markets, in that as a closed loop network, rather than a national grid, there is only one 'supplier'. Appropriate governance structures need to be put in place for all heat customers to provide safeguards that the heat tariff is equivalent, if not discounted, against other forms of energy supply. This may also be necessary to provide the incentive for heat users to sign up in the first place - particularly given the potential for up-front connection costs, and the inevitability of construction disturbance caused by the implementation of building efficiency measures, internal wet system upgrades (upsized radiators), and boiler replacement with Heat Interface Units to enable connection to a low temperature network.

The revenue for heat sales was modelled as 6 p/kWh which offers a 2% saving to Council tenants compared to an assumed price of heat from gas of approximately 6.13 p/kWh. Owner-occupiers would benefit from a higher alternative price if the cost of boiler replacement is factored in, however this could be handled through a connection charge to customers wishing to connect to the network.

Specific decisions on heat prices will need to be further considered in order to offer an incentive to customers to connect. The issues to consider will be:

  • How investment cost of heat interface unit (HIU) and branch connection are shared between the network operator and the customer;
  • Standing/capacity charges for heat (£/kW) supplied to customers and whether this cost varies between customers; and
  • Unit cost of heat (£/kWh) supplied to customers:
    • Whether this cost varies between different types of off-takers;
    • Whether or not cost varies with time of day, season, etcetera;
    • Whether or not the tariff rates be linked to gas-prices, for instance through a % discount or offset and floor-price.

The unit cost of heat is not the only consideration. For example if the network operator provides financial support for the investment in energy efficiency improvements to customer properties, then these should result in an overall reduction in heat demand. It may then be reasonable to consider a higher unit cost than the Business as Usual alternative while offering customers a reduction in their annual energy bill.

In order to understand the effect of variations in the usage tariff on the financial model, this was one of a number of factors which were included in a sensitivity analysis. Other factors include variations in the CAPEX and OPEX, and the rate applied for the Renewable Heat Incentive.

Another factor which has the potential to affect the financial model relates to the cost savings to the Council arising from the new minewater treatment facility. The Council currently spends an average of £50,000 per annum on mitigating minewater resurgence from Kingshill on the village of Allanton. The initial results of the financial analysis are reported with and without this cost saving taken into account.

The figures in Table ES.3 below show the key financial metrics for the four design options. For the time being we have elected to use the 20 year aggregate cash flow rather than net present value. This is due to the current uncertainty around the ESCO structure and the resultant difficulty in determining an appropriate discount rate.

Table ES.3: Headline results for design options 1A, 1B, 1C and 2.

Design Option: HP Size, Temp

Descriptor

20 year net cash (£m)

Project IRR (%)

CAPEX (£m)

COP

% Debt

1A: 700kW Pump, 75°C

LT small network + passive treatment

-3.1

0.0

5.7

3.34

50

1B: 1MW Pump, 75°C

LT medium network + passive treatment

-0.8

0.0

7.2

3.39

50

1C: 2MW Pump, 75°C

LT large network + passive treatment

3.2

1.6

10.6

3.58

60

2: 2MW Pump, 75°C

LT large network + injection wells

3.4

1.7

10.8

3.58

60

The obvious conclusion to draw from these figures is that the number of users connected to the network is critically important. The higher the network demand, the better the returns for investors. Only the largest network options (1C and 2) have positive IRRs and positive aggregate net cash flows over the first 20 years. However, in neither case is the Project IRR sufficiently high to attract external investors. This indicates that the project structure will be a not-for-profit ESCO which is 100% owned by the Council. This preliminary conclusion may change as the CAPEX and OPEX estimates are refined further in the next phase of development.

If the cost savings for the Council for mitigating minewater resurgence through a new passive minewater treatment facility are taken into account in options 1A, 1B and 1C then the figures in would be as follows:

Table ES.4: Improvements in project IRR and aggregate 20 year cash flow when accounting for potential cost saving to NLC of £50,000 per annum through implementation of a passive minewater treatment facility integrated with the geothermal DHN

Design Option: HP Size, Temp

Descriptor

20 year net cash (£m)

Project IRR (%)

CAPEX (£m)

COP

% Debt

1A: 700kW Pump, 75°C

LT small network + passive treatment

-1.7

0.0

5.7

3.34

50

1B: 1MW Pump, 75°C

LT medium network + passive treatment

0.6

0.0

7.2

3.39

50

1C: 2MW Pump, 75°C

LT large network + passive treatment

4.6

2.7

10.6

3.58

60

The longer term financial modelling indicate that the removal of the RHI revenue after 20 years will have an adverse impact on the project economics. There are however a number of ways in which this reduction in revenue could be addressed, including:

  • The expansion of the network into Shotts would increase the Linear Heat Density and therefore the potential revenue.
  • Setting up a trading arm as a subsidiary, to connect non-Council off-takers on a commercial basis.
  • DECC expects gas prices to increase in the future. This will drive up the costs of alternative sources of heating and allow higher tariffs to be used at Fortissat, while still offering customers a discount compared to the alternatives.
  • Given the ambitious UK and Scottish targets for decarbonising heat, it is possible that new policies could be implemented to either (i) reform or extend the RHI, or (ii) replace the RHI with another support mechanism.
  • Direct carbon taxes may become more prevalent. This would have the impact of increasing the price of gas and heating oil, which in turn would allow the Fortissat project to charge a higher tariff while still offering customers a discount.

There are also a number of factors which may in future reduce the project's operating costs. It is difficult to predict at this stage the likelihood of any of these occurring, or the impact that they may have on the project economics. These factors include:

  • The project relies on electricity to power the heat pumps, Electric Submersible Pump (ESP) and network pumps. It is possible that electricity cost will reduce over time as increased penetration of renewable energy in the UK lowers the marginal cost of generation.
  • It may be possible in the future to install on-site electricity generation (e.g. solar PV) in order to lower the electricity cost for the project.
  • A gradual improvement in minewater chemistry may reduce maintenance costs for the equipment.
  • Maintenance and infrastructure costs may decrease as heat networks become more common in the UK.

Next Steps

The Fortissat Community Minewater Geothermal Energy District Heating Network project has the potential for multiple benefits - social, environmental, carbon reduction, financial.

On the basis that the Catalyst Stage has identified a potentially feasible project, and the outcomes of the engagement undertaken to date has been positive, the next steps and an indicative programme are set out for the Development Stage. There are distinct, but interdependent work streams identified:

(i) confirming the heat resource through testing and using the data on flow rates, minewater chemistry and temperature to design how the geothermal energy system will be built and maintained;

(ii) confirming the heat market through both consultation and developing detailed proposals for how the required building efficiency measures and connections will be programmed and financed, and how the operational system will be managed.

These need to be progressed in parallel. In order to proceed, there will need to be increasing levels of confidence and certainty for both the supply and demand as the knowledge and understanding of how the system will be built and operated is refined.