Retrofit Decarbonization of Coal Power Plants—A Case Study for Poland
Abstract
:1. Introduction
- To what extent existing coal power plant assets may play a role in a future decarbonized power system, either by adding carbon capture, replacing the feedstock to biomass, or replacing the coal boilers with low-carbon energy sources.
- What the most effective retrofit decarbonization options are for the most modern coal units in operation or under construction today.
- Whether such replacements or retrofits makes technical and economic sense, compared to abandoning existing coal plant assets entirely and building a new low-carbon power system from scratch.
- Retire the coal power plants and replace their function with a combination of energy efficiency (reducing demand for heat and electricity) and new, greenfield, low-carbon energy production, or
- Maintain the assets and decarbonize them by reducing direct emissions by adding carbon capture or lifecycle emissions by switching to biomass combustion.
- The repowering of a coal power unit with a new low-carbon energy source
- The conversion of feedstock from coal to a sustainable sourced biofuel
- The retrofit installation of carbon capture at a coal power unit
- Lifecycle emissions lower than 50 gCO2-eq/kWh, in line with what is assessed by the OECD to be the required average power system emissions intensity globally by 2050 in order to meet the 2015 Paris Agreement goals [2] and the local requirement by earlier dates in many countries to achieve national targets (for example in the UK by 2030 [3]).
- Maintaining an annual energy production (electricity and/or heat) of at least 50% of the reference value of the coal unit within the existing site footprint. This corresponds to an areal generation capacity of ~1 MWh/m2/y.
- Not just the power plant site, but existing coal plant equipment, representing at least 5% of original plant capital expenditure (CAPEX), is re-utilized and remains in operation at the retrofit decarbonized plant.
- Adding post-combustion carbon capture
- Converting to biomass feedstock
- Converting to natural gas combined cycle (NGCC) with added carbon capture
- Wind power
- Solar photovoltaic (PV) power
- Combinations of wind power and solar PV
- Solar thermal power
- Adding a nuclear reactor heat source
- Adding a geothermal heat source
2. Research Method and Paper Structure
- In Section 1 (Introduction), we introduced and defined the concept of “retrofit decarbonization” of coal power plants and briefly presented nine main possible technical options.
- In Section 2, we describe the structure of this analysis and research.
- In Section 3, we present a literature review and overview of the present status of research and implementation of the technical options that were identified for retrofit decarbonization.
- In Section 4, we present the likely remaining carbon budgets for different global warming targets (below 1.5 °C and 2 °C, respectively) and analyze what implications these budgets have for the future operation of existing and planned coal power plants. The analysis in Section 4 illustrates the need for existing and planned coal power capacity to be either scrapped ahead of its useful technical life or to be retrofit decarbonized.
- In Section 5, we analyze the remaining useful life and economic value of existing coal power plant equipment, which determines the overall potential for retrofit decarbonization of any kind.
- In Section 6, we determine the physical footprint of existing coal power plants. As a condition of the analysis in this paper, the retrofit decarbonized plant must fit inside the original site boundary of the coal plant that is to be decarbonized.
- In Section 7, we analyze the physical footprint requirements of each of the nine retrofit decarbonization technology options to determine whether sufficient annual energy production is possible on-site for the plant to qualify as a retrofit decarbonization option (criterion #2 in Section 1). On the basis of this analysis, four out of the nine original technical options are discarded from further analysis.
- In Section 8, we introduce the technical characteristics of the coal power plant fleet of Poland, including the age distribution, size of units, steam parameters, and applications. From this analysis, existing Polish coal plants are grouped in to three major categories. For each category, we define one specific representative coal unit to use for more detailed analysis.
- In Section 10 and Section 11, we present and analyze in detail the prospects of retrofit decarbonization of coal plants in Poland using high-temperature geothermal energy and nuclear energy, respectively.
- Finally, in Section 12, we summarize the results and conclusions, comparing all of the studied options for retrofit decarbonization in terms of economics and the overall potential scale of possible implementation both in Poland and globally.
3. Literature Review
4. Carbon Budgets and the Future of Unabated Coal Power
5. The Lifespan and Value of Coal Power Plant Equipment
6. The Physical Footprint of a Coal Power Plant or Unit
- Rural, semi-urban, or urban siting
- Size of on-site coal and ash storage piles
- Open (direct) cooling or the use of cooling towers
7. The Physical Footprint of Retrofit Decarbonization Options
7.1. Introduction
7.2. Adding Carbon Capture
7.3. Converting to Biomass Feedstock
7.4. Converting to Natural Gas and Carbon Capture
7.5. Switching Out Coal Boilers for Nuclear Reactors
7.6. Wind Turbines
7.7. Solar Photovoltaic Panels
7.8. Onshore Wind + Solar Photovoltaic Panels
7.9. Concentrating Solar Power
7.10. Geothermal Power
7.11. Other Low-Carbon Energy Sources
7.12. Summary
8. The Existing Polish Coal Power Fleet
8.1. Age and Size of Units
8.2. Steam Parameters
8.3. Applications
8.4. Polish Coal Unit Categorization
9. Retrofit Decarbonization with a New Low-Carbon Heat Source
9.1. Re-Utilizing Existing Equipment
9.2. Matching Thermal Output
9.3. Water Scarcity Issues
9.4. Coal Plant Decommissioning Costs and Salvage Value
10. Retrofit Decarbonization Using Geothermal Energy
10.1. Introduction
10.2. Experience in Poland
10.3. The Polish Geothermal Energy Resource Base
10.4. High-Temperature EGS Prospects in Poland
10.4.1. Existing Research
- The Gorzow block area and the Parczew area, where there is the potential to build a ~1 MWe geothermal power plant, using a ~153 °C reservoir at the depth of 4.3 km.
- Szklarska Poręba, supporting a ~1–2 MWe plant with a 165 °C reservoir at 4 km.
- Central part of Polish Lowlands, supporting a ~1.5–2 MWe plant with reservoirs at 5.5 km
10.4.2. Deep-Drill EGS Potential in Poland
10.5. Geothermal Retrofit Decarbonization Potential in Poland
11. Repowering Coal Units with Nuclear Reactors
11.1. Introduction
- A nuclear building (or “island”) that houses the nuclear steam supply system (NSSS) whose main function is to supply steam, as well as the equipment necessary for the operation such as facilities for the receipt and interim storage of fuel
- A conventional, non-nuclear turbine island, devoted to the generation of electricity, the turbines of which are driven by steam.
- The balance of plant (BOP) equipment, which covers all items of mechanical and electrical equipment not related to the operation of the nuclear island and the turbine, such the cooling water intake station and cooling towers of the condenser, administrative buildings, switchyards, and incoming and outgoing grid connections.
11.2. Licensing Aspects
- Possibility of obtaining a construction and operating license from the relevant nuclear regulatory authority at the site of a suitable existing coal power unit
- Local social acceptance for the siting of a nuclear energy facility
11.3. General Site Requirements
- extreme wind speeds
- probability and severity of flooding
- extreme snow or rainfall
- probability of aircraft crashes on the site
- nearby industrial hazards, e.g., blast and pressure loadings arising from ignition of gas clouds escaping from rail, road or water-borne tankers or nearby storage facilities in close enough proximity to physically impact the nuclear plant
11.4. Seismic Conditions
11.5. Establishing Construction Sites
11.6. Reactor and Coal unit Pairing
- The HTR-PM reactor unit was analyzed for retrofit decarbonization for the representative “large power unit” (Łagisza B10). The reactor unit was selected primarily based on its level of maturity, with two units already constructed in China and power operations scheduled for 2021. Pairing analysis of HTR-PM with other representative coal units was omitted due to thermal power mismatch.
- The Kairos KP-FHR reactor unit was analyzed for retrofit decarbonization of all representative coal units, because its thermal power output allows for effective pairing in each case.
- A “representative molten salt reactor unit”, with parameters based primarily on the ThorCon TMSR design and with a thermal power rating of 275 MWth, was used to assess pairing with CHP (CEZ Chorzów) and 200-units. Pairing with Łagisza B10 was omitted due to the thermal power mismatch.
- The reactor design should be maintained as is and operating at nominal thermal load.
- The existing steam unit modernization should be minimized to maximize the utilization of existing infrastructure.
11.7. Cost Savings from Retrofit Decarbonization Compared to Greenfield
11.7.1. Advanced High-Temperature SMR Units with Steam Cycle Integration
11.7.2. Water-Cooled SMR Units without Steam Cycle Integration
12. Results and Conclusions
12.1. Comparative Analysis of Retrofit Decarbonization Options
12.2. Potential for Retrofit Decarbonization Globally and in Poland
Supplementary Materials
Author Contributions
Funding
Institutional Review Board Statement
Informed Consent Statement
Data Availability Statement
Acknowledgments
Conflicts of Interest
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Generation Type | Annual Output Replacement Possible within Site Boundary | Applicable for Retrofit Decarbonization Analysis | Assessed in this Study |
---|---|---|---|
Coal | 100% (reference value) | N/A | N/A |
Coal + CCS | 80–100% | Yes | In Supplementary Materials Section 2 |
Biomass | >50% | Yes | In Supplementary Materials Section 3 |
NGCC + CCS | >100% | Yes | No |
Nuclear | >100% | Yes | Yes |
Wind (onshore) | Up to 0.6% | No | No |
Solar PV | Up to 1.6% | No | No |
Wind + Solar PV | Up to 1.8% | No | No |
Solar CSP | Up to 1.7% | No | No |
Geothermal | Up to 90% | Yes | Yes |
Parameter | Value | Motivation |
---|---|---|
Maximum current effective age of relevant equipment | 20 years | One of the main motivations for retrofit decarbonization is to make use of the remaining useful life of what would otherwise be stranded assets. Much of the equipment at units that have not undergone modernizations in the last 20 years (and thus have an “effective age” higher than this) are significantly depreciated, and such units are likely in need of substantial investments in the near-term to carry on operating. These units are much more likely to be decommissioned than to be remain viable candidates for re-use of equipment in the next 10–15 years, and they are therefore excluded from this analysis. |
Minimum rated capacity | 50 MWe | A total of less than 400 MWe of capacity resides in coal units meeting the effective age criterion with an individual power rating lower than 50 MWe. These are mainly very small CHP units on small plot sites close to town centers, which would be very challenging sites for any retrofit project. |
Category | Description | Technical Details |
---|---|---|
1. Combined heat and power plants [Green in Figure 6] | Units with an individual electric capacity of less than 200 MWe, providing electricity and district/process heating | Capacity: 1546 MWe Number of units: 15 Subcritical steam cycles Temperature: 510–550 °C Located in, or adjacent to, cities Small site footprints |
2. “200” and “360” units [Brown in Figure 6] | The “200-units” (essentially identical units in the range of ~200 MWe) constitute the bulk of the polish power system, built in the 1970s. Out of 12.3 GWe total installed capacity, 4.9 GWe have been modernized. “200-units” potentially applicable for retrofit decarbonization analysis are available at Kozienice, Patnów, Połaniec, Turów, Ostrołęka, and Jaworzno power plants. In addition, the Bełchatów plant has 11 units in the 380–394 MW range (“360”-units), 10 of which have been modernized between 2008 and 2016, for a combined applicable capacity of 3874 MWe in this category. At the Opole plant, units 1–4 (1532 MWe) are 360-units that have not been included here, but they are not unlikely to be further modernized in the near future and therefore are potentially applicable. | Capacity: 8824 MWe # of units: 31 Subcritical steam cycles Temperature: 535–560 °C Many units together at very large power plants Typically located in rural areas with larger site footprints Turów and Bełchatów are located at the large lignite mines that feed them |
3. Large units [Purple in Figure 6] | Large units are defined as having a capacity larger than 400 MWe. In total, 10 included units, nine of which were in operation at the end of 2019, are included. In addition, the 496 MW Turow-11 unit is expected to enter commercial operation before the end of 2020. | Capacity: 6723 MWe # of units: 10 Mainly supercritical steam cycles Temperature: >560 °C All units are add-ons at existing plants |
Unit Name | Electric Capacity | Year of Commissioning or Modernization | Live Steam Parameters |
---|---|---|---|
Pątnów-1, B1 | 222 MWe | 2016 | 535 °C, 12.75 MPa |
Pątnów-1, B2 | 222 MWe | ||
Pątnów-2 | 540 MWe | 2008 | 540 °C, 25.8 MPa |
Type of Reactor | Reactor Coolant Pressure/Temperature | Supplied Steam Pressure/Temperature |
---|---|---|
Pressurized Water Reactor (PWR) | 12.7–15.5 MPa/300–330 °C | 5.7–7 MPa/270–290 °C |
Pressurized heavy-water reactor (PHWR) | 8.7–10.0 MPa/310–320 °C | 4.0–5.1 MPa/250–260 °C |
Boiling Water Reactor (BWR) and water-cooled, graphite moderated reactor (RBMK) | 6.9–7.5 MPa/290 °C |
Type of Reactor | Supplied Steam Temperature | Development Status |
---|---|---|
Sodium fast reactor (SFR) | 450–530 °C | Operating |
Lead fast reactor (LFR) | 450–530 °C | Demonstrated and Under Construction |
High-temperature gas-cooled reactor (HTGR) | 540–600 °C | Operating |
Molten salt reactor (MSR) | 535–585 °C | Prototype |
Super-critical water reactor (SCWR) | 500–560 °C | Concept |
Name | Coolant | Thermal Power Per Unit | Steam Temperature | Expected First Operation |
---|---|---|---|---|
HTR-PM (China) | Gas | 250 MWth | 570 °C, current 600 °C, 2nd-gen | 2021 |
Kairos KP-FHR (US) | Salt | 320 MWth | 585 °C | 2030 or earlier |
Terrestrial iMSR (Canada) | Salt | 400 MWth | ~585 °C (600°C coolant) | Late 2020s |
ThorCon (US) | Salt | 557 MWth | 547 °C | Late 2020s or early 2030s |
X-Energy (US) | Gas | 200 MWth | 565 °C | 2027 |
Seaborg (Denmark) | Salt | 250 MWth | 570–580 °C | ~2027 |
USNC (US/Canada) | Gas | 15 MWth | ~550 °C | Mid 2020s |
U-Battery | Gas | 10 MWth | >600 °C | 2028 |
Moltex SSR-W/U/Th | Salt | ~330 MWth | N/A | Early 2030s |
Terrapower MCFR | Salt | 600–2500 MWth | N/A | Demo: 2027 Commercial: Early 2030s |
SINAP TMSR-LF (China) | Salt | 2–373 MWth | Up to 600 °C (700 °C coolant) | 2 MWth: 2021/22 373 MWth: 2030 |
Flibe Energy LFTR (US) | Salt | 600 MWth | N/A | N/A |
Elysium (US) | Salt | 125 MWth (and other sizes) | N/A | 2030 |
Parameter | Coal Power Plant | Nuclear Power Plant |
---|---|---|
Fuel delivery | Up to several million tons per year | Low volume and infrequent |
Cooling water a (a) Direct cooled (b) Tower cooled | (a) 3 m3/s per 100 MWe (b) 0.2 m3/s abstracted, about 0.05 m3/s evaporated per 100 MWe b | |
Geology | Ground able to support heavy loads | Seismically stable ground able to support heavy loads with virtually no differential settlement |
Access (a) Construction materials (b) Abnormal loads | (a) Road, rail, or sea access to deliver up to >1 million tons (b) Road or sea access to deliver about 80 very large loads | |
Waste disposal | Means of disposing of up to 60,000 tons per year of ash per 100 MWe | Near to railhead or port for transport of irradiated fuel |
Special considerations | Delivery of about 20,000 tons per year of limestone and disposal of about 30,000 tons per year per year of gypsum per 100 MWe | Subject to nuclear regulatory approval and local social acceptance for siting |
Grid integration | Suitable for connection to a point on the grid able to accept output of station |
Component | Budget Share | Possible Retrofit Savings | Description |
---|---|---|---|
Pre-construction costs | 5% | 0% | Costs associated with development |
Non-EPC indirect costs | 5% | ||
Owner’s costs | 1% | ||
Supplementary costs | 1% | ||
Contingency | 5% | ||
Fuel Core Load | 3% | ||
Infrastructure, incl: | 80% | 35–44% | Depending on integration scheme |
Reactor | 11% | 0% | Not available at coal plant |
Primary heat transfer system | 11% | 0% | Not available at coal plant |
Intermediate heat transfer system | 10% | 0% | Not available at coal plant |
Steam cycle | 25% | 80–97% | Depending on required changes in the existing steam cycle |
Reactor Aux Systems | 2% | 0% | Not available at coal plant |
Instrumental and control | 6% | 25–35% | Control room rebuild and advanced control for the SMR |
Plant auxiliaries | 6% | 25–35% | e.g., spent fuel handling, additional cooling pumps |
Electrical | 4% | 50–70% | e.g., additional electrical equipment, back-up generators |
Civil structures | 25% | 40–50% | e.g., nuclear buildings and control room needed, security perimeter |
Capex fraction | ∑100% | 28–35% | Exact value depends on the integration scheme |
Case Description | WACC (%) | Build Time (Years) | Greenfield CAPEX (€/kWe) | Greenfield LCOE (€/MWh) | Retrofit LCOE (€/MWh) | Retrofit LCOE Savings |
---|---|---|---|---|---|---|
Worst case | 10% | 6 | 7000 | 127 | 91 | 28% |
Conservative | 7% | 5 | 6000 | 75 | 57 | 24% |
Reference | 6% | 4 | 4000 | 47 | 38 | 19% |
Optimistic | 5% | 3 | 3000 | 33 | 28 | 15% |
Best case | 3% | 2 | 2000 | 22 | 20 | 9% |
Positive Factors | Negative Factors | ||
---|---|---|---|
Internal | Strengths | Weaknesses | |
Geothermal |
|
| |
Nuclear |
|
| |
Biomass |
|
| |
Coal + CCS |
|
| |
External | Opportunities | Threats | |
Geothermal |
|
| |
Nuclear |
|
| |
Biomass |
|
| |
Coal + CCS |
|
|
Parameter | Geothermal | Nuclear SMR | Biomass | CCS |
---|---|---|---|---|
Technological availability | 2030s for EGS deep-drill | Early 2030s | Available | Available |
Energy security impacts | (no fuel) | | (domestic fuel) | (domestic fuel) |
Domestic input in project value | | | | |
Re-utilization potential of existing infrastructure value | | | | |
Social acceptance | | | | |
Tie-in with Polish energy policy | | | | |
Implementation potential for units 50–200 MWe (MW) | N/A | 1120 | 626 | 0 |
Implementation potential for units 200–500 MWe (MW) | N/A | 8920 | 444 | 0 |
Implementation potential for units >500 MWe (MW) | 0 | 0 | 0 | 5800 |
Total implementation potential MW | N/A | 10,040 | 1070 | 5800 |
Total implementation potential TWh/year | N/A | 79 | 7 | 33 |
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Qvist, S.; Gładysz, P.; Bartela, Ł.; Sowiżdżał, A. Retrofit Decarbonization of Coal Power Plants—A Case Study for Poland. Energies 2021, 14, 120. https://doi.org/10.3390/en14010120
Qvist S, Gładysz P, Bartela Ł, Sowiżdżał A. Retrofit Decarbonization of Coal Power Plants—A Case Study for Poland. Energies. 2021; 14(1):120. https://doi.org/10.3390/en14010120
Chicago/Turabian StyleQvist, Staffan, Paweł Gładysz, Łukasz Bartela, and Anna Sowiżdżał. 2021. "Retrofit Decarbonization of Coal Power Plants—A Case Study for Poland" Energies 14, no. 1: 120. https://doi.org/10.3390/en14010120