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Competitiveness and Cost Sensitivity Study of Underground Coal Gasification Combined Cycle using Lignite Peng Pei, Kirtipal Barse, and Junior Nasah Energy Fuels, Just Accepted Manuscript • DOI: 10.1021/acs.energyfuels.6b00019 • Publication Date (Web): 19 Feb 2016 Downloaded from http://pubs.acs.org on February 21, 2016

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Competitiveness and Cost Sensitivity Study of Underground Coal Gasification Combined Cycle using Lignite Peng Pei*, Kirtipal Barse, Junior Nasah Institute for Energy Studies, University of North Dakota, 243 Centennial Dr., Upson II Room 366, Grand Forks, ND 58202, USA *Corresponding Author Email: [email protected] Tel: 1-701-777-6327 Fax: 1-701-777-1820 Address: 243 Centennial Drive Upson II Room 366 Grand Forks, ND 58202 USA

Abstract To push the underground coal gasification (UCG) technology towards commercialization, its competiveness and cost components still need to be investigated. This paper compares the power generation cost of UCG Combined Cycle (UCGCC) with Pulverized Coal (PC) plants, Integrated Gasification Combined Cycle (IGCC), and Natural Gas Combined Cycle (NGCC). Cost sensitivity of the UCGCC as a function of coal seam depth and thickness was also examined. The results indicate that UCGCC is very competitive compared with PC and IGCC. Within the same assumed fuels price range, the power generation cost for UCGCC was $45 to 48/MWh, whereas it was $45 to 60/MWh for PC and over $100/MWh for IGCC. The generation cost of UCGCC was as low as NGCC at low natural gas prices, but UCGCC was able to provide a lower CO2 capture cost. Depending on the assumed fuel prices, the capture cost for the UCGCC was $27 to 28/ton of CO2, whereas it was $47 to 58/ton of CO2 for NGCC. It is also found that the cost of UCGCC decreased with increase in coal seam thickness and increased with coal seam depth, but the effect of depth was not as pronounced as that of the seam thickness. An effective way to enhance the competitiveness of UCGCC is to utilize thicker coal seams. 1

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Keyword: Underground coal gasification; generation cost; CO2 capture cost; cost sensitivity; competitiveness

1. Introduction Coal will play a key role in the global energy supply over the next several decades, and there is a significant potential to improve the efficiency of coal extraction and utilization. Because of the limitations of current coal mining technologies, 85% of the world’s coal resources are unmineable by traditional methods1, which incurs concerns relating to safety, subsidence, groundwater contamination, surface pollution, and greenhouse gas emissions. Underground coal gasification (UCG) is a promising clean coal technology that converts coal in situ into a combustible gaseous product, through the same chemical reactions that occur in surface gasifiers2. The product gas primarily consists of carbon monoxide (CO), hydrogen (H2), carbon dioxide (CO2), and methane (CH4). There are two main types of UCG process: shaft gasification and shaftless gasification. The shaft type requires laborers to work underground to engineer the gasifier, and uses coal mine galleries and shafts to transport the reagent and products3. The shaft method was the first technique utilized within UCG systems4. The shalftless type, however, uses directional in-seam boreholes for oxidant injection and product collection, and is the focus of most recent UCG research works4. UCG offers several major advantages over surface mining and gasification of coal that makes it safer, cleaner, and more economical2: no laborers work underground, leading to improved safety; all coal is gasified in place, which reduces the surface footprint of the UCG plant by eliminating the need for a surface gasifier, thereby eliminating associated dust emissions and coal transportation, handling, and storage costs; all product gas generated rises to the surface at a pressure near the hydrostatic pressure of the UCG cavity, which generally facilitates its 2


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conversion to other products and aids many CO2 capture technologies and reduces flue gas compression cost5; the water and feedstock available in situ may be directly used6; and the majority of fly ash remains underground as well as significant amounts of pollutants – particulate matter (PM), sulfur oxides (SOx), nitrous oxides (NOx), etc. leading UCG more environmentally friendly7. The gas produced from UCG can be used in power generation or manufacturing other fuel and chemicals8. When used in power generation, the plant configuration is similar to an Integrated Gasification Combined Cycle (IGCC), except that the surface gasifier is replaced by an underground reactor. Fig. 1 shows the UCG Combined Cycle (UCGCC) coupled with a CO2 capture system. The product gas is cooled, cleaned of particulate matter, and converted to primarily H2 and CO2 in sour water-gas shift (WGS) reactors. After further cooling, H2S and CO2 are separated from the product gas through the acid gas absorption process in two stages, usually through a physical solvent process such as Selexol. The CO2 stream is dried and compressed for pipeline transport and underground sequestration. The product gas is combusted to drive a gas turbine. The waste heat from the gas turbine is recovered in a heat recovery steam regenerator (HRSG) to drive a steam turbine. GasTech9 performed a viability study of UCG in the Powder River Basin (sub-bituminous coal), Wyoming. Assuming 15% discount rate, it is found that a 200 MW air-fired UCGCC project has a generation cost of 52 USD per megawatt-hour ($/MWh). In 2011, Lawrence Livermore National Laboratory10 also estimated generation cost of UCGCC in the Powder River Basin, and the result was calculated as $60/MWh. The costs of electricity produced from UCGCC based on bituminous coals in Indiana were estimated in 20117. The cost for a coal seam of 5 m thick was

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estimated at $53 to64/MWh, and a seam of 2.5 m thick at $64 to 86/MWh. The lower and higher values present air and oxygen enriched injection respectively. CO2 Compressor

Combustor Gas turbine

To CO2 storage

Generator

Compressor

Air separation unit Water-gasshift reactor

CO 2 absorber HRSG

ESP Generator

Steam turbine

Syngas cooler Sulfur H2S stripper

CO2 stripper

Condensor Pump Injection compressor

H2S stripper

Production Well

Injection Well Overburden Coal seam

Gasification cavity

Underlayer

Fig. 1. UCGCC with CO2 capture system The UCG power generation cost is controlled by various geological factors, and those factors should be investigated to understand the approach to improve UCG economics11. However, the aforementioned literature excluded the impact of fuel price variation, and did not indicate the variation of generation cost as a function of coal seam depth and thickness at the same time. Historically, low natural gas price is one of the main contributing factors for delaying the commercialization of UCG11. In the recent 3 years, a significant change of fuel price on the global market has occurred. UCG now faces stiff economic competition from other fuels of low price, but also might be benefited from decreased well drilling and completion cost. Therefore, the competiveness and cost components of UCG need to be reviewed and analyzed. Lignite is lower in heating value than other coals12, but its high moisture content and high reactivity13 makes lignite a competitive feedstock for gasification. This paper examines components in 4


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power generation cost of UCGCC using North Dakota lignite, including the influences of fuel prices, coal seam depth and thickness. The cost was compared with that generated from natural gas combined cycle (NGCC), lignite-fired pulverized coal (PC) plants and IGCC. The results of this study offers a better understanding to the cost components of UCGCC and approaches to reduce its cost, in turn pushing the technology towards commercialization.

2. Competitiveness Investigation 2.1 UCGCC configuration In the proposed concept of a commercial-scale UCG plant, coal is gasified in multiple underground gasification reactors, as shown in Fig.2. These multiple gasification reactors (cavities) are arrayed as a set of “parallel tunnels” in the coal seam. During the operation of a UCG plant, these gasification reactors will be developed sequentially to ensure continuous production14. At times more than one gasification reactor may be simultaneously operated to supply enough product gas for downstream facilities. Each gasification cavity can either have its own injection and production wells, and wellhead. The gas transmission pipelines and other maintenance facilities on the surface are shared by the cavities. Once a cavity is finished with gasification, it is decommissioned and the injection and production wells are plugged. The size of these gasification cavities, spacing, in situ stresses, and properties of the coal-bearing strata together determine the stability of the altered formation structure as well as how much coal can be recovered15. The recovery efficiency of a UCG plant is defined as the ratio of the energy contained in the product gas to the energy contained in the in situ target coal seam. The recovery efficiency is determined by two factors: the mining recovery factor and the chemical conversion efficiency. The mining recovery factor refers to the volume percent of the target coal seam that can be 5


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recovered. The chemical conversion efficiency is the efficiency of converting the “mined” coal to product gas. The chemical conversion efficiency is equivalent to the cold gas efficiency of the surface gasifiers, which is between 70% and 90% in most cases. The mining recovery factor is approximately 30%15.

Overburden

Coal seam Gasification Reactor 3

Gasification Reactor 2

Gasification Reactor 1

Underlayer

Fig. 2. Concept of a commercial UCG plant Major cost components associated with UCG plants include: •

air separation unit (ASU)

•

monitoring wells

•

UCG reactor, including well drilling and completion, wellhead and gas clean facilities

•

severance tax and royalties

Oxygen (O2) is injected to the underground reactor through an injection well using a 6 inch schedule 40 pipe. The ratio of the product gas to the injected O2 was assumed to be 48, so the injection rate was assumed to be 235 cubic meters per minute (m3/min). Based on the product gas supply rate, the O2 injection rate and ASU cost were calculated. The ASU operation and

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maintenance (O&M) cost was attributed to the electricity cost and miscellaneous cost. The power requirement is 464.4 MWh/ton of O2, and the industry electricity price was set at $0.1128/kWh16. To monitor the impact of UCG on nearby aquifers, 18 monitoring wells will be drilled in two rings around the gasification area. The monitoring wells require very little maintenance, so the operating costs arise from water sampling and analysis. Groundwater was assumed to be sampled on a daily basis. A severance tax will be applied to extracted coal. The base tax is set at $0.413 per metric ton, paid monthly17. The project developer also needs to pay the mineral owner royalties for the mineral rights which might be applied or not depending on the kind of coal seam. For a conservative analysis, the authors assumed the royalty was applied and the rate was set at 8% of the coal price. As described above, during UCG development, coal pillars are left between cavities to maintain structural stability. These coals left underground are stranded coals from the view of the mineral owner: they are not mined by the UCG process but are unlikely to be recoverable or useable in the future. Therefore, in this paper, it was assumed that royalty on the unmined coals should also be paid. To support the power island, new gasification reactors are developed continuously. Well drilling and completion is the major expense in reactor development. In this study, the Harmon lignite seam in North Dakota, United States was used as an example18, the drilling depth was set as 295 m, and the coal seam depth was set as 7.6 m. Geological survey indicated that the coal seam permeability is very low, with a permeability less than 2.4×10-2 mD18, so it was assumed that the UCG reactors were developed using the linear Controlled Retraction and Injection Point (CRIP) technology18. For each reactor, one vertical injection well and one horizontal production well would be drilled. As gasification process begins, a pear-shaped cavity would grow around the 7


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injection well19. During the stable gasification state, the injection point is retracted to continue gasifying fresh coals. The cavity keep growing as the injection point constantly moves towards upstream. Therefore, the reactor geometry can be modeled as a cylinder extending the full height of the coal seam20. In this study, the UCG reactor is assumed to have an approximate round cross section whose diameter is equal to the coal seam thickness. The startup wells were treated as capital cost. The gas clean, collection and distribution facility was as assumed as 10% of capital cost of the startup wells. Annual O&M costs included new wells for developing gasification cavities and maintenance labor fees. Based on required product gas feed rate and the size of a cavity, the service life of the cavities was calculated as 78 days. Due to the relatively short service life, there should be no depreciation or maintenance cost for the injection and production wells. Table 1. Assumptions relating to UCG reactor Coal seam and aquifer depth Drilling & completion cost Pipes and support system Miscellaneous O&M cost Average gasification cavity diameter Gasification cavity length In situ coal density Coal heating value UCG chemical recovery efficiency UCG mining recovery efficiency

295 m $820/m 10% of startup well drilling & completion 3% of of drilling & completion 7.6 m 1525m 1280 kg/ m3 16 MJ/kg 75% 30%

The dry UCG-product gas composition was determined from the dry off gas composition produced by Lurgi gasifier using North Dakota lignite21: Table 2. Product gas Composition Composition H2 CO CO2

mole%, dry 38.8 15.6 32.5

mass%, dry 3.5 19.9 65.2

mole%, wet 18.9 7.5 15.7

8


mass%, wet 1.9 10.6 34.7

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CH4 C2+ other (N2) H2O Total Mean molar mass Heating value

10.8 7.9 5.2 0.8 1.6 0.4 1.5 1.9 0.7 51.6 100.0 100.0 100.0 21.9 kg/kmol (dry), 19.9 kg/kmol (wet) 11.89 MJ/ m3 (dry), 5.81 MJ/m3 (wet)

4.2 0.9 1.0 46.7 100.0

The costs associated with the ASU, drilling and completion of monitoring and reactor wells, and severance tax and royalties were determined by the aforementioned factors. The calculation process is summarized in Fig. 3. The investment of well drilling & completion and wellhead installation is a function of depth, D (m), and includes well drilling ($910/m), well casing ($295/m), well cementing ($197/m), and equipment lease, Clease ($)14:

Clease = 9277+ 46.92× D

ASU size and cost

Oxygen feed rate

(1)

Oxygen injection rate per well

Syngas production rate per cavity

Gas turbine

Monitoring well drilling & completion cost

Syngas feed rate

Number of gasification cavity in operation

New cavity to develop per year

Syngas heating value

Energy extraction rate per cavity

Cavity service life

Coal seam thickness, cavity length

Cavity volume, coal density and heating value

Coal seam & aquifer depth

Reactor well drilling & completion cost

Severance tax and royalty

Fig. 3. Calculation of cost associated with UCG reactors

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2.2 Cost comparison – base case This section compares power generation cost of hypothetical NGCC, IGCC, UCGCC and PC plants without CCS systems installed. Typical new plants were used for the purpose of the analysis. The NGCC, IGCC, and UCGCC plants were all equipped with one GE 7FB gas turbine and a HRSG of corresponding size. The PC plant was equipped with a supercritical unit of 650 MW gross output. The IGCC employed a Shell gasifier. All the coal-fired plants were fed by North Dakota lignite, the same coal feeding UCG. The cooling process was assumed to be a wet cooling tower. The generation cost was calculated as a function of the fuel price to provide an objective base for comparison. The price of North Dakota lignite was set between 10 and 30 USD per metric tonne ($/tonne), and the price of natural gas ranged between 2.50 and 6.50 USD per thousand standard cubic feet ($/kscf), or 2.31 to 6.01 USD per gigajoule ($/GJ). To compare the generation cost on the same basis, the fuel prices were converted to USD per gigajoule. The capacity factor was set at 75% for all power plants. The assumptions are summarized in Table 3. All the capital investments involved were converted to annualized value, A ($M/year), by Equation (2)23:

 i (1 + i )y  A = C  y  (1 + i ) − 1 

(2)

where C (USD) is the capital cost including procurement and installation, i is the annual discount rate, and y (year) is the project life. The project life was set at 30 years with an annual discount rate of 8%. Table 3. Assumption of power generation units Power island

NCGG 1 GE 7FB gas

PC Supercritical 650

IGCC 1 GE 7FB gas

10


UCGCC 1 GE 7FB gas

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Cooling system Natural gas price NOX control Particulates control SO2 control

turbine

MW gross output Wet cooling tower

turbine and steam cycle Wet cooling tower

turbine and steam cycle Wet cooling tower

Wet cooling tower $2.31 - 6.01/GJ

N/A

N/A

N/A

N/A

Hot side SCR

N/A

N/A

N/A

Cold-side ESP

N/A

N/A

N/A

N/A $10/ton to $30/ton Shell

N/A $10/ton to $30/ton N/A

Lignite price

N/A

Gasifier Dry product gas heating value H2S control

N/A

Wet FGD $10/ton to $30/ton N/A

N/A

N/A

9.98 MJ/m3

N/A

N/A

N/A

Selexol

Selexol

The calculation results are displayed in Fig.4. The IGCC had the highest generation cost, ranging from $104 – 117/MWh. When the coal price was as low as $10/tonne, PC and UCGCC had similar generation costs, at about $45/MWh. However, the PC was more sensitive to the coal price and its cost was higher than the UCGCC when the coal price was over $10/tonne. The NGCC is very competitive; its cost was lower than UCGCC if the natural gas price was lower than $4.50/GJ, or $4.85/kscf. In general, the UCGCC had low generation cost ($45 – 50/MWh) and was less sensitive to the fuel price. This is because the UCG combines the coal mining and utilization processes, and only the royalties and severance fees are assessed, saving significant costs in coal procurement, storage, and handling.

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120 110

Generation cost, $/MWh

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NGCC

100

PC

IGCC

UCGCC

90 80 70 60 50 40 30 20 0.00

1.00

2.00

3.00

4.00

5.00

6.00

Fuel price, $/GJ

Fig. 4. Power generation cost comparison, base case

2.3 Cost comparison – with CO2 capture system (CCS) This section compares the generation cost ($/MWh) and cost of CO2 captured. The hypothetical IGCC and UCGCC plants were installed with a Selexol pre-combustion capture system. The NGCC and PC plants were installed with an amine post-combustion capture system. The calculated generation cost is displayed in Fig.5. The IGCC-CCS had the highest cost. The cost gap between IGCC and UCGCC was increased in the CCS case over the base case. This means that installation of the CCS system had a larger impact on the PC than on the UCGCC. The NGCC-CCS had a low cost at low fuel prices (lower than $4.50/GJ). However, at higher fuel prices (over $4.50/GJ), the UCGCC-CCS had a lower generation cost than the NGCC-CCS.

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Generation cost, $/MWh

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160

NGCC-CCS

150

PC-CCS

140

IGCC-CCS

130

UCGCC-CCS

120

PC

110

IGCC

100

UCGCC

90

NGCC

80 70 60 50 40 30 0.00

1.00

2.00

3.00

Fuel price, $/GJ

4.00

5.00

6.00

Fig. 5. Power generation cost comparison, with CCS case. Dash lines represent corresponding base cases in Fig. 4. Another important factor to assess the CCS economic performance is the cost of CO2 captured, CCO2 ($/ton of CO2), which is defined as24:

CCO2 =

RCCS − Rref

(MCO2/ MWh)CCS − (MCO2/ MWh)ref

(3)

where Rccs ($/MWh) is the generation cost for CCS case, Rref ($/MWh) is the generation cost for the base case, (MCO2/MWh)CCS is the CO2 emission rate in tonne per MWh of net electricity output for CCS case, and (MCO2/MWh)ref is the CO2 emission rate in tonne per MWh of net electricity output for the base case. The cost of CO2 captured is plotted in Fig. 6. The NGCC-CCS had the highest CO2 capture cost, followed by the IGCC-CCS and PC-CCS. The cost of CO2 captured was lowest for UCGCCCCS. Lower CO2 capture cost offered by UCGCC renders it an advantage in the CO2 utilization market.

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60 55

Cost of CO2 captured, $/ton

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50 45 NGCC-CCS PC-CCS IGCC-CCS UCGCC-CCS

40 35 30 25 20 15 0.00

1.00

2.00

3.00

4.00

5.00

6.00

Fuel price, $/GJ

Fig. 6. CO2 capture cost comparison

3. Cost Sensitivity of UCGCC 3.1 Cost components The cost share of UCGCC base case and with CCS case at lignite prices of $20/ton is shown in Fig. 7. The annual expense of each component, which is the sum of annualized capital cost and O&M costs, is shown. From the figure, it is clear that well drilling and completion comprises the largest cost portion in both cases. Compared to other surface facilities, the well drilling and completion cost would be more impacted by the coal seam thickness and depth. Drilling cost per well is a function of coal depth, so the cost is proportional to the coal seam depth. The number of new cavities and wells drilled each year is a function of coal seam thickness. Thicker coal seams allow gasification cavities with larger diameters. Therefore, more coal is available per cavity, and fewer cavities and new wells are needed every year to support downstream product gas demand. To examine the effects of depth and seam thickness, a sensitivity analysis of UCG-gas cost as a function of coal depth and thickness was performed. Assuming the coal seam thickness varied from 4.5 to 10.5 m and the depth varied from 180 to 300 m, the power generation and CO2 capture cost were calculated.

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Cost share in UCGCC Other 33%

6% Severance tax and Royalty

Cost share in UCGCC wth CCS ASU 26%

Other 25%

21% ASU

28% CCS 21%

35% Well drilling and completion

Severance tax 5% and royalty

Well drilling and completion

Fig. 7. Cost share in UCGCC and UCGCC with CCS

3.2 Cost variation – base case The generation cost ($/MWh) as a function of depth and thickness for UCGCC without CCS is shown in Fig. 8. The cost decreased with increasing seam thickness and increased with increasing seam depth. However, the effect of depth was not as pronounced as that of the seam thickness. When the coal seam thickness reached 10.5 m, the required revenue dropped to a range between $35 to 38/MWh, which is less than the cost of NGCC at current low natural gas prices. It is worth noting that when the UCG is conducted at different depths, the product gas composition might change due to different hydrostatic (gasification) pressures. This in turn might result in change of heating value of the production gas and generation cost. Fig. 8 shows the general trend of the cost and the detailed variation of cost incorporating different gas composition should be investigate in further studies.

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Fig.8. UCG power generation cost as a function of coal seam depth and thickness, base case

3.3 Cost comparison – with CCS The generation cost ($/MWh) as a function of depth and thickness for UCGCC with CCS is shown in Fig. 9. Similar to the base case, the cost decreased with increasing seam thickness and increased with increasing seam depth, and the effect of depth was not as pronounced as that of the seam thickness. This trend is the same for the cost of CO2 captured (Fig. 10). When the coal seam thickness reached 9 m, the generation cost dropped close to $60/MWh, which is less than the cost of NGCC-CCS at current low natural gas prices.

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Fig. 9. UCG power generation cost as a function of coal seam depth and thickness, with CCS case 50

50

40 35 30 25

Thickness=4.5 m Thickness=7.5 m Thickness=10.5 m

45

Cost of CO2 captured, $/tonne

Depth=180 m Depth=215 m Depth=245 m Depth=275 m Depth=300 m

45

Cost of CO2 captured, $/tonne

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Thickness=6 m Thickness=9 m

40 35 30 25 20

20

15

15 4

6 8 Coal seam thickness, m

10

170

220 270 Coal seam depth, m

320

Fig. 10. UCG CO2 capture cost as a function of coal seam depth and thickness 4. Discussion The results outlined in Sections 2 and 3 indicate that UCGCC is very competitive compared with other power generation process. When thicker coal seams (thicker than 10 m) are utilized, UCGCC could compete with NGCC plant fueled by low-price natural gas. The annual required revenue is about 50% of IGCC using a surface gasifier. Fig. 11 compares the cost components of IGCC and UCGCC. The required annual revenue, in million USD per year ($M/year), is the sum of annualized capital costs and annual O&M costs. It can be seen that costs associated with the

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CCS were similar for UCGCC and IGCC, but UCGCC had significantly less cost in gasification and coal expense. The major cost associated with UCG reactor is well drilling and completion, which is significantly cheaper than the capital investment and O&M cost of gasifier. Also, UCG only requires payment of royalties at 8% of the market price, instead of purchasing coal at full market price, saving expense in coal procurement.

UCGCCCCS

IGCC-CCS

ASU Gasification Reactor Coal cost Other CCS

UCGCC

IGCC

0

50

100

150

200

250

Required annual revenue, $M/year

300

350

Fig.11. Comparison of UCG and IGCC cost components

5. Conclusions UCG technology may use coal seams that are too deep to be economically mined, significantly increasing recoverable global coal reserves. It has a smaller environmental footprint than conventional mining and surface gasifiers. Also, as the product gas is generated by UCG at relatively high pressures, when UCG is incorporated with a CCS system, the energy penalty and cost associated with CO2 capture and compression is reduced. Successfully applying UCG technology will be one of the strategies for satisfying energy demand at the world scale. In this paper, the competiveness of UCGCC was analyzed and approaches to reduce power generation costs were discussed. The required revenue of UCGCC and other common power generation

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process were calculated. The generation cost is largely determined by the fuel price. The results indicated that, for the base case without CCS, the UCGCC was comparable with PC and NGCC; with CCS, UCGCC generation cost was significantly lower than PC and comparable with NGCC. However, the UCGCC was able to provide CO2 at a cheaper price on the carbon utilization market. Also, generation cost of UCGCC is much less sensitivity to fuel price than the others. This mean the profitability of UCGCC is more stable regardless of the fluctuation on fuel price. Compared to IGCC, UCGCC significantly reduces cost in gasifier and coal procurement. UCGCC’s production cost is significantly influenced by the coal seam depth and thickness. The cost was within the range of NGCC costs. An effective way to enhance the competitiveness of UCGCC is to utilize thicker coal beds. The thicker the coal bed, the larger the gasification reactor can be. Therefore, one cavity can provide more coal to gasify and fewer new cavities have to be developed each year. This saves significant expense in well drilling each year, which is the largest portion of the annual O&M cost.

Abbreviations and Symbols ASU CCS CH4 CO CO2 CRIP H2 HRSG IGCC PC PM NGCC NOx

air separation unit CO2 capture system methane carbon monoxide carbon dioxide controlled retracting injection point hydrogen heat recovery steam generator Integrated gasification combined cycle pulverized coal particle matter natural gas combined cycle nitrogen oxides 19


Energy & Fuels

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

O2 O&M

oxygen operation and maintenance

SOx UCG

sulphur oxides underground coal gasification

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UCGCC underground coal gasification combined cycle USD U.S. dollar

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