Below is the uncorrected machine-read text of this chapter, intended to provide our own search engines and external engines with highly rich, chapter-representative searchable text of each book. Because it is UNCORRECTED material, please consider the following text as a useful but insufficient proxy for the authoritative book pages.
Appendix F Geologic Storage ENERGY REQUIREMENTS AND COSTS FOR COMPRESSION, TRANSPORT, AND INJECTION OF CO2 This appendix calculates the energy requirements and costs for compressing captured CO2, transporting it to the sequestration site, and injecting it into a deep sedimentary formation. COMPRESSION AT THE CAPTURE UNIT Following separation of CO2 from flue gas, air, or some other source, the now rich CO2 stream must be dehydrated and compressed to a level suitable for transport, typically above 10 MPa for pipeline to ensure the supercritical phase is maintained and frictional losses overcome. Compression power is calculated from: â = â1 â1 where Z is the compressibility factor (0.9942), is the inlet temperature (313.15 K), R is the universal ideal gas constant (8.3145 J/(mol K)), M is the molar mass of CO2 (44.01 g/mol), N is the number of compression stages (4), is the specific heat ratio â (1.293759), and p1 and p2 are the inlet and outlet pressures, respectively (0.101325 and 11 MPa) (Damen et al., 2007). Based on these parameters, and assuming an isoentropic efficiency of 80 percent, the electrical work for compression equals 400 MJ/tCO2, or 0.09 and 0.055 tCO2 emitted per tCO2 compressed using electricity sourced from coal and natural gas, respectively. Material requirements for the construction and demolition of compression equipment and infrastructure are negligibly small and can be ignored in this analysis. PIPELINE TRANSPORT There are three factors to consider in estimating the carbon footprint of a CO2 pipeline: (1) the embodied energy in the materials used in construction (including transport of these materials to the building site and demolition at end-of-life), (2) indirect emissions associated with the electricity required to power CO2 pumps along the pipeline length to maintain pressure, and (3) fugitive emissions associated with leakage and loss of CO2 over the pipeline lifetime. All calculations assume a 10-mile pipeline length and all associated components are expected to scale linearly for longer pipelines.1 The dimensions used in these calculations are sufficient to transport 10 MtCO2/y. Materials, Construction, and Demolition. The major material requirements for pipeline construction include 31,200 t sand and 7,680 t steel (Kornreef et al., 2008). The embodied energy in steel is 11,254 MJ/t (Kirchofer et al., 2012), such that every 10-mile section of pipeline results in emissions of 0.02 and 0.012 MtCO2 from the production of steel,2 using energy sourced from coal and natural gas, respectively. 1 For example, if a 10-mile segment requires 80,000 t steel, a 50-mile segment requires 400,000 t. 2 Analysis assumes primary steel. Adjustments for secondary steel may assume an embodied energy of 7,230 MJ/t. PREPUBLICATION COPY 351
352 Negative Emissions Technologies and Reliable Sequestration: A Research Agenda Collection and handling of sand is expected to have a small energy requirement relative to transport and is thus ignored. Transport of all materials to the construction site results in 2.26 Ã 106 tonne-miles of material hauling. Assuming an energy density of 35.9 MJ/L for LHV diesel with a carbon intensity of 102.82 g/MJ, this material can be transported via heavy-duty trucking at an emission rate of 0.11 kgCO2 per tonne-mile, or 249 tCO2 per 10-mile pipeline segment. Energy consumed over the course of construction is estimated at 53,000 GJ diesel per 10-mile segment (Koornneef et al., 2008). Using the same energy density and carbon intensity described above yields an additional 5.4 kt of CO2 emissions. After a pipeline lifetime of 30 years, all materials must be demolished and transported off-site. Here, it is assumed that 50 percent of the materials are left in-ground and 50 percent is demolished and hauled away (Kornreef et al., 2008). Assuming a demolition energy of 11.1 MJ/t (Phua, 2009), and a hauling requirement equal to 50 percent of that required for construction, an additional 0.15 ktCO2 is emitted in pipeline removal. Pipeline Compression. The optimal number of pumps to overcome pressure loss3 along the pipeline length is calculated from the FE/NETL CO2 Transport Model (JEN REF). For the case of a 10-mile pipeline segment of with nominal diameter of 30 inches, 2 compression pumps ( = 0.75) are spaced 3.3 miles apart and require 8,379 MWh/yrâcollectivelyâto operate. This compression work adds 6.6 and 4.1 ktCO2 per year, or 198 and 123 ktCO2 over the lifetime of the pipeline, using energy sourced from coal and natural gas, respectively. It is important to note that the number of compression pumps does not scale perfectly linearly as the materials, and a pipeline model (e.g., FE/NETL model) should be used to assess the optimal number of pumps for a given length and desired pressure. Fugitive Emissions. Over the course of compression and transport, a small percentage of CO2 will be lost due to system leakage. Using guidelines for fugitive emission calculations provided by the IPCC (2006), an estimated 3.74 tCO2/mile per year is lost, or 1.12 ktCO2 per 10-mile segment over the course of the pipeline lifetime. INJECTION This section outlines the carbon footprint of CO2 injection with the ultimate goal of permanent storage in the subsurface.4 This chain involves construction of the injection well plus compression and injection energy to pump approximately 7.3 Mt/y underground5 (NAM/GASUNIE, 1991). Emissions associated with materials (embodied energy) and transport to the construction site are approached with the same assumptions outlined in âPipeline Transport: Materials, Construction and Demolitionâ above. A key difference in the life cycle treatment of injection wells is that after a 30-year lifespan, the injection well is abandoned; thus, no emissions are accountable to project demolition and disposal. Materials and Construction. A 7.3 Mt/y injection project requires approximately 6 wells, each 1.86 miles in length. It is worth noting that a smaller (larger) capacity can be achieved by subtraction (addition) of wells, and the calculations outlined in this section should be scaled accordingly. The material requirements for well construction include 712,000 t sand, 11,900 t steel, and 25,111 t concrete, resulting in 46,452,000 tonne-miles of material hauling. Using an average value of 3,255 MJ/tonne for the 3 Assuming an 11 MPa input pressure and 10.7 MPa output pressure. 4 Alternative injection goals (e.g., enhanced oil recovery) may require additional equipment and energy requirements for processing of re-circulated CO2. 5 This injection capacity is based on reports for underground natural gas storage, where the lifecycle data scales to a 7.3 Mt/y capacity operation. PREPUBLICATION COPY
Appendix F 353 embodied energy of reinforced concrete, indirect emissions from material production total 0.047 and 0.03 MtCO2 assuming power sourced from coal and natural gas, respectively. Transport of construction materials to the site results in an additional 5.11 ktCO2 emissions. Energy consumed over the course of construction is unknown, but a conservative estimate may be obtained from the energy of construction per tonne of steel in the pipeline case. This results in a consumed energy of 255,400 GJ, or 37.3 ktCO2 emissions. Injection Energy. Assuming a 0.3 MPa pressure loss over the course of pipeline transport, the CO2 arrives at the wellhead at a pressure of 10.7 MPa. The energy required to pressurize the incoming CO2 to 15 MPa for injection can be calculated from the same equation presented above for compression work post-capture. However, the pre-injection compression train requires only 2 stages to achieve the desired pressure of 15 MPa. Using the assumptions outlined in âCompression at the Capture Unitâ above, and changing the inlet and outlet pressures to 10.7 and 15 MPa, respectively, the injection well compression energy totals 25.2 MJ/t, or 0.04 and 0.025 MtCO2 in indirect emissions if using power generated in coal and natural gas firing, respectively. CARBON EMISSIONS AND COSTS A summary of the carbon emissions associated with compression, transport, and injection chain is presented in Table F.1. TABLE F.1 Contributions to the carbon footprint from compression, transport, and injection (kgCO2emitted/tCO2 processeda) Power Source Parameter Diesel Coal Natural Gas N/A Compression (at the capture unit) 90 55 Embodied energy of materials (pipeline construction)b 0.2 0.13 Transport of materials (pipeline construction)b 0.003 Energy consumed in construction (pipeline)b 0.06 Pipeline demolition 0.002 Pipeline pumps 0.07 0.04 Fugitive emissions 0.012 Embodied energy of materials (well construction) 0.2 0.14 Transport of materials (well construction) 0.02 Energy consumed in construction (injection well) 0.17 Injection (compression) energy 0.18 0.11 Total carbon footprint 90.9 55.7 a Assumes a 30 year-lifetime. b Assumes a 10-mile segment. TABLE F.2. Economic costs associated with compression, transport and injection of CO2 Factor Cost ($M) Comment CAPEX Compressor 100 Value scaled from IECM estimate, assuming a product pressure of 11 MPa, compressor efficiency of 80%, product purity of 99.5%, and a maximum CO2 compressor capacity of 300 t/hr. Pipeline 25â225 Lower bound: value calculated from the FE/NETL CO2 Transport Cost Model (https://www.netl.doe.gov/research/energy- analysis/search-publications/vuedetails?id=543).
354 Negative Emissions Technologies and Reliable Sequestration: A Research Agenda Factor Cost ($M) Comment Assumes 10 Mt/yr transport and pipeline length of 10 mi. Upper bound: value calculated as above assuming pipeline length of 100 mi. Injection site screening and evaluation 2.5 Value adjusted for current USD from estimate based on the work of Smith et al. (2001) Injection equipment 0.6â8.0 Values calculated from actual injection site costs provided in Herzog et al. (2003) and include supply wells, plants, distribution lines, headers, and electrical services. Values called to current dollars. Lower bound: low case, aquifera Upper bound: high case, gas reservoira Well drilling 0.20â210 Values calculated based on estimates provided in Herzog et al. (2003), which were derived from data presented in the report â1998 Joint American Survey (JAS) on Drilling Costsâ. Capital expense tied to number of wells required, which is in turn calculated from the equations outlined in McCollum and Ogden (2006) and uses the high and low case parameters outlined in the table notesa Lower bound: low case, aquifera Upper bound: high case, gas reservoira CAPEX Subtotal 128â546 Annualized Capital Payment ($M/yr) 14â62 Assumes a project-life of 30 years and fixed charge factor of 0.11278 (Rubin et al., 2007). OPEX Maintenance: compression 3 Range calculated as 0.03 of total capital requirement for compression. Labor: compression 0.9 Range calculated as 0.30 of maintenance cost for compression. Electricity: compression 67â100 Calculated from energy requirement (400 MJ/t CO2) and electricity cost range of $60/MWh lower bound to $90/MWh upper bound. Operation and maintenance: pipeline 0.2â1.3 Pipeline operational and maintenance expenses reported in the FE/NETL CO2 Transport Cost Model (https://www.netl.doe.gov/research/energy- analysis/search-publications/vuedetails?id=543) includes labor, excludes cost of electricity. Range in costs here reflect 10-mile (low) and 100-mile (high) pipeline segments. Electricity: pipeline 0.2â2.9 Range calculated based on low case of 10-mile segment, 2700 MWh/yr electric requirement, and $60/MWh, and high case of 100-mile segment, 32,000 MWh/yr electric requirement, $90/MWh. Operation and maintenance: injection 0.6â34 Operational and maintenance costs estimated from McCollum and Ogden (2006) and include: normal daily expenses, consumables, surface maintenance and subsurface maintenance. Compression energy at the wellhead is included and is considered negligible compared to other electric requiremetns in the transport and storage chain, thus no range for electric cost is reported. Lower bound: low case, aquifera Upper bound: high case, gas reservoira PREPUBLICATION COPY
Appendix F 355 Factor Cost ($M) Comment OPEX Subtotal 72â142 Total Annual Cost 86â204 Levelized Cost ($/tCO2 yr-1)b 8.6â20.4 Avoided Cost ($/tCO2 yr-1)c Natural Gas 9.1â21.6 Coal 9.5â22.4 aHigh and low cases were calculated for three injection sites: aquifer, oil reservoir and gas reservoir. Variables for each scenario include reservoir pressure, thickness, depth, and horizontal permeability. These values are taken from Herzog et al., 2003) and are tabulated in McCollum and Ogden, 2006). bLevelized basis = 10 MtCO /yr 2 cLevelized basis = 10 MtCO /yr less 0.55 MtCO /yr (0.90 MtCO /yr) for emissions associated with natural gas (coal) firing. 2 2 2
356 Negative Emissions Technologies and Reliable Sequestration: A Research Agenda PREPUBLICATION COPY