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 carbon dioxide (CO₂), transporting it to the sequestration site, and injecting it into a deep sedimentary formation. It also provides the timeline and costs for an experimental injection of CO₂ into peridotite or basalt (Table F.3).

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 that the supercritical phase is maintained and frictional losses overcome. Compression power is calculated from:

where Z is the compressibility factor (0.9942), T₁ 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), γ is the specific heat ratio (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/t CO₂, or 0.09 and 0.055 t CO₂ emitted per t CO₂ 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 Mt/y CO₂.

Materials, Construction, and Demolition. The major material requirements for pipeline construction include 31,200 t sand and 7,680 t steel (Koornneef 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 Mt CO₂ from the production of steel,² using energy sourced from coal and natural gas, respectively. 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 × 10⁶ ton-miles of material hauling. Assuming an energy density of 35.9 MJ/L for lower heating value (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 ton-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 are demolished and hauled away (Koornneef 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 DOE Fossil Energy (FE)/ National

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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.

³ Assuming an 11 MPa input pressure and 10.7 MPa output pressure.

Energy Technology Laboratory (NETL) CO₂ Transport Model (NETL, 2018). For the case of a 10-mile pipeline segment with nominal diameter of 30 inches, two compression pumps (η= 0.75) are spaced 3.3 miles apart and require 8,379 MWh/y—collectively—to 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. 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 underground.⁵ Emissions associated with materials (embodied energy) and transport to the construction site are approached with the same assumptions outlined in “Pipeline Transport: Materials, Construction and Demolition” 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. 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 ton-miles of material hauling. Using an average value of 3,255 MJ/t for the embodied energy of reinforced concrete, indirect emissions from material production total 0.047 and 0.03 Mt CO₂ 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

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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 life-cycle data scales to a 7.3 Mt/y capacity operation.

be obtained from the energy of construction per ton 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 “Compression at the Capture Unit” 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 Mt CO₂ in indirect emissions if using power generated in coal and natural gas firing, respectively.

CARBON EMISSIONS AND COSTS

A summary of the carbon emissions and costs associated with compression, transport, and injection chain is presented in Tables F.1 and F.2.

TABLE F.1 Contributions to the Carbon Footprint from Compression, Transport, and Injection (kgCO₂emitted/tCO₂ processed^a)

^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

^aSee https://www.netl.doe.gov/projects/energy-analysis-details.aspx?id=543 (accessed January 29, 2019).

^b High 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).

^cLevelized basis = 10 Mt/y CO₂

^dLevelized basis = 10 Mt/y CO₂ less 0.55 Mt/y CO₂ (0.90 Mt/y CO₂) for emissions associated with natural gas (coal) firing.

ESTIMATED COST OF A PILOT EXPERIMENT ON IN SITU CARBON MINERALIZATION IN PERIDOTITE OR BASALT

TABLE F.3 Timeline and Budget, Generic In Situ Carbon Mineralization Experiment in Peridotite or Basalt at 100,000 Tons/y

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