Co2 Capture From Natural Gas Power Plant

Case Study: CO2 Capture from NGCC Power Plant Stack Gas Case Study: CO2 Capture from Natural Gas Combined Cycle Power Plant Stack Gas Electricity generation in the United States has shifted over the last 20 years from coal as the primary heat source to natural gas. Economic and environmental factors have both contributed to this shift. The development of hydraulic fracturing (fracking) and horizontal drilling technologies have made available U.S. shale gas deposits that were previously too expensive to exploit. In addition, replacing coal with natural gas can reduce CO2 emissions, per kilowatt-hour of electrical energy produced, by up to 50% while also eliminating the need for capture and disposal of ash and sulfur dioxide. When compared to coal-fired plants, CO2 emissions reduction in natural gas combined cycle (NGCC) power plants are a result of two primary factors: the reduced carbon content of natural gas per unit of energy available, and the increased plant efficiency that results from the use of both gas turbine and steam turbine power cycles employed by NGCC plants. The switch from coal-fired electricity production to NGCC has substantially reduced CO2 emissions from the US power sector, but further emissions reductions are necessary to meet the country’s goals. One approach is to capture CO2 from power plant stack gas for sequestration or for beneficial use. CO2 capture through absorption into aqueous amine solutions has been used commercially for many years but has yet to be widely employed in the power sector. Equipment costs and high process energy consumption have been the major drawbacks to its adoption, along with concerns for transport and sequestration of the substantial amounts of CO2 produced by fossil-fuel fired power plants. The use of advanced amine technology can reduce the equipment costs and power consumption associated with CO2 capture from NGCC power plants. This case study examines one such process as applied to a model NGCC plant. Amine-Based CO2 Capture Process Overview Post combustion CO2 capture processes for fossil-fuel fired power plants and industrial facilities, using advanced amines, can capture greater than 90% of the CO2 from flue gas while producing pipeline quality CO2 for sequestration, enhanced oil recovery, or other beneficial use. The thermal swing absorption process utilizes a packed bed adsorption tower where flue gas comes into contact with the amine-based scrubbing solution and carbon dioxide is absorbed. The CO2 rich solution is subsequently heated in a pressurized, packed bed regenerator tower which releases the CO2 from solution. The now CO2 lean solution is then cooled and returned to the absorption tower for reuse. CO2 released in the regenerator tower is dried and compressed to meet the requirements for carbon steel pipeline transport and storage. The process described here utilizes aqueous piperazine (C4H10N2), a cyclic diamine capable of capturing CO2 via the following reactions: 1) CO2(g) + C4H10N2(aq) ↔ C4H8N(NH2CO2)(aq) 2) CO2(g) + C4H8N(NH2CO2)(aq) ↔ C4H6(NH2CO2)2(aq) The capture reactions are reversible with the application of heat, producing CO2 gas and a regenerated solvent for reuse. Major units in the CO2 capture process are described below. Flue Gas Booster Fan A booster fan is used to transport the flue gas through the system. It provides the motive force required for flow through the flue gas cooling equipment, the CO2 absorber, the exhaust stack, and all associated ductwork. Flue Gas Cooling The capture process requires cooling of the flue gas when the flue gas temperature is above that where solvent degradation and water loss is a concern. Flue gas is cooled using a non-contact fresh-water cooling system upstream of the CO2 absorber. Additionally, a heat recovery steam generator (HRSG or boiler) may be used to improve overall system efficiency and reduce the flue gas temperature before the flue gas cooler. Low pressure steam produced in the HRSG can be used in the solvent regeneration process, reducing the energy demand on the facility. CO2 Absorber The CO2 absorber uses stainless steel structured packing for gas-liquid contact and consists of two separate packed sections. As the gas enters the absorber tower a gas distribution tray located below the first packing section ensures even distribution of the gas throughout the cross-section of the tower. The gas travels upwards through the tower and each of the packed sections. The two packed sections are used to absorb CO2 from the flue gas using aqueous piperazine solvent. As the flue gas travels upwards through these sections, CO2 is removed from the flue gas through its reaction with the solvent. The CO2 absorption reaction is exothermic, increasing the temperature of the solvent as it moves downward through the absorber tower. The temperature of the solvent is controlled using a lean solvent heat exchanger, at the inlet to the tower, and with an intercooler which cools the liquid between the two CO2 packing sections. Temperature control with both the lean cooler and the intercooler improve absorber performance, maintain the process water balance and minimize solvent volatility. Cross Heat Exchanger Recovery of heat between the absorption and regeneration steps is essential to minimize the energy demand of the process. Cool CO2-rich solvent from the absorber is pumped by the absorber pumps through plate-and-frame heat exchangers prior to entering the Regenerator. Hot CO2-lean solvent from the CO2 regenerator is pumped by the regenerator pump also through the plate-and-frame heat exchanger to transfer heat from the lean solvent to the rich solvent, reducing the lean solvent temperature and raising the CO2 rich solvent temperature prior to regeneration. Solvent Regenerator (for information only – not covered in this case study) The CO2 regenerator tower is used to release CO2 from the CO2-rich solvent, regenerating the solvent for reuse in the absorber. The hot, CO2-rich scrubbing liquor from the cross-heat exchanger enters the top of the regenerator tower. The regenerator tower is maintained at elevated pressure and consists of two sections of structured, stainless-steel packing, with liquid redistribution between the sections. CO2 rich gas leaving the regenerator passes through a mist eliminator, which captures and returns entrained liquid. CO2 rich gas leaving the regenerator is cooled in the regenerator condenser, removing water vapor from the CO2 stream prior to compression and final drying. Condensed water from the gas is returned to the CO2 scrubbing process for reuse. The regenerator condenser is cooled with water from the fresh water cooling system. The heat of reaction needed to release CO2 from the scrubbing solution is supplied by steam passing upward through the regenerator column. The steam also helps carry the CO2 up the regenerator and into the condenser. Operation of the regenerator and steam system are not addressed in this case study. CO2 Compression and Drying (for information only – not covered in this case study) Although a substantial amount of water vapor is removed from the CO2 rich gas in the regenerator condenser, the gas still contains higher moisture than is acceptable for pipeline transport. As the gas is further compressed and cooled a portion of the water condenses in the inter-stage coolers of the compressor, which is sent back to the CO2 absorber. Following compression, the CO2 is dried in a molecular sieve dehydration unit to achieve the required dewpoint. Dry CO2 gas is then compressed to the final product pressure and cooled to the specified temperature. Operation of the compression and drying system is not addressed in this case study. NGCC CO2 Capture Process Description The NGCC power plant described here produces 535 MW of electrical power and operates with an annual capacity factor of 60%. The composition and heating value of the fuel burned by the plant is presented in table 1. Table 1: Fuel Properties CH4 94.7 vol% C2H6 4.2 vol% C3H8 1.1 vol% HHV 52 kJ/g Temp 25 oC Press 1 atm Combustion air fed to the gas turbine is at a temperature of 25oC, pressure of 1 atm and a relative humidity of 40%. Stack gas produced by the NGCC plant, and to be treated in the CO2 capture system, is described in Table 2. Table 2: Flue Gas Properties Temp 104 oC Press 1 atm O2 12.21 vol% CO2 3.86 vol% H2O 9.43 vol% N2 74.50 vol% Gas Flow 3,149,700 kg/hr This case study will address only the CO2 absorption part of the process, and not cover solvent regeneration, CO2 compression and drying. A simplified schematic diagram of the absorption process is shown in Figure 1. Figure 1: Schematic Diagram of CO2 Capture Plant Flue gas from the NGCC plant (stream 1) is pumped by the booster fan through the flue gas cooler (heat exchanger) where it is cooled to the gas dew point before entering the lower section of the absorber tower (Absorber 1). The flue gas then passes through the two absorber sections (Absorber 1 and Absorber 2) before exiting through the plant’s exhaust stack at 40oC and 1 atm. The gas pressure drop through the flue gas cooler is 1.05 kPa and through the absorber sections is 10.45 kPa. The CO2 lean solution (stream 8) enters absorber 2 at 38oC. It exits absorber 2 (stream 9) and is cooled back to 38oC in the intercooler (heat exchanger or HE). It then enters absorber 1 (stream 11) where it continues to absorb CO2 and exits absorber 1 (stream 12) as CO2 rich solution at 42oC. The CO2 rich solution is pumped (stream 13) to a cross heat exchanger where it heated to 104oC by the CO2 lean solution (stream 6) returning from the from the solvent regenerator. The temperature of the lean solution entering the cross heat exchanger (stream 6) is 112oC. The lean solution leaving the cross heat exchanger (stream 7) is cooled to 38oC in the lean heat exchanger and returned to the absorber (stream 8). Cooling water (CW Supply) for the flue gas cooler, intercooler and lean heat exchanger is fresh water available at 20oC. The maximum allowable increase in the cooling water temperature is 12oC in any heat exchanger. Heats of reaction and properties of the CO2 lean and rich solutions are provided in the document “Properties of Piperazine Solutions for CO2 Scrubbing”. CASE STUDY PROBLEMS 1. Natural gas is burned in the combustor of the NGCC’s gas turbine with excess air to ensure complete combustion and to limit the temperature of the hot gas entering the turbine. In addition, liquid water is injected into the combustor to reduce the combustion temperature and increase the mass flow of gas through the turbine. Based on the fuel and flue gas compositions given, calculate: a. the excess air (in %) fed to the combustor and b. the water injection rate (in kg/hr). 2. Calculate the CO2 capture rate (kg/hr) based on 90% capture. What is the amount of CO2 captured annually (based on the plant capacity factor)? 3. Calculate the rate of work performed by the booster fan. Assume the fan is adiabatic. Find the temperature of the flue gas emerging from the fan (stream 2). 4. Calculate the cooling required in the flue gas heat exchanger and the cooling water flowrate. 5. Calculate the volumetric flowrate (m3/hr) of streams 1, 2, 3. 6. Calculate the flow rate (m3/hr) of liquid absorbing solution (lean solution) into the top of the absorber (stream 8) based on removal of 90% of the carbon dioxide from the flue gas. 7. Calculate the amount of water that evaporates into (or condenses from) the flue gas in the absorber. Find the moisture content and dew-point temperature of the flue gas leaving the absorber. Assume that it is in vapor/liquid equilibrium with the lean solution entering the column. 8. Assume that each absorber stage removes the same amount of carbon dioxide from the flue gas. Calculate the fraction of piperazine that is unbound, the fraction that is bound to one carbon dioxide and the fraction that is bound to two carbon dioxides in the absorber feed (stream 8), the intercooler fluid stream (stream 9) and the absorber outlet (stream 12). From this, determine the extents of Reactions 1 and 2 in each absorber stage. The reactions are given in the document “Properties of Piperazine Solutions for CO2 Scrubbing”. 9. Calculate the heat exchanged between the lean and rich solutions in the cross-heat exchanger. 10. Calculate the cooling required, and the cooling water flowrates in the lean cooler and the intercooler. Page 4 of 4 Properties of Piperazine solutions for CO2 Scrubbing Heats of Reaction 1. CO2 (g) + C4H10N2 (aq) → C4H8N(NH2CO2) (aq) ΔH = -76.6 kJ 2. CO2 (g) + C4H8N(NH2CO2) (aq) → C4H6(NH2CO2)2 (aq) ΔH = -44.9 kJ Absorber Feed (lean) solution: 25 wt% Piperazine 0.36 mole CO2 per mole base (0.72 mole CO2 per mole piperazine) Fraction of Piperazine as free (no bound CO2) piperazine: 0.37 Feed Temperature: 38oC Heat capacity of lean solution: Cp (KJ/kg-oC) = 3.21 + 0.00450 T (oC) Density of lean solution: ρ (g/cm3) = 1.1325 – 6.623x10-4 T + 1.620 x10-6 T2 (T [=] oC) Water vapor pressure: Boiling point elevation 3.88oC Regenerator Feed (rich) Solution 0.50 mole CO2 per mole of base (1 mole CO2 per mole piperazine) Fraction of Piperazine as free (no bound CO2) piperazine: 0.14 Feed Temperature: 104oC Heat capacity of rich solution: Cp (KJ/kg-oC) = 3.21 + 0.00450 T (oC) Density of rich solution: ρ (g/cm3) = 1.1525 – 6.623x10-4 T + 1.620 x10-6 T2 (T [=] oC) Water vapor pressure: Boiling point elevation 10.35oC CO2 Vapor Pressure over aqueous piperazine solutions ln P*(CO2) = A + B/T + Cx2 + Dx/T + Ex2/T P* [=] Pa, x = CO2 loading [=] moles CO2 per mole of base T [=] K A = 27.80, B = -9184, C = -19.93, D = 3903, E = 9711