Analysis of CO2 Separation from Flue Gas, Pipeline Transportation, and Sequestration in Coal (original) (raw)
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Proceedings of SPE Gas Technology Symposium, 2006
Carbon dioxide (CO 2) from energy consumption is a primary source of anthropogenic greenhouse gas. Injection of CO 2 in coalbeds is a plausible method of reducing atmospheric emissions, and it can have the additional benefit of enhancing methane recovery from coal. Most previous studies have evaluated the merits of CO2 disposal in high-rank coals. The objective of this research is to determine the technical and economic feasibility of CO 2 sequestration in, and enhanced coalbed methane (ECBM) recovery from, low-rank coals in the Texas Gulf Coast area. Our research included an extensive coal characterization program, deterministic and probabilistic simulation studies, and economic evaluations. We evaluated both CO 2 and flue gas injection scenarios. In this study coal core samples and well transient test data were obtained for characterization of Texas low-rank coals. Simulation studies evaluated the effects of well spacing, injectant fluid composition, injection rate, and dewatering on CO 2 sequestration and ECBM recovery. Probabilistic simulation of 100% CO 2 injection in an 80acre 5-spot pattern indicate that these coals can store 1.27 to 2.25 Bcf of CO 2 with an ECBM recovery of 0.48 to 0.85 Bcf. Simulation results of 50% CO 2-50% N 2 injection in the same 80-acre 5-spot pattern indicate that these coals can store 0.86 to 1.52 Bcf of CO 2 , with an ECBM recovery of 0.62 to 1.10 Bcf. Simulation results of flue gas injection (87% N 2-13% CO 2) indicate that these same coals can store 0.34 to 0.59 Bcf of CO 2 at depths of 6,200 ft, with an ECBM recovery of 0.68 to 1.20 Bcf. Economic modeling of CO 2 sequestration and ECBM recovery for 100% CO 2 injection indicates predominately negative economic indicators for the reservoir depths and well spacings investigated, using natural gas prices ranging
Optimized CO2 flue gas separation model for a coal fired power plant
International Journal of Energy and Environment, 2013
The detailed description of the CO2 removal process using mono-ethylamine (MEA) as a solvent for a coal-fired power plant is present in this paper. The rate based Electrolyte NRTL activity coefficient model was used in the Aspen Plus. The complete removal process with re-circulating solvent back to the absorber was implemented with the sequential modular method in Aspen Plus. The most significant cost related to CO2 capture is the energy requirement for re-generating solvent, i.e. re-boiler duty. Parameters’ effects on re-boiler duty were studied, resulting in decreased re-boiler duty with the packing height and absorber packing diameter, absorber pressure, solvent temperature, stripper packing height, and diameter. On the other hand, with the flue gas temperature, re-boiler duty is increased. The temperature profiles and CO2 loading profiles were used to check the model behavior.
Test results from a CO2 extraction pilot plant at boundary dam coal-fired power station
Energy, 2004
A CO 2 extraction pilot plant adjacent to SaskPower's boundary dam power station (BDPS) was re-commissioned in the Fall of 2000 and has since been in operation to process 14 Â 10 3 m 3 =day (500,000 SCFD) of flue gases, and capture up to 4 ton of carbon dioxide (CO 2) per day. This facility is being used for testing and demonstrating the potential of various CO 2 capture technologies. This pilot plant has provided us with the capability to evaluate the performance and reliability of proprietary CO 2 solvent extraction technologies as well as to obtain the much needed engineering data that can used for the design of commercial scale CO 2 absorption units. A series of tests have been carried out over a reasonably long testing period with a monoethanolamine (MEA) based solvent (i.e. Fluor's Econamine FG SM technology). Valuable information was obtained both in design and operational aspects. This paper provides details of the test facilities at the Boundary Dam CO 2 pilot plant and discusses the results obtained in terms of the absorption performance, or mass-transfer efficiency of the process, under ranges of typical operating conditions including energy consumption for solvent regeneration. It also discusses operational problems such as solvent degradation, levels of heat-stable salts, as well as corrosion in the CO 2 plant.
Engineering assessment of CO{sub 2} recovery, transport, and utilization
1998
The need to establish benchmarks for available power-generating cycles having reduced atmospheric emissions of CO{sub 2} served as the basis for this study. Innovative process technologies need this benchmark so they can be appreciated in their proper perspective. An oxygen-blown KRW coal-gasification plant producing hydrogen, electricity, and supercritical-CO{sub 2}, was studied in a full-energy cycle analysis extending from the coal mine to the final destination of the gaseous product streams. A location in the mid-western US 100 mi from Old Ben No.26 mine was chosen. Three parallel gasifier trains, each capable of providing 42% of the plant's 413.5 MW nominal capacity use 3,845 tons/day of Illinois No.6 coal from this mine. The plant produces a net 52 MW of power and 131 MMscf/day of 99.999% purity hydrogen which is sent 62 mi by pipeline at 34 bars. The plant also produces 112 MMscf/day of supercritical-CO{sub 2} at 143 bars, which is sequestered in enhanced oil recovery ope...
Potential Flue Gas Impurities in Carbon Dioxide Streams Separated from Coal-Fired Power Plants
Journal of The Air & Waste Management Association, 2009
For geological sequestration of carbon dioxide (CO 2 ) separated from pulverized coal combustion flue gas, it is necessary to adequately evaluate the potential impacts of flue gas impurities on groundwater aquifers in the case of the CO 2 leakage from its storage sites. This study estimated the flue gas impurities to be included in the CO 2 stream separated from a CO 2 control unit for a different combination of air pollution control devices and different flue gas compositions. Specifically, the levels of acid gases and mercury vapor were estimated for the monoethanolamine (MEA)-based absorption process on the basis of published performance parameters of existing systems. Among the flue gas constituents considered, sulfur dioxide (SO 2 ) is known to have the most adverse impact on MEA absorption. When a flue gas contains 3000 parts per million by volume (ppmv) SO 2 and a wet flue gas desulfurization system achieves its 95% removal, approximately 2400 parts per million by weight (ppmw) SO 2 could be included in the separated CO 2 stream. In addition, the estimated concentration level was reduced to as low as 135 ppmw for the SO 2 of less than 10 ppmv in the flue gas entering the MEA unit. Furthermore, heat-stable salt formation could further reduce the SO 2 concentration below 40 ppmw in the separated CO 2 stream. In this study, it is realized that the formation rates of heat-stable salts in MEA solution are not readily available in the literature and are critical to estimating the levels and compositions of flue gas impurities in sequestered CO 2 streams. In addition to SO 2 , mercury, and other impurities in separated CO 2 streams could vary depending on pollutant removal at the power plants and impose potential impacts on groundwater. Such a variation and related process control in the upstream management of carbon separation have implications for groundwater protection at carbon sequestration sites and warrant necessary considerations in overall sequestration planning, engineering, and management.
This feasibility study involves the potential application of oxyfuel technology on a refinery-wide basis at the BP Grangemouth unit in Scotland. A total of seven boilers and 13 process heaters of various types, burning a mixture of refinery fuel gas and fuel oil resulting in the production of approximately 2.0 million tonnes per annum of CO2, form the basis of this study. This work considers the issues involved in modifying the process heaters and boilers for oxyfuel combustion and locating two world scale air separation plants totalling up to 7400 tonne/day of oxygen plus a CO2 compression and purification system on a congested site. In addition, we present the scheme for distributing the oxygen around the site and collecting the CO2-rich effluent from the combustion processes for purification, final compression, and delivery into a pipeline for enhanced oil recovery. The basic case, Case 1, is presented and costed involves the supply of the complete oxyfuel system with installation and start-up and includes all required utilities. The electrical energy required for the system is provided by a GE 6FA gas turbine combined cycle cogeneration unit with 10.7 MW of excess power available as surplus. Two further cases are also presented. The first uses a GE 7EA gas turbine plus heat recovery steam generator producing steam primarily at the refinery condition of 127 barg 518 ~ together with some additional supplies at 13.7 barg. The steam production from the existing boilers is reduced by a corresponding amount. The third case uses a similar 7EA gas turbine plus heat recovery steam generator, but in this case the fuel is hydrogen produced from an oxygen autothermal reformer with product steam generation and CO2 removed using a methyl diethanolamine (MDEA) system. In each of these three cases the total quantity of CO2 emission avoided and the quantity of CO2 available for pipeline delivery is calculated, costed and presented in Table 1.
Economics of CO 2 and Mixed Gas Geosequestration of Flue Gas Using Gas Separation Membranes
Industrial & Engineering Chemistry Research, 2006
Greenhouse gas emission sources generally produce mixed gases. Previous studies of CO 2 capture and storage have typically examined only sequestration of pure CO 2 . This paper analyses the cost of separating a gas mixture from a power station flue gas stream and injecting it into an offshore subsurface reservoir. The costs of separating and storing various gas mixtures were analysed at two extremes. One extreme in which the entire flue gas stream containing both CO 2 and N 2 is stored. The other extreme in which as much CO 2 is separated as is technically possible using gas membrane capture coupled with chemical absorption. The results indicate that for the gases investigated, using a gas 2 membrane capture system, the lowest sequestration cost per tonne of CO 2 avoided occurs when a mixed gas with a CO 2 content of about 60% is sequestered. Lower costs and higher tonnages of CO 2 avoided can be achieved using an amine based absorption capture system. At the lowest cost point, and for most of the range of cases studied, the cost of capture is significantly greater than the cost of storage.
Sequestration of Carbon Dioxide in Coal with Enhanced Coalbed Methane RecoveryA Review †
Energy & Fuels, 2005
This article reviews the storage of captured CO 2 in coal seams. Other geologic formations, such as depleted petroleum reservoirs, deep saline aquifers and others have received considerable attention as sites for sequestering CO 2 . This review focuses on geologic sequestration of CO 2 in unmineable coalbeds as the geologic host. Key issues for geologic sequestration include potential storage capacity, the storage integrity of the geologic host, and the chemical and physical processes initiated by the deep underground injection of CO 2 . The review topics include (i) the estimated CO 2 storage capacity of coal, along with the estimated amount and composition of coalbed gas; (ii) an evaluation of the coal seam properties relevant to CO 2 sequestration, such as density, surface area, porosity, diffusion, permeability, transport, rank, adsorption/desorption, shrinkage/swelling, and thermochemical reactions; and (iii) a treatment of how coalbed methane (CBM) recovery and CO 2 -enhanced coalbed methane (ECBM) recovery are performed (in addition, the use of adsorption/ desorption isotherms, injection well characterization, and gas injection are described, as well as reservoir screening criteria and field tests operating in the United States and abroad); (iv) leak detection using direct measurements, chemical tracers, and seismic monitoring; (v) economic considerations using CO 2 injection, flue gas injection, and predictive tools for CO 2 capture/ sequestration decisions; (vi) environmental safety and health (ES&H) aspects of CO 2 -enhanced coalbed methane/sequestration, hydrodynamic flow through the coal seam, accurate gas inventory, ES&H aspects of produced water and practices relative to ECBM recovery/sequestration; (vii) an initial set of working hypotheses concerning the chemical, physical, and thermodynamic events initiated when CO 2 is injected into a coalbed; and (viii) a discussion of gaps in our knowledge base that will require further research and development. Further development is clearly required to improve the technology and economics while decreasing the risks and hazards of sequestration technology. These concerns include leakage to the surface, induced seismic activity, and long-term monitoring to verify the storage integrity. However, these concerns should not overshadow the major advances of an emerging greenhouse gas control technology that are reviewed in this paper.
Simulated Flue Gas Feed on Coals for Attraction of Subcritical CO 2
2015
In recent years, attention has been drawn towards decreasing the effusion of anthropogenic carbon dioxide (CO2). CO2 sequestration is one approach used to reduce its concentration in the atmosphere. This is often the case in deep and inaccessible coal seams where underground storage techniques i.e., flue gas and CO2 injection under feeds of subcritical and supercritical settings are required. In a bid to reducing carbon footprints, subcritical CO2 affinity of two sample coal types (sample A-anthracite and sample Bbituminous) in South Africa was evaluated from adsorbates of flue gas and pure CO2. Volumetric approach using 35 ̊C and 5MPa was used to measure the attraction/adsorption isotherms of the flue gas and pure CO2 respectively. Measurements were carried out on 5g samples all passing the 2.36mm American standard sieve size while the flue gas was simulated from industrial coal fired plant having CO2 = 96.2%, O2 = 1.5% and N2 = 2.3% in a high pressure CO2 volumetric adsorption app...