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1.
《International Journal of Greenhouse Gas Control》2007,1(2):261-270
This paper summarizes the results of a first-of-its-kind holistic, integrated economic analysis of the potential role of carbon dioxide (CO2) capture and storage (CCS) technologies across the regional segments of the United States (U.S.) electric power sector, over the time frame 2005–2045, in response to two hypothetical emissions control policies analyzed against two potential energy supply futures that include updated and substantially higher projected prices for natural gas. This paper's detailed analysis is made possible by combining two specialized models developed at Battelle: the Battelle CO2-GIS to determine the regional capacity and cost of CO2 transport and geologic storage; and the Battelle Carbon Management Electricity Model, an electric system optimal capacity expansion and dispatch model, to examine the investment and operation of electric power technologies with CCS against the background of other options. A key feature of this paper's analysis is an attempt to explicitly model the inherent heterogeneities that exist in both the nation's current and future electricity generation infrastructure and in its candidate deep geologic CO2 storage formations. Overall, between 180 and 580 gigawatts (GW) of coal-fired integrated gasification combined cycle with CCS (IGCC + CCS) capacity is built by 2045 in these four scenarios, requiring between 12 and 41 gigatonnes of CO2 (GtCO2) storage in regional deep geologic reservoirs across the U.S. Nearly all of this CO2 is from new IGCC + CCS systems, which start to deploy after 2025. Relatively little IGCC + CCS capacity is built before that time, primarily under unique niche opportunities. For the most part, CO2 emissions prices will likely need to be sustained at over $20/tonne CO2 before CCS begins to deploy on a large scale within the electric power sector. Within these broad national trends, a highly nuanced picture of CCS deployment across the U.S. emerges. Across the four scenarios studied here, power plant builders and operators within some North American Electric Reliability Council (NERC) regions do not employ any CCS while other regions build more than 100 GW of CCS-enabled generation capacity. One region sees as much as 50% of its geologic CO2 storage reservoirs’ total theoretical capacity consumed by 2045, while most of the regions still have more than 90% of their potential storage capacity available to meet storage needs in the second half of the century and beyond. A detailed presentation of the results for power plant builds and operation in two key regions: ECAR in the Midwest and ERCOT in Texas, provides further insight into the diverse set of economic decisions that generate the national and aggregate regional results. 相似文献
2.
By analyzing how the largest CO2 emitting electricity-generating region in the United States, the East Central Area Reliability Coordination Agreement (ECAR), responds to hypothetical constraints on greenhouse gas emissions, the authors demonstrate that there is an enduring role for post-combustion CO2 capture technologies. The utilization of pulverized coal generation with carbon dioxide capture and storage (PC + CCS) technologies is particularly significant in a world where there is uncertainty about the future evolution of climate policy and in particular uncertainty about the rate at which the climate policy will become more stringent. The paper's analysis shows that within this one large, heavily coal-dominated electricity-generating region, as much as 20–40 GW of PC + CCS could be operating before the middle of this century. Depending upon the state of PC + CCS technology development and the evolution of future climate policy, the analysis shows that these CCS systems could be mated to either pre-existing PC units or PC units that are currently under construction, announced and planned units, as well as PC units that could continue to be built for a number of decades even in the face of a climate policy. In nearly all the cases analyzed here, these PC + CCS generation units are in addition to a much larger deployment of CCS-enabled coal-fueled integrated gasification combined cycle (IGCC) power plants. The analysis presented here shows that the combined deployment of PC + CCS and IGCC + CCS units within this one region of the U.S. could result in the potential capture and storage of between 3.2 and 4.9 Gt of CO2 before the middle of this century in the region's deep geologic storage formations. 相似文献
3.
K. Michael A. Golab V. Shulakova J. Ennis-King G. Allinson S. Sharma T. Aiken 《International Journal of Greenhouse Gas Control》2010,4(4):659-667
The experience from CO2 injection at pilot projects (Frio, Ketzin, Nagaoka, US Regional Partnerships) and existing commercial operations (Sleipner, Snøhvit, In Salah, acid-gas injection) demonstrates that CO2 geological storage in saline aquifers is technologically feasible. Monitoring and verification technologies have been tested and demonstrated to detect and track the CO2 plume in different subsurface geological environments. By the end of 2008, approximately 20 Mt of CO2 had been successfully injected into saline aquifers by existing operations. Currently, the highest injection rate and total storage volume for a single storage operation are approximately 1 Mt CO2/year and 25 Mt, respectively. If carbon capture and storage (CCS) is to be an effective option for decreasing greenhouse gas emissions, commercial-scale storage operations will require orders of magnitude larger storage capacity than accessed by the existing sites. As a result, new demonstration projects will need to develop and test injection strategies that consider multiple injection wells and the optimisation of the usage of storage space. To accelerate large-scale CCS deployment, demonstration projects should be selected that can be readily employed for commercial use; i.e. projects that fully integrate the capture, transport and storage processes at an industrial emissions source. 相似文献
4.
Kay Damen André Faaij Wim Turkenburg 《International Journal of Greenhouse Gas Control》2009,3(2):217-236
We sketch four possible pathways how carbon dioxide capture and storage (CCS) (r)evolution may occur in the Netherlands, after which the implications in terms of CO2 stored and avoided, costs and infrastructural requirements are quantified. CCS may play a significant role in decarbonising the Dutch energy and industrial sector, which currently emits nearly 100 Mt CO2/year. We found that 15 Mt CO2 could be avoided annually by 2020, provided some of the larger gas fields that become available the coming decade could be used for CO2 storage. Halfway this century, the mitigation potential of CCS in the power sector, industry and transport fuel production is estimated at maximally 80–110 Mt CO2/year, of which 60–80 Mt CO2/year may be avoided at costs between 15 and 40 €/t CO2, including transport and storage. Avoiding 30–60 Mt CO2/year by means of CCS is considered realistic given the storage potential represented by Dutch gas fields, although it requires planning to assure that domestic storage capacity could be used for CO2 storage. In an aggressive climate policy, avoiding another 50 Mt CO2/year may be possible provided that nearly all capture opportunities that occur are taken. Storing such large amounts of CO2 would only be possible if the Groningen gas field or large reservoirs in the British or Norwegian part of the North Sea will become available. 相似文献
5.
James J. Dooley Robert T. Dahowski Casie L. Davidson 《International Journal of Greenhouse Gas Control》2009,3(6):720-730
Desires to enhance the energy security of the United States have spurred renewed interest in the development of abundant domestic heavy hydrocarbon resources including oil shale and coal to produce unconventional liquid fuels to supplement conventional oil supplies. However, the production processes for these unconventional fossil fuels create large quantities of carbon dioxide (CO2) and this remains one of the key arguments against such development. Carbon dioxide capture and storage (CCS) technologies could reduce these emissions and preliminary analysis of regional CO2 storage capacity in locations where such facilities might be sited within the U.S. indicates that there appears to be sufficient storage capacity, primarily in deep saline formations, to accommodate the CO2 from these industries. Nevertheless, even assuming wide-scale availability of cost-effective CO2 capture and geologic storage resources, the emergence of a domestic U.S. oil shale or coal-to-liquids (CTL) industry would be responsible for significant increases in CO2 emissions to the atmosphere. The authors present modeling results of two future hypothetical climate policy scenarios that indicate that the oil shale production facilities required to produce 3 MMB/d from the Eocene Green River Formation of the western U.S. using an in situ retorting process would result in net emissions to the atmosphere of between 3000 and 7000 MtCO2, in addition to storing potentially 900–5000 MtCO2 in regional deep geologic formations via CCS in the period up to 2050. A similarly sized, but geographically more dispersed domestic CTL industry could result in 4000–5000 MtCO2 emitted to the atmosphere in addition to potentially 21,000–22,000 MtCO2 stored in regional deep geologic formations over the same period. While this analysis shows that there is likely adequate CO2 storage capacity in the regions where these technologies are likely to deploy, the reliance by these industries on large-scale CCS could result in an accelerated rate of utilization of the nation's CO2 storage resource, leaving less high-quality storage capacity for other carbon-producing industries including electric power generation. 相似文献
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8.
P. Luckow M.A. Wise J.J. Dooley S.H. Kim 《International Journal of Greenhouse Gas Control》2010,4(5):865-877
Large-scale, dedicated commercial biomass energy systems are a potentially large contributor to meeting global climate policy targets by the end of the century. We use an integrated assessment model of energy and agriculture systems to show that, given a climate policy in which terrestrial carbon is appropriately valued equally with carbon emitted from the energy system, biomass energy has the potential to be a major component of achieving these low concentration targets. A key aspect of the research presented here is that the costs of processing and transporting biomass energy at much larger scales than current experience are explicitly incorporated into the modeling. From the scenario results, 120–160 EJ/year of biomass energy is produced globally by midcentury and 200–250 EJ/year by the end of this century. In the first half of the century, much of this biomass is from agricultural and forest residues, but after 2050 dedicated cellulosic biomass crops become the majority source, along with growing utilization of waste-to-energy. The ability to draw on a diverse set of biomass-based feedstocks helps to reduce the pressure for drastic large-scale changes in land use and the attendant environmental, ecological, and economic consequences those changes would unleash. In terms of the conversion of bioenergy feedstocks into value added energy, this paper demonstrates that biomass is and will continue to be used to generate electricity as well as liquid transportation fuels. A particular focus of this paper is to show how climate policies and technology assumptions – especially the availability of carbon dioxide capture and storage (CCS) technologies – affect the decisions made about where the biomass is used in the energy system. The potential for net-negative electric sector emissions through the use of CCS with biomass feedstocks provides an attractive part of the solution for meeting stringent emissions constraints; we find that at carbon prices above $150/tCO2, over 90% of biomass in the energy system is used in combination with CCS. Despite the higher technology costs of CCS, it is a very important tool in controlling the cost of meeting a target, offsetting the venting of CO2 from sectors of the energy system that may be more expensive to mitigate, such as oil use in transportation. CCS is also used heavily with other fuels such as coal and natural gas, and by 2095 a total of 1530 GtCO2 has been stored in deep geologic reservoirs. The paper also discusses the role of cellulosic ethanol and Fischer–Tropsch biomass derived transportation fuels as two representative conversion processes and shows that both technologies may be important contributors to liquid fuels production, with unique costs and emissions characteristics. 相似文献
9.
《International Journal of Greenhouse Gas Control》2007,1(3):374-385
Methodology is presented for a first-order regional-scale estimation of CO2 storage capacity in coals under sub-critical conditions, which is subsequently applied to Cretaceous-Tertiary coal beds in Alberta, Canada. Regions suitable for CO2 storage have been defined on the basis of groundwater depth and CO2 phase at in situ conditions. The theoretical CO2 storage capacity was estimated on the basis of CO2 adsorption isotherms measured on coal samples, and it varies between ∼20 kt CO2/km2 and 1260 kt CO2/km2, for a total of approximately 20 Gt CO2. This represents the theoretical storage capacity limit that would be attained if there would be no other gases present in the coals or they would be 100% replaced by CO2, and if all the coals will be accessed by CO2. A recovery factor of less than 100% and a completion factor less than 50% reduce the theoretical storage capacity to an effective storage capacity of only 6.4 Gt CO2. Not all the effective CO2 storage capacity will be utilized because it is uneconomic to build the necessary infrastructure for areas with low storage capacity per unit surface. Assuming that the economic threshold to develop the necessary infrastructure is 200 kt CO2/km2, then the CO2 storage capacity in coal beds in Alberta is greatly reduced further to a practical capacity of only ∼800 Mt CO2. 相似文献
10.
Wenying Chen Yves-Michel Le Nindre Ruina Xu Delphine Allier Fei Teng Kim Domptail Xing Xiang Laura Guillon Jiyong Chen Lingyan Huang Rongshu Zeng 《International Journal of Greenhouse Gas Control》2010,4(2):341-350
A method, based on spatial analysis of the different criteria to be taken into consideration for building scenarios of CO2 capture and storage (CCS), has been developed and applied to real case studies in the Hebei province. Totally 88 point sources (42 from power sector, 9 from iron and steel, 18 from cement, 16 from ammonia, and 3 from oil refinery) are estimated and their total emission amounts to 231.7 MtCO2/year with power, iron and steel, cement, ammonia and oil refinery sharing 59.13%, 25.03%, 11.44%, 3.5%, and 0.91%, respectively. Storage opportunities can be found in Hebei province, characterised by a strong tectonic subsidence during the Tertiary, with several kilometres of accumulated clastic sediments. Carbon storage potential for 25 hydrocarbon fields selected from the Huabei complex is estimated as 215 MtCO2 with optimistic assumption that all recovered hydrocarbon could be replaced by an equivalent volume of CO2 at reservoir conditions. Storage potential for aquifers in the Miocene Guantao formation is estimated as 747 MtCO2 if closed aquifer assumed or 371 MtCO2 if open aquifer and single highly permeable horizon assumed. Due to poor knowledge on deep hydrogeology and to pressure increase in aquifer, injecting very high rates requested by the major CO2 sources (>10 MtCO2/year) is the main challenge, therefore piezometry and discharge must be carefully controlled. A source sink matching model using ArcGIS software is designed to find the least-cost pathway and to estimate transport route and cost accounting for the additional costs of pipeline construction due to landform and land use. Source sink matching results show that only 15–25% of the emissions estimated for the 88 sources can be sequestrated into the hydrocarbon fields and the aquifers if assuming sinks should be able to accommodate at least 15 years of the emissions of a given source. 相似文献
11.
Marjolein de Best-Waldhober Dancker Daamen André Faaij 《International Journal of Greenhouse Gas Control》2009,3(3):322-332
Two research methods were used in this study to analyze the awareness and perception of the Dutch general public regarding Carbon dioxide Capture and Storage (CCS). In an Information-Choice Questionnaire (ICQ), a representative sample of the Dutch public (n = 995) was provided with all information on attributes of six CCS options, which experts deemed necessary to come to well-considered and well-informed opinions. A traditional questionnaire was used simultaneously (n = 327) to study uninformed evaluations of these technologies. The results showed that the Dutch public is mostly unaware of CCS and has little knowledge about how current energy use causes global warming. Uninformed respondents are still inclined to give their opinion however, which results in unpredictive, easily changeable opinions. ICQ respondents who processed information on attributes of CCS options were likely to base their option evaluations on this information, though not entirely. All in all, the results of the ICQ suggest that, after processing information deemed necessary by experts, Dutch people reluctantly agree with large scale implementation of each of the six CCS options. 相似文献
12.
Suzanne J.T. Hangx Christopher J. Spiers 《International Journal of Greenhouse Gas Control》2009,3(6):757-767
Qualitative proposals to control atmospheric CO2 concentrations by spreading crushed olivine rock along the Earth's coastlines, thereby accelerating weathering reactions, are presently attracting considerable attention. This paper provides a critical evaluation of the concept, demonstrating quantitatively whether or not it can contribute significantly to CO2 sequestration. The feasibility of the concept depends on the rate of olivine dissolution, the sequestration capacity of the dominant reaction, and its CO2 footprint. Kinetics calculations show that offsetting 30% of worldwide 1990 CO2 emissions by beach weathering means distributing of 5.0 Gt of olivine per year. For mean seawater temperatures of 15–25 °C, olivine sand (300 μm grain size) takes 700–2100 years to reach the necessary steady state sequestration rate and is therefore of little practical value. To obtain useful, steady state CO2 uptake rates within 15–20 years requires grain sizes <10 μm. However, the preparation and movement of the required material poses major economic, infrastructural and public health questions. We conclude that coastal spreading of olivine is not a viable method of CO2 sequestration on the scale needed. The method certainly cannot replace CCS technologies as a means of controlling atmospheric CO2 concentrations. 相似文献
13.
A. Kranzmann T. Neddemeyer A.S. Ruhl D. Huenert D. Bettge G. Oder R. Saliwan Neumann 《International Journal of Greenhouse Gas Control》2011
Basic research on the corrosive effect of flue gases has been performed at the BAM Federal Institute for Materials Research and Testing (Germany). Conditions at both high and low temperatures were simulated in specially designed experiments. Carburization occured in flue gases with high CO2 content and temperatures higher than 500 °C. In SO2 containing flue gases sulphur was detected in the oxide scale. At lower temperatures no corrosion was observed when gases with low humidity were investigated. Humidity higher than 1500 ppm was corrosive and all steels with Cr contents lower than 12% revealed corroded surfaces. At low temperatures below 10 °C a mixture of sulphuric and nitric acid condensed on metal surfaces. Acid condensation caused severe corrosion. Humidity, CO2, O2, and SO2 contents are the important factors determining corrosion. Below 300 °C acid condensation is the primary reason for corrosion. Low humidity and low temperatures are conditions which can be expected in the CO2 separation and treatment process. This work includes major conditions of the flue gas and CO2 stream in CCS plants and CCS technology. 相似文献
14.
Takeshi Kuramochi André Faaij Andrea Ramírez Wim Turkenburg 《International Journal of Greenhouse Gas Control》2010,4(3):511-524
Industrial Combined Heat and Power plants (CHPs) are often operated at partial load conditions. If CO2 is captured from a CHP, additional energy requirements can be fully or partly met by increasing the load. Load increase improves plant efficiency and, consequently, part of the additional energy consumption would be offset. If this advantage is large enough, industrial CHPs may become an attractive option for CO2 capture and storage CCS. We therefore investigated the techno-economic performance of post-combustion CO2 capture from small-to-medium-scale (50–200 MWe maximum electrical capacity) industrial Natural Gas Combined Cycle- (NGCC-) CHPs in comparison with large-scale (400 MWe) NGCCs in the short term (2010) and the mid-term future (2020–2025). The analyzed system encompasses NGCC, CO2 capture, compression, and branch CO2 pipeline.The technical results showed that CO2 capture energy requirement for industrial NGCC-CHPs is significantly lower than that for 400 MWe NGCCs: up to 16% in the short term and up to 12% in the mid-term future. The economic results showed that at low heat-to-power ratio operations, CO2 capture from industrial NGCC-CHPs at 100 MWe in the short term (41–44 €/tCO2 avoided) and 200 MWe in the mid-term future (33–36 €/tCO2 avoided) may compete with 400 MWe NGCCs (46–50 €/tCO2 avoided short term, 30–35 €/tCO2 avoided mid-term). 相似文献
15.
As one of the three major carbon capture technologies associated with carbon capture and storage (CCS), oxy-fuel technology is currently undergoing rapid development with a number of international demonstration projects of scale 10–30 MWe having commenced and units with a scale of 250–300 MWe emerging in the progression towards commercialisation. Industrial scale testing of coal combustion and burners is also being conducted by technology vendors.The paper details the current international status of the technology; the contributions of current demonstrations; and a roadmap for commercial deployment.At its current state of maturity oxy-fuel technology may be considered semi-commercial, in that even if a unit was economically viable and could be provided by a vendor, the generator and vendor would need to share the technical risk. This is because guarantees could not at present be provided for operating characteristics associated with mature technologies such as reliability, emissions, ramp rate and spray control. This is due to the maturity of the technology associated with the capability of vendors and associated design and operational uncertainties, associated with a lack of plant experience at scale.The projected development of oxy-fuel technology for first-generation plant is provided, using an ASU for oxygen supply, standard furnace designs with externally recirculated flue gas, and limited thermal integration of the ASU and compression plant with the power plant. Potential features of second generation technology are listed.Listed issues delaying deployment indicate that market, economic, legal and issues of public acceptance are more significant than technical barriers. 相似文献
16.
M. Olivares-Marín T.C. Drage M. Mercedes Maroto-Valer 《International Journal of Greenhouse Gas Control》2010,4(4):623-629
In this work several Li4SiO4-based sorbents from fly ashes for CO2 capture at high temperatures have been developed. Three fly ash samples were collected and subjected to calcination at 950 °C in the presence of Li2CO3. Both pure Li4SiO4 and fly ash-based sorbents were characterised and tested for CO2 sorption at different temperatures between 400 and 650 °C and adding different amounts of K2CO3 (0–40 mol%). To examine the sorbents performance, multiple CO2 sorption/desorption cycles were carried out. The temperature and the presence of K2CO3 strongly affect the CO2 sorption capacity for the sorbents prepared from fly ashes. When the sorption temperature increases by up to 600 °C both the CO2 sorption capacity and the sorption rate increase significantly. Moreover when the amount of K2CO3 increases, the CO2 sorption capacity also increases. At optimal experimental conditions (600 °C and 40 mol% K2CO3), the maximum CO2 sorption capacity for the sorbent derived from fly ash was 107 mg CO2/g sorbent. The Li4SiO4-based sorbents can maintain its original capacity during 10 cycle processes and reach the plateau of maximum capture capacity in less than 15 min, while pure Li4SiO4 presents a continual upward tendency for the 15 min of the capture step and attains no equilibrium capacity. 相似文献
17.
Robert Dilmore Craig Griffith Zhu Liu Yee Soong Sheila W. Hedges Richard Koepsel Mohammad Ataai 《International Journal of Greenhouse Gas Control》2009,3(4):401-410
A novel CO2 separation concept is described wherein the enzyme carbonic anhydrase (CA) is used to increase the overall rate of CO2 absorption after which hydrated CO2 reacts with regenerable amine-bearing polyacrylamide buffering beads (PABB). Following saturation of the material's immobilized tertiary amines, CA-bearing carrier water is separated and recycled to the absorption stage while CO2-loaded material is thermally regenerated. Process application of this concept would involve operation of two or more columns in parallel with thermal regeneration with low-pressure steam taking place after the capacity of a column of amine-bearing polymeric material was exceeded. PABB CO2-bearing capacity was evaluated by thermogravimetric analysis (TGA) for beads of three acrylamido buffering monomer ingredient concentrations: 0 mol/kg bead, 0.857 mol/kg bead, and 2 mol/kg bead. TGA results demonstrate that CO2-bearing capacity increases with increasing PABB buffering concentration and that up to 78% of the theoretical CO2-bearing capacity was realized in prepared PABB samples (0.857 mol/kg recipe). The highest observed CO2-bearing capacity of PABB was 1.37 mol of CO2 per kg dry bead. TGA was also used to assess the regenerability of CO2-loaded PABB. Preliminary results suggest that CO2 is partially driven from PABB samples at temperatures as low as 55 °C, with complete regeneration occurring at 100 °C. Other physical characteristics of PABB are discussed. In addition, the effectiveness of bovine carbonic anhydrase for the catalysis of CO2 dissolution is evaluated. Potential benefits and drawbacks of the proposed process are discussed. 相似文献
18.
Bhawna Singh Anders H. Strømman Edgar Hertwich 《International Journal of Greenhouse Gas Control》2011,5(3):457-466
Hybrid life cycle assessment has been used to assess the environmental impacts of natural gas combined cycle (NGCC) electricity generation with carbon dioxide capture and storage (CCS). The CCS chain modeled in this study consists of carbon dioxide (CO2) capture from flue gas using monoethanolamine (MEA), pipeline transport and storage in a saline aquifer.Results show that the sequestration of 90% CO2 from the flue gas results in avoiding 70% of CO2 emissions to the atmosphere per kWh and reduces global warming potential (GWP) by 64%. Calculation of other environmental impacts shows the trade-offs: an increase of 43% in acidification, 35% in eutrophication, and 120–170% in various toxicity impacts. Given the assumptions employed in this analysis, emissions of MEA and formaldehyde during capture process and generation of reclaimer wastes contributes to various toxicity potentials and cause many-fold increase in the on-site direct freshwater ecotoxicity and terrestrial ecotoxicity impacts. NOx from fuel combustion is still the dominant contributor to most direct impacts, other than toxicity potentials and GWP. It is found that the direct emission of MEA contribute little to human toxicity (HT < 1%), however it makes 16% of terrestrial ecotoxicity impact. Hazardous reclaimer waste causes significant freshwater and marine ecotoxicity impacts. Most increases in impact are due to increased fuel requirements or increased investments and operating inputs.The reductions in GWP range from 58% to 68% for the worst-case to best-case CCS system. Acidification, eutrophication and toxicity potentials show an even large range of variation in the sensitivity analysis. Decreases in energy use and solvent degradation will significantly reduce the impact in all categories. 相似文献
19.
Andrew C. Mitchell Adrienne J. Phillips Randy Hiebert Robin Gerlach Lee H. Spangler Alfred B. Cunningham 《International Journal of Greenhouse Gas Control》2009,3(1):90-99
In order to develop subsurface CO2 storage as a viable engineered mechanism to reduce the emission of CO2 into the atmosphere, any potential leakage of injected supercritical CO2 (SC-CO2) from the deep subsurface to the atmosphere must be reduced. Here, we investigate the utility of biofilms, which are microorganism assemblages firmly attached to a surface, as a means of reducing the permeability of deep subsurface porous geological matrices under high pressure and in the presence of SC-CO2, using a unique high pressure (8.9 MPa), moderate temperature (32 °C) flow reactor containing 40 millidarcy Berea sandstone cores. The flow reactor containing the sandstone core was inoculated with the biofilm forming organism Shewanella fridgidimarina. Electron microscopy of the rock core revealed substantial biofilm growth and accumulation under high-pressure conditions in the rock pore space which caused >95% reduction in core permeability. Permeability increased only slightly in response to SC-CO2 challenges of up to 71 h and starvation for up to 363 h in length. Viable population assays of microorganisms in the effluent indicated survival of the cells following SC-CO2 challenges and starvation, although S. fridgidimarina was succeeded by Bacillus mojavensis and Citrobacter sp. which were native in the core. These observations suggest that engineered biofilm barriers may be used to enhance the geologic sequestration of atmospheric CO2. 相似文献
20.
Implementing geologic storage of CO2 at a material scale (ca. 1 Gt C/year) will require an industry comparable in size to the current oil and gas industry and a workforce trained in subsurface engineering. Since the same technologies that apply to hydrocarbon production apply to the subsurface storage of CO2, petroleum engineering (PE) graduates will be valuable candidates to work in the carbon storage industry. We expect however that the demand for PEs from the oil and gas industry will increase, and that already strained educational capacity will not be sufficient to supply both industries. Thus we advocate building new targeted educational infrastructure. We present a model curriculum based on an existing accredited multidisciplinary degree program. This program combines the fundamentals of petroleum engineering with the subsurface architecture emphasis of geology and the environmental perspective of hydrogeology. We indicate key elements of this program that could be integrated with other, more traditional undergraduate engineering majors that also deal with the subsurface. 相似文献