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• UCCS research, initiated in the 1990s, is following a sigmoidal growth pattern. • No highly active research group has been identified in UCCS research. • USA and China are currently leading countries in UCCS research. • More systematic studies are required to promote UCCS for real applications. • Findings can be used by stakeholders such as governments, among others. In this study, a scientometric comprehensive analysis has been executed in order to explore the scientific situation of research efforts performed previously with regard underground CO 2 sequestration and encapsulation. To this end, a total of 1280 bibliographic records from the Web of Science (WoS) database were extracted and analysed to report the analysis of scientific state of the authors, journals, countries, and categories. Eventually, geospatial maps of the progress in this field are created and presented. As per the results obtained, efforts on this subject have been initiated significantly since 1990s. Scientific articles and proceeding papers share nearly 63% and 31% of the documents published. The results indicate that USA and China are the most contributing countries. Among the active journals, international journal of greenhouse gas control impact is the most active journal. It may be concluded that no highly active research group has yet been emerged. Hence, more supports and scientific efforts are needed to promote carbon dioxide capture and storage technologies. [ABSTRACT FROM AUTHOR]

• The maximum possible CO 2 uptake by Portland cement during carbonation curing is determined. • Carbonation curing of cement-bonded fiberboards promotes CO 2 uptake to 85% efficiency. • The flexural strength by carbonation curing can reach 70 to 100% of ultimate strength within 24 h. • Carbonated fiberboards are more resistant to freeze-thaw cycling and wet-dry cycling. • Cement fiberboards can serve as CO 2 sink for carbon capture and storage. CO 2 sequestration in cement-bonded cellulose fiberboards through carbonation curing was studied. The maximum possible carbon dioxide uptake by ordinary Portland cement within a curing process was determined by a cement solution carbonation. It was 28.5% based on cement mass after 18 h initial hydration and 24 h carbonation. The best combination of material and process parameters in fiberboard carbonation had facilitated a curing process to allow 24.4% carbon uptake in 8 h carbonation and 20% carbon uptake in 0.5 h carbonation, a 70–85% reaction efficiency within 24 h. It was found that the CO 2 sequestration was dependent on the water content in fiberboards after preconditioning. An optimal water content was ranged from 40 to 60%. Carbonated fiberboards had shown a flexural strength at least 70% of ultimate strength within 24 h and a much improved freeze-thaw and wet-dry durability performance. If all cement-bonded cellulose fiberboards in United States adopt carbonation production, the annual CO 2 consumption by fiberboards can reach 0.36 Mt. [ABSTRACT FROM AUTHOR]

Abstract: Reservoir modeling is an important process for improving our understanding of processes during and after CO2 injection, and traditional rock and fluid characterization is the first step in building a static reservoir model. This model can be further refined by integrating dynamic data as they become available during the life of the project. Such data could improve the static model such that the field could be simulated and its future behavior predicted—especially CO2 plume size and amount of reservoir pressurization. Cranfield is an active CO2 flooding field with a focused research area in the water leg of the reservoir. One injection and two observation wells at a depth of >3000m with spacing <80m in this area are used to assess storage potential. Integrating various dynamic data into the initial static model provides a unique and challenging modeling opportunity. These data include well-test data, reservoir saturation tool (RST) measurements, pressure and temperature data both in and above the injection zone, U-tube samples from bottom-hole fluids, etc. Integration of all these data into a single numerical model helps to reduce the uncertainty of model parameters. [Copyright &y& Elsevier]

Abstract: The feasibility of carbon dioxide sequestration research at Cranfield, Mississippi is studied by injecting millions tonnes of CO2 into the lower Tuscaloosa sandstone Formation over a two year period. Time-lapse surface seismic surveys were recorded at pre-(2007) and post-(2010) injection stages to monitor the subsurface fluid plume. The injection interval, appearing as a thin layer in the well-log data, shows very weak signature of CO2 injection in the time-lapse seismic amplitude data. In order to improve the capability of tracking CO2 plume movement using seismic data, we have applied a basis pursuit inversion (BPI) method to the post-stack seismic datasets. This method of inversion incorporates a priori information as a wedge dictionary and employs a L 1-norm optimization for obtaining solutions with improved resolution. The inverted time-lapse acoustic impedances show a strongly decreasing trend mostly at the top of the injection interval, which is in agreement with well-log measurements for CO2 saturation. Improved resolution time-lapse impedance mapping therefore is an effective tool for imaging the displacement of the CO2 plume. [Copyright &y& Elsevier]

Diagenetic iron (oxyhydr)oxide minerals are common precipitates expected in CO2 reservoirs, and these minerals record fluid flow for application to carbon capture and sequestration ( CSS). Multiple mineralogy and spectroscopy analyses on a pore to meter scale characterize a well-exposed, lithologically controlled, iron (oxyhydr)oxides reaction front in the Jurassic Navajo Sandstone. Dolomite is the most prevalent cement (up to 23 area%), followed by only several percent or less of iron (oxyhydr)oxides, kaolinite, illite, and gypsum cements. Bulk geochemistry based on diagenetic mineralogies in the reaction front is compared with the water chemistry from nearby modern spring effluent emanating from the Navajo Sandstone to conclude that similar fluids (i.e., CO2-charged, saline waters containing hydrocarbons) are responsible for the precipitation. A second comparison of bulk geochemistry and diagenetic mineralogies of the reaction front with data from other abundant Navajo Sandstone concretions in the Spencer Flat region (in south central Utah) shows that reservoir fluids likely vary spatially and temporally in the porous and permeable Navajo Sandstone. CO2 injection into porous and permeable, quartz arenite, saline aquifers will likely result in minor clay and abundant dolomite precipitation that will significantly decrease porosity. [ABSTRACT FROM AUTHOR]

Abstract: In recent years, shales have attracted increased attention as a potential source of natural gas. In the U.S., recovery of natural gas from shales is expected to grow significantly in the coming years. Shale gas reservoirs may also offer the potential for CO2 sequestration. Since a large proportion of gas in shale reservoirs is in an adsorbed state, knowledge of gas adsorption behavior on shales is required for design of optimal gas recovery and sequestration processes. Only limited measurements have been reported in the literature for high-pressure gas adsorption on shales. In this work, adsorption isotherms of methane, nitrogen and CO2 were measured on a New Albany shale sample from the Illinois basin. As-received samples were used for measurements at 328.2K and pressures to 12.4MPa. At about 7MPa pressure, the excess adsorptions on New Albany shale for N2, CH4 and CO2 are in the ratio 1:3.2:9.3. This N2:CH4 ratio is similar to that for gas adsorption on coals and activated carbons, while the adsorption ratios of CO2:CH4 and CO2:N2 are much higher than those typically seen for coals. Further, the amounts adsorbed on this shale are 10 to 30 times lower than adsorption on coals of varying rank. The low levels of total organic carbon content (5.5%) and higher ash content of the shale (90%) play a role in reducing the gas adsorption capacity of the shale compared to coal. The newly acquired data yielded average experimental uncertainties of about 0.0095, 0.0081 and 0.024mmol/g for the methane, nitrogen and CO2 adsorption isotherms, respectively. At a pressure of about 7MPa, the excess adsorption of methane, nitrogen and CO2 are 0.0374, 0.0116 and 0.1085mmol/g, respectively. A simplified local-density (SLD) model was applied to describe the adsorption data of this study and was found to represent these data within the expected experimental uncertainties. Further, the model was applied to data for methane and CO2 on 34 shale samples reported in the literature. These data were represented with average absolute percentage deviations (%AAD) of about 4 and 9 for methane and CO2, respectively. In these predictions, the SLD model required one gas-specific parameter plus two adsorbent-specific parameters that are independent of the adsorbing gas species. [Copyright &y& Elsevier]

Abstract: Multi-phase reactive flow and transport modeling is an effective tool for monitoring, verification, and accounting of CO2 sequestration in deep geological formations. In the current study, modeling is performed to simulate large scale CO2 injection (a million tons per year for 100 years) into Mt. Simon sandstone, a major candidate saline reservoir in the Midwest of USA. The long term fate of CO2 was simulated by extending the modeling period to 10,000 years. The results indicate that most of the injected CO2 remains within a radius of 3300m lateral distribution. Four major trapping mechanisms and their spatial and temporal variations are evaluated in our simulations: hydrodynamic, solubility, residual, and mineral trapping. A strongly acidified zone (pH 3–5) forms in the areas affected by the injected CO2 (0–3300m), and consequently causes extensive mineral precipitation and dissolution. The predicted long-term fate of CO2 is closely linked to the geochemical reactions conceptualized in the models. In our model, the replenishing upstream water continues to dissolve CO2 long after the injection, which results in total dissolution of hydrodynamically trapped CO2 at the end of 10,000 years. In contrast, most previous models neglected the regional flow after injection and hence artificially limited the extent of geochemical reactions as if in a batch system. Consequently, a supercritical CO2 plume (hydrodynamic trapping) would persist after 10,000 years. The continued supply of acidified water from interaction between replenishing water and CO2 also results in extensive dissolution of feldspars and precipitation of secondary clay minerals, to a much more extent than what predicted in models without including regional flow. However, the prediction of complete dissolution of feldspars in 10,000 years can also result from the artifact that the linear rate laws are used in our model (as well as all previous work), which overestimates the rates of feldspar dissolution near equilibrium. Nevertheless, our simulations indicate the prolonged existence of an acidic brine plume, which suggests long-term risk assessment should transfer from the primary risk of CO2 leakage to secondary risk of acidic plume leakage after all CO2 is dissolved. [Copyright &y& Elsevier]

Abstract: Sustainability is a key principle in natural resource management, and it involves operational efficiency, minimisation of environmental impact and socio-economic considerations; all of which are interdependent. It has become increasingly obvious that continued reliance on fossil fuel energy resources is unsustainable, owing to both depleting world reserves and the green house gas emissions associated with their use. Therefore, there are vigorous research initiatives aimed at developing alternative renewable and potentially carbon neutral solid, liquid and gaseous biofuels as alternative energy resources. However, alternate energy resources akin to first generation biofuels derived from terrestrial crops such as sugarcane, sugar beet, maize and rapeseed place an enormous strain on world food markets, contribute to water shortages and precipitate the destruction of the world''s forests. Second generation biofuels derived from lignocellulosic agriculture and forest residues and from non-food crop feedstocks address some of the above problems; however there is concern over competing land use or required land use changes. Therefore, based on current knowledge and technology projections, third generation biofuels specifically derived from microalgae are considered to be a technically viable alternative energy resource that is devoid of the major drawbacks associated with first and second generation biofuels. Microalgae are photosynthetic microorganisms with simple growing requirements (light, sugars, CO2, N, P, and K) that can produce lipids, proteins and carbohydrates in large amounts over short periods of time. These products can be processed into both biofuels and valuable co-products. This study reviewed the technologies underpinning microalgae-to-biofuels systems, focusing on the biomass production, harvesting, conversion technologies, and the extraction of useful co-products. It also reviewed the synergistic coupling of microalgae propagation with carbon sequestration and wastewater treatment potential for mitigation of environmental impacts associated with energy conversion and utilisation. It was found that, whereas there are outstanding issues related to photosynthetic efficiencies and biomass output, microalgae-derived biofuels could progressively substitute a significant proportion of the fossil fuels required to meet the growing energy demand. [Copyright &y& Elsevier]

Abstract: The purpose of this research is to present a best-case paradigm for geologic CO2 storage: CO2 injection and sequestration in saline formations below oil reservoirs. This includes the saline-only section below the oil–water contact (OWC) in oil reservoirs, a storage target neglected in many current storage capacity assessments. This also includes saline aquifers (high porosity and permeability formations) immediately below oil-bearing formations. While this is a very specific injection target, we contend that most, if not all, oil-bearing basins in the US contain a great volume of such strata, and represent a rather large CO2 storage capacity option. We hypothesize that these are the best storage targets in those basins. The purpose of this research is to evaluate this hypothesis. We quantitatively compared CO2 behavior in oil reservoirs and brine formations by examining the thermophysical properties of CO2, CO2–brine, and CO2–oil in various pressure, temperature, and salinity conditions. In addition, we compared the distribution of gravity number (N), which characterizes a tendency towards buoyancy-driven CO2 migration, and mobility ratio (M), which characterizes the impeded CO2 migration, in oil reservoirs and brine formations. Our research suggests competing advantages and disadvantages of CO2 injection in oil reservoirs vs. brine formations: (1) CO2 solubility in oil is significantly greater than in brine (over 30 times); (2) the tendency of buoyancy-driven CO2 migration is smaller in oil reservoirs because density contrast between oil and CO2 is smaller than it between brine and oil (the approximate density contrast between CO2 and crude oil is ∼100kg/m3 and between CO2 and brine is ∼350kg/m3); (3) the increased density of oil and brine due to the CO2 dissolution is not significant (about 7–15kg/m3); (4) the viscosity reduction of oil due to CO2 dissolution is significant (from 5790 to 98mPas). We compared these competing properties and processes by performing numerical simulations. Results suggest that deep saline CO2 injection immediately below oil formations reduces buoyancy-driven CO2 migration and, at the same time, minimizes the amount of mobile CO2 compared to conventional deep saline CO2 injection (i.e., CO2 injection into brine formations not below oil-bearing strata). Finally, to investigate practical aspects and field applications of this injection paradigm, we characterized oil-bearing formations and their thickness (capacity) as a component of the Southwest Regional Partnership on Carbon Sequestration (SWP) field deployments. The field-testing program includes specific sites in Utah, New Mexico, Wyoming, and western Texas of the United States. [Copyright &y& Elsevier]

Abstract: Through work with the Department of Energy and Environmental Protection Agency, ICF has developed a costing model for geologic sequestration of CO2 by geologic setting in the U.S. The GeoCAT model is being used by the EPA Office of Air and Radiation to assist in analyzing the impact of potential climate change legislation. GeoCAT includes an assessment of sequestration capacity by state and geologic setting. Costing algorithms are based upon a detailed analysis of individual cost components, such as site characterization and injection well construction. The study shows that the cost of geologic sequestration without by-product credits (such as additional oil produced with enhanced oil recovery (EOR)) ranges from $2.84 to $28.12 per metric ton of CO2, depending on characteristics specific to the type of geologic formation. By-product impacts on costs for EOR, enhanced coalbed methane, and shale gas production are very significant. [Copyright &y& Elsevier]