4D seismic monitoring of the onshore carbon dioxide injection in Japan

To mitigate the global climate change due to excess carbon dioxide emission, geologic sequestration by carbon dioxide injection in the subsurface has been proposed. To monitor and verify the long-term safe storage in the subsurface, 4D or time-lapse 3D seismic technology is the most effective to spatially and efficiently detect the change of fluid saturation and pore pressure in the target aquifer and others. In RITE/METI Nagaoka carbon dioxide injection test field, 4D seismic survey was conducted to monitor injected carbon dioxide as a collaborative research of Japex and RITE/METI. It was the first 4D seismic survey for onshore aquifer injection monitoring in the world.Target reservoir in saline aquifer is at approximately 1100m deep. Carbon dioxide saturation was observed with approximately 6m thick by logging survey. To estimate the saturation zone by 3D seismic surveys, I had to overcome the problems of data acquisition and processing, i.e., 1) irregular 3D geometry in the land 3D seismic surveys, and 2) to enhance data resolution to meet the thinner target reservoir.In order to detect and highlight 4D anomaly zones, for relatively high noise content data, it is inadequate to simply subtract baseline and monitor seismic data as there are no ways to discriminate the noises from geological changes by this volume alone. It turns out that 4D anomaly detectability is improved if supervised pattern recognition technology is implemented in the multi-attributes approach. Estimated anomaly pattern is consistent with the observation of time-lapse wireline data and total amount of injected carbon dioxide incorporated with probability of distribution. It has improved the results of visual inspection of simple math difference of 3D seismic volume.3D data were evaluated using well synthetics data and impedance inversion data to estimate several physical parameters such as porosity and permeability combined with the wireline data and geological constraints. Estimated high permeability zone by baseline data prior to the repeat survey showed a correlation with the detected 4D anomalies.The first onshore 4D seismic monitoring of the injected carbon dioxide in aquifer was successfully conducted, though there were difficulties caused by the irregular 3D geometry and thinner target reservoir. It provides the prototype approach to the similar onshore carbon dioxide monitoring.

Summary Geologic sequestration by carbon dioxide injection into saline aquifers and others is one of the promising options to mitigate global climate changes. Elastic parameters are fundamental in estimating rock properties, fluid saturation and pore pressure in carbon dioxide injection and 4D seismic survey efficiently provides spatial and temporal changes of elastic parameters as well as baseline parameters. 4D seismic survey data, collaboratively acquired by Japex in 2003 and 2005 on the area of onshore RITE/METI carbon dioxide injection test site in Japan, were analysed incorporated with repeated time-lapse logging data matched in scale by the current method. In this study, 1) newly built the most probable full-scale baseline and monitor elastic wave velocity model of the 4D seismic survey in the depth domain using time scale adjusted and calibrated 4D AI cube in the time domain and 2) examined the feasibility of nonlinear elastic wavefield inversion of synthetic 4D seismic data assuming regular 3D geometry, though the original 3D was covered by irregular geometry, with common smoothest quasi-linear initial macro-velocity model for baseline and monitor surveys. Results of non-linear elastic wavefield inversion (FWI) with frequency-cascade scheme successfully showed estimates of 4D elastic wave velocity changes at excellent quality and accuracy.

Integrated assessment model simulations are often cited when recommending  carbon capture and storage (CCS) as an important component of decarbonization for the power industry. Here, we use a simplified setting to analyze the economic sensitivity of post-combustion fossil-fuel CCS to a set of parameters including fuel costs, electricity prices, and subsidies. We formulate the model to represent coal and natural gas power plants fitted with CCS. We then ask what level of subsidies are necessary to make CCS profitable for the operator. Our results indicate that: (1) With current US subsidies and under most market conditions, CCS is much more profitable when injected carbon dioxide is used for enhanced oil recovery than for geologic storage. For this reason, CCS is likely to continue to be used for enhanced oil recovery and so will increase system-wide emissions because the combustion of the oil produced emits more carbon dioxide than is injected to produce the oil. (2) CCS subsidies can drop the marginal cost of electricity generation to near zero, making CCS fossil fuel electricity competitive with renewables in the power market, even as these power plants continue to emit a portion of their carbon dioxide. (3) With CCS subsidies, coal-fired power production can become more profitable than natural gas power because coal produces more carbon dioxide and hence harvests more subsidies. To be profitable, natural gas power plants require higher tax subsidies than coal, and their cash flow is more sensitive to changes in the price of power, which disadvantages natural gas plants when coupled to CCS. (4) In the US, subsidies are provided per ton of carbon dioxide stored rather than per ton of carbon dioxide kept out of the atmosphere. Our calculations demonstrate how the effective subsidy per ton of emissions avoided is more than the subsidy paid per ton of carbon dioxide captured unless the grid is completely decarbonized, because of the energy penalty of CCS. (5) The value of natural gas CCS for reducing emissions diminishes as the carbon intensity of the local power grid increases. We recommend that these insights be used in integrated assessment models such that these models more accurately represent the influence of market dynamics and provide better insights for reducing emissions. 

The principal mechanisms for the geologic sequestration of carbon dioxide in deep saline formations include geological structural trapping, hydrological entrapment of nonwetting fluids, aqueous phase dissolution and ionization, and geochemical sorption and mineralization. In sedimentary saline formations the dominant mechanisms are structural and dissolution trapping, with moderate to weak contributions from hydrological and geochemical trapping; where, hydrological trapping occurs during the imbibition of aqueous solution into pore spaces occupied by gaseous carbon dioxide, and geochemical trapping is controlled by generally slow reaction kinetics. In addition to being globally abundant and vast, deep basaltic lava formations offer mineralization kinetics that make geochemical trapping a dominate mechanism for trapping carbon dioxide in these formations. For several decades the United States Department of Energy has been investigating Columbia River basalt in the Pacific Northwest as part of its environmental programs and options for natural gas storage. Recently this nonpotable and extensively characterized basalt formation is being reconsidered as a potential reservoir for geologic sequestration of carbon dioxide. The reservoir has an estimated storage capacity of 100 giga tonnes of carbon dioxide and comprises layered basalt flows with sublayering that generally alternates between low permeability massive and high permeability breccia. Chemical analysis of themore » formation shows 10 wt% Fe, primarily in the +2 valence. The mineralization reaction that makes basalt formations attractive for carbon dioxide sequestration is that of calcium, magnesium, and iron silicates reacting with dissolved carbon dioxide, producing carbonate minerals and amorphous quartz. Preliminary estimates of the kinetics of the silicate-to-carbonate reactions have been determined experimentally and this research is continuing to determine effects of temperature, pressure, rock composition and mineral assemblages on the reaction rates. This study numerically investigates the injection, migration and sequestration of supercritical carbon dioxide in deep Columbia River basalt formations using the multifluid subsurface flow and reactive transport simulator STOMP-CO2 with its ECKEChem module. Simulations are executed on high resolution multiple stochastic realizations of the layered basalt systems and demonstrate the migration behavior through layered basalt formations and the mineralization of dissolved carbon dioxide. Reported results include images of the migration behavior, distribution of carbonate formation, quantities of injected and sequestered carbon dioxide, and percentages of the carbon dioxide sequestered by different mechanisms over time.« less

The emission of carbon dioxide into the atmosphere, which is one of the causes of the greenhouse effect, could be reduced by the removal of carbon dioxide from stack gases of power plants and subsequent injection of the removed carbon dioxide in depleted gas reservoirs. In The Netherlands there are some 220 gas reservoirs of which 90 are in production. The largest field, Groningen, with initial gas reserves of some 2,500 mrd m3 has a potential for carbon dioxide storage of 8 × 109 ton. The field cannot play an immediate role in the combat against the greenhouse effect, since its presently estimated depletion date is around the middle of the next century. Other Dutch onshore fields have a storage potential of 1.3 × 109 ton of carbon dioxide divided over about 100 reservoirs. These fields will gradually become available starting from about 2000 onwards. The cost of transport and injection of carbon dioxide in onshore reservoirs is estimated at Dfl 7,50/ton of carbon dioxide.

Carbon dioxide (CO2) injection is currently used as a tertiary recovery method in the Permian San Andres Formation, Central Vacuum Unit, Lea County, New Mexico. Multicomponent, 3D seismic surveys were conducted prior to and 8 months after carbon dioxide injection in an attempt to monitor the fluid front. Poststack cross-equalization techniques were applied to the time-lapse data volumes to enhance the interpretability of the compressional and shear wave velocity and amplitudes, and their variation over time. Fluid porperties for a carbonate rock invaded by CO2 displacing oil suggest a complex interplay between density and compressibility of the mix which is mostly governed by pressure conditions. Time-lapse, crossequalized images also reveal a complex behaviour of the rock-fluid interaction with areas of decrease in shear wave velocities surrounding high fluid pressure, CO2 injectors, and areas of S2 velocity increase surrounding low fluid pressure producer wells. This result, validated by time-lapse amplitude anomalies, has important consequences for shear waves in the detection of fluid changes associated with CO2 flooding.

Numerical simulation and optimization of CO2-enhanced water recovery by employing a genetic algorithm

Analytical study of CO2–CH4 exchange in hydrate at high rates of carbon dioxide injection into a reservoir saturated with methane hydrate and gaseous methane

Economic Feasibility of Carbon Sequestration with Enhanced Gas Recovery (CSEGR)

Carbon dioxide injection will induce fracture network. Carbon dioxide will reach a supercritical state under tight reservoir temperatures and pressures. During prolonged carbon dioxide injection, fracture network will extend directionally or even connect to production wells causing gas breakthroughs. Numerical simulations demonstrate that the induced fracture network will affect carbon dioxide utilization and reduce carbon dioxide storage efficiency. Therefore, the identification and efficient utilization of dynamic induced fracture network is necessary. Carbon dioxide injection will induce fracture network. Carbon dioxide will reach a supercritical state under tight reservoir temperatures and pressures. During prolonged carbon dioxide injection, fracture network will extend directionally or even connect to production wells causing gas breakthroughs. Numerical simulations demonstrate that the induced fracture network will affect carbon dioxide utilization and reduce carbon dioxide storage efficiency. Therefore, the identification and efficient utilization of dynamic induced fracture network is necessary. Results demonstrate that tri-radial flow with micro-stepped characteristic, fracture storage with V-shape characteristic, and dynamic fracture network flow with peak-shape characteristic regimes are shown in type curve. Innovation parameters—fracture inter-porosity flow coefficient (ω), dynamic fracture network conductivity (Fdf), and dynamic fracture network radius (rdf) are introduced the DIFN model. Numerical simulations verified the accuracy of the DIFN model. Multi-temporal field cases from the same well are matched by the DIFN model. The physical processes of dynamic induced fracture network expansion are characterized. It is worth noting that the innovative parameters can be used to calculate carbon dioxide fracture storage volume. By coupling the injection parameters, the carbon dioxide physical properties parameters, and the fracture storage volume we will obtain the tight reservoir carbon dioxide storage volume to monitor carbon dioxide storage efficiency in real time. In conclusion, different from the conventional view the supercritical carbon dioxide induced dynamic fracture network will form a circular zone in the near-well area. The dynamic induced fracture network will extend in the maximum principal stress direction to form an elliptical area. The identification of dynamic induced fracture network characteristics helps guide researchers to set reasonable injection parameters and assess carbon dioxide storage efficiency. The supercritical carbon dioxide induced dynamic fracture network is identified and its physical processes can be described by matching multi-temporal field cases using the DIFN model. The innovative flow regimes demonstrate the directional extension and closure of the fracture network preventing them from being identified as incorrect data. Innovative parameters are used to characterize the induced dynamic fracture network and to calculate the carbon dioxide storage volume and storage efficiency.

Fundamental Tests on Carbon Dioxide Sequestration Into Coal Seams

To prevent recovered carbon dioxide from entering the atmosphere, it must be disposed of or stored. In this chapter the global potential for storing carbon dioxide underground is discussed together with the associated costs. Special attention is given to the injection of carbon dioxide into former hydrocarbon reservoirs and in aquifers.The potential storage capacity in hydrocarbon reservoirs is calculated on the assumption that all the space left after extraction of the natural gas or oil can be used for carbon dioxide storage. The density of the stored carbon dioxide depends on the depth of the reservoir and local geothermal and pressure gradients. The potential storage capacity in natural gas fields is estimated at 600 to 1500 Gtonnes carbon dioxide and in oil fields at 200 to 400 Gtonnes carbon dioxide.The potential storage capacity in aquifers is calculated on the assumption that injected carbon dioxide replaces water. The capacity will also depend on whether a structural trap is required or not. If a structural trap is required the storage capacity in aquifers is about 200 Gtonne of carbon dioxide. If a structural trap is not required the storage potential might be up to several tens of thousands.The carbon dioxide to be stored must be injected into an underground reservoir through a well. The maximum flow rate that can be applied at the well depends on the permeability of the matrix, the thickness of the reservoir, and the maximum permissible overpressure in the reservoir. It is calculated that the flow rate may vary from 2 to 20 of mN 3 carbon dioxide per second (340–3400 tonnes per day).The pressure at the well-bottom is roughly the sum of the well-head pressure and the pressure caused by the weight of the carbon dioxide column. At regular hydrostatic pressure gradients, it will often not be necessary to compress the carbon dioxide to higher pressures than the transport pressure, which is assumed to be 8000 kPa.The costs of carbon dioxide storage depend on the depth, the size and location of the reservoir and the flow rate at the well. Storage costs in onshore aquifers are calculated to be typically between 2 and 8 US$ per tonne of carbon dioxide. In a large onshore natural gas field the storage costs will be 0.5 to 3 US$ per tonne of carbon dioxide. Storage costs for offshore reservoirs are typically 50% higher. If additional compression is required at the well-head the costs are increased by up to 0.5 US$ per tonne carbon dioxide stored.

Carbon dioxide in the atmosphere causes global warming as a greenhouse gas. Therefore, countries around the world are considering underground storage to reduce carbon dioxide. Carbon dioxide underground storage means injection before waste gas filed, oil field, deep saline aquifer and so on. The temperature and pressure conditions of carbon dioxide for underground storage are supercritical, and a reduction in injection efficiency is expected due to high capillary pressure during injection. In this study, considering the high capillary pressure, utilizing anionic surfactants (SDS, SDBS). Thus, the enhancement of carbon dioxide efficiency with surfactant type and concentration was evaluated. In addition, quantitative injection characteristics according to the injection rate of carbon dioxide were analyzed using a micro model.Experimental results look like follow. Surfactant exhibits higher injection efficiency than water at low carbon dioxide injection rates, and the difference in injection efficiency between water and surfactant decreases as the injection rate increases. However, the differences between the types of surfactants (SDS, SDBS) and concentrations used in this study are relatively modest.To solve the experimental technology limitations in field use, the pore network model is used. The pore network model has the advantage of effective prediction of carbon dioxide injection efficiency in the future. To validate the Pore network model, constructed network is like the micromodel. As a result, the analysis derived the same tendency as the experiment. In the future expected, the pore network model developed in this study will be able to predict carbon dioxide injection.

Due to the unique corrosion potential and safety hazards of carbon dioxide (CO), tubing leakage of CO in a CO injection well may occur and lead to undesired consequences to environment, human being and facility. As a result, quick detection of any carbon dioxide leakage and accurate identification of leakage location are extremely beneficial to obtain critical information to fix the leakage in a prompt manner, prevent incidents / injury / casualty, and achieve high standards of operational safety. Annular pressure monitoring has been identified as an effective and reliable approach for detecting tubing and casing leakage of fluids (including hazardous gas like CO) in a well. Accurate prediction of annular pressure change associated with the leakage will certainly help the operation. In an effort to assess annular pressure characteristics and thus improve understanding of tubing leakage, a multiphase dynamic modeling approach has been applied to simulate the carbon dioxide, completion brine and formation water’s flow and associated heat transfer processes along wellbore, tubing and annulus in carbon dioxide injection wells designed for carbon capture and sequestration (CCS) [1] projects. Two operational scenarios – one for routine CO injection and another for well shut-in – have been considered in the investigation. Key parameters that may have significant impacts on the process have been investigated. On the basis of the investigation, a novel approach has been proposed in the paper for quickly detecting the leakage of carbon dioxide in a CO injection well. Two simple equations have been developed to pinpoint the leakage location by means of real-time measurement and monitoring of the change in annular pressure. Recommendations based on a series of dynamic simulation results have been provided and can be readily incorporated into detailed operating procedures to enhance carbon dioxide injection wells’ operational safety.

To reduce the emission of carbon dioxide from a conventional coal-fired power plant, carbon dioxide can be separated from the flue gases by using polymer membranes. In this chapter a theoretical investigation into the technological and economic outlook of this option is described.At present the best types of membranes available for separating carbon dioxide from nitrogen are non-porous polymer membranes based on polyimide, polydimethylphenyleneoxide, polydimethylsiloxane and cellulose acetate. The carbon dioxide can be recovered by applying a single membrane stage configuration. The disadvantage of such a configuration is that it leads to a carbon dioxide gas that is highly diluted with nitrogen. This is an unwanted situation because the carbon dioxide is a liquid in the conditions (8000 kPa and 10°C) under which it will be transported, whereas nitrogen remains gaseous under these conditions. Moreover, the transport facilities and storage capacity for carbon dioxide will not be utilized optimally.Three methods for purifying the carbon dioxide are considered. In the first method the carbon dioxide product gas is purified by feeding it to a second membrane unit. This configuration is called the two-stage cascade. The second method makes use of the different phases of nitrogen and carbon dioxide at high pressures. In this method the carbon dioxide product gas is compressed to 8000 kPa and cooled down to 25°C. Subsequently the nitrogen, contaminated with some carbon dioxide vapour, is separated from the condensed carbon dioxide. This nitrogen off-gas is released to the atmosphere. The third method is similar to the second one, except that the nitrogen off-gas is recycled back to the membrane unit.With a computer program based on a cross-flow permeation model for polymer membranes, the recovery design is optimized to obtain the lowest recovery costs per tonne carbon dioxide avoided.For the membranes examined, a lowest cost figure of 51 US$ per tonne carbon dioxide avoided is calculated. This figure is found for a polyimide-based membrane in a single membrane stage configuration combined with separation of the carbon dioxide by compression and venting the nitrogen off-gas. In this set-up 75% of the carbon dioxide is recovered and the carbon dioxide is nearly pure. For a 90% recovery either the two-stage cascade or the single membrane stage with recycling of the nitrogen off-gas are attractive routes, leading to recovery costs of about 65 US$ per tonne carbon dioxide avoided. Recovery with polymer membranes is calculated to be 50 to 100% more expensive than recovery using cold distillation or a chemical absorption technique. Although some cost reductions are feasible, membrane separation is not expected to become a competing option for carbon dioxide recovery from flue gases of conventional coal-fired power plants in the near future.KeywordsInvestment CostPolymer MembraneRecovery CostMembrane UnitIsentropic EfficiencyThese keywords were added by machine and not by the authors. This process is experimental and the keywords may be updated as the learning algorithm improves.