The composition of tuffaceous sandstone is complex, and it is easy to react with CO2, resulting in significant changes in wettability during CO2 flooding. However, the change mechanism for wettability is still unclear. Therefore, researches are carried out in laboratory to study the wettability change mechanism during CO2 flooding in a tuffaceous sandstone reservoir. A high temperature and high pressure reactor is used to establish a reaction environment of CO2-water-minerals, the maximum temperature is 65℃, and the maximum pressure is 20 MPa. The changes of wettability, mineral composition and mineral morphology of tuffaceous sandstone reservoir rock samples were measured by contact angle meter, EDS energy spectrometer and scanning electron microscope (SEM). The SEM results show that the mineral morphology changes significantly after CO2 contacted with the tuffaceous rock, from the original smooth and flat surface to a large corrosion pit on the surface. The contact angle increases by an average of 18.77° after CO2-water-mineral reactions, and the wettability changes from strong water-wet to neutral-wet. The mineral composition also changes significantly after CO2-water-mineral reactions, which is mainly manifested by the increase of Al content with a maximum increase of 142%, and the decrease of Si and K content with a maximum decrease of 32% and 54%, respectively. The change mechanism of wettability is mainly due to the transform of mineral potassium feldspar to kaolinite, and the temperature and pressure will further promote the growth of kaolinite. The innovation is to study the reaction of CO2, water and minerals for the tuffaceous reservoir, and the mechanism of wettability change are revealed by the CO2-water-mineral reactions. And the influence of wettability change on miscible CO2 flooding recovery are also studied in this paper.
With the rapid development of the global economy and the massive consumption of fossil energy, CO2 emissions are increasing year by year, leading to global warming and triggering a series of ecological and environmental problems. Carbon capture and storage (CCS) technology is one of the most promising CO2 emission reduction technologies. Subsurface storage of CO2 in deep saline aquifer has received much attention due to its potential huge storage volume and technical feasibility. The large-scale implementation of CO2 storage in saline aquifers is still confronted with complex reservoir structure, unclear spatial and temporal evolution of CO2, and difficult to predict spatial spreading, and there is an urgent need to clarify the carbon migration behavior and influencing factors in the reservoir. In this paper, a simulation study of CO2 storage in deep saline aquifer will be carried out in the Yaojia Formation of Sanzhao Depression in Songliao Basin. The 100-meter-deep sandstone stratum of the Yaojia Formation was selected for the study and divided into 10 lithologic layers, and the property parameters of each lithologic layer were assigned according to the actual situation. CO2 was injected at a rate of 10kg/s for a total simulation time of 250 years, including 10 years of injection, and the stationary observation is 240 years. The results show that the density of supercritical CO2 is slightly lower than that of water, and most of the CO2 will float upward and a small amount of CO2 will diffuse downward. After reaching the bottom of the cap layer, the CO2 plume will migrate laterally along the cap layer. At the beginning of injection, most of the CO2 will accumulate at the bottom of the cap, and a few will dissolve in the formation water. After injection stops, CO2 has a tendency to continue to accumulate and migrate laterally to the cap layer. Over time, convection phenomena favoring CO2 dissolution will occur.
Supercritical CO2 pipeline is the main way to transport carbon dioxide. However, due to the decompression wave characteristics of supercritical CO2, once the pipeline cracked, it will lead to the continuous propagation of cracks, which threatens the safety of pipeline operation. To study the crack propagation mechanism of supercritical CO2 pipeline, the instrumented impact test is carried out, and the parameters of Cohesive Zone Model are calibrated by inversion the test results. By comparing the trapezoidal traction separation law and linear traction separation law, it is found that the simulation results of the trapezoidal constitutive are in good agreement with the experimental results, and a more accurate material model of the crack propagation region is obtained. Based on the Cohesive Zone Model, the finite element model of crack propagation in supercritical CO2 pipeline is established to analyze the effects of pressure, wall thickness, pipe diameter on the crack propagation velocity. The results show that for supercritical CO2 pipeline, under the given gas composition, pressure and temperature conditions, with the increase of internal pressure, the decrease of wall thickness and the increase of pipe diameter, the crack arrest pressure of pipeline decreases. It is necessary to improve the crack arrest toughness of pipeline to ensure that the pipeline can achieve crack arrest within a limited length. The research results can provide a theoretical basis for crack propagation of supercritical CO2 pipeline and have practical engineering reference significance.
CO2 intrusion into the drilling fluid during bauxite drilling can cause hydration swelling and dispersion of clays and lead to massive foaming of them. Additionally, the formation develops micro-nano fractures, which also have a large difference in compressive strength and a high percentage of bound water. Once the foreign fluid invades, it will lead to wellbore destabilization and reservoir damage. Thus, the designed drilling fluid formulation does not contain solid phase particles such as bentonite. And we obtained the optimal proportion of hydrolocker, penetrant, and defoamer by Mixture Designs. Then the shielding plugging theory was introduced, and a temporary plugging gradation consisting of acid-soluble inert particles, deformable nano-sealers, and non-permeable sealers was constructed with the aid of BridgePro software. And other surfactants were optimized indoors to build a low-damage, strong anti-CO2 pollution water-based drilling fluid. It could resist the high temperature of 150℃ and has a remarkable ability to lower surface tension (17.3mN). The rolling recovery, the plugging rate, and permeability recovery value can reach more than 90%, the lubrication coefficient was around 0.125. The constructed drilling fluid completed 9 wells in field application, with an obvious reservoir protection effect and an average increase of more than 20% in single-well daily production compared to the expected daily production. It will be an important reference for future bauxite horizontal well drilling fluids to prevent CO2 contamination and reduce reservoir damage.
CO2 emission reduction has become the consensus of various industries in China. CO2 capture, utilization and storage, as an important means for CO2 emission reduction, is one of the necessary paths to achieve carbon neutrality. Combined with the CO2 emission of a chemical industry company in the region of East China, this paper introduces the recovery methods, processes and costs of different CO2 emission sources, and analyzes the CO2 emission reduction path for the company. Results showed that the process complexity and unit cost of CO2 capture decreased with the increase of concentration of CO2 emission sources, the carbon recovery cost per ton of high concentration CO2 emission source is only about 1/3 of that of low concentration CO2 emission source, which has significant economic benefits on the premise of downstream absorption pathway. Therefore, priority should be given to the recovery of high concentration CO2 emission sources. The carbon recovery economy of low concentration CO2 emission sources is poor, so priority should be given to using new energy to reduce their emissions, and coupling new energy technologies in the recovery process to reduce the recovery cost.
To clarify the driving mechanisms of carbon capture, utilization, and storage (CCUS), phase behaviors in bulk CO2-oil-brine system is inevitably foundational investigation. In this study, we conducted pressure-volume-temperature tests under single-variable control in laboratory with in-situ crude oil and synthetic brine samples. First, constant composition expansion tests were designed to examine saturation pressure between CO2 and oil phases with varied CO2 mole concentration and temperature, respectively. Meanwhile, as a major mechanism for carbon storage, CO2 solubility in brine and oil was then measured with changing pressures at a specific reservoir temperature. Growth of the saturation pressure was constantly detected with increasing CO2 mole concentration and temperature, respectively. With sufficient CO2 guaranteed during the tests, we found that CO2 solubility in tested liquids was strengthened by the pressure increase as expected. Moreover, within the same pressure range, incremental CO2 solubility in oil was about ten times larger than that in the brine, which indicated potentially underestimated CO2 storage capacity in depleted oil reservoirs.
Based on the cubic equation of state, the effect of impurities such as nitrogen, methane, hydrogen and oxygen on the characteristics of phase behavior of carbon dioxide (CO2) was discussed in this study. A prediction model of the phase characteristics of CO2 system containing impurities was established by correlating phase equilibrium and critical state prediction. Additionally, a mathematical model for the calculation of physical properties of the multi-component system was established. The changing rules of the physical properties including density, viscosity, Joule-Thomson coefficient, and specific heat capacity at constant pressure were analyzed. Based on the constructed prediction model, the analysis of phase properties and physical properties of impurity-containing CO2 streams under various transport conditions was carried out. The comparison of the prediction results with the experimental results shows that the prediction accuracy was improved under certain conditions, which provides a certain theoretical basis for the analysis of pipeline transmission chain in the CCUS engineering practice.
Whether the crack of CO2 transportation pipeline containing impurities can be stopped automatically after crack initiation depends on the comparison between the pressure decompression velocity and the fracture propagation velocity after crack initiation of CO2 pipeline. If the pressure decompression velocity is greater than the fracture propagation velocity, the crack can be stopped automatically, otherwise the crack propagation. The calculation of pressure decompression wave velocity is the key to the prediction and control of the crack arrest of pipeline. Based on the GERG-2008 equation of state, the prediction model of the pressure reduction wave velocity of the CO2 pipeline containing impurities is established. Based on a series of full-size blasting experimental data from Battelle Research Institute, the calculation model of the fracture propagation velocity of the pipeline is established, and it is verified by the shock tube experimental data. The pipeline crack propagation prediction and control software based on the Battelle Two-Curve Method for CO2 transportation was developed by using MATLAB to call the international authoritative database of the physical properties, fluid thermodynamics and transport properties of the working fluid Refprop. The prediction of the crack propagation of the CO2 pipeline containing impurities by the software can be completely verified by the results of the shock tube discharge experiment in the literature, By using this software, the minimum fracture toughness (CVN) and critical wall thickness required for crack arrest can be obtained by matching the pressure decompression wave velocity prediction curve with the pipeline fracture propagation velocity curve, which provides a reference basis for the selection of pipes and the design of pipeline wall thickness.