Abstract

CO2 has the advantages of strong solubility, good viscosity reduction ability and low miscible pressure, which has a great potential in enhancing oil recovery (EOR). Shale has a high content of organic porous media and clay minerals, which is conducive to long-term adsorption and retention of CO2, and is one of the best CO2 storage environments. However, with the exploitation of hydraulic fracturing and CO2 huff-n-puff, the water cut of the reservoir is increasing, and the mechanism of oil, water, CO2 molecular interaction and fluid-rock molecular interaction in shale is still unclear. In previous studies, we developed a new nano-scale porous media model based on the lattice Boltzmann method (LBM). A CO2 huff-n-puff model including fracture and matrix (including macro poress, micro-pores (inorganic), nano-pores (organic) ) were designed. The multi-relaxation Shan-Chen model was used to simulate the diffusion and adsorption behavior of CO2 in the miscible state of shale. In this study, we additionally consider the water cut of different development stages of reservoir development to set the oil-water occurrence state in the matrix. Meanwhile, we comprehensively considered the effects of heterogeneous wettability caused by organic porous media and inorganic porous media in shale and the varying interfacial fluid viscosity of interfacial caused by adsorption on CO2 huff-n-puff. Through the simulation of oil-water phase separation in the matrix, we set up four oil-water occurrence states (water cut is 10 %,30 %, 50 % and 70 % respectively). Water molecules mainly aggregate in inorganic matter. By injecting CO2 into the fracture, the oil and gas density distribution and oil-water-gas three-phase distribution are analyzed. The results show that the adsorption quantity of CO2 is reduced due to the stronger adsorption capacity of water molecules on the surface of inorganic rock particles, and the quantity of CO2 entering the matrix in the fracture is reduced. The contact area between CO2 and crude oil decreases with the increase of water content, and the miscibility of oil and gas slows down. We also found that the increase of water content will promote oil recovery in inorganic matter. But it will also reduce the contact area of oil and CO2. When the water content is 0.5, the two effects are the weakest, and the oil recovery is the smallest. This paper provides theoretical guidance for the field application of CO2 huff-n-puff mining unconventional oil and gas resources and the field application of CO2 storage technology in different development stages.

Abstract

CO2 flooding can effectively improve the recovery factor of low permeability reservoir. However, problems such as strong heterogeneity and gas channeling in low permeability reservoir restrict the development of CO2 flooding.At present, the industrial application of CCUS in Jilin Oilfield is in the stage of large-scale promotion. It is of great significance to study the matching foam control technology suitable for low permeability reservoir with high temperature and acid resistance.In combination with the characteristics of Jilin oilfield oil reservoir, considering the strong penetrability of CO2 and its acidity when encountering water, the mechanism of action of single agent molecular characteristic groups and the evaluation of changes in micro bubble diameter and liquid film.It is clear that high temperature and CO2 medium is the key factors affecting the comprehensive performance of CO2 foam,make full use of the characteristics of strong foaming of long carbon chain, good foam stability of double bonds and inhibition of CO2 adsorption by multiple hydroxide groups to improve the high temperature resistance, CO2 resistance and comprehensive performance of foam,the indoor parallel core displacement experiment shows that on the basis of CO2 flooding, injecting the foam control slug can effectively improve the diversion rate of high and low permeability cores and further improve the displacement efficiency of low permeability cores.The field foam control test of CO2 flooding has played a good role in raising pressure, reducing gas and increasing oil. The gas injection pressure increased by 3.2MPa, gas production decreased by 57.3%, and the cumulative oil increased by 1355t.At present, foam channeling control technology is gradually popularized and applied in Jilin Oilfield, which is of great significance for CO2 flooding in low permeability reservoir to expand the wave reach volume and further improve the oil recovery.

Abstract

Hydraulic fracturing is an important means to develop tight reservoirs. However, many drawbacks have been exposed in the hydraulic fracturing process for a tight reservoir. For example, the clay minerals in the fractures are soaked and hydrated by fracturing fluid, which results in high pollution and poor transformation effect of the near-well area and seriously affects the flow capacity of reminding oil and the fracturing effect of tight reservoirs. This paper proposes a fracturing method that uses CO2 as the fracturing fluid to transform the seepage capacity and quickly supply energy for a tight reservoir. The EOR mechanism of CO2 fracturing has also been discussed by analyzing the physical properties change of CO2 in reservoir conditions. Three kinds of advantages can be shown in the fracturing process with CO2 fracturing fluid. Firstly, the fractures of CO2 fracturing are more complex than those caused by hydraulic fracturing, which greatly enhances the seepage capacity of a tight reservoir after CO2 fracturing. Secondly, a quick reservoir energy supply can be found in the process of CO2 injection, because of the high diffusion ability and good solubility of CO2 in oil of tight reservoir pores. Thirdly, as an inert gas, CO2 can reduce the influence of water sensitivity on reservoir rock, which can effectively resist the clay swelling pollution to oil production. The numerical simulation method of CO2 fracturing is used to optimize the supercritical CO2 fracturing parameters. According to the simulation results of CO2 fracturing, the optimized fracture half-length in the tight reservoir is 130 m, the fluid conductivity ability of a sand-filled fracture is 30 μm2·cm, the injection rate of CO2 fracturing fluid is 5.5 m3/min, and the energy storage time of a CO2 injection well is 7 days in the tight reservoir with permeability 0.35 mD. Compared with before fracturing, the actual CO2 fracturing wells in the study block also have an obvious oil increase effect, with a daily oil increase of 3.2 tons and a cumulative annual oil increase of 1650 tons.

Abstract

Either surface transportation line integrity monitoring or downhole injection well tubular and rock formation integrity monitoring plays a crucial part in a geological carbon dioxide (CO2) sequestration project, especially in providing early warnings of failure. Various monitoring technologies have been tested and applied in carbon sequestration projects world widely, whereas a lot of them are often low in spatial resolution and time-consuming, or expensive and have system longevity issues. The recent developed coaxial cable Fabry-Perot interferometer sensors have been put forward as a robust and cost-effective solution to carbon sequestration project monitoring strategies. Flexible RG58 coaxial cable is used in the fabrication of Fabry-Perot interferometer strain sensors. The strain sensors were loaded with progressive dynamic loads with the tensile testing machine in laboratory and the sensor measurement results were compared with the electronic extensometer. The sensor characteristics such as measuring range and dynamic response accuracy were analyzed for changing reflection point distance during manufacture, loading speed of the tensile testing machine, and pretensions applied to the sensor before testing. The results show that the coaxial cable Fabry-Perot interferometer strain sensors have steady performance under changing parameters as mentioned above, which means that the sensor accuracy remains invariable. The sensors have engineeringly accepted accuracy and almost real-time response to the dynamic loads applied during the test. And the sensors have large measuring range (up to 10,000 με) due to its excellent ductility. The research proves that the coaxial cable Fabry-Perot interferometer strain sensors can be as a feasible solution to carbon sequestration project monitoring strategies, and is of great value in providing early warnings of failure.

Abstract

Ocean carbon sequestration is a process of storing captured CO2 in the ocean, using liquid or solid forms of storage. Compared to liquid CO2 sequestration, dry ice ocean sequestration is simpler, more efficient, and has a larger capacity. However, research on the free-settling process of dry ice in ocean sequestration is still lacking, which limits the efficiency of dry ice ocean sequestration. In this study, the settling process of bullet-shaped dry ice is researched, and different models are established based on the main shape factors. The six-degree-of-freedom dynamic mesh is adopted to simulate the free settling of dry ice, and the mesh is kept near dry ice unchanged to ensure numerical simulation accuracy. The study shows that shapes with larger ellipticity of the front end have lower drag coefficients, and the shape factors mainly depend on ellipticity to influence the settling velocity. The correlation between Reynolds number and shape factors is obtained to predict the settling terminal velocity of bullet-shaped dry ice, providing a reference for the shape design of dry ice sequestration. This research provides theoretical support and practical guidance for efficient dry ice ocean sequestration.

Abstract

In the past, the attention of CO2 flooding is merely paid to the CO2 Enhanced Oil Recovery (CO2-EOR) of low permeability reservoirs. However, facing the worldwide warming impact caused by excessive CO2 emissions, improving the gas sequestration efficiency in a reservoir within the process of CO2 displacement is becoming the research hotspot. In this work, we investigated the oil production characteristics and gas sequestration law in the pores of reservoirs by conducting several CO2-induced experiments. The nuclear magnetic resonance (NMR) test is used to monitor the seepage law of oil and gas in the pores of core samples during CO2 flooding. The underlying mechanisms of improving oil recovery and CO2 storage efficiency in different water-cut reservoirs are also investigated through Scanning Electron Microscopy (SEM), X-ray diffraction (XRD), and wettability angle analyses. The experiment results show that the CO2 flooding and gas storage efficiency are mainly related to the factors of water-cut fw of reservoirs, CO2 flooding pressure, and the geophysical properties changes induced by the CO2-brine-oil-rock reaction. Compared with the amount of oil extraction in the oil-saturated rock samples by CO2 injection, much more formation oil can be produced, and laying more amount of CO2 to be stored under the reservoir with fw=50% by immiscible CO2 flooding with the mechanism of gas breakthrough prevention. The oil yield and CO2 storage efficiency in reservoirs can also be effectively enhanced by rising the CO2 flooding pressure and prolonging the contact time of CO2 with the formation brine and rocks. Compared with the reaction results of CO2-brine-oil-rock that occurred in the reservoir with only bound water, the reaction that occurred in the reservoirs with fw=50% is more intense, leading to more minerals dissolution, thus increasing the larger pore volume (PV) of rocks and making the rock surface more hydrophilic. Otherwise, the hydrophilic wettability modification of rocks can improve the CO2 displacement and gas storage effect within the reservoir due to the capillary resistance reduction in the process of CO2 flooding oil. The experimental evidence additionally indicates that CO2 flooding applied within the reservoir after a stage of water flooding is more suitable to boost the oil displacement and gas sequestration effect.

Abstract

In recent years, the screening criteria for an ultra-low permeability reservoir in the periphery of Daqing Oilfield are not detailed, which leads to the problem of inapplicability of CO2 flooding. In this paper, a new screening criterion suitable for CO2 flooding in this ultra-low permeability reservoir is established by using the ridge regression method. Six factors including effective thickness, oil saturation, formation temperature, formation pressure, average permeability and gas injection rate were selected based on the results of CMG numerical simulation, and a total of 30 groups of sensitive factor analysis data were carried out. Then, a ridge regression method for CO2 flooding was established by using the t-value test for the CO2 flooding potential of an extra-low permeability reservoir in the periphery of Daqing Oilfield. Finally, CMG numerical simulation is used to evaluate the effect of increasing oil production of potential well groups. The ridge regression results show that the oil recovery is sensitive with effective thickness, oil saturation, formation temperature, formation pressure, average permeability and gas injection rate, and their index weights are 0.37, 0.21, 0.15, 0.12, 0.09 and 0.06, respectively. Then, the critical t-value are calculated as 0.5 according to the weights, which means that a well group is potential if its t-value is above 0.5. According to the above screening criteria, a total of 25 well group in the block are evaluated, and 18 groups are screened as the potential for CO2 flooding, which accounts for 72% of the block. The CMG simulation results show that the screened well groups contribute an average oil production of 0.36×104 t per year, and the annual oil change ratio is more than 0.4, which represents an excellent CO2 flooding efficiency for this block. The innovation of this study is to use the ridge regression method to evaluate the influence factors on oil recovery of CO2 flooding, and the calculate results are unique using the regression model. And a screening criterion for CO2 flooding are then established for this extra-low permeability reservoir.

Abstract

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.

Abstract

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.

Abstract

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.