Carbon Capture, Utilisation and Storage

Carbon Capture, Utilisation and Storage. CO2 Storage.

[Audio] The objective of this project is to investigate the feasibility of using a new method for capturing carbon dioxide from industrial sources. The goal is to design a system that can capture at least 90% of the CO2 emissions from power plants. This system would be based on a novel approach that utilizes a membrane separation technology to separate CO2 from other gases. The system would also include a post-processing unit to remove impurities and contaminants from the captured CO2. The overall objective is to reduce greenhouse gas emissions by at least 20% through the implementation of this system..

[Audio] The use of CO2 in industrial processes is becoming increasingly common. Many industries, including chemical manufacturing, steel production, and cement production, utilize CO2 as a raw material or byproduct. The primary goal of using CO2 in these processes is to reduce costs associated with traditional materials like limestone and silica. Additionally, many companies are seeking ways to minimize their carbon footprint. One way to achieve this is through the use of CO2 in industrial processes. By utilizing CO2, companies can reduce their reliance on fossil fuels and lower their greenhouse gas emissions. This approach can help mitigate climate change by reducing the amount of CO2 released into the atmosphere. Furthermore, the use of CO2 in industrial processes can lead to increased efficiency and productivity. For example, in the production of cement, CO2 is used to react with lime and silica to produce cement clinker. This process reduces the energy required for cement production and lowers the cost of production. Similarly, in chemical manufacturing, CO2 is used as a raw material to produce chemicals such as methanol and formic acid. These chemicals have numerous applications in various industries. Moreover, the use of CO2 in steel production can lead to significant reductions in greenhouse gas emissions. By using CO2 instead of fossil fuels, steel producers can lower their carbon footprint and contribute to a more sustainable future..

CO2 Storage in saline aquifers. Saline aquifers are widely distributed globally and offer more storage capacity than depleted oil and gas reservoirs. They are usually situated at appropriate distances from emission sources. Key factors for storing CO2 in saline formations include established formation pressure, adequate porosity, high permeability, and an impermeable caprock..

[Audio] The characteristics of depleted oil and gas reservoirs make them suitable for storing carbon dioxide. The seal created by impermeable caprock layers surrounding the reservoir prevents gas leakage into the environment. The geological structures within the reservoir allow for efficient flow and storage of CO2. The permeability and porosity of the reservoir enable the necessary movement and storage of CO2. These characteristics make depleted oil and gas reservoirs ideal locations for storing CO2..

[Audio] The process of mineral carbonation involves the reaction of CO2 with minerals in the rock to form stable carbonate minerals. These minerals can persist for millions of years, effectively trapping CO2 in the rock. The reaction occurs when CO2 reacts with calcium and magnesium ions present in the rock's minerals. The resulting stable carbonate minerals include calcite and aragonite. Mineral carbonation can be used to mitigate climate change by storing CO2 in the rock..

[Audio] CO2 trapping mechanisms involve three main types of trapping mechanisms: physical trapping, chemical trapping, and hydrodynamic trapping. Physical trapping occurs when CO2 is physically trapped in pore spaces or adsorbed onto mineral surfaces. This type of trapping prevents CO2 from moving further into the rock formations. Chemical trapping involves reactions between CO2 and minerals to form stable carbonate minerals. This process creates a solid barrier that prevents CO2 from migrating deeper into the earth's crust. Hydrodynamic trapping occurs when buoyant CO2 is trapped beneath impermeable layers or barriers. This mechanism relies on the density difference between CO2 and the surrounding rock to keep it in place. The three mechanisms work together to effectively trap and store CO2 underground..

Site/field selection for CO2 Storage. Assessing potential CO2 storage sites involves examining the geological, geomechanical, and fluid flow properties of formations. Geological - parameters such as structure depth, thickness, tightness, reservoir pressure, and porosity. Geomechanics – Include fracture pressure, cap rock integrity evaluation, pressure regime. Fluid flow – permeability and injectivity efficiency. Other factors - environmental, legal, and economic aspects..

[Audio] The capacity of depleted oil and gas reservoirs can be used to store carbon dioxide. This method relies on the principle that the volume of oil and gas produced is replaced by an equivalent volume of CO2. The volumetric-based CO2 storage estimate is calculated using the equation: M = A × H × ∅ × (1 - Swi) × B × ρstd × ER. Where: A = Area of the reservoir H = Height of the reservoir ∅ = Porosity of the reservoir Swi = Saturation water in the reservoir B = Formation volume factor ρstd = Density of the standard CO2 at STP ER = Reservoir storage efficiency factor. This equation calculates the maximum amount of CO2 that can be stored in a depleted oil and gas field. However, it's essential to note that this method has limitations, such as the need for precise calculations of reservoir properties and the potential for water injection, which can affect the storage capacity. To accurately estimate the CO2 storage capacity, it's crucial to consider factors like reservoir geometry, fluid properties, and geological constraints. Additionally, the choice of CO2 density and reservoir storage efficiency factor can significantly impact the results. By applying this equation and considering these factors, we can gain a better understanding of the potential for CO2 storage in depleted oil and gas reservoirs..

[Audio] The process of estimating CO2 storage capacity in saline aquifers requires careful evaluation of various factors including temperature, pressure, and rock properties. A suitable condition for storing CO2 in these formations is when the temperature and pressure conditions allow CO2 to exist in its supercritical or liquid state. This typically occurs at depths greater than or equal to 800 meters. The formation must also have a suitable caprock composed of low-permeability sealing rocks to prevent leakage. Moreover, the formation should possess hydrogeological conditions that enable CO2 to remain within the formation. These conditions are crucial for ensuring the long-term stability and effectiveness of CO2 storage in saline aquifers..

[Audio] The volumetric method uses a formula that combines several key parameters to estimate the amount of carbon dioxide stored in a reservoir. The formula multiplies these parameters together to calculate the total volume of CO2 stored. The parameters used are reservoir area, thickness, porosity, density of CO2 at reservoir conditions, and an efficiency factor. The formula is as follows: M = A x H x ∅ x ρres x Es, where M represents the volume of CO2 stored, A is the area of the reservoir, H is the thickness of the reservoir, ∅ is the porosity of the reservoir, ρres is the density of CO2 at reservoir conditions, and Es is the storage efficiency factor. The storage efficiency factor varies between 0.4-5.5%. The volumetric method provides a way to quantify the amount of CO2 stored in a reservoir, which can be useful for understanding the potential for carbon sequestration..

[Audio] The CO2 storage capacity estimation is based on various data sources including lithology, drill cuttings, cores, well logs, and formation properties such as porosity, thickness, saturation, depletion profile, and reservoir pressure. These data sources provide valuable information about the characteristics of the reservoir, which is essential for estimating the storage capacity of CO2. The data used in this estimation includes core analysis, well logs, drill cuttings, and well tests, which allow us to determine the porosity, thickness, and saturation of the reservoir. Additionally, the formation volume factor, PVT analysis, and reservoir boundary data are also considered to ensure accurate calculations. By combining these data sources, we can obtain a reliable estimate of the CO2 storage capacity. This approach allows us to account for the complexities of the reservoir and provides a more comprehensive understanding of the storage potential. Therefore, the use of multiple data sources is crucial in accurately estimating the CO2 storage capacity..

[Audio] The concept of facies categorization is crucial in understanding the characteristics of different rock units within a reservoir. In this context, we have four main facies categories: coarse sand, medium sand, fine sand, and shale. Each of these facies has a specific range of porosity values associated with it. For instance, coarse sand typically ranges from 29-33% porosity, while medium sand falls between 24-29%. On the other hand, fine sand exhibits a lower porosity range of 18-24%, and shale has the lowest porosity value among all the facies, ranging from 12-18%. These porosity ranges are critical in determining the storage capacity of CO2 in the reservoir. By understanding the distribution and characteristics of each facies, engineers can better assess the potential for CO2 sequestration and optimize the injection process. Furthermore, the geothermal gradient and formation pressure gradient provide essential information about the thermal and pressure conditions within the reservoir, which are vital for designing effective CO2 storage operations..

[Audio] The table provides information on the storage capacity of a specific type of sand used for carbon capture and utilization. The measurements include depth, thickness, area, density, porosity, storage efficiency factor, and CO2 volume. To calculate the storage capacity, we must multiply these values together. In this case, the example shows that the targeted sand can store up to 133 mega tons of injected CO2 at reservoir conditions. This value is calculated using the formula: M = A x H x ∅ x ρres x ES, where M is the storage capacity, A is the area, H is the height, ∅ is the porosity, ρres is the reservoir density, and ES is the storage efficiency factor. By plugging in the values from the table, we get M = 1.13E+09 x 47.38 x 0.28 x 0.02 x 0.02 = 133.11 MMt. Therefore, the storage capacity of this sand is approximately 133 mega tons..

[Audio] Injectivity refers to the ability of a formation to allow fluids to flow through it. In the context of CO2 storage, good injectivity is essential for injecting CO2 into the reservoir at a high rate without causing damage to the caprock. This means that the formation should be able to withstand the pressure of the injected CO2 without fracturing or deforming excessively. A higher injectivity allows for faster injection rates and reduces the risk of damage to the reservoir. On the other hand, low injectivity may lead to slower injection rates and increased risks of damage. Therefore, operators need to carefully evaluate the injectivity of the reservoir before injecting CO2. This evaluation includes assessing the permeability and porosity of the formation, as well as its mechanical strength and stability. By doing so, they can ensure that the CO2 is injected at a sustainable rate, minimizing the risks associated with CO2 storage..

[Audio] The factors affecting the injectivity of CO2 are numerous and complex. The injectivity of CO2 is determined by various parameters such as permeability, thickness of the formation, depth, porosity, fluid viscosity, pressure, temperature, and brine salinity. Permeability is a measure of how easily fluids can flow through the rock, while thickness of the formation and depth determine the volume of space available for the CO2 to flow through. Porosity is related to the amount of space available for the CO2 to occupy. Fluid viscosity affects the flow rate of the CO2 through the reservoir. Pressure and temperature influence the ability of the CO2 to flow through the reservoir. Brine salinity affects the relative permeability to brine and gas. Relative permeability to brine and gas determines the ability of the brine and gas to flow through the reservoir. Understanding these factors is essential for designing and implementing effective CO2 storage projects..

[Audio] The injectivity index of a CO2 well is a measure of how much CO2 a well can receive without fracturing the formation. This index is calculated as the ratio of the volumetric injection flow rate to the pressure drop. In other words, it represents the amount of CO2 that can be injected into a reservoir without causing damage to the surrounding rock. To calculate this index, we need to consider several factors, including the volumetric injection flow rate, the pressure drop, the CO2 density at reservoir conditions, the CO2 density at standard conditions, and the CO2 viscosity at reservoir conditions. These values are then used to determine the reservoir drainage area and the well radius. By understanding these parameters, operators can design and optimize their CO2 injection wells to achieve the desired level of injectivity while minimizing the risk of fracturing the formation. This is crucial for ensuring the safe and efficient storage of CO2 in geological formations..

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