Review of CO2 storage efficiency in deep saline aquifers

A comparison of volumetric and dynamic CO2 storage resource and efficiency in deep saline formations

Effects of impurities N2 and O2 on CO2 storage efficiency and costs in deep saline aquifers

Deep Saline Formations (DSFs) are increasingly recognized for their significant role in geological carbon dioxide (CO2) storage, a crucial part of Carbon Capture and Storage (CCS) strategies aimed at mitigating climate change. Nevertheless, formation overpressure, capillary breakthrough pressure, and injectivity impairment often compromise the actual CO2 Storage Efficiency (CSE) in these formations, potentially reducing storage efficiency by up to 22%. However, comprehensive knowledge of Pore Space Utilization (PSU) in CO2 storage in deep saline formation must be improved to address this inefficiency. This study presents a first-of-its-kind work combining a comprehensive review with a proposed innovative concept on the viability and effectiveness of the Simultaneous or Alternate Aquifer Injection (SAI) method to enhance CO2 storage within DSFs. Further, a conceptual future direction for optimizing CO2 storage in deep saline formations was proposed. We introduced the Simultaneous or Alternate Aquifer Injection (SAI) as a useful approach to optimizing PSU and CSE in DSFs. This method is similar in principle to Water Alternating Gas (WAG) used in CO2-EOR. While there is a lack of data on the SAI process, WAG data shows that incremental CO2 is stored in a reservoir when water is introduced in a CO2-EOR, thereby increasing the oil recovery and CO2 storage. This incremental ranges from 3–100% CO2 stored in a formation. The SAI method can enhance CSE by approximately 25% on average compared to traditional injection methods when using this as an analog. Our study further highlights the complexities of the SAI method and its potential to enhance storage efficiency and capacity, which is crucial for large-scale CCS implementation. We compared various trapping mechanisms, their impacts on CSE, and how they can be potentially augmented through the SAI to increase PSU in saline aquifers to mitigate climate change. The SAI method, involving simultaneous or alternate injection of CO2 and brine, may yield a novel approach to managing the movement of the CO2 plume in the aquifer reservoir, thereby maximizing storage efficiency and minimizing leakage risks. While our review of the SAI method shows promise, it still poses technical, regulatory, and economic challenges. Our review findings emphasize the need for more integrated dynamic modeling, numerical simulations, and sensitivity analyses for successful implementation. With adequate experimental and simulation support, the SAI approach has the potential to revolutionize CO2 storage operations in DSFs, contributing significantly to global net-zero carbon emission goals.

CO2 storage in saline aquifers: A simulation on quantifying the impact of permeability heterogeneity

Numerical research on CO2 storage efficiency in saline aquifer with low-velocity non-Darcy flow

Storing CO2 in deep saline aquifers is a viable technology to manage carbon emissions. However, in finite aquifers, reservoir pressure builds up quickly which can reduce injectivity and limit the ultimate storable quantities of CO2. Therefore, the purpose of this work is to investigate the optimum design for reservoir pressure-management wells during carbon dioxide (CO2) storage in finite aquifers using a numerical simulation method. In this paper, a synthetic aquifer model was used to investigate the optimal well placement and geometry, and well spacing to maximize CO2 storable quantities with a less total number of wells. Furthermore, the main target is to maximize the pore volume utilization and target injection rate per well without exceeding the reservoir fracture limit. A fit-for-purpose 3D reservoir simulation model used in this study was built to allow robust and accurate large-scale numerical simulation studies related to CO2 sequestration and storage using synthetic data. Multiple CO2 gas injectors were placed at the crest of the structure to utilize most of the available pore volume and maximize the injection rate. Various pressure management schemes were modeled and compared to find out the optimal design which can provide maximum injection rate and ultimate storage capacity. The results showed that well placement depth and the number of active relief wells both are playing a major role in maximizing the ultimate storage efficiency. Since reservoir heterogeneity and anisotropy can significantly affect the relief wells’ design, streamlines tracing can be very helpful to optimize the well spacing and orientation. After 80 years of injection, the simulation sensitivity study showed a significant difference (10-20% of CO2 storage efficiency) between the different pressure management schemes. In conclusion, relief wells are often needed to manage reservoir pressure build-up during CO2 storage in finite aquifers and their design is vital in maximizing the ultimate CO2 storage capacity. The outcome of this study is providing a useful guideline to optimize the field development plans and maximize the CO2 storage capacity in finite aquifers.

In an effort to reduce carbon dioxide (CO2) emissions from large stationary sources, carbon capture and storage (CCS) is being investigated as one approach. This work assesses CO2 storage resource estimation methods for deep saline formations (DSFs) and hydrocarbon reservoirs undergoing CO2 enhanced oil recovery (EOR). Project activities were conducted using geologic modeling and simulation to investigate CO2 storage efficiency. CO2 storage rates and efficiencies in DSFs classified by interpreted depositional environment were evaluated at the regional scale over a 100-year time frame. A focus was placed on developing results applicable to future widespread commercial-scale CO2 storage operations in which an array of injection wells may be used to optimize storage in saline formations. The results of this work suggest future investigations of prospective storage resource in closed or semiclosed formations need not have a detailed understanding of the depositional environment of the reservoir to generate meaningful estimates. However, the results of this work also illustrate the relative importance of depositional environment, formation depth, structural geometry, and boundary conditions on the rate of CO2 storage in these types of systems. CO2 EOR occupies an important place in the realm of geologic storage of CO2, as it is likely to be the primary means of geologic CO2 storage during the early stages of commercial implementation, given the lack of a national policy and the viability of the current business case. This work estimates CO2 storage efficiency factors using a unique industry database of CO2 EOR sites and 18 different reservoir simulation models capturing fluvial clastic and shallow shelf carbonate depositional environments for reservoir depths of 1219 and 2438 meters (4000 and 8000 feet) and 7.6-, 20-, and 64-meter (25-, 66,- and 209-foot) pay zones. The results of this work provide practical information that can be used to quantify CO2 storage resource estimates in oil reservoirs during CO2 EOR operations (as opposed to storage following depletion) and the uncertainty associated with those estimates.

Two of the most important challenges facing the global energy sector are to reduce the CO2 intensity and the water intensity of energy production. Because many economies will continue to depend on fossil fuels as primary energy sources, CO2 capture and storage (CCS) must play a major role in curbing CO2 emissions. A large portion of CO2 storage will need to occur in saline reservoirs because these resources are more widely distributed than hydrocarbon resources—where CO2 capture utilization and storage (CCUS) can be deployed for enhanced oil recovery (EOR). CCS deployment can be accelerated with a pressure-management strategy, called pre-injection brine production that proactively manages project risks linked to reservoir pressure. In this approach, a CCS wellfield is deployed sequentially, one well at a time, with each well being used for three stages: (1) monitoring, (2) brine production, and (3) CO2 injection. Using the same well to produce brine before injecting CO2 provides pre-injection reservoir diagnostics needed for proactive planning of wellfield operations. Because pressure drawdown is greatest where CO2 injection will subsequently occur, reservoir pressure is efficiently managed per well, and per unit of removed brine. This approach to managing geologic CO2 storage can (1) identify resources with sufficient CO2 storage capacity and permanence, and provide information needed to effectively manage those resources prior to injecting CO2; (2) increase CO2 storage capacity and efficiency; (3) limit pore-space competition with neighboring subsurface operations; and (4) reduce the duration of post-injection site care and monitoring, while (5) creating the opportunity to generate water, using an emerging CCUS technology called enhanced water recovery (EWR). Although beneficial consumptive use of produced brine may be preferred in water-constrained regions, there may be situations where the brine composition is not economically treatable, which could necessitate reinjecting some or all of the produced brine into a separate reservoir. In this study we consider a range of brine-disposition options, from 100% reinjection in the subsurface to near zero net injection of fluid, which maximizes the water generation benefit per tonne of stored CO2. These options are analyzed for a case where a nearby saline reservoir overlying a CO2 storage reservoir is used to store some or all of the brine removed from the CO2 storage reservoir.

Produced water integration in CO2 storage using different injection strategies: The effect of salinity on rock petrophysical, mineralogy, wettability and geomechanical properties

In this study, we examined the effect of CO2 injection into deep saline aquifers, considering impurities present in blue hydrogen production. A fluid model was designed for reservoir conditions with impurity concentrations of 3.5 and 20%. The results showed that methane caused density decreases of 95.16 and 76.16% at 3.5 and 20%, respectively, whereas H2S caused decreases of 99.56 and 98.77%, respectively. Viscosity decreased from 0.045 to 0.037 cp with increasing methane content up to 20%; however, H2S did not affect the viscosity. Notably, CO2 with H2S impacted these properties less than methane. Our simulation model was based on the Gorae-V properties and simulated injections for 10 years, followed by 100 years of monitoring. Compared with the pure CO2 injection, methane reached its maximum pressure after eight years and eleven months at 3.5% and eight years at 20%, whereas H2S reached maximum pressure after nine years and two months and nine years and six months, respectively. These timings affected the amount of CO2 injected. With methane as an impurity, injection efficiency decreased up to 73.16%, whereas with H2S, it decreased up to 81.99% with increasing impurity concentration. The efficiency of CO2 storage in the dissolution and residual traps was analyzed to examine the impact of impurities. The residual trap efficiency consistently decreased with methane but increased with H2S. At 20% concentration, the methane trap exhibited higher efficiency at the end of injection; however, H2S had a higher efficiency at the monitoring endpoint. In carbon capture and storage projects, methane impurities require removal, whereas H2S may not necessitate desulfurization due to its minimal impact on CO2 storage efficiency. Thus, the application of carbon capture and storage (CCS) to CO2 emissions containing H2S as an impurity may enable economically viable operations by reducing additional costs.

Quantifying the effects of depositional environment on deep saline formation co2 storage efficiency and rate

Carbon capture from stationary sources and geologic storage of carbon dioxide (CO2) is an important option to include in strategies to mitigate greenhouse gas emissions. However, the potential costs of commercial-scale CO2 storage are not well constrained, stemming from the inherent uncertainty in storage resource estimates coupled with a lack of detailed estimates of the infrastructure needed to access those resources. Storage resource estimates are highly dependent on storage efficiency values or storage coefficients, which are calculated based on ranges of uncertain geological and physical reservoir parameters. If dynamic factors (such as variability in storage efficiencies, pressure interference, and acceptable injection rates over time), reservoir pressure limitations, boundaries on migration of CO2, consideration of closed or semi-closed saline reservoir systems, and other possible constraints on the technically accessible CO2 storage resource (TASR) are accounted for, it is likely that only a fraction of the TASR could be available without incurring significant additional costs. Although storage resource estimates typically assume that any issues with pressure buildup due to CO2 injection will be mitigated by reservoir pressure management, estimates of the costs of CO2 storage generally do not include the costs of active pressure management. Production of saline waters (brines) could be essential to increasing the dynamic storage capacity of most reservoirs, but including the costs of this critical method of reservoir pressure management could increase current estimates of the costs of CO2 storage by two times, or more. Even without considering the implications for reservoir pressure management, geologic uncertainty can significantly impact CO2 storage capacities and costs, and contribute to uncertainty in carbon capture and storage (CCS) systems. Given the current state of available information and the scarcity of (data from) long-term commercial-scale CO2 storage projects, decision makers may experience considerable difficulty in ascertaining the realistic potential, the likely costs, and the most beneficial pattern of deployment of CCS as an option to reduce CO2 concentrations in the atmosphere.

With increased commercial interest in geologic CO2 sequestration and 45Q-related activities in the United States, the Midwest Regional Carbon Initiative (MRCI) includes a pertinent evaluation of stimulation strategies for enhancing well injectivity and storage efficiency. This could open significant additional resource potential to the existing onshore storage options by leveraging several complex or seemingly ‘lower quality’ reservoirs found throughout the MRCI region that could potentially be cost-effective compared to ultra-deep targets to support carbon capture and sequestration (CCS) projects. This manuscript discusses innovative scenario analyses of different well configurations and operational strategies adapted from oil and gas industry practices to identify potential optimal storage solutions and their impacts on CO2 injectivity and storage efficiency. A scoping evaluation for preliminary insights into specific injection strategies in complex systems including naturally fractured reservoirs for their impacts on CO2 injectivity and storage efficiency is conducted using simplified representative sites for CO2 storage. The scoping simulations provide a framework to inform optimal storage solutions for the MRCI region that can be investigated further during the subsequent detailed design phase of analogous sites.

CO2 storage efficiency refers to the amount of CO2 storage in a certain volume of underground space, which is directly affected by CO2 sweeping volume. Besides, the balance between vertical and horizontal migration of CO2 is the key to increase the sweeping volume. This study focused on the influence of foam fluid on the fluidity and percolation characteristics of CO2 in porous media. The rheological properties, percolation characteristics and maximum injection volume of pure CO2 and CO2 foam were investigated by rheometer, percolation performance test and CO2 storage simulation experiment, respectively.As the experimental results shown, the apparent viscosity of CO2 foam reached 6000 mPa·s at 85℃, and the viscosity of pure CO2 was below 0.1 mPa·s at the same temperature; the resistance factor (the ratio of the pressure difference between the two ends of the core during foam injection and the pressure difference between the two ends of the core during water injection) of foam was over 500 times that of pure CO2 in 10mD core, and the difference in resistance factors was more significant in cores with lower permeability; in a core with a pore volume of 127 ml, the CO2 storage amount of foam injection was 136% that of pure CO2 injection. Meanwhile, the impact of foam`s property, such as diameter distribution, gas-liquid ratio, on the storage efficiency was investigated by a series experiments. Firstly, the resistance factor and residual resistance factor of CO2 foam reached the highest in the cores with permeability of 110 mD class, and the second in the cores with 1 mD class. Secondly, under the condition of the same permeability, the larger the gas-liquid ratio is, the better the blocking effect is. Thirdly, under all three permeability conditions, the residual resistance factor showed a decreasing and then increasing trend at the beginning of injection.According the results and analysis, foam injection can effectively improve the CO2 storage efficiency. The key parameters affecting the effectiveness of storage efficiency improvement are as follows. Firstly, matching of foam particle size to formation pore size. Bubbles shown a higher probability of entering narrow pore channels with pore diameters smaller than their particle sizes, resulting in a more frequent occurrence of the Jarman effect, which manifested in the increase of sweeping volume and fluidity control capacity in macroscale. Secondly, the larger the gas ratio, the more frequently the foam system is generated, and the greater the density of bubbles in the system, giving the foam system a higher chance of blocking when passing through pores and pore throats.Although the global CO2 storage potential is more than 4 trillion tonnes, if geological sequestration becomes a routine method to reduce CO2 emissions, underground space will be used up. Therefore, improving the CO2 storage efficiency is a key choice to enhance the CO2 storage potential and extend the life of CCUS technology. This study proposed a method to improve the CO2 storage potential by changing the fluid form, which can provide a new idea for the better utilization of underground space.

Numerical simulation study on enhanced efficiency of carbon dioxide geological storage with nanoparticles in deep saline aquifer