Foam flooding can effectively suppress CO2 channeling, improving oil recovery and CO2 storage efficiency. However, elevated reservoir temperatures can considerably impair the effectiveness of CO2 foam. Moreover, our comprehension of the storage capacity and mechanisms involved in CO2 foam flooding remains limited. This study introduces a temperature-resistant foam system, denoted as EFS, and conducts assessments of its enhanced oil recovery (EOR) efficiency and CO2 storage ability. To begin, the polymeric surfactant (FA) was synthesized by micellar polymerization, and its temperature resistance performance was evaluated by the TGA curve, aging viscosity, and hydrodynamic size test. Following, the room- and high-temperature foaming performance of FA, foaming agent EBB, and the compound system (EBB + FA, named EF, and EBB + FA + nano-SiO2, named EFS) were compared, and the optimal foam system formula was optimized. Next, the plugging performance of EFS foam under three gas–liquid ratios and two injection rates was evaluated by core injectivity experiments. Lastly, CO2 flooding (5 MPa, 15 MPa, and 30 MPa) and CO2 foam flooding (15 MPa) were carried out to clarify the CO2 channeling law, EOR, and CO2 storage effect of CO2 foam flooding. Meanwhile, the contribution rates of different mechanisms to CO2 storage were qualitatively split. The TR-IR and 1H spectra confirm the successful synthesis of FA, whose molecular degradation temperature surpasses 230 °C and has good solution thermal stability. Upon meticulous evaluation of foam volume and half-life, the pinnacle formulation for the EFS foam system emerged as comprising 0.2 wt% EBB, 0.3 wt% FA, and 0.05 wt% nano-SiO2. Notably, the introduction of nano-SiO2 exerted a profound influence on enhancing foaming performance, particularly at elevated temperatures. In terms of plugging efficacy, the EFS foam exhibited impressive performance. Optimal results were obtained using a gas–liquid ratio of 3:1 and an injection rate of 0.4 mL/min. Supercritical CO2 flooding can slightly delay CO2 channeling, but the effect is significantly lower than near-miscible CO2 flooding. CO2 foam flooding can further increase EOR by 13.74 % based on CO2 flooding. Meanwhile, CO2 foam flooding can increase the storage rate by 3.53 % based on reducing CO2 consumption by 15.23 %. Residual storage, comprising a substantial majority at over 65 %, stands as the predominant method for CO2 storage, with oil dissolution storage following behind, which increases significantly with the remaining oil. 

Investigation on enhanced oil recovery and CO2 storage efficiency of temperature-resistant CO2 foam flooding

Injection and production of hydrogen gas storage through multiple cycles often lead to significant variations in the gas water occurrence state and the associated relative permeability curve (RPC). In this study, a visual sandstone etching model and numerical simulation method are used to analyze the alteration of the occurrence state after multiple cycles of gas-water inter drive. The influence of the occurrence state on the variation of the RPC is revealed. The experimental results demonstrate that with an increasing number of cyclic injection and production cycles, the gas saturation in the model shows an upward trend, rising from 64.26% to 73.89%. However, the water block phenomenon also increases, leading to only a small amount of gas bubbles undergoing discrete flow, resulting in a reduction of the porosity utilization from 51.06 % to 40.57 %. In different injection and production cycles, the liquid phase at the corners and blind ends of large pores is difficult to displace. The continuity of gas-liquid distribution enhances with the increase in injection and production cycles. The phenomenon of phase trapping during hydrogen multi-cycle injection is evident, and the relative permeability of the gas phase rapidly declines during the imbibition first stage. The difference in gas saturation between the displacement and imbibition processes gradually decreases, reducing from 0.314 to 0.054. The Carlson model achieves a final simulation accuracy of over 90 % for wettability hysteresis. The numerical simulation results indicate that the modified relative permeability curves can more accurately simulate the changes in hydrogen gas storage during injection and production. The relative error of the hydrogen saturation in the uppermost layer of the reservoir at 1673 days of operation is 8.51 %. And the pressure increase is 13.32% without considering the wetting hysteresis model. 

Pore-scale mechanisms and hysteresis effect during multi-cycle injection and production process in underground hydrogen storage reservoir

Continuous CO2 injection (CCI) into the saline aquifers always suffers from low sweep efficiency. Foam can effectively address this issue. However, the strong foam may undesirably reduce the injectivity. In this study, the potential of CO2-soluble surfactants assisted carbon storage in carbonate saline aquifers was evaluated by core flooding tests and numerical simulations. It is found that foam can be generated at the displacement front during continuous CO2 injection with 0.39 g/L surfactant (CCI + S, fg = 100 %). The CO2 saturation can reach 60 % after 1.0 pore volume of CCI + S, approximately 50 % higher than that of CCI. The maximum pressure gradient is around 1.5 psi/ft at an injection rate of 1.0 ft/d in 162 mD Indiana Limestone for CCI + S. The effects of surfactant concentration, foam quality, and rock permeability were also investigated by core flooding. Moreover, the influence of surfactant partitioning and adsorption on CO2 transport behavior was systematically evaluated by numerical simulation in synthetic and geological models, using modeling parameters that are realistic for field applications. The advantage of injecting surfactant with CO2 is more evident in heterogeneous saline aquifers. Such novel injection strategy provides a promising approach for carbon sequestration in saline aquifers by controlling the mobility of CO2 at the displacement front and simultaneously maintaining acceptable injectivity in the field. The CCI + S process may also impose less risk to the caprock. Expanding the potential CO2 storage sites to heterogeneous saline aquifers could be a game-changer. Our understanding of foam dynamics in porous media could also be advanced. 

CO2 soluble surfactants for carbon storage in carbonate saline aquifers with achievable injectivity: Implications from the continuous CO2 injection study

CO2 huff-n-puff has been accepted as an effective technique to improve oil recovery in tight oil reservoirs. Even though CO2 EOR mechanisms were extensively investigated from laboratory experiments, the links of experimental results to field-scale performance have not been widely investigated as few pilot tests were conducted. In this study, laboratory experiments and CO2-huff-n-puff pilot test were performed. First, phase behaviors of the Lucaogou crude oil and oil-CO2 mixtures were investigated via Pressure-Volume-Temperature (PVT) tests including flash evaporation, constant composition extension (CCE), and CO2 injection and slim tube tests, respectively. Experimental results showed that due to the higher concentration of the intermediate components, the saturation pressure of the Lucaogou crude oil is 6.18 MPa, which is much smaller than the initial and current formation pressures. The oil viscosity decreased from 24.8 mPa s to 3.0 mPa s and swelling factor increased to 1.848 after about 85 mol% CO2 dissolved. Moreover, slim tube test showed the minimum miscible pressure of the Lucaogou crude oil is 24.28 MPa, which is smaller than the current formation pressure, indicating multi-contact miscibility could be reached easily. Second, fracturing fluid imbibition and CO2 huff-n-puff experiments were carried out to evaluate the performance of CO2 EOR after fracturing. The oil recovery factor increased after imbibition time and the number of huff-n-puff cycles, and was impacted by petrophysical properties, like porosity and pore structure. In addition, performance of CO2 huff-n-puff pilot test in the J30 well was reported. Approximately 1.9% of original oil in place was recovered after one huff-n-puff cycle, showing a significant potential of CO2 EOR in the Lucaogou tight formation. Analysis of oil production rate, composition and density of produced oil shows the dominant EOR mechanisms in the early production stage were miscibility and CO2 vaporization, then viscosity reduction. Findings from this study will provide insights on CO2 EOR in tight oil reservoirs. 

Insights into CO2 huff-n-puff mechanisms from laboratory experiment and single-well pilot test in the Lucaogou tight oil reservoir, Jimsar sag, China

Major concerns of carbon dioxide (CO2) sequestration in subsurface formations are knowledge of the well injectivity and gas storage capacity of the formation, the CO2 pressure and saturation plume extensions during and after injection, and the risks associated with CO2 leakage and fault reactivation. Saline reservoirs are considered as one of the target formations for CO2 sequestration through structural, residual, dissolution, and mineral trapping mechanisms. The boundary condition of the saline reservoir dictates the pressure and saturation plume extension of the injected supercritical CO2 that could expand over large distances. This can lead to sources of risk, e.g., leakage and/or fault reactivation due to presence of wells, thief zones, and geological discontinuities. Therefore, there is a critical need to develop a model that describes how risk-related performance metrics (i.e., the CO2 saturation plume size, the pressure differential plume area, and the pressure differential at specific locations) vary as a function of the size of injection, time following injection, injection operations, and geologic environment. In this study, a systematic reservoir modeling studies of anthropogenic CO2 sequestration in Citronelle dome, Alabama, was performed where all relevant scenarios and conditions to address the questions of the saturation and pressure plume size in the area of review (AoR) and post-injection site care (PISC) are considered. The objective for this study was firstly to systematically simulate CO2 sequestration, i.e., saturation dynamics, and pressure behavior over a range of operational and geological conditions and to derive conclusions about the factors influencing saturation and pressure plume size, post-injection behavior, and the risk associated with them, by developing third-generation reduced order models (ROMs) for reservoir behavior. Finally, to assess the uncertainty associated with our studies, Latin Hypercube Sampling (LHS) together with an experimental design technique, i.e., Plackett–Burman design, was used. Application of Pareto charts and respond surfaces enabled us to determine the most important parameters impacting saturation and pressure plume sizes and to quantify the auto- and cross-correlation among different parameters in both history-matched and upscaled models.

/pdf/impacts-of-different-operation-conditions-and-geological-uapuim8u.pdf

Impacts of Different Operation Conditions and Geological Formation Characteristics on CO2 Sequestration in Citronelle Dome, Alabama

Investigation of enhanced CO2 storage in deep saline aquifers by WAG and brine extraction in the Minnelusa sandstone, Wyoming

Hydrogen (H₂), as a renewable energy source, holds immense importance in energy conversion and storage. Among various methods, underground hydrogen storage (UHS) stands out, especially during high energy demand in winter, owing to the vast subsurface reservoirs. This study aims to uncover the impact of engineering constraints on H₂ storage conditions and recovery processes. To begin, a geological model mirroring a genuine deep saline aquifer found in the Rock Springs Uplift of Wyoming is developed. This model is intricately linked with fluid composition and multiphase flow properties. The resulting reservoir is utilized in a series of computational experiments, shedding light on the intricate interplay between engineering constraints and H₂ storage dynamics. The research findings indicate that a longer duration of H₂ injection or production stages leads to higher H₂ retention within the aquifer. Specifically, the study reveals that a 3-month injection period (with a final recovery of 0.864) retains less H₂ compared to a 6-month injection period (with a final recovery of 0.805). Regarding well patterns, the research highlights that trapped H₂ steadily accumulates due to the mutual displacement of H₂ and water in a single-well scenario, intensifying the impact of multiphase hysteresis. The study shows that H₂ recovery increases over time for different well configurations: a single well, one injection well + one production well, and two injection wells + two production wells, reaching final values of 0.839, 0.76, and 0.778, respectively. After undergoing 9 cycles of operations, top perforation, as opposed to bottom perforation and full perforation, leads to the highest recovery rate of 0.864. These findings not only provide valuable insights for guiding the engineering design of UHS systems but also pave the way for the practical implementation of UHS on a commercial scale. 

Unveil the role of engineering parameters on hydrogen recovery in deep saline aquifer, Rock Springs Uplift, Wyoming

Aim: This study improved the in vivo bioreactor (IVB) for bone regeneration by enhancing stem cell survival and promoting vascularized tissue-engineered bone. Methods: 12 New Zealand rabbits received β-TCP scaffolds with rabbit bone mesenchymal stem cells (BMSCs) implanted. Perfusion IVB with a perfusion electronic pump was compared with the control group using micro-CT, Microfil perfusion, histological staining and RT-PCR for gene expression. Results: Perfusion IVB demonstrated good biocompatibility, increased neoplastic bone tissue, neovascularization and upregulated osteogenic and angiogenesis-related genes in rabbits (p < 0.05). Conclusion: Perfusion IVB holds promise for bone regeneration and tissue engineering in orthopedics and maxillofacial surgery. 

Perfusion in vivo bioreactor promotes regeneration of vascularized tissue-engineered bone.

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Investigation of enhanced CO2 storage in deep saline aquifers by WAG and brine extraction in the Minnelusa sandstone, Wyoming

Unveil the role of engineering parameters on hydrogen recovery in deep saline aquifer, Rock Springs Uplift, Wyoming

Perfusion in vivo bioreactor promotes regeneration of vascularized tissue-engineered bone.