Injection Wells Research Articles

Study on Improving Recovery of Highly Heterogeneous Reservoirs by Unsteady Water Injection Technology

Unstable water injection can effectively improve the recovery ratio of reservoirs with strong heterogeneity. However, the oil displacement mechanism and the determination method of unstable water injection parameters still need to be clarified, especially for complex fracture reservoirs, which greatly restrict the popularization and development of unstable water injection technology. This paper studies unstable water injection technology in highly heterogeneous reservoirs from the core and reservoir scales, utilizing many displacement experiments and numerical simulations. The differences in oil displacement efficiency, remaining oil distribution, pressure field, and streamlines between continuous water injection and unstable water injection are compared and evaluated. Five flow stages of unstable injection and production are precisely divided, and the microscopic and macroscopic displacement mechanism is clarified. A numerical model of two injection wells and one production is established to determine the best time to implement unstable water injection technology. Based on the principle of pressure superposition, the expression of pressure field distribution between injection and production well in each period of unstable water injection is analytically solved. This formula has provided a new development parameter optimization method aiming at the maximum pressure fluctuation range and optimized the development technology parameters in the water injection process. The results show that precise control injection and production parameters can expand water swept volume, effectively improve the degree of reserve utilization, and improve the recovery of complex reservoirs by 3–7%, which provides a reliable basis for the practical implementation of unstable water injection technology.

Novel Gel Formulation and Deep Injection Techniques for Lifting Effects in Cosmetic Dermatology.

In recent years, the field of aesthetic dermatology has witnessed a surge in demand for minimally invasive procedures aimed at rejuvenating aging skin. This study aims to address this demand by evaluating the effectiveness of the injectable gel in rejuvenating aging skin, particularly by targeting collagen regeneration and lifting effect. The study involved 43 participants who underwent three monthly injection sessions targeting retaining ligaments. The injections were administered deeply to ensure proper targeting. Follow-up assessments were conducted after each treatment session and three months after the final injection. Evaluation methods included subjective assessments by both patients and investigators using the Global Aesthetic Improvement Scale (GAIS), as well as objective assessments using a 3D photosystem to measure wrinkle conditions and vectors of traction. All participants completed the study, with no significant adverse effects observed apart from mild swelling at the injection sites. Despite the high viscosity of HA necessitating the use of a 27 G needle, the injection process was generally comfortable and minimally painful. Subjective evaluations revealed consistent improvements in skin appearance from the first application, which continued to increase throughout the study and remained high even 3 months post-treatment. Objective evaluations demonstrated significant improvements in wrinkle conditions and lifting effects, with a substantial increase in the standard deviation score for wrinkle conditions and the average traction vector length measuring 1.6 mm. The study findings confirm the safety and efficacy of the injectable formula, with high patient satisfaction, noticeable lifting effects, and significant improvements in wrinkle conditions. These results support the use of the injectable as a promising option for non-invasive skin rejuvenation treatments.

Cyclic regulation of self-induced hydraulic fracturing cracks to improve the flooding efficiency of low-permeability reservoirs

The article is devoted to the topical issue of optimizing flooding in the development of deposits using a reservoir pressure maintenance system. In conditions of low permeability and weak reservoir connectivity, when water is injected into the injection well, when the injection pressure exceeds the pressure of rock rupture, auto-fracturing cracks occur. In order to ensure the maximum coverage factor of the reservoir by flooding during the development of the field, it is necessary to initiate and maintain the optimal fracture geometry of the auto-fracturing. The aim of the work is to analyze the modes of cyclic regulation of injection into the reservoir to maintain the optimal size of man-made cracks during the development of the field. The article presents the results of hydrodynamic modeling of flooding options with varying injection and shutdown times of injection wells, taking into account the geomechanical patterns of the spread of man-made cracks in the formation. Based on the results of the calculations performed, based on the forecast characteristics of displacement and the rate of oil extraction, the optimal modes of cyclic reservoir flooding were determined. The work is of great commercial importance, which is confirmed by the positive effect in the form of additional oil production within the framework of pilot tests of the proposed scheme. Keywords: self-induced hydraulic fracture; low-permeability reservoir; waterflood; water injection system; horizontal well; bottom hole pressure; reservoir pressure; fracture half-length; periodic injection of water.

Research methods of the potential of long-term operated reservoirs based on the hydrodynamic model

Studying the potential of long-term operated fields and evaluating their efficiency requires the application of modern approaches. In this regard, by using three-dimensional geological and hydrodynamic models of the Pirallahi Island field, various complex impact mechanisms were modeled, as well as the solution of the mentioned issues based on the established model was considered on the basis of simulation to maintain the development rate of the field and increase the oil production rate. When there is no accurate information about the initial condition of the field, as well as when the data is partially insufficient and inaccurate in some intervals of the long-term production performance, methods of restoring information in different ways for building a hydrodynamic model were investigated, and ways to minimize the negative impact of this type of uncertainty on the model were also studied. For this purpose, a new method called intermediate initialization was developed and applied to the construction of the reservoir model. On the basis of the established model, a more efficient method of field exploitation, water injection into formations, optimal placement of new production and injection wells was selected, modeling was carried out for various options and scenarios, a plan of necessary measures was drawn up to maximize the life of the field, development parameters were predicted and the results were compared. Keywords: field; formation; well; development; model; information recovery; intermediate initialization method; prediction.

"LiquiPerfPro" reagent for increasing the permeability of the well bottom hole zone

The purpose of the technology's development is to reduce the skin effect and restore the permeability of wells, which have experienced a significant reduction in permeability for various reasons, including contamination of the filter zone by oil-based drilling fluids during drilling. The developed alkaline-based new chemical composition, "LiquiPerfPro", reduces the interfacial surface tension on the rock surfaces contaminated by oil-based drilling fluid in the near-wellbore zone, altering the wetting angle in favor of oil and creating a hydrophilic surface. Additionally, it removes the oil screen formed on the weighting components present in the drilling fluid and reduces adhesion forces. After reacting with the oil-based component, the weighting components undergo segregation, increasing their ability to migrate and enabling them to be easily displaced from the pores. Furthermore, after the weighting particles are cleaned from the oil screen, their surfaces become open to other solvents, allowing the application of other traditional methods for deeper cleaning of contamination. Moreover, the "LiquiPerfPro" reagent, due to its physico-chemical properties, has the ability to penetrate a significant distance from the wellbore into the drainage area. The application of the "LiquiPerfPro" reagent is also favorable for lithologically weakly cemented rocks, as it does not create the risk of formation collapse, unlike traditional acid treatment methods, and does not damage the matrix. The reagent can be applied to both production and injection wells. Keywords: Alkali; acid; permeability; reservoir model; wellbore zone; new chemical composition; surfactant; organic solvent; oil-based drilling mud.

Integrated approach to determining the effectiveness of the reservoir pressure maintenance system in carbonate reservoirs

Relevance. The need to improve the oil recovery factor from carbonate reservoirs by increasing sweep/displacement coefficients, as well as by searching for ways to improve the efficiency of the reservoir pressure maintenance system. Aim. To increase the efficiency of developing carbonate reservoirs using a reservoir pressure maintenance system through an integrated approach to studying the impact of injected fluid on reservoir systems with natural and man-made fracturing. Objects. Bashkir (C2bsh) and Vereisky (C2vr) Middle Carboniferous objects of the Dachnoe structure of the Dachnoe deposit of the Republic of Tatarstan, tectonically confined to the Ulyanovsk structure of the South Tatar arch. Methods. Seismic, acoustic, radioactive, hydrodynamic methods, as well as methods of ground microseismic monitoring to identify the nature of the activation of natural and man-made fracturing during hydraulic fracturing and cyclic injection into injection wells. Results. The authors have carried out an analysis of the hydrodynamic system of carbonate reservoirs of the Vereiskian-Bashkirian deposits; identified filtration channels; assessed the direction of injected fluid movement; carried out the analysis of the impact of the formation pressure maintenance system on producing wells at various injection modes and compensation levels in carbonate reservoirs. When carrying out hydraulic fracturing in the reservoirs under consideration, it was established that the crack propagates to both objects, thereby forming a single hydrodynamic system. The conclusions obtained from the work indicate the effectiveness of the system for maintaining reservoir pressure in these carbonate reservoirs. Clarification of data on the filtration channels of both the working agent and the oil displaced by it, in combination with knowledge of the rates of movement of the injected liquid and its distribution profiles, makes it possible to effectively manage the oil field development.

Maximum Magnitude of Induced Earthquakes in Rate and State Friction Framework

Abstract We analyze the evolution of the rupture radius and maximum magnitude (Mmax) of injection-induced earthquakes on faults obeying rates and state friction. We define the radii of two different slip modes, aseismic (Ra) and seismic slip (Rs), and derive an expression for maximum magnitude evolution. If the flow rate is sufficiently high, the seismic moment grows with the scaled injection volume, Qt/wS, as M∼Cf(Qt/wS)3/2, in which Cf depends on the initial stress level, S is storage coefficient, and w is the thickness of the reservoir. These findings are confirmed using numerical simulations conducted with varied initial states. The simulations show that Rs behaves as a rupture arrest radius and Ra behaves as the minimum possible radius of aseismic creep at a given injection volume. The Mmax evolution curve can be steeper if the fault is slightly critically stressed. A high-flow rate results in frequent seismic events, starting at relatively low-injected volume, which helps track the evolution of Mmax, providing a way to anticipate the risk of a large event. Conversely, a low-flow rate allows for a larger volume injection without seismic events but may lead to sudden large events without precursory events.

Hypothetical CO2 leakage into, and hydrological plume management within, an underground source of drinking water at a proposed CO2 storage facility, Kemper County, Mississippi, USA

A large Geologic Carbon Sequestration (GCS) hub has been proposed in Kemper County, Mississippi. The target injection interval consists of numerous Cretaceous-aged deep saline aquifers overlain by a competent and extensive regional sealing layer. Above the seal, the deepest Underground Source of Drinking Water (USDW) at the site is the Eutaw aquifer of the Eutaw Group and McShan Formation, undifferentiated. To assess potential risks of leakage from the deep sequestration reservoir, a model of a portion of the Cretaceous Eutaw Group was constructed in this study. Simulations tested various permeabilities, hypothetical leakage rates, and plume mitigation strategies utilizing existing wells. Results suggest that, under the influence of regional groundwater flow fields, leaking CO2 would effectively bypass the existing wells, and to influence this migration would require very large water extraction rates. Therefore, to ensure plume detection, monitoring for leakage at the injection wells themselves is very important.

Quantitative Characterization Method of Additional Resistance Based on Suspended Particle Migration and Deposition Model

The phenomenon of pore blockage caused by injected suspended particles significantly impacts the efficiency of water injection and production capacity release in offshore oilfields, leading to increased additional resistance during the injection process. To enhance water injection volumes in injection wells, it is essential to quantitatively study the additional resistance caused by suspended particle blockage during water injection. However, there is currently no model for calculating the additional resistance resulting from suspended particle blockage. Therefore, this study establishes a permeability decline model based on the microscopic dispersion kinetic equation of particle transport. The degree of blockage is characterized by the reduction in fluid volume, and the additional resistance caused by particle migration and blockage during water injection is quantified based on the fluid volume decline. This study reveals that over time, suspended particles do not continuously migrate deeper into the formation but tend to deposit near the wellbore, blocking pores and increasing additional resistance. Over time, the concentration of suspended particles near the wellbore approaches the initial concentration of the injected water. An increase in seepage velocity raises the peak concentration of suspended particles, but when the seepage velocity reaches a certain threshold, its effect on particle migration stabilizes. The blockage location of suspended particles near the wellbore is significantly influenced by seepage velocity and time. An increase in particle concentration and size accelerates blockage formation but does not change the blockage location. As injection time increases, the fitted injection volume and permeability exhibit a power-law decline. Based on the trend of injection volume reduction, the additional resistance caused by water injection is calculated to range between 0 and 3.85 MPa. Engineering cases indicate that blockages are challenging to remove after acidification, and the reduction in additional resistance is limited. This study provides a quantitative basis for understanding blockage patterns during water injection, helps predict changes in additional resistance, and offers a theoretical foundation for targeted treatment measures.

Impact of plasma‐treated nano‐alumina on the thermal and electrical properties of epoxy resin at elevated temperatures

AbstractIn this study, to ramp up the thermal stability and insulation characteristics of epoxy resin (EP), the plasma‐treated EP/alumina composites with a mass fraction of 1 wt% were fabricated. The variations of functional groups in the EP composites with/without plasma treatment were characterized by Fourier transform infrared spectroscopy (FTIR), and the glass transition temperature of the specimens was analyzed by differential scanning calorimetry (DSC) analysis. The space charge distributions, the electrical conductivity and DC breakdown strength of the specimens were measured at 90°C. Moreover, the results were further analyzed in depth. The results indicated that the nanocomposites prepared with plasma‐treated nano‐alumina exhibited a higher concentration of OH and CO groups. At 90°C, the plasma‐treated alumina nanoparticles significantly increased the charge injection threshold of EP from about 26 nC (untreated) to 19 nC (treated); reduced the internal electric field distortion, decreased the charge accumulation and dissipation, and increased the breakdown strength from about 104 kV/mm (untreated) to 115 kV/mm (treated), and the conductivity from about 5.1 × 10−14 S/m (untreated) to 3.1 × 10−14 S/m (treated). In summary, it was elucidated that plasma‐treated nano‐alumina particles could effectively reduce deep trap density, trapped charges, charge injection and transportation and reinforce composites' insulation performance at high temperatures.Highlights The DBD plasma treatment is environmentally friendly with high efficiency. The testing adopted advanced characterization and analysis techniques. Plasma treatment of alumina nanoparticles enhanced the thermal stability. The treated nano‐alumina reinforced insulation performance of EP nanocomposites. The plasma treatment raised the space charge injection threshold and barrier.

Deep Learning-Based Reservoir Simulation Proxy Models

The behavior of oil reservoirs, characterized by geophysical, geochemical, and geological properties, can be understood through the simulation of computational models, involving the construction of meshes of finite volume elements with equations derived from fundamental principles. However, the execution of multiple simulations for activities such as optimization and uncertainty assessment results in substantial computational costs.To overcome this challenge, proxy models are proposed, aiming to replace reservoir simulators with adequate precision. This work proposes the implementation of data-based proxies for reservoir simulators using Artificial Neural Networks (ANNs). This approach utilizes time series of well controls as inputs, generating responses for Bottom Hole Pressures (BHPs) and/or flow rates.In recent years, proxy models based on neural networks have been applied to obtain predictions of flows and/or pressures in reservoirs. For example, Recurrent Neural Networks (RNNs), specialized in handling sequential data, were used by [1] to predict water flows in the Xiluodu hydroelectric reservoir in China. Convolutional Neural Networks (CNNs), specialized in pattern recognition in images and videos, were also employed by [2] to predict pressures and flow rates of injector and producer wells, respectively.In the scope of this study, distinct neural network architectures were evaluated to predict outputs of a synthetic two-phase model with partial faults. Given the adoption of mixed controls, where producer wells are controlled by BHP and injector wells by flow rate, the use of Multihead Neural Networks [3] was also investigated. This approach allows differentiated processing of input data, contributing to more robust and efficient learning.For each considered architecture, the impact of the number of timesteps in the samples and their size on the accuracy of predictions was analyzed. The results indicate that parallel hybrid architectures exhibit the best performance, forming a complementary mutual network where each architecture contributes with different learning approaches. Additionally, a higher number of samples contributes to reducing result dispersion, while an increase in the number of timesteps does not show a significant contribution to reducing mean error.We gratefully acknowledge the support provided by PETROBRAS, ANP, FINEP, PRH, EMBRAPII, FACEPE, CNPq, and CAPES, which has been instrumental in the successful execution of this work.

CO2 injection modeling in a reservoir: Phase transition study

The study explores the phase transition of carbon dioxide from liquid to gas after injection and storage in a confined aquifer at a temperature of 30°C. By utilizing a compositional isotropic model and data from the NIST webbook (Linstrom and Mallard, 2024), the simulation analyzes, using compositional mesh model in tNavigator software (by Rock Flow Dynamics), the behavior of CO2 within a confined aquifer, seeking to identify the phase transition of the fluid. The effects of capillarity are neglected, and the main parameters of the reservoir are a pressure of 65 bar at the wellhead and a constant temperature of 31°C throughout the aquifer to evaluate the phase transition close to the supercritical point of CO2. The analysis reveals that the drastic pressure reduction within the confined aquifer leads to the formation of free gas within the reservoir after the closure of injection wells, which becomes a problem, as occurred in the Ordos CCS Project in China, allowing fluid backflow during non-injection (CAI, Yuna et al.). The results showed that the closer the temperature approaches the supercritical point of CO2, the greater the probability of free gas formation within the reservoir. Therefore, the conclusions emphasize the impact of the pressure reduction on the stability of CO2, which will undergo a phase transition from the liquid to the gaseous state, so that free gas is generated within the reservoir. In this way, it is highlighted the importance of understanding phase transition in CO2 injection processes for effective carbon capture and storage strategies.

Effect of polymer emulsion and calcium sulfate whisker on an-corrosion of cement stone for CO2 multiple gas injection and production wells

Abstract An oilfield in the South China Sea will be developed by CO2 injection to enhance oil recovery and carbon sequestration. It is challenging to prevent corrosion in the cementing operation of injection wells, and high requirements are put forward for the anti-corrosion performance of cementing slurry. In this paper, aiming at the sealing problem of the cement ring, which is easy to corrode under the condition of stratified gas injection, the rheological properties and thickening properties of cement slurry, as well as the tensile strength, compressive strength, elastic modulus, and porosity permeability of the cement slurry system, are simulated under the condition of an underground field with polymer emulsion and calcium sulfate whiskers as the research objects. Through experimental and theoretical comparison, the results show that the addition of polymer emulsion and calcium sulfate whisker can significantly improve the tensile strength and tensile strength and reduce porosity and permeability, elastic modulus has been controlled below 7.5 GPa, and the performance has been dramatically improved. In addition, according to electron microscope scanning and other experimental methods, it is found that the cement stone cured by cement slurry with polymer emulsion and calcium sulfate whisker is more compact and compact in structure and has higher strength and toughness, which fully meets the requirements of stratified gas injection conditions, providing theoretical basis and data support for the corrosion prevention of cementing cement slurry in oil fields. Promoting the safe and efficient development of oil and gas resources is of great significance.

Guidelines Assist Selection of Corrosion-Resistant Alloys for CCS and CCUS Injection Wells

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 217664, “Selection of Corrosion-Resistant Alloys for CCS and CCUS Injection Wells,” by Adam C. Rowe, SPE, Stress Engineering Services, and Bruce D. Craig, SPE, MetCorr. The paper has not been peer reviewed. _ Currently, few test data are available for determining the most suitable corrosion-resistant alloys (CRAs) for downhole injection equipment in carbon capture and storage (CCS) and carbon capture, use, and storage (CCUS) wells. The complete paper provides a guideline for such selections based on the composition of the CO2 stream, including impurities and the composition of the saline formation into which the CO2 will be injected. Introduction For those CCS and CCUS systems where water is expected to be present at some point, such as injection into a saline formation or by virtue of incomplete dehydration, carbon steel will corrode and CRAs must be considered. Because carbon steel pipelines are standard practice for transport of supercritical CO2 and have a long, successful history, this paper is strictly focused on the selection of CRAs for injection wells. While the selection of CRA material can be, and often is, based on common practices, each application requires an in-depth review of the complete system to determine the best materials for the job. In the case of storage, service life is ostensibly forever, so even otherwise minor pitting rates may not be tolerable in permanent equipment. The most important factors to consider for CRA corrosion are temperature, pH of the water phase, formation-water composition (typically chloride content), and stream impurities. With respect to temperature, this paper is focused on corrosion within CCS and CCUS wells and, therefore, considers only elevated temperature resulting from downhole geothermal gradients. Stream impurities have a significant effect on potential CRA selection, especially when certain species such as oxygen are present. However, hydrogen sulfide (H2S) and nitrogen and sulfur oxides also can be important to this selection. Technical Review of CCS and CCUS Injection Conditions Much of the CRA experience from the oil patch cannot be applied directly to CCS and CCUS well design. Multiple sources are susceptible to significant residual H2S in the injectate. Currently, no standards or guidelines exist relating to the effect of H2S in supercritical CO2 on materials. Therefore, the industry default at the time of writing is to apply the industry standard NACE MR0175/ISO 15156-3, though it is important to note that environmentally assisted cracking resistance has not been established for many CRAs at pH 3 and lower. It also is important to recognize that this standard is specifically applicable to production of oil and gas, and it remains to be determined whether CCS and CCUS operations are similar enough to apply this guide, or if supercritical CO2 warrants different limits, particularly when O2 is present. The presence of O2 in supercritical-CO2 streams presents a significant problem for the selection of CRAs. The corrosivity from O2 is defined by the dissolved oxygen concentration in the water phase, which is difficult to model in complex systems. Currently, these data are not readily available for supercritical-CO2 streams commingled with formation brines. As a guide, albeit a qualitative one, use of the pitting resistance equivalent number (PREN) is helpful for ranking resistance to pitting and crevice corrosion in aerated brine.

European and US Efforts To Develop Geothermal Energy Are Headed in Different Directions

_ Writing about emerging geothermal technology requires dealing with the fact that it is emerging in different forms in different places. A common thread of what’s new are methods based on drilling wells into hot rock to deliver fluid into hot formations to harvest energy. Chances are that sentence is not exactly an accurate description of any particular method because of the significant differences among them. Some use hydraulic fracturing while others do not. One pumps water from well to well, another into the fractures of a single well, and the third keeps the fluid inside the wellbore. And the end product varies as well. In the US, the big early developments are aimed at generating electricity for the grid and storing energy in developments where wells are fractured. In Germany, the big target is providing hot water to district heating systems that deliver it to a wide range of customers in urban areas. New technology there must avoid fracturing. In Germany, they are testing a new geothermal method that harvests heat in deep well loops using a fluid that brings energy to the surface with minimal pumping. “In Utah or Nevada, the use case is they do electric only versus in Europe where it is more heat plus electricity,” said Florian Mueller, a PhD candidate doing research on geothermal at the Energy and Technology Policy Group in Zurich, Switzerland. In both cases these methods were developed by startups whose early commercial applications require adapting to a mind-numbing list of external factors. As a result, “Geothermal will look different everywhere,” said Ken Medlock, the senior director of the Center for Energy Studies at Rice University, during a panel session at this year’s Offshore Technology Conference (OTC). Adaptation The differences reflect a common challenge faced by innovators. A practical solution to a pressing problem, engineered to be reliable and cost-competitive, is just the starting point. Growth from there will depend on how they adapt to the market. In the US, Fervo Energy’s first large-scale commercial project in southern Utah is heating water by pumping it from injection wells to production wells through rock fractured from both sides. Produced water will need to be around 400°F—higher is better—to ensure it can be used to efficiently generate electricity for consumers in southern California. In southern Germany, Calgary-based Eavor Technologies is building a series of 12 flow loops with cased vertical wells linked by a long, uncased lateral that is treated to ensure the fluid remains in the wellbore and is heated efficiently. When built, each loop will be filled with a fluid formulated to conduct geothermal energy to the surface where it will be used for home heating during the cold months, and electric generation during warmer ones. The differences often reflect the vagaries of regulation. Fervo is building its 400 MW geothermal electric plant, Cape Station, 500 miles from its initial customers at a site in southern Utah where the quality of the formation was already known because it adjoins the US geothermal test site commonly known as FORGE. Also, the remote desert site minimizes the likelihood of opposition to drilling and fracturing, which is not the case in California which has banned fracturing.

The research of corrosion behaviour and protection of 3Cr pipes in gas injection wells with oxygen flooding

The research of corrosion behaviour and protection of 3Cr pipes in gas injection wells with oxygen flooding

Lipotransfer Under Ultrasound-guided Helium Pneumodissection With Closed Lipotransfer Equipment.

Gluteal hypoplasia and ptosis reduction are common concerns among patients seeking optimal body contouring in Peru and other countries. Although silicone implants are a traditional solution, they are not suitable for all patients. Fat grafting has emerged as an alternative, with various techniques aimed at enhancing fat graft viability and patient safety. We conducted a study to evaluate the effectiveness and safety of ultrasound-guided helium pneumodissection for gluteal-hip contouring. Between January 2021 and December 2022, 220 patients with varying degrees of gluteal hypoplasia were treated using ultrasound-assisted helium pneumodissection. The amount of fat grafted ranged from 200 to 1500 mL per buttock, with most patients receiving 701-800 mL. The integration of color Doppler ultrasound allowed for precise visualization throughout the procedure and safe placement of fat grafts. Helium pneumodissection facilitated efficient fat graft injection with reduced resistance at the recipient site. Mild complications included temporary hyperthermia in 4.5% of patients and one instance of retraction in the lower quadrant of the right buttock. Ultrasound-guided helium pneumodissection for gluteal-hip contouring demonstrates significant advantages in patient safety, fat graft viability, and overall satisfaction. This advanced technique allows for efficient fat injection with reduced resistance in the subcutaneous plane, minimizing the risk of deep plane injections into the muscle. Although occasional mild complications were observed, they were manageable and did not compromise the overall safety of the technique.

Can section 45Q tax credit foster decarbonization? A case study of geologic carbon storage at Acid Gas Injection wells in the Permian Basin

Carbon capture, utilization, and storage (CCUS) is an important pathway for meeting climate mitigation goals. While the economic viability of CCUS is well understood, previous studies do not evaluate the economic feasibility of carbon capture and storage (CCS) in the Permian Basin specifically regarding the new Section 45Q tax credits. We developed a technoeconomic analysis method, evaluated the economic feasibility of CCS at the acid gas injection (AGI) wells, and assessed the implication of Section 45Q tax credits for CCS at the AGIs. We find that the compressors, well depth, and the permit and monitoring costs drive the facility costs. Compressors are the predominant contributors to capital and operating expenditure driving the levelized cost of CO2 storage. Strategic cost reduction measures identified include 1) sourcing of low-cost electricity and 2) optimizing operational efficiency in well operations. In evaluating the impact of the tax credits on CCS projects, facility scale proved decisive. We found that facilities with an annual injection rate exceeding 10,000 MT storage capacity demonstrate economic viability contingent upon the procurement of inputs at the least cost. The new construction of AGI wells were found to be economically viable at a storage capacity of 100,000 MT. The basin is heavily focused on CCUS (tax credit – $65/MT CO2), which overshadows CCS ($85/MT CO2) opportunities. Balancing the dual objectives of CCS and CCUS requires planning and coordination for optimal resource and pore space utilization to attain the basin's decarbonization potential. We also found that CCS on AGI is a lower cost CCS option as compared to CCS on other industries.

Enhanced aerobic bioremediation of an aquifer heavily contaminated with a mixture of chlorobenzenes and hexachlorocyclohexanes at the Sardas landfill (Spain)

The groundwater at the Sardas landfill in Huesca, Spain, is contaminated with benzene, chlorobenzenes, and hexachlorocyclohexane (HCH) isomers due to illegal waste dumping from a former lindane factory. In this study, microcosms using field-derived groundwater to evaluate in situ bioremediation were constructed. Anaerobic biostimulation with lactate successfully transformed α-, β-, δ-, and γ-HCH within two weeks, but failed to degrade benzene and less chlorinated benzenes, even with nutrient addition. In contrast, aerobic biostimulation led to rapid degradation of benzene, chlorobenzenes, and α-, δ-, and γ-HCH. Notably, adding a phosphorus source significantly increased the degradation rates. Following these laboratory results, an in situ pilot test using the oxygen-releasing compound CaO2 was conducted at two site injection wells. The field results mirrored those from the microcosms, showing a marked reduction in contaminants at both the injection wells and surrounding wells. Bacterial community analysis based on the 16S rRNA genes in samples derived from aerobic microcosms and groundwater before and after the biostimulation test revealed a marked increase in the genus Pseudomonas, suggesting its potential role as biodegrading agent. This study illustrates the effectiveness of biostimulation as a viable strategy for treating groundwater contaminated with HCH isomers, benzene, and chlorobenzenes.

The role of structural compartmentalization in carbon storage site selection in Permian (Rotliegend Group) reservoirs in the Southern North Sea

The Southern North Sea (SNS) gas basin is a key area for CO 2 storage projects in the UK. Many of the now-depleted Permian (Rotliegend) Leman Sandstone Formation fields are being re-evaluated as carbon stores. However, the reservoir is known to be highly faulted, often leading to field compartmentalization. This has historically impacted field development and production, and will challenge suitability for CO 2 storage by limiting site capacity, requiring a high number of injector wells, and increasing capital costs. It is necessary to understand the nature of these pressure compartments - and whether any individual culmination can house sufficient capacity - before devising a carbon storage development programme. The highly compartmentalized Indefatigable (Inde) Field was evaluated as a case study. A static model of the field was constructed using 3D seismic and well log data, and subsequently used to calculate the CO 2 capacity of each of the 12 compartments. Five compartments were found to have capacities larger than 10 Mt, with the large Main Horst found to host 51% of total CO 2 capacity. A sequential filling-and-sealing storage site development plan is suggested based on the evaluation and ranking of these compartments.