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A band design of a quantum cascade laser with a generation frequency higher than 6 THz and an active region based on four GaAs/Al0.14Ga0.86As quantum wells is proposed. Calculations were carried out based on the solution of the Schrödinger equation taking into account the dephasing of quantum states, as well as a closed system of balance equations. The temperature dependences of the gain at frequencies of 6.3–6.6 THz were calculated for the proposed quantum cascade laser with a double metal waveguide. Features of the proposed laser structure include two injection quantum wells and the suppression of non-radiative transitions between laser levels. According to calculations, this provides the maximum operating temperature of up to 81 K at 6.4 THz. The results of this study open up the way for quantum cascade lasers based on GaAs/AlGaAs to operate at frequencies above 6 THz. [ABSTRACT FROM AUTHOR]

Recent experimental results showed that an electron gas in an asymmetrical double barrier heterostructure can be effectively cooled down under resonant tunneling condition, thus leading to the realization of an electronic cooler. The cooling process is a multi-parameters phenomenon and it is desirable to handle this problem through a reasonably simple approach, in order to understand the role of each parameter. To this end, we present a rate equation modeling of the electron cooling. We model the resonant tunnel injection of the electrons in the well and their thermionic emission assisted by Longitudinal Optical (LO) phonons absorption and emission. The influence of several parameters on the electronic temperature is discussed. This simple model compares rather well to the predictions of non-equilibrium Green function approach and to the experiments. [ABSTRACT FROM AUTHOR]

ABSTRACT Hepatitis C virus (HCV) causes substantial morbidity and mortality, particularly among people who inject drugs (PWID). While elimination of HCV as a public health problem may be possible through treatment‐as‐prevention, reinfection can attenuate the impact of treatment scale‐up. There is a need to better understand the distribution and temporal trends in HCV infection risk, including among HCV‐seropositive individuals who will be eligible for treatment and at risk for subsequent reinfection. In this analysis of 840 seronegative and seropositive PWID in Baltimore, MD USA, we used random forest methods to develop a composite risk score of HCV infection from sociodemographic and behavioural risk factors. We characterised the individual heterogeneity and temporal trajectories in this composite risk score using latent class methods and compared that index with a simpler, conventional measure, injection drug use frequency. We found that 15% of the population remained at high risk of HCV infection and reinfection by the composite metric for at least 10 years from study enrolment, while others experienced transient periods of moderate and low risk. Membership in this high‐risk group was strongly associated with higher rates of HCV seroconversion and post‐treatment viraemia, as a proxy of reinfection risk. Injection frequency alone was a poor measure of risk, evidenced by the weak associations between injection frequency classes and HCV‐associated outcomes. Together, our results indicate HCV infection risk is not equally distributed among PWID nor well captured by injection frequency alone. HCV elimination programmes should consider targeted, multifaceted interventions among high‐risk individuals to reduce reinfection. [ABSTRACT FROM AUTHOR]

Phonon lasers, as mechanical analogues of optical lasers, are unique tools for not only fundamental studies of the emerging field of phononics but also diverse applications such as deep-ocean monitoring, force sensing, and biomedical ultrasonics. Recently, nonlinear phonon-lasing effects were observed in an opto-levitated micro-sphere, i.e., the spontaneous emerging of weak signals of high-order phonon harmonics in the phonon lasing regime. However, both the strengths and the quality factors of the emerging phonon harmonics are very poor, thus severely hindering their potential applications in making and utilizing nonlinear phonon-laser devices. Here we show that, by applying a single-colour electronic injection to this levitated system, giant enhancement can be achieved for all higher-order phonon harmonics, with more than 3 orders enhanced brightness and 5 orders narrowed linewidth. Such an electronically-enhanced phonon laser is also far more stable, with frequency stability extended from a dozen of minutes to over 1 h. More importantly, higher-order phonon correlations, as an essential lasing feature, are confirmed to be enhanced by the electronic injection as well, which as far as we know, has not been reported in previous works using this technique. This work, providing much stronger and better-quality signals of coherent phonon harmonics, is a key step towards controlling and utilizing nonlinear phonon lasers for applications such as phonon frequency combs, broadband phonon sensors, and ultrasonic bio-medical diagnosis. [ABSTRACT FROM AUTHOR]

The gas lift technique applies gas bubble injection into the vertical wells to raise production. Gas and liquid rates, shifts in flow regimes, and system equilibrium influence this process. This study explores the efficient implementation of gas lift techniques to maximize production from the Asmari Formation in the Abu Ghirab Field, southeastern Iraq, using a continuous gas lift for maximum production rate by PIPESIM TM software. The results of the gas lift design for the four wells (AGCS-33, 26, 28, and 36) show that the Vogel method provided the best results for the gas lift design, and faults and facies distribution impact the gas lift injection and oil production rates. These will become evident with wells AGCS-33 and 36 as their proximity to faults will increase oil production rates with a gas injection rate limit of 7 MMSCF/d. Conversely, for wells 26 and 28, the limit will marginally rise, starting at 5 MMSCF/d. In addition, the effect of gas lift is clearly in the middle western of the crest, which shows an increasing percentage of oil production of 136.6% at minimum rate and 198.5% at maximum for the well AGCS-26, 89.7% and 105.7% for the well AGCS-36. Wellhead pressure has a significant impact on gas-lift performance, and improving gas-lift efficiency can be accomplished using an electric control valve. The feasibility of implementing gas lift in the Asmari Formation depends on the water cut, well location, and water saturation distribution within the Formation. [ABSTRACT FROM AUTHOR]

It is suggested that in addition to seismicity deep fluid injection may cause surface uplift and subsidence in oil and gas‐producing regions. This study uses the Raton Basin as an example to investigate the hydromechanical processes of surface uplift and subsidence during wastewater injection. The Raton Basin, in southern central Colorado and northern central New Mexico, has experienced wastewater injection related to coalbed methane and gas production starting in 1994. In this study, we estimate the extent and magnitude of total vertical deformation in the Raton Basin from 1994 to 2020 and incremental deformation between the years 2017 to 2020. Results indicate a modeled uplift as much as 15 cm occurring between 1994 and 2020. Between 2017 and 2020, up to 3 cm of uplift occurred, largely near the northwestern injection wells. Most modeled uplift between 1994 and 2020 occurred near the southern wells, where the greatest cumulative volume of wastewater was injected. However, modeled subsidence occurred around the southern and eastern wells between 2017 and 2020, after the rate of injection decreased. Modeling indicates that while the magnitude of modeled uplift corresponds to cumulative injection volume and maximum rate in the long‐term, short‐term incremental deformation (uplift or subsidence) is controlled by changes in the rate of injection. The number of yearly earthquake events follows periods of rapid modeled uplifting throughout the Basin, suggesting that measurable surface deformation may be caused by the same injection‐induced pore pressure perturbations that initiate seismicity. [ABSTRACT FROM AUTHOR]

Hydraulic fracture, natural fracture and fracture networks play a vital role for heat mining of Enhanced Geothermal System (EGS). In this work, a two-dimensional thermo-hydro-mechanical (THM) EGS model was proposed to investigate the effect of natural fracture on heat extraction performance. Based on the local thermal non-equilibrium theory and discrete natural fracture network, the spatial and temporal distribution of temperature, pore pressure, effective stress, rock matrix porosity and permeability are investigated. The results show that the natural fracture has a significant negative effect on the production temperature. After the 40-year prediction, the production temperature of the base model is 45.5°C lower than that of the without natural fracture model. In the initial operation stage, the low-temperature region is mainly distributed in the region of artificial fracture and injection well, then it expands significantly to the natural fracture due to the stress redistribution. The key parameters of quantity and orientation of natural fracture can lead to a decline in production temperature and earlier thermal breakthroughs within the thermal reservoir. [ABSTRACT FROM AUTHOR]

The hydraulic conductivity of aquitard is difficult to assess, yet its accurate determination is critical to understanding the hydraulic connections of a multi-layered aquifer system. A new method called the single-well water injection test is proposed for estimating the hydraulic conductivity of an aquitard in a multi-layered aquifer system. Considering the influence of the overlying and the underlying aquifers, the stable well flow formula was deduced according to the water injection test using a mirror-image method. Also, the method was applied in a field test in Nantong City, China. The calculated hydraulic conductivity of the aquitard was consistent with results of the laboratory and field tests, which illustrates the correctness and engineering applicability of the proposed method. The proposed method is simple and easy to implement, and field examples demonstrate the potential applications of the proposed method in determining the hydraulic conductivity of aquitards. [ABSTRACT FROM AUTHOR]

The geometry of an orifice is a major determinant of nozzle internal flow and cavitation, which directly govern spray atomization and consequently affect combustion and fuel economy in internal combustion engines. In this study, simulation models of the nozzle at different angles between the normal and the injection hole inlet cross-section and the injection hole axis, as well as with different injection hole cone angles (a positive angle between the injection hole axis and its walls implies a divergent hole), were investigated by means of a previously developed numerical model that was validated based on experimental data from X-ray image technology. The results indicate that as the angle between the normal and the injection hole inlet cross-section and the injection hole axis increases, the cavitation asymmetry within the injection hole intensifies, accompanied by a decrease in the gas volume fraction. On one side of the injection hole, the hydraulic flip width expands, while, on the other side of the injection hole, the flow state gradually changes from hydraulic flip to super-cavitation flow, transitional cavitation and fully reattached flow. The divergent orifice layout intensifies cavitation, and the higher the positive injection hole cone angle, the bigger the hydraulic flip width. The convergent layout of the injection hole suppresses cavitation, and cavitation inside the nozzle disappears completely when the injection hole cone angle is less than −10°. [ABSTRACT FROM AUTHOR]

Commercial scale decarbonization through carbon capture and storage may likely involve many CO2 storage projects located in close proximity. The close proximity could raise concerns over caprock integrity associated with reservoir pressure buildup and interference among adjacent projects. Commercial-scale injection will also require large prospective CO2 storage resource and high injectivity in the targeted storage formations. To accommodate the need for both large resource and high injectivity, project operators could consider injecting CO2 into a stacked sequence of formations. This analysis investigates the benefits of injecting CO2 into a vertically stacked sequence of saline formations, over injecting the same amount of CO2 into a single saline formation, in addressing these challenges. Our analysis shows that injecting into the stacked sequence mitigates the extent of pressure buildup among the stacked formations, while still achieving the same or greater target CO2 storage volumes. Among cases modeled, the resulting pressure buildup front is most reduced when each storage site distributes injection volumes over several wells, each of which injects a portion of the total CO2 mass across the stacked sequence. This favorable case not only results in the smallest CO2 aerial footprint, but also shows the largest reduction in the pressure buildup at the top of perforation at the injection wells (upwards of approximately 46% compared to the single-formation storage), the result of which is crucial to maintain caprock integrity. This analysis provides insights into required decision-making when considering multi-project deployment in a shared basin. [ABSTRACT FROM AUTHOR]

The spatiotemporal evolution of earthquakes induced by fluid injections into the subsurface can be erratic owing to the complexity of the physical process. To effectively mitigate the associated hazard and to draft appropriate regulatory strategies, a detailed understanding of how induced seismicity may evolve is needed. In this work, we build on the well-established continuous-time random walk (CTRW) theory to develop a purely stochastic framework that can delineate the essential characteristics of this process. We use data from the 2003 and 2012 hydraulic stimulations in the Cooper Basin geothermal field that induced thousands of microearthquakes to test and demonstrate the applicability of the model. Induced seismicity in the Cooper Basin shows all the characteristics of subdiffusion, as indicated by the fractional order power-law growth of the mean square displacement with time and broad waiting-time distributions with algebraic tails. We further use an appropriate master equation and the time-fractional diffusion equation to map the spatiotemporal evolution of seismicity. The results show good agreement between the model and the data regarding the peak earthquake concentration close to the two injection wells and the stretched exponential relaxation of seismicity with distance, suggesting that the CTRW model can be efficiently incorporated into induced seismicity forecasting. [ABSTRACT FROM AUTHOR]

Intraplate earthquakes induced by anthropogenic fluid injection present unexpected seismic risk to previously quiescent or low seismicity-rate regions. Despite many studies of induced seismicity, there are relatively few with detailed openly accessible constraints on the interaction between seismic sources and subsurface structures. In this study of the Raton Basin, we refine source observations from a dense nodal array and constrain basin structure using teleseismic receiver functions. The cross-correlation-based relocated hypocentres and a new set of focal mechanisms light up active fault segments and show clear spatiotemporal patterns. The geometric complexity of reactivated fault clusters appears greatest near higher rate injection wells. Simpler normal fault structure is found farther from injection wells and near abrupt structural transitions suggested by receiver functions. While less induced seismicity in the crystalline basement is expected when injection is >1 km from the top of the basement (like Raton), our receiver function analysis identified a basin thickness ~3 km beneath the nodal array and lateral variations in sedimentary structures. Our results explain potential fluid connectivity between the injection depths focused at ~1–1.5 km below the surface and basement fault activity that begins at ~3 km and reaches peak activity at ~4–8 km depths. This article is part of the theme issue 'Induced seismicity in coupled subsurface systems'. [ABSTRACT FROM AUTHOR]

Induced seismicity poses a challenge to the development of Enhanced Geothermal Systems (EGS). Improving monitoring and forecasting techniques is essential to mitigate induced seismicity and thereby fostering a positive perception of EGS projects among local authorities and population. Induced seismicity is the result of complex and coupled thermo-hydro-mechanical-chemical mechanisms. Injection flux and pressure are crucial controlling parameters for both hydraulic stimulation and circulation protocols. We develop a methodology combining a hydro-mechanical model with a seismicity rate model to estimate the magnitude and frequency of mainshocks and aftershocks induced by fluid injection. We apply the methodology to the case of the Basel EGS (2006, Switzerland) to compare the effects of progressive, cyclic and constant injections on the mechanical response of discrete faults. Results from the coupled hydro-mechanical models show that the pore pressure diffusion and consequent enhancement of fault permeability are limited to the vicinity of the injection well during cyclic injection. Additionally, constant injection induces seismicity from the start of the injection but enhances the permeability of most of the faults within a shorter duration, inducing less post-injection seismicity. The methodology can be adapted to any numerical model and allows new projects to be developed by anticipating the safest injection protocol. This article is part of the theme issue 'Induced seismicity in coupled subsurface systems'. [ABSTRACT FROM AUTHOR]

Understanding flow behavior in a geothermal reservoir is important for managing sustainable geothermal energy extraction. Fluid flow in geothermal reservoirs generally occurs in complex existing fracture systems in which the reservoirs are situated in highly fractured rocks. To simulate a discrete fracture model, the location and orientation of the fracture were computed using statistical processes and observational data. In many cases, estimating the location and orientation of fractures from 1D borehole logging data is challenging. In this study, we used microseismic data to build the fracture network systems and extract the detailed positions and dimensions of the fractures. We used the microseismic data recorded at the Okuaizu Geothermal Field, Fukushima Prefecture, Japan, from 2019 to 2021. First, we located the hypocenters, removing the effect of uncertainty in the velocity structure of the geothermal fluids. We relocated and clustered the seismic events based on waveform similarity. We analyzed each cluster to define the fracture orientation using principal component analysis (PCA) and focal mechanism (FM) analysis. We used the P polarity with the S/P ratio as a constraint for a better fault-plane solution. With PCA, we can extract the fracture dimension of each cluster. Our cluster analysis showed that the clusters were not always planar fractures, and we interpreted them as fracture zones. Based on the consistency between PCA and FM, each cluster/fracture zone was classified into three conceptual models to characterize the fracture network system in this field. This model showed variations in the orientation of small fractures within the fracture zone. We characterized the spatial variation in fracture distribution and orientations in the reservoir and demonstrated the fracture network system of this field. The fracture zone near the injection well has a N–S strike, and the dip is above 80°; however, the fracture zone in the northeastern part of the injection well has a NW–SE strike with a dip between 60° and 80°. The fracture network system estimated in this study is crucial for robust reservoir modeling because our model is more realistic, observation-orientated, and includes local anomalies of reservoir properties. [ABSTRACT FROM AUTHOR]

In this work, for the first time, the specific impedances of various injection solutions as well as the surface and tissue impedance after injection of these solutions were analyzed and compared regarding the radio-frequency surgical cutting process. The impedances of 0.9% NaCl, 4% gelatine, 6% hydroxyethyl starch, 10% glycerol/5% fructose, 10% glucose, 5% and 20% albumin, blood, and blood plasma as well as aqua destillata have been tested in vitro. Even if EMR and ESD are routinely used in clinical practice, there is so far no easy, fast, and safe method to remove larger lesions en bloc. We show that the impedance of the injected solution shows to be a crucial factor for safe removal, especially of larger lesions (Ø > 20 mm) and more importantly in accordance with the requirements of oncology and pathology. Key messages: Impedance is playing a crucial factor in the radio-frequency (RF)-surgery. With a higher Impedance there will be less current necessary to reach the aimed voltage. Injection solution Aqua destillata and 10% Glucose, show significantly higher Impedances. Higher impedances lead to less surgical related complications. Minor changes in existing method to improve patent safety. [ABSTRACT FROM AUTHOR]

Purpose: With the development of fracturing technology, the research of multi-well hydrofracturing becomes the key issue. Frac-hits in multi-well hydrofracturing has an important effect on fracture propagation and final production of fractured well; in the process of hydrofracturing, there are many implement parameters that can affect frac-hits, and previous studies in this area have not systematically targeted the influence of a single parameter on multi-well hydrofracturing. Therefore, it is of great significance to study the occurrence rule and influence of frac-hits for optimizing the design of fracturing wells. Design/methodology/approach: Based on the proposed numerical models, the effects of different fracturing implement parameters (perforation cluster spacing, well spacing and injection rate) on frac-hits are compared in numerical cases. Through the analysis of fracture network, stress field and microseismic, the effects of different fracturing implement parameters on frac-hits and connections are compared. Findings: The simulation results show that the effect of perforation cluster spacing and well spacing on frac-hits is greater than that of injection rate. Smaller well spacing makes it easier for fractures between adjacent wells to interact with each other, which increases the risk of frac-hits and reduces the risk of fracture connections. Smaller perforation cluster spacing results in larger individual fracture lengths and greater deflection angles, which makes the possibility of frac-hits and connections greater. The lower the injection rate, the lower the probability of frac-hits. Originality/value: In this study, the influence of different fracturing implement parameters on frac-hits and connections in multi-well hydrofracturing is studied, and the mechanism of frac-hits and connections is analyzed through fracture network, stress field and microseismic analysis. Different simulation results are compared to optimize fracturing well parameter design and provide reference for engineering application. [ABSTRACT FROM AUTHOR]

Enhanced geothermal systems (EGSs) are expected to be one of the most promising methods of supplying energy to meet the world's increasing energy demand. However, little attention has been paid to the influence of the number of production wells on the heat extraction performance of an EGS. A series of numerical simulations is organized in this work with three cases: Case 1 (one production well), Case 2 (two production wells), and Case 3 (three production wells). The results indicate that a slight temperature difference exists among the three simulation cases at the planes X-Y (Z = 0) and Y-Z (X = 0), while Case 1 ensures a greater cooling area, and the more production wells, the smaller the cooling area during the heat extraction in plane X-Z (Y = 0). In addition, the continuous injection of cooling water from the injection well and its arrival at different reference points enable the temperature at each point to declining with a variable amplitude of variation. This work also sets an efficiency (ef) to investigate the temperature variation in the EGS, where Case 1 exhibits a similar variation as Case 2, which is also similar to Case 3. It is hoped that this work will play a guiding role in EGS-related exploration and exploitation. [ABSTRACT FROM AUTHOR]

Aged hydrocarbon wells, if proper care is not ensured, can crack, get corroded, and leak subsurface fluids. Permian Basin in Texas, home to thousands of such wells, has seen numerous blowouts and wastewater leaks. Our study employs surface deformation derived from satellite observations, and injection well records to investigate these events. The results reveal an over‐pressurized wastewater aquifer producing a surface uplift of 20 cm/yr, likely due to wastewater being injected tens of kilometers away. Focusing on a January 2022 blowout resulting in 3 cm subsidence in 2 weeks, our geophysical model suggests aquifer over‐pressurization as the cause. With an excess pressure of over 3 MPa in the aquifer, several more such blowouts are possible in the near future. This research highlights the urgent need to better understand the impact of subsurface fluid injection and calls for prompt action to mitigate the environmental effects of oil and gas production. Plain Language Summary: Wastewater, a byproduct during oil extraction, is generally injected back into the ground. Permian Basin has witnessed several incidents of leakage of wastewater in the last 3 years. Recently in January 2022, huge amounts of wastewater were expelled at a high pressure from an old well. We used satellite data and wastewater injection data to understand the cause of these events. We found that the wastewater injection happening nearly several kilometers away is responsible for these leakages. We also discovered a highly pressurized wastewater lake below the surface in this region using geophysical modeling. Due to high pressures, the land in this region rose by 40 cm in just 2 years. Meanwhile, a part of this region sunk by 3 cm because of the leakage in January 2022. Our findings raise concerns about the potential for more leakages in the near future if action is not taken. Key Points: We utilized satellite observations of land surface deformation to explore the subsurface anomalies in the Permian BasinWe established a significant link between wastewater injection and oil well blowouts in the Permian BasinWe discovered an over‐pressurized aquifer responsible for the reported blowouts, with a potential for more blowouts in the near future [ABSTRACT FROM AUTHOR]

A versatile vapor generation module has been developed for both field-based water vapor isotope calibrations and laboratory-based liquid water isotope measurements. The vapor generation module can generate a stream of constant vapor at a wide variety of humidity levels spanning 300 to 30 000 ppmv and is fully scalable, allowing in principle an unlimited number of standards or samples to be connected to a water vapor isotope analyzer. This versatility opens up the possibility for calibrating with multiple standards during field deployment, including examining instrument humidity–isotope dependence. Utilizing the ability to generate an uninterrupted constant stream of vapor, we document an Allan deviation for 17O -excess (Δ17O) of less than 2 per meg for an approximate 3 h averaging time. For similar averaging time, the Allan deviations for δ17O , δ18O , δ D, and d-excess are 0.004 ‰, 0.005 ‰, 0.01 ‰, and 0.04 ‰, respectively. Measuring unknown samples shows that it is possible to obtain an average standard deviation of 3 per meg for Δ17O and an average standard error (95 % confidence limit) of 5 per meg. Using the vapor generation module, we document that an increase in the Allan deviation above the white noise level for integration times between 10 min and 1 h is caused by cyclic variations in the cavity temperature, which if improved upon could result in an improvement in liquid sample measurement precision of up to a factor of 2. We further argue that increases in Allan deviation for longer averaging times could be a result of memory effects and not only driven by instrumental drifts as it is often interpreted. The vapor generation module as a calibration system has been documented to generate a constant water vapor stream for more than 90 h, showing the feasibility of being used to integrate measurements over much longer periods than achievable with syringe-based injections as well as allowing the analysis of instrument performance and noise. Using clean in-house standards, we have operated the vapor generation module daily for 1–3 h for more than 6 months without the need for maintenance, illustrating its potential as a field-deployed autonomous vapor isotope calibration unit. When operating the vapor generation module for laboratory-based liquid water isotope measurements, we document a more than 2 times lower memory effect compared to a standard autosampler system. [ABSTRACT FROM AUTHOR]

The reaction between the lixiviant and the minerals in the aquifer of In-situ uranium leaching (ISL) will result mineral dissolution and precipitation. ISL will cause changes in the chemical composition of groundwater and the porosity and permeability of aquifer, as well as groundwater pollution. Previous studies lack three-dimension numerical simulation that includes a variety of minerals and considers changes in porosity and permeability properties simultaneously. To solve these problems, a three-dimensional reactive transport model (RTM) which considered minerals, main water components and changes in porosity and permeability properties in Bayanwula mine has been established. The results revealed that: (1) Uranium elements were mainly distributed inside the mining area and had a weak trend of migration to the outside. The strong acidity liquid is mainly in the mining area, and the acidity liquid dissolved the minerals during migrating to the outside of the mining area. The concentration front of major metal cations such as K+, Na+, Ca2+ and Mg2+ is about 150m away from the boundary. (2) The main dissolved minerals include feldspar, pyrite, calcite, sodium montmorillonite and calcium montmorillonite. Calcite is the most soluble mineral and one of the sources of gypsum precipitation. Other minerals will dissolve significantly after calcite is dissolved. (3) ISL will cause changes in porosity and permeability of the mining area. Mineral dissolution raises porosity and permeability near the injection well. Mineral precipitation reduced porosity and permeability near the pumping well, which can plugging the pore throat and affect recovery efficiency negatively. [ABSTRACT FROM AUTHOR]

The space of production well plays a crucial role in the heat extraction performance of the Enhanced Geothermal System (EGS), which have the potential to meet the growing global energy demand as a reliable energy source. Nonetheless, there has been insufficient research and attention focused on comprehending the impact of the space of production well on the efficiency and effectiveness of EGS. In this work, a series of numerical simulations were conducted to assess the impact of the space of production well on heat extraction efficiency in EGS. Three different cases were considered: Case 50 with 50 m production well spacing, Case 100 with 100 m production well spacing, and Case 150 with 150 m production well spacing. At the X-Y plane and Y-Z plane, the simulation results indicated that there were slight differences in temperature variation among the Case 50, Case 100 and Case 150. And the cooling area decreasing as the spacing of production wells decreased. Moreover, the delivery of cooling water via the injection well and its subsequent distribution to various reference points lead to a decline in temperature at each point, albeit with varying degrees of variation. Besides, the established efficiency (ef) for Case 50 is smaller than the Case 100 and Case 150 during the last 15 years. These findings contribute valuable insights to the exploration and exploitation of EGS systems and can serve as a guide for further research in this field. [ABSTRACT FROM AUTHOR]

Gas injection for enhanced oil and gas reservoir recovery is a crucial method in offshore Carbon Capture, Utilization, and Storage (CCUS). The B6 buried hill condensate gas reservoir, characterized by high CO2 content, a deficit in natural energy, developed fractures and low-pressure differentials between formation and saturation pressures, requires supplementary formation energy to mitigate retrograde condensation near the wellbore area through gas injection. However, due to the connected fractures, the B6 gas reservoir exhibits strong horizontal and vertical heterogeneity, resulting in severe gas channeling and a futile cycle, which affects the gas injection efficiency at various levels of fracture development. Based on these findings, we conducted gas injection experiments and numerical simulations on fractured cores. A characterization method for oil and gas relative permeability considering dissolution was established. Additionally, the gas injection development boundary for this type of condensate gas reservoir was quantified according to the degree of fracture development, and the gas injection mode of the B6 reservoir was optimized. Research indicates that the presence of fractures leads to the formation of a dominant gas channel; the greater the permeability difference, the poorer the gas injection effect. The permeability gradation (fracture permeability divided by matrix permeability) in the gas injection area should be no higher than 15; gas injection in wells A1 and A2 is likely to achieve a better development effect under the existing well pattern. Moreover, early gas injection timing and pulse gas injection prove beneficial in enhancing the recovery rate of condensate oil. The study offers significant guidance for the development of similar gas reservoirs and for reservoirs with weakly connected fractures; advancing the timing of gas injection can mitigate the retrograde condensation phenomenon, whereas initiating gas injection after depletion may reduce the impact of gas channeling for reservoirs with strongly connected fractures. [ABSTRACT FROM AUTHOR]

The characteristics of geological reservoirs are an important means to evaluate the feasibility of water injection development. The differences in reservoir characteristics in different regions make it difficult to scale up the promotion of water injection development parameters. A more effective way is to establish efficient water injection development methods and strategies suitable for the region. Therefore, based on the geological characteristics of the Wucangbao Chang 6 and Chang 9 oil reservoirs, the feasibility of water injection development in Wucangbao reservoir is analyzed from several aspects such as interstitial material content, reservoir hydrophilicity, and stress sensitivity. The water injection parameters of Wucangbao Chang 6 and Chang 9 single wells are calculated using methods such as apparent flow rate method, permeability and single well productivity regression method, and stratigraphic series curve regression method, respectively. The water injection parameters are obtained based on the single well production. The results show that the Wucangbao Chang 6 and Chang 9 reservoirs have good water injection feasibility and prospects in terms of sandstone cement, reservoir fluid properties, wettability, and water flooding efficiency; And the production of single well Chang 6 is 1.5-4.0 t/d, while the production of single well Chang 9 is 2.0-4.5 t/d; According to the injection production balance, the initial single well injection volume of the Wucangbao Chang 6 layer is 10 m3, and the initial single well injection volume of the Chang 9 layer is 20 m3, in order to maximize the recovery rate of the reservoir during the dry or low water cut period. [ABSTRACT FROM AUTHOR]

Global warming that has an impact on climate change is mostly influenced by an increase in carbon dioxide (CO2) gas in the air. Decarbonization programs in building green industry ecosystems play an important role in achieving Net Zero Emissions (NZE) by 2060. The Objective of the study is to investigate risk control in the Decarbonization program consisting of Carbon Reduction and Carbon Capture Utilization and Storage (CCUS). The focus of the study area in this research is the Donggi Matindok gas field in Central Sulawesi. The research method is to conduct a risk analysis of the decarbonization program implemented so that it can mitigate the risk of operation failure and safety. The results of the evaluation obtained that the carbon reduction program that has been carried out consists of gas processing innovations, energy efficiency, flaring reduction has a low risk with a reduction of 22% per year from the total CO2 produced. The application of the energy management system or ISO 50001 supports in maintaining energy performance so that energy efficiency can be achieved so that the carbon reduction program can be developed every period. Then for the implementation of the CCUS program has a medium to high risk with significant CO2 reduction potential, which later in this research will review the risk mitigation that needs to be prepared for project completion. CCUS programs that will be carried out are CCU Microalgae and CCS well Injection programs. Well targeted risk mitigation can help ensure that government efforts to support decarbonization programs are effective and successful in the long term. [ABSTRACT FROM AUTHOR]

Conventional coalbed methane (CBM) reservoir models for injection fall-off testing often disregard the quadratic pressure gradient's impact. This omission leads to discrepancies in simulating the transient behavior of formation fluids and extracting critical reservoir properties. Accurate determination of permeability, storability, and other properties is crucial for effective reservoir characterization and production forecasting. Inaccurate estimations can lead to suboptimal well placement, ineffective production strategies, and ultimately, missed economic opportunities. To address this shortcoming, we present a novel analytical model that explicitly incorporates the complexities of the quadratic pressure gradient and dual-permeability flow mechanisms, prevalent in many CBM formations where nanopores are rich, presenting a kind of natural nanomaterial. This model offers significant advantages over traditional approaches. By leveraging variable substitution, it facilitates the derivation of analytical solutions in the Laplace domain, subsequently converted to real-space solutions for practical application. These solutions empower reservoir engineers to generate novel type curves, a valuable tool for analyzing wellbore pressure responses during injection fall-off tests. By identifying distinct flow regimes within the reservoir based on these type curves, engineers gain valuable insights into the dynamic behavior of formation fluids. This model goes beyond traditional approaches by investigating the influence of the quadratic pressure gradient coefficient, inter-porosity flow coefficient, and storability ratio on the pressure response. A quantitative comparison with traditional models further elucidates the key discrepancies caused by neglecting the quadratic pressure gradient. The results demonstrate the proposed model's ability to accurately depict the non-linear flow behavior observed in CBM wells. This translates to more reliable pressure and pressure derivative curves that account for the impact of the quadratic pressure gradient. [ABSTRACT FROM AUTHOR]

There are many dissolved salt caverns in China, but most of the existing caverns cannot be used for gas storage directly, especially the huge number of horizontal old caverns. First, situations of the main existing old salt caverns in China were investigated, including the burial depth, thickness of the salt formations, grade of the salt layer, number of existing caverns, mining methods and inferred cavern shapes. Then, a typical process for screening and evaluating existing salt caverns was proposed, and then a new reconstruction method by drilling new wells between injection and production wells was introduced. Thirdly, theoretical analysis methods that can be used to evaluate the geotechnical feasibility of horizontal salt caverns were summarized. Finally, numerical simulation was carried out to study the geotechnical feasibility of the reconstructed horizontal cavern and the influencing law of the specific reconstructed measures. Some conclusions were drawn as follows: (1) For the reconstruction of horizontal salt cavern by drilling a new well between injection and production wells, the size of the newly solved cavern, operation time and internal pressure are the three most important influence factors; (2) Combined with the numerical simulation results, the surrounding rock of the horizontal cavern should mainly focus on the tensile and shear failure around the cavern and the instability of the key roof; (3) Compared with the method of drilling new wells outside the cavern, drilling new wells between wells are different in the displacement scope, volume shrinkage and plastic zone distribution. In summary, the introduced reconstruction can enlarge the small volume of existing horizontal old caverns, but more in-depth research and field engineering practice are needed to optimize the reconstruction method. [ABSTRACT FROM AUTHOR]

Simulation of subsurface energy system involves multi-physical processes such as thermal, hydraulical, and mechanical (THM) processes, and requires a so-called THM coupled modeling approach. THM coupled modeling is commonly performed in geothermal energy production. However, for hydrocarbon extraction, we need to consider multiphase flow additionally. In this paper, we describe a three-dimensional numerical model of nonisothermal two-phase flow in the deformable porous medium by integrating governing equations of two-phase mixture in the porous media flow in the reservoir. To account for inter-woven impacts in subsurface conditions, we introduced a temperature-dependent fluid viscosity and a fluid density along with a strain-dependent reservoir permeability. Subsequently, we performed numerical experiments of a ten-year water flooding process employing the open-source parallelized code, OpenGeoSys. We considered different well patterns with colder water injection in realistic scenarios. Our results demonstrate that our model can simulate complex interactions of temperature, pore pressure, subsurface stress and water saturation simultaneously to evaluate the recovery performance. High temperature can promote fluid flow while cold water injection under non-isothermal conditions causes the normal stress reduction by significant thermal stress. Under different well patterns the displacement efficiency will be changed by the relative location between injection and production wells. This finding has provided the important reference for fluid flow and induced stress evolution during hydrocarbon exploitation under the environment of large reservoir depth and high temperature. [ABSTRACT FROM AUTHOR]

Fracture-cavity carbonate reservoirs provide a large area, fracture development, high productivity, long stable production time, and other characteristics. However, after long-term exploitation, the lack of energy in the formation leads to a rapid decrease in production, and the water content in crude oil steadily increases, thereby disrupting normal production. To recover normal production, it is necessary to connect the cracks and pores that have not been affected during the original production, so as to allow the crude oil inside to enter the production cracks and replenish energy through methods such as hydraulic expansion of fracture-cavity carbonate rock. Accordingly, we propose hydraulic expansion techniques based on the following four processes for implementation: (1) applying high pressure to prevent a nearby fracture network from opening the seam, (2) connecting a distant fracture-cavity body, (3) breaking through the clay filling section of a natural fracture network, and (4) constructing an injection production well pattern for accelerating injection and producing diversion. Hydraulic fracturing involves closing or partially closing the original high-permeability channels, which usually produce a large amount of water, while opening previously unaffected areas through high pressure to increase crude oil production. We also introduce two composite techniques: (1) temporary plugging of the main deep fractures, followed by hydraulic expansion; and (2) capacity expansion and acidification/pressure processes. Hydraulic expansion allowed us to recover and supplement the formation energy and efficiently increase production. We tested various wells, achieving an effective hydraulic expansion rate of up to 85%. In addition, the productivity of conventional water injection and hydraulic expansion after on-site construction was compared for one well, clearly indicating the effectiveness of water injection and the remarkable crude oil increase after hydraulic expansion. [ABSTRACT FROM AUTHOR]

To avoid or mitigate the unwanted water and gas content, inflow control devices (ICDs) are designed and installed in the well to disturb the water and gas breakthrough which are trying to overtake the oil inflow, water and gas coning and sand production. Smart wells with permanent downhole valves such as ICDs are used to balance production and injection in wells. A paramount issue regarding using downhole control devices is determining the required cross-sectional area of them for control of the imposed pressure drop across the device to stabilize the fluid flow. Current methods for calculating the opening size of the ICDs are mainly based on sensitivity analysis of the ICD flow area or optimization algorithms coupled with simulation models. Although these approaches are quite effective in oil field cases, they tend to be time-consuming and require demanding system models. This paper presents a fast analytical method to determine the ICD flow area validated by a genetic algorithm (GA). Analytically, a closed-form expression is introduced by manipulating Darcy's law applicable to multi-layer injection wells with different layer properties to balance the injection profile in the reservoir pay zone, based on equalizing injected front velocity in layers with different permeability. Considering various scenarios of analytical technique, GA optimization, and sensitivity analysis scenarios for ICD cross-sectional area determination, results for oil recovery, water production, water breakthrough time, and net present value (NPV) are discussed and compared. NPV values obtained by both analytical and GA approaches are virtually identical and greater than those of other scenarios. Compared to the base field case, the analytical method improved the oil recovery by almost 1%, reduced water production by almost 91%, and synchronized the water breakthrough time of high- and low-permeability layers (from a ratio of 1.76–1.06). The proposed analytical solution proved to be capable of providing desirable results with only one reservoir simulation run in contrast to GA and sensitivity analysis scenarios which require iterative simulation runs. The proposed analytical solution outperformed the GA as it is less computationally demanding in addition to its success in case of lowering water production for the field data. The findings of this study can help for a better understanding of the situation where water injection into the oil reservoir is problematic as the layers present different permeabilities which can induce problems such as early water breakthrough from the more permeable layer and hinder the success of the water injection process. Using ICDs and a faster and more accurate approach to calculate its cross-sectional area such as the analytical method that was used in this study can greatly increase the success rate of water injection in case of oil recovery and lower the amount of the produced water. [ABSTRACT FROM AUTHOR]

Near miscibility widely exists in carbon dioxide (CO2) injection development projects. However, there is no existing approach to quantify the effect of near miscibility on oil recovery. In this paper, slim tube experiments were conducted to study near miscible region. The oil displacement efficiency curve is divided into immiscibility, near miscibility and miscibility. And three linear function is obtained, respectively. Then, the space between production well and CO2 injection well is discrete to characterize the effect of near miscibility on oil recovery. Then, a new approach is proposed to calculate oil recovery of CO2 displacement in tight oil reservoirs. This approach can calculate oil recovery considering near miscibility. It is found that minimum miscibility pressure (MMP) without considering near miscibility is 4 MPa lower than considering near miscibility. The near miscible pressure range is from 0.77 times to 1 time MMP considering near miscibility. Oil displacement efficiency difference reaches to be the maximum when the pressure is the minimum miscibility pressure without considering near miscibility. The maximum of the oil displacement efficiency difference is 3.4%. The optimal formation pressure considering near miscibility is 5 MPa larger than that without considering near miscibility. The oil recovery considering near miscibility is from 0.9 to 1.3% lower than that not considering near miscibility. It reaches to be the maximum when the pressure is the optimal formation pressure level without considering near miscibility. The maximum of the oil recovery difference is 1.3%. [ABSTRACT FROM AUTHOR]

Purpose. Increasing oil recovery from deposits and reducing the water content of producing wells by providing conditions for uniform displacement of oil from the reservoir under the influence of high reservoir pressure. Methodology. The purpose of the work is achieved by conducting theoretical and experimental studies of the process of creating high elastic energy in the formation by pumping water with injection well pumps to overcome the resistance of oil and water filtration through the pores of the rock and oil rise at the mouth of producing wells. The absence of pumps from producing wells and the acceptance of equal amounts of injection and production wells over the reservoir area significantly increases the reservoir pressure above the pressure of oil saturation with gas. Due to the significant elasticity of the rock and fluids under high reservoir pressure, the oil coverage with water increases and there is no premature breakthrough of water into producing wells. The possibility of creating high elastic energy in an oil reservoir by pumping water into injection wells has been experimentally studied. Findings. It has been established that high reservoir energy in the field of elastic deformation of rock and fluids can be created mainly by pumps from injection wells, due to which oil is uniformly displaced from the reservoir along the entire front without breaking through the injected water into producing wells along the path of least resistance. The adoption of equal amounts of producing and injection wells and their sequential arrangement in rows contributes to the development of high potential energy in the reservoir and increase the pick-up rate of injection and production wells. As a result, the skeleton of the rock forming the pores expands, and the water injected into the reservoir and the displaced oil accumulate and increase reservoir energy. Originality. The effectiveness of the proposed method for maintaining high reservoir pressure is achieved as a result of creating high energy of rock and fluids in the area of their elastic deflation and increasing the coverage coefficients of oil displaced by water over the area and profile of the productive formation without the use of additional capacities and pumping units from producing wells. Practical value. The developed new technique for maintaining high elastic reservoir pressure not lower than the pressure of oil saturation with gas by pumping water into the reservoir can be carried out in oil fields using standard technological equipment and increase oil recovery to 60–70 % at its existing values of 40–45 % and reduce the water content of produced oil to 0–10 % at its existing values of 20–80 % and above. [ABSTRACT FROM AUTHOR]

Martensitic and super martensitic stainless steels are widely used in the oil and gas industry for general corrosion mitigation in the presence of sweet corrosion (CO2) and sour corrosion (H2S), providing a cost-effective alternative to more expensive exotic corrosion-resistant alloys. Martensitic stainless steel is an approved material for construction when selecting tubular CO2 injection wells. This work aims to review the published literature on the subject of the operation limits of martensitic stainless steel and super martensitic stainless steel in high temperatures and high pressure under corrosive environments. Stress corrosion cracking (SCC) and sulfide stress corrosion cracking (SSCC) mechanisms on martensitic and super martensitic stainless steel surfaces are thoroughly analyzed. In this review paper, we have analyzed the factors that play a crucial role in passive film growth and passivity breakdown. The present work is to review the state of the art of mechanism responsible for SCC and SSCC susceptibility in different modified martensitic stainless steel materials, which are applied to the industry and lab scale. We have reviewed the effect of different concentrations of molybdenum content on SCC and SSCC susceptibility of conventional martensitic stainless steel, modified martensitic stainless steel, and super martensitic stainless steel. The effect of tempering temperature on the SCC and SSCC performance of the martensitic and super martensitic stainless steel was also studied. We also studied the effect of different concentrations of chromium on the improved corrosion-resistant properties and stability of passivation film. [ABSTRACT FROM AUTHOR]

This study pioneers a transformative approach to sustainable energy recovery, repurposing abandoned petroleum wells in the Nigerian Chad Basin as a triplet-deep closed-loop heat exchanger. We employed a computational numerical approach to designed two deep closed loop systems, which share a common production well, and to evaluate the thermal performance as well as its sustainability over a period of 25 years. The geometrical configuration consists of two injection wells, which converge to the common production one doubling the flow rate at surface and minimising the heat loss during the ascent of the fluid. The availability of detailed abandoned well specifications enabled us to constrain three-dimensional geological and thermal models of the undisturbed underground and, subsequently, to simulate numerically the production temperature and the thermal disturbance in the surrounding rocks. A comprehensive sensitivity analysis optimized the best operational design for total recovered thermal energy and uninterrupted heat recovery. When the deep close loop heat system operates with a fluid circulation rate of 0.03 m³s⁻1 and an injection temperature of 20 °C, it sustains a production temperature of over 100 °C, which generates total recovered thermal energy of 9730 TW th and 817 TW e over 25 years (9000 days). The average annual thermal and electricity productions of 389 TW th and 33 TW e , respectively, are more than the demand of the entire population of Magumeri district. The study's findings offer practical implications for policymakers, industry stakeholders, and local communities, emphasising the potential for socio-economic development while fostering environmental stewardship in the Nigerian Chad Basin. • Novel approach to developed three abandoned wells into deep borehole heat exchanger. • A comprehensive sensitivity analysis optimized the best operational design. • Periodic interchangeable operation between loop one and loop two is adopted. • Total recovered thermal energy of 9730 TWth was recovered • 817 TWe of electricity using geothermal binary plant was generated. [ABSTRACT FROM AUTHOR]

To help meet emission standards, hydrogen sulfide (H2S) from geothermal production may be injected back into the subsurface, where basalt offers, in theory, the capacity to mineralize H2S into pyrite. Ensuring the viability of this pollution mitigation technology requires information on how much H2S is mineralized, at what rate and where. To date, monitoring efforts of field‐scale H2S reinjection have mostly occurred via mass balance calculations, typically capturing less than 5% of the injected fluid. While these studies, along with laboratory experiments and geochemical models, conclude effective H2S mineralization, their extrapolation to quantify mineralization and its persistence over time leads to considerable uncertainty. Here, a geophysical methodology, using time‐domain induced polarization (TDIP) logging in two of the injection wells (NN3 and NN4), is developed as a complementary tool to follow the fate of H2S re‐injected at Nesjavellir geothermal site (Iceland). Results show a strong chargeability increase at +40 days, interpreted as precipitation of up to 2 vol.% based on laboratory relationships. A uniform increase is observed along NN4, whereas it is localized below 450 m in NN3. Changes are more pronounced with larger electrode spacing, indicating that pyrite precipitation takes place away from the wells. Furthermore, a chargeability decrease is observed at later monitoring rounds in both wells, suggesting that pyrite is either passivated or re‐dissolved after precipitating. These results highlight that a sequence of overlapping reactive processes (pyrite precipitation, passivation, pore clogging and possibly pyrite re‐dissolution) results from H2S injection and that TDIP monitoring is sensitive to this sequence. Plain Language Summary: High‐temperature geothermal production is responsible for air pollution due to hydrogen sulfide (H2S) present in the magmatic fluid. To help meet emission standards, H2S may be injected back into the subsurface, where basalt offers the capacity to transform H2S into pyrite. Transformation into an immobile mineral prevents further transport into the atmosphere, sea, surface streams, or lakes. However, ensuring the viability of this pollution mitigation technology requires information such as how much H2S is mineralized, at what rate and where, which are highly uncertain due to the heterogeneity and inaccessibility of subsurface processes. Here, a geophysical monitoring methodology is developed and tested during the re‐injection of H2S at Nesjavellir geothermal site in south‐west Iceland. According to laboratory studies, pyrite precipitation is expected to increase the electrical capacitance, "chargeability," of the subsurface. Using the so‐called time‐domain induced‐polarization (TDIP) method embedded in a wireline logging tool, the chargeability of a 2 m‐wide cylinder around the injection wells is measured with high spatial‐resolution before and during H2S injection. A strong chargeability increase at +40 days indicates that up to 2% pyrite is formed. A subsequent decrease at later rounds raises questions on whether pyrite is re‐dissolved or passivated by other secondary minerals. Key Points: H2S reinjection in basalt and mineralization into pyrite was monitored using TDIP logging in two of the injection wellsChargeability increases observed at +40 days (first monitoring round) correspond to 1%–2% pyrite precipitation with great spatial variabilitySubsequent monitoring rounds show a decrease in chargeability, suggesting that pyrite is either passivated or re‐dissolved [ABSTRACT FROM AUTHOR]

Waterflooding is a widely-used secondary oil recovery technique employed in the oil industry. In mature oil fields, waterflooding becomes increasingly essential in order to maximize oil recovery and extend field life, but optimizing its performance remains a complex and challenging task. In recent years, there has been growing interest in developing integrated approaches combining reservoir simulation, well modeling, and data-driven techniques to improve waterflood performance. The Capacitance–Resistance Model (CRM) has been proven to be a fast and effective tool for predicting waterflooding and reservoir characterization. Previous studies have successfully applied CRM to waterflood management to increase oil recovery. This paper develops a novel integrated and iterative workflow for waterflooding optimization in mature fields using the CRM for multilayer reservoirs equipped with Interval Control Valves (ICVs). The proposed approach, which integrates geological and well data with CRM results, was validated using a benchmark field model named the Olympus. This new workflow will help to put connected injection and production wells in different groups to reduce computational costs. In addition, this workflow can be used to determine the optimized number and proper location of the ICVs inside production wells. We determined the workover programs for existing wells, such as installing sensors and ICVs, deepening the wells, or plug-backs. Finally, it can be used for determining optimal water injection rates and well control strategies, such as valve openings in different production layers. As a result, the oil recovery factor increased, and the NPV was maximized, respecting the Olympus field's economic and operational constraints. [ABSTRACT FROM AUTHOR]

The article focuses on the potential of geothermal energy, particularly through Enhanced Geothermal Systems (EGS), which aim to harness deep Earth heat for electricity and heating/cooling. It discusses the historical context of geothermal technologies, the current state of EGS technology, including challenges and recent innovations, and initiatives like the FORGE project aimed at advancing EGS from experimental stages to commercial viability.

The data presented in this paper are related to the paper entitled "Optimal Estimation of Under-Frequency Load Shedding Scheme Parameters by Considering Virtual Inertia Injection", available in the Energies journal. Here, data are included to show the results of an Under-Frequency Load Shedding (UFLS) scheme that considers the injection of virtual inertia by a VSC-HVDC link. The data obtained in six cases which were considered and analyzed are shown. In this paper, each case represents a different frequency response configuration in the event of generation loss, taking into account the presence or absence of a VSC-HVDC link, traditional and optimized UFLS schemes, as well as the injection of virtual inertia by the VSC-HVDC link. Data for each example contain the state of the relay, threshold, position in every delay, load shed, and relay configuration parameters. Data were obtained through Digsilent Power Factory and Python simulations. The purpose of this dataset is so that other researchers can reproduce the results reported in our paper. Dataset: 10.5281/zenodo.11371324 Dataset License: Creative Commons Attribution 4.0 International (CC BY 4.0) [ABSTRACT FROM AUTHOR]

Earth system models are powerful tools to simulate the climate response to hypothetical climate intervention strategies, such as stratospheric aerosol injection (SAI). Recent simulations of SAI implement a tool from control theory, called a controller, to determine the quantity of aerosol to inject into the stratosphere to reach or maintain specified global temperature targets, such as limiting global warming to 1.5°C above pre‐industrial temperatures. This work explores how internal (unforced) climate variability can impact controller‐determined injection amounts using the Assessing Responses and Impacts of Solar climate intervention on the Earth system with Stratospheric Aerosol Injection (ARISE‐SAI) simulations. Since the ARISE‐SAI controller determines injection amounts by comparing global annual‐mean surface temperature to predetermined temperature targets, internal variability that impacts temperature can impact the total injection amount as well. Using an offline version of the ARISE‐SAI controller and data from Earth system model simulations, we quantify how internal climate variability and volcanic eruptions impact injection amounts. While idealized, this approach allows for the investigation of a large variety of climate states without additional simulations and can be used to attribute controller sensitivities to specific modes of internal variability. Plain Language Summary: Stratospheric aerosol injection (SAI) is a proposed climate intervention strategy that injects aerosols into the stratosphere to mitigate some climate change impacts. Several studies that have used climate models to investigate how the atmosphere may respond to SAI implement control algorithms to determine how much aerosol to inject and where in order to achieve certain climate targets. This work explores how changes to the controller input can impact the amount of aerosol injected. Here we focus on the controller from the Assessing Responses and Impacts of Solar climate intervention on the Earth system with Stratospheric Aerosol Injection (ARISE‐SAI) simulations. This specific controller uses the annual‐mean surface temperature to determine how much aerosol to inject. Therefore, internal variability that impacts temperature can impact the total injection amount as well. To quantify how patterns of internal variability impact how much aerosol is injected, we isolate the ARISE‐SAI controller and pass a variety of temperature patterns into it. While this method ignores some interactions between the controller and the climate simulation, it is a quick way to quantify the controller's sensitivity to a large variety of temperature patterns without additional simulations. Key Points: We quantify how the ARISE‐SAI controller responds to different patterns of internal variabilityThe impact from internal variability on the controller‐determined injection is dependent on the background warmingThis method provides a straight‐forward way to efficiently quantify controller sensitivity to internal variability [ABSTRACT FROM AUTHOR]

Extraction of high-temperature geothermal resources from reservoirs is a challenge due to the complex interactions between temperature, permeability, and stress fields. Variations in physical fields are critical to thermal reservoir engineering. In this study, the coupling mechanism between temperature, permeability, and stress fields is systematically explored using theoretical analyses and numerical simulations, by using the three-field coupling model. This study models the changes in porosity and permeability evolution during geothermal extraction, emphasizing the importance of the coupling term. The effects of pressure differences between injection and production wells, reservoir temperature variations, and fluid property changes on the temperature distribution and output thermal power within the geothermal reservoir were modeled and analyzed. The results reveal the significant effect of pressure differences between wells, and show that the geothermal extraction capacity of supercritical carbon dioxide (SC-CO2) is 1.83 times higher than that of water. Based on the statistical characteristics of the distribution pattern of natural fractures within the geothermal reservoir, the study simulated the distribution of natural fractures and developed a coupled thermo-hydro-mechanical (THM) model containing natural fractures. The results show that increasing the porosity of hydraulic and natural fractures can effectively increase the geothermal production capacity, especially the increase in the porosity of natural fractures is significant. These findings provide a key theoretical basis for understanding the THM coupling mechanism during geothermal extraction, and provide substantial support for optimizing the development and use of geothermal resources. [ABSTRACT FROM AUTHOR]

The coupled analysis of multi-field heat and mass transfer in geothermal reservoirs is a pivotal concern within the realm of geothermal rock exploitation. It holds significant implications for the assessment of thermal energy capacity and the formulation of reservoir optimization strategies in the context of geothermal rock resources. Parameters governing production, along with fracture network characteristics (such as injection well temperature, injection well pressure, fracture width, and fracture network density), exert an influence on enhanced geothermal systems (EGS) heat production. In this study, aiming to comprehend the dynamic heat generation of EGS during prolonged exploitation, a coupling of various fields including permeation within the rock formations of geothermal reservoirs and the deformation of these rocks was achieved. In this study, we formulated the governing equations for the temperature field, stress field, and permeability field within the geothermal reservoir rock. Subsequently, we conducted numerical simulations to investigate the heat transfer process in an enhanced geothermal system. We analyzed the effects of injection well temperature, injection well pressure, primary fracture width, and secondary fracture density on the temperature distribution within the reservoir and the thermal power output of the production well. The research findings underscore that ill-conceived exploitation schemes markedly accelerate the thermal breakthrough rate of production wells, resulting in a diminished rate of geothermal resource extraction from the geothermal reservoir rock. Variations in influent well temperature and secondary fracture density exhibit an approximately linear impact on the output from production wells. Crucially, injection well pressure and primary fracture width emerge as pivotal factors influencing reservoir output response, with excessive widening of primary fractures leading to premature thermal breakthrough in production wells. [ABSTRACT FROM AUTHOR]

Rates of seismicity in the Delaware Basin of Texas and New Mexico increased from 10 earthquakes per year of local magnitude (ML) 3.0 and above in 2017 to more than 185 in 2022, coincident with increasing oil and gas production and wastewater re‐injection into strata shallow or deeper than producing intervals. Events of large magnitude—up to ML 5.4 to‐date—occur on faults extending into formations above the basement that have received more than four billion barrels of injection. Here, we demonstrate the link between injection geology, pore pressure evolution, fault stability, and induced seismicity in this region. We find that the injection targets are largely dolomitized platform carbonates with low (<5 vol.%) matrix porosity and fracture‐enhanced permeability with inherent heterogeneity in flow properties. A comprehensive, three‐dimensional geological model populated with reservoir properties is used for fluid flow modeling, with global calibration supplemented by dynamic injectivity data. Pore pressure changes with deep injection are up to 5 MPa from 1983 to 2023, increasing the native pore pressure state by 10% locally. Modeling results show that earthquakes occurring at distances of up to 30 km from deep injection have experienced small (<0.1 MPa) pore pressure increases, indicating that the faults hosting these earthquakes are highly sensitive to changes in effective stress and have lower frictional stability than the 0.6 generally assumed. These results serve as a critical step in understanding the stress changes that induce earthquakes in one of the most seismically active and geologically complex basins in the US. Plain Language Summary: Earthquakes have become more frequent in areas with historically little seismicity and are coincident in space and time with an increase in oil and gas production and the re‐injection of wastewater. Larger‐magnitude earthquakes occur on deep faults and generally within the crystalline basement. They are likely caused by wastewater injection into carbonate rocks above the basement, causing changes in pressure and stress on nearby faults. Results from this modeling work show that deep fluid injection increases pressure by up to 10% near deep injection wells. Key Points: Injection of oil field wastewater into deep strata in the Delaware Basin causes pore pressure changes of up to 5 MPaEarthquakes occurring in crystalline basement are likely induced by pore pressure diffusion associated with regional deep injectionMany basement‐rooted faults hosting earthquakes are optimally oriented, sensitive, and slip with small pore pressure perturbations [ABSTRACT FROM AUTHOR]

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This study aimed to develop and implement a nanotechnology-based alternative to traditional tracers used in the oil and gas industry for assessing interwell connectivity. A simple and rapid hydrothermal protocol for synthesizing carbon quantum dots (CQDs) using agroindustry waste was implemented. Three commercial CQDs were employed (CQDblue, CQDgreen, and CQDred); the fourth was synthesized from orange peel (CQDop). The CQDs from waste and other commercials with spherical morphology, nanometric sizes less than 11 nm in diameter, and surface roughness less than 3.1 nm were used. These tracers demonstrated high colloidal stability with a negative zeta potential, containing carbonyl-type chemical groups and unsaturations in aromatic structures that influenced their optical behavior. All materials presented high colloidal stability with negative values of charge z potential between −17.8 and −49.1. Additionally, individual quantification of these tracers is feasible even in scenarios where multiple CQDs are present in the effluent with a maximum percentage of interference of 15.5% for CQDop in the presence of the other three nanotracers. The CQDs were injected into the field once the technology was insured under laboratory conditions. Monitoring the effluents allowed the determination of connectivity for five first-line producer wells. This study enables the application of CQDs in the industry, particularly in fields where the arrangement of injector and producer wells is intricate, requiring the use of multiple tracers for a comprehensive description of the system. [ABSTRACT FROM AUTHOR]

A common separation approach for polar compounds involves coupling reversed‐phase liquid chromatography (RPLC) with hydrophilic interaction chromatography (HILIC) in two‐dimensional chromatography. The higher proportion of acetonitrile used in the HILIC mobile phase, which enhances mass spectrometry detection, encourages its use in the second dimension. Previous studies demonstrated that the HILIC column can be partially equilibrated within very short timeframes without compromising retention time stability, rendering it suitable in online comprehensive two‐dimensional liquid chromatography (LC×LC) setups. In addition, a specific number of conditioning cycles seems necessary to establish stable retention times. Here, the repeatability of HILIC when employed as second dimension in LC×LC was investigated, with a focus on determining the required number of conditioning cycles to achieve repeatable retention times. Various parameters influenced by the LC×LC online modulation system were studied, such as steep gradient slopes up to 8%, and very short equilibration times, less than or equal to dead time, as well as injection volume and solvent, which depend on the first dimension. Finally, the use of HILIC as a second dimension with tailored conditioning runs was applied to the analysis of hyaluronic acid hydrogel digests. The application of an RPLC×HILIC method using five conditioning runs yielded exceptional stability in second‐dimension retention times. [ABSTRACT FROM AUTHOR]

Estimating the frequency and magnitude of natural hazards largely hinges on stationary models, which do not account for changes in the climatological, hydrological, and geophysical baseline conditions. Using five diverse case studies encompassing various natural hazard types, we present advanced statistical and machine learning methods to analyze and model transient states from long‐term inventory data. A novel storminess metric reveals increasing European winter windstorm severity from 1950 to 2010. Non‐stationary extreme value models quantify trends, seasonal shifts, and regional differences in extreme precipitation for Germany between 1941 and 2021. Utilizing quantile sampling and empirical mode decomposition on 148 years of daily weather and discharge data in the European Alps, we assess the impacts of changing snow cover, precipitation, and anthropogenic river network modifications on river runoff. Moreover, a probabilistic framework estimates return periods of glacier lake outburst floods in the Himalayas, demonstrating large differences in 100‐year flood levels. Utilizing a Bayesian change point algorithm, we track the onset of increased seismicity in the southern central United States and find correlation with wastewater injections into deep wells. In conclusion, data science reveals transient states for very different natural hazard types, characterized by diverse forms of change, ranging from gradual trends to sudden change points and from altered seasonality to overall intensity variations. In synergy with the physical understanding of Earth science, we gain important new insights into the dynamics of the studied hazards and their possible mechanisms. Plain Language Summary: According to global databases on natural hazard events and associated risks, there has been a noteworthy escalation in the extent of economic losses during past decades. It is important but difficult to distinguish and disentangle trends due to changing hazard occurrence or damage potential. Accurately quantifying altered hazards requires high‐quality data sets and robust statistical methodologies. Here, we present recent progress in earth and data science toward a quantitative assessment of natural hazards in a changing world. We show that winter storms have become more frequent and more severe in Europe; that extreme precipitation in Germany shows seasonal shifts and changing intensities with regional variation; that river runoff in Central Europe is changing due to modifications of the river network, declining snowpacks, and changes in precipitation; that frequency of glacier lake outburst floods in the Himalayas have remained unchanged over the past 30 years despite rapid glacier melt and lake growth; and that earthquake activity in Oklahoma (USA) has increased with the onset of wastewater injection wells. We infer that recent advances in data science can efficiently provide new knowledge from big data sets, but interpreting these results needs a solid understanding and rather detailed analysis of the underlying processes. Key Points: Time‐dependent approaches are key to capture changing hazards, with diverse altered frequencies, intensities, timing or spatial occurrencesAdvances in data‐driven methods and increasing availability of geodata foster new ways to detect changes in natural hazardsOver‐simplification or averaging over large scales in time or space cause severe information loss and may hide the mechanisms for change [ABSTRACT FROM AUTHOR]

Injection mandrel is one of the key components to control the water injection rate of each layer in the layered injection process in the oilfield. The imbalance between the layers can be changed by an optimized injection mandrel to control the appropriate injection rate. This study introduces an approach to optimize water injection in oilfields, focusing on a new eccentric injection mandrel with adjustable flat nozzles. Firstly, computational fluid dynamics (CFD) simulations were carried out using FLUENT software to model and analyze the flow characteristics of the injection mandrel. The simulation results were validated through experimental comparisons, demonstrating excellent consistency. Secondly, the nozzle shapes were identified and optimized. The semicircle nozzle demonstrating superior regulation performance due to its smallest differential pressure and a robust linear relationship between flow rate and opening degree. Finally, orthogonal tests are designed for three influencing factors of the eccentric injection mandrel: number of injection holes, injection hole diameter, and nozzle shape. The simulation results show that the number of injection holes is 36, the diameter of injection holes is 3.2 mm, and the eccentric injection mandrel has relatively better performance. After optimization, the differential pressure between the inlet and outlet is reduced by 57.14%, and the average shear stress on the fluid is reduced by 3.88%. This innovative methodology, employing CFD simulations and orthogonal tests, offers precise water injection rate control, reducing water wastage, and optimizing energy consumption in water injection systems. [ABSTRACT FROM AUTHOR]

Many onshore oil fields currently adopt water flooding as a means to supplement reservoir energy. However, due to reservoir heterogeneity, significant differences in permeability exist not only between different reservoirs but also within the same reservoir across different planar orientations. After prolonged fluid flushing in the near-wellbore zone of injection wells, the resulting increased flow resistance between layers exacerbates inefficient and ineffective circulation. A considerable amount of remaining oil is left unexploited in untouched areas, significantly impacting the overall recovery. To investigate the multiscale plugging mechanisms of fracture-dominated pore channels in high-water-cut oil reservoirs and achieve efficient management of fractured large channels, this study explores the formation of the fracture-flushing zone-low saturation oil zone. A physical experimental model with fractures and high-intensity flushing is established to analyze changes in pore structure, mineral composition, residual oil distribution, and other characteristics at different positions near the fractures. The research aims to clarify the mechanism behind the formation of large channels with fracture structures. The results indicate that under high-intensity water flushing, cementing materials are washed away by the flowing water, clay particles are carried to the surface with the injected fluid, and permeability significantly increases, forming high-permeability zones with fracture structures. In the rock interior away from the fracture end, channels, corners, and clustered oil content noticeably decrease, while the content of film-like oil substantially increases, and clay minerals are not significantly washed away. Under strong flushing conditions, the number of residual clay particles near the fracture end is mainly influenced by flow velocity and flushing time; thus, the greater the flushing intensity, the faster the water flow, and the longer the flushing time, the fewer residual clay particles near the fracture end. [ABSTRACT FROM AUTHOR]

Evaluating uncertainties of geological features on fluid temperature and pressure changes in a reservoir plays a crucial role in the safe and sustainable operation of high-temperature aquifer thermal energy storage (HT-ATES). This study introduces a new automated surface fitting function in the Python API (application programming interface) of Gmsh (v4.11) to simulate the impacts of structural barriers and variations of the reservoir geometries on thermohydraulic behaviour in heat storage applications. These structural features cannot always be detected by geophysical exploration but can be present due to geological complexities. A Python workflow is developed to implement an automated mesh generation routine for various geological scenarios. This way, complex geological models and their inherent uncertainties are transferred into reservoir simulations. The developed meshing workflow is applied to two case studies: (1) Greater Geneva Basin with the Upper Jurassic ("Malm") limestone reservoir and (2) the 5° eastward-tilted DeepStor sandstone reservoir in the Upper Rhine Graben with a uniform thickness of 10 m. In the Greater Geneva Basin example, the top and bottom surfaces of the reservoir are randomly varied by ± 10 and ± 15 m , generating a total variation of up to 25 % from the initially assumed 100 m reservoir thickness. The injected heat plume in this limestone reservoir is independent of the reservoir geometry variation, indicating the limited propagation of the induced thermal signal. In the DeepStor reservoir, a vertical sub-seismic fault juxtaposing the permeable sandstone layers against low permeable clay-marl units is added to the base case model. The fault is located in distances varying from 4 to 118 m to the well to quantify the possible thermohydraulic response within the model. The variation in the distance between the fault and the well resulted in an insignificant change in the thermal recovery (∼ 1.5 %) but up to a ∼ 10.0 % pressure increase for the (shortest) distance of 4 m from the injection well. Modelling the pressure and temperature distribution in the 5° tilted reservoir, with a well placed in the centre of the model, reveals that heat tends to accumulate in the updip direction, while pressure increases in the downdip direction. [ABSTRACT FROM AUTHOR]

Carbon Capture and Storage (CCS) stands as a pivotal technological stride toward a sustainable future, with the practice of injecting supercritical CO2 into subsurface formations being already an established practice for enhanced oil recovery operations. The overarching objective of CCS is to protract the operational viability and sustainability of platforms and oilfields, thereby facilitating a seamless transition towards sustainable practices. This study introduces a comprehensive framework for optimizing well placement in CCS operations, employing a derivative-free method known as Bayesian Optimization. The development plan is tailored for scenarios featuring aquifers devoid of flow boundaries, incorporating production wells tasked with controlling pressure buildup and injection wells dedicated to CO2 sequestration. Notably, the wells operate under group control, signifying predefined injection and production targets and constraints that must be adhered to throughout the project's lifespan. As a result, the objective function remains invariant under specific permutations of the well locations. Our investigation delves into the efficacy of Bayesian Optimization under the introduced permutation invariance. The results reveal that it demonstrates critical efficiency in handling the optimization task extremely fast. In essence, this study advocates for the efficacy of Bayesian Optimization in the context of optimizing well placement for CCS operations, emphasizing its potential as a preferred methodology for enhancing sustainability in the energy sector. [ABSTRACT FROM AUTHOR]