Search Results (66)

River water quality is a direct determinant of both drinking water security and regional economic vitality. However, the hydrochemical trajectories and solute provenance of agricultural streams remain only fragmentarily understood. Here, we examine the Jinqian River—a representative agricultural tributary of the Danjiangkou Reservoir source area for the South-to-North Water Diversion Project—by coupling hydrochemistry with multivariate statistics techniques. The results revealed that the pH values of the river water ranged from 7.55 to 8.30, indicating a weakly alkaline condition. During all three hydrological periods, the concentrations of total nitrogen (TN) exceeded the limits set by the Class Ⅲ surface water quality standards in China, suggesting that the agricultural river has been significantly impacted by human activities. Solute dynamics followed three rainfall-modulated patterns: (i) dilution-driven decreases in the flood season (e.g., Na⁺), (ii) concentration via flushing or evaporative concentration (e.g., SO₄²⁻), and (iii) reservoir-induced damping of seasonal contrasts (e.g., TN), the latter attributable to nitrogen retention behind upstream dams. Geochemical fingerprints reveal that Cl⁻ and Na⁺ originate predominantly from halite dissolution; Ca²⁺, Mg²⁺ and HCO₃⁻ from coupled carbonate–silicate weathering; and SO₄²⁻ from evaporite dissolution. Principal component analysis distills four dominant quality controlling factors: agricultural fertilizers, halite weathering, evaporite dissolution, and domestic effluent. These findings provide a quantitative basis for managing nutrient and salt fluxes in agricultural rivers and for safeguarding water sustainability within water-diversion source regions. Full article

Both water and sediment resource allocation are critical for achieving sustainable development in sediment-laden river basins. However, current understanding lacks a holistic perspective and fails to capture the inseparability of water and sediment. The Yellow River Basin (YRB) is the world’s most sediment-laden river, characterized by pronounced ecological fragility and uneven socio-economic development. This study introduces integrated water-sediment allocation frameworks for the YRB based on the perspective of the water-sediment nexus, aiming to regulate their impacts on socio-economic and ecological systems. The frameworks were established for both artificial units (e.g., irrigation zones and reservoirs) and geological units (e.g., the Jiziwan region, lower channels, and estuarine deltas) within the YRB. The common feature of the joint allocation of water and sediment across the five units lies in shaping a coordinated water–sediment relationship, though their focuses differ, including in-stream water-sediment processes and combinations, the utilization of water and sediment resources, and the constraints imposed by socio-economic and ecological systems on water-sediment distribution. In irrigation zones, the primary challenge lies in engineering-based control of inflow magnitude and spatiotemporal distribution for both water and sediment. In reservoir systems, effective management requires dynamic regulation through density current flushing and coordinated operations to achieve water-sediment balance. In the Jiziwan region, reconciling socio-economic development with ecological integrity requires establishing science-based thresholds for water and sediment use while ensuring a balance between utilization and protection. Along the lower channel, sustainable management depends on delineating zones for human activities and ecological preservation within floodplains. For deltaic systems, key strategies involve adjusting upstream sediment and refining depositional processes. Full article

Compared with conventional gas reservoirs, deep shale gas reservoirs are characterized by developed faults and fractures, strong heterogeneity, high stress sensitivity, and complex in situ stress distribution. To address traditional 3D static models’ inability to predict in situ stress changes in strongly heterogeneous reservoirs during fracturing, this study takes the deep shale gas in the Zigong block of the Sichuan Basin as an example. By comprehensively considering the heterogeneity and anisotropy of geomechanical parameters and natural fractures in shale gas reservoirs, a 4D in situ stress multi-physics coupling model for shale gas reservoirs based on geology–engineering integration is established. Through coupling geomechanical parameters with fracturing operation data, the dynamic evolution laws of multi-scale stress fields from single-stage to platform-scale during large-scale fracturing of horizontal wells in deep shale gas reservoirs are systematically studied. The research results show the following: (1) The fracturing process has a significant impact on the magnitude and direction of the stress field. With the injection of fracturing fluid, both the minimum and maximum horizontal principal stresses increase, with the minimum horizontal principal stress rising by 1.8–6.4 MPa and the maximum horizontal principal stress by 1.1–3.2 MPa; near the wellbore, there is an obvious deflection in the direction of in situ stress. (2) As the number of fracturing stages increases, the minimum horizontal principal stress shows an obvious cumulative growth trend, with a more significant increase in the later stages, and there is a phenomenon of stress accumulation along the wellbore, with the stress difference decreasing from 15 MPa to 11 MPa. (3) The on-site adoption of the fracturing operation method featuring overall flush advancement and inter-well staggered fracture placement has achieved good stress balance; comparative analysis shows that the stress communication degree of the 400 m well spacing is weaker than that of the 300 m well spacing. This study provides a more reasonable simulation method for large-scale fracturing development of deep shale gas, which can more accurately predict and evaluate the dynamic stress field changes during fracturing, thereby guiding fracturing operations in actual production. Full article

Reservoir sedimentation, a global challenge causing an annual loss of 0.8–1% of reservoir storage capacity, disrupts fluvial sediment continuity and impacts ecology and societal needs. This study focuses on the Pulangi IV reservoir in the Philippines, a shallow and wide reservoir facing significant sedimentation issues. The research aims to investigate drawdown flushing and dredging of a flushing channel for future sustainable drawdown sluicing. A test flushing event was conducted and monitoring data, including discharge, suspended sediment concentration, bathymetry, and grain size distribution, were collected. Laboratory analyses, such as critical shear stress tests, were performed for model calibration. A 3D reservoir model and a 1D sediment transport model were applied incorporating cohesive sediment behavior. Scenarios were simulated to assess drawdown flushing, dredging and downstream impacts. Results highlight the importance of drawdown level, with cohesive sediment properties playing a critical role. Sedimentation downstream of the dam, resulting from dumped or flushed sediments, was low. However, downstream ecological and morphodynamic monitoring was found to be essential for all modeled strategies. This study demonstrates potential for establishing a flushing channel enabling future sustainable drawdown sluicing during floods by conducting repeated drawdown flushing in combination with dredging in the upper reservoir. Full article

This field study describes the successful implementation and evaluation of a Polymer-free Delayed Acid System, a next-generation acid retarder system that is chemically superior to traditional emulsified acid systems with an amphoteric-based surfactant. It is a polymer-free system that stimulates ultra-tight carbonate reservoirs in extreme sour and high-temperature conditions. The candidate well, located in an onshore gulf region field, for a major oil and gas company demonstrated chronically unstable production behavior for over two years, with test volumes fluctuating unpredictably between 200 and 400 barrels of oil per day. This indicated severe near-wellbore damage, high skin, and limited matrix permeability (<0.3 mD). The well was chosen for a pilot trial of the Polymer-free Delayed Acid System technology after a thorough formation study, which included mineralogical characterization and capillary diagnostics. The innovative acid retarder formulation, designed for deep matrix penetration and controlled acid–rock reaction, uses intrinsic encapsulation kinetics to significantly increase the acid’s reactivity, allowing it to bypass damaged zones, minimize acid leak-off, and initiate dominant wormhole propagation into the tight formation. The stimulation procedure began with a custom pre-flush designed to change nanoscale wettability and interfacial tension, so increasing acid displacement and assuring effective contact with the formation rock. Real-time injectivity testing and operational data collecting were performed prior to, during, and following the acid job, with pre-stimulation injectivity peaking at 1.2 bpm, indicating poor formation conductivity. Treatment with the Polymer-free Delayed Acid System resulted in a 592% increase in post-stimulation injectivity, indicating significant increases in near-wellbore permeability and successful propagation. However, a substantial operational difficulty arose: the well remained shut down for more than two months following the acid stimulation work due to surface infrastructure delays, notably the scheduling and execution of a flowline cleanup campaign. This lengthy closure slowed immediate flowback analysis and impeded direct assessment of treatment performance because production could not be tracked in real time. Despite this, once the surface system was operational and the well was open to flow, a structured production testing program was carried out over four quarterly intervals. The well regularly produced at an average stable rate of 500 bbl/day, more than doubling pre-treatment performance and demonstrating the long-term effectiveness and mechanical durability of the acid-induced wormhole network. Despite the post-job shut-in, the Polymer-free Delayed Acid System maintained the stimulating impact even under non-ideal settings, demonstrating its robustness. The Polymer-free Delayed Acid System outperforms conventional emulsified acid systems, giving better control over acid placement and reactivity, especially under severe reservoir conditions with bottomhole temperatures reaching 200 °F. This project offers a field-proven methodology that combines advanced chemical engineering, formation-specific design, and live diagnostics, as well as a scalable blueprint for unlocking hydrocarbon potential in similarly complicated, low-permeability reservoirs. Full article

Asynchrony between the movement of water and sediment in a reservoir will affect long-term maintenance of the reservoir’s capacity to a certain extent. Based on water and sediment data on the Three Gorges Reservoir (TGR) measured over the years and a river network model, optimization of the dispatching mode of the reservoir’s sand peak process was studied, and the corresponding water and sediment dispatching indicators were provided. The results show that (1) sand peak discharge dispatching of the TGR can be divided roughly into three stages, namely the flood detention period, the sediment transport period, and the sediment discharge period. (2) According to the process of the flood peak and the sand peak, a division method for each period is proposed. (3) A corresponding scheduling index is proposed according to the characteristics of the sand peak process and the needs of flood control scheduling. This research can provide operational indicators for the operation and management of the sediment load in the TGR and also provide technical support for sustainable reservoirs similar to TGR. Full article

Unconventional hydrocarbon reservoirs with low matrix permeability (<0.3 mD), high temperatures, and sour conditions present significant challenges for stimulation and production enhancement. This study examines field trials for a large oil and gas operator in the UAE, focusing on tight carbonate deposits with reservoir temperatures above 93 °C and high sour gas content. A novel multi-stage chemical stimulation workflow was created, beginning with a pre-flush phase that alters rock wettability and reduces interfacial tension at the micro-scale. This was followed by a second phase that increased near-wellbore permeability and ensured proper acid placement. The treatment’s core used a thermally stable, corrosion-resistant retarded acid system designed to slow reaction rates, allow deeper acid penetration, and build prolonged conductive wormholes. Simulations revealed considerable acid penetration of the formation beyond the near-wellbore zone. The post-treatment field data showed a tenfold improvement in injectivity, which corresponded closely to the acid penetration profiles predicted by modeling. Furthermore, oil production demonstrated sustained, high oil production of 515 bpd on average for several months after the treatment, in contrast to the previously unstable and low-rate production. Finally, the findings support a reproducible and technologically advanced stimulation technique for boosting recovery in ultra-tight carbonate reservoirs using the acid retardation effect where traditional stimulation fails. Full article

Studies have demonstrated that heavy oil flow exhibits threshold pressure gradient (TPG) which is closely related to the permeability and viscosity of the crude oil. Also, long-term water flooding continuously alters unconsolidated sandstone reservoir permeability through water flushing. These combined effects significantly influence water flooding performance. Therefore, in this paper, a comprehensive oil–water two phase mathematical model is developed for waterflooded heavy oil unconsolidated sandstone reservoirs based on the traditional black oil model, incorporating both time-varying permeability and threshold pressure gradient. The water-flooding-dependent threshold pressure gradient is firstly proposed, accounting for time-varying permeability. Subsequently, a simulator is developed with finite volume and Newton iteration method. Good agreement is obtained with the commercial simulator based on traditional black oil model. Afterward, the influence of permeability time variation and threshold pressure gradient is analyzed in detail. Results demonstrate that the threshold pressure gradient and time-varying permeability both decrease the oil recovery. The threshold pressure gradient (TPG) reduces the oil flow region and displacement efficiency since production. The increases in permeability after long term water flooding exacerbate reservoir heterogeneity and reduce sweep efficiency. The lowest oil recovery is observed when non-Darcy flow and permeability time variation are considered simultaneously. Furthermore, the time-varying threshold pressure gradient is observed with permeability time variation. Finally, a field data history matching was successfully performed, demonstrating the practical applicability of the proposed model. This new model better aligns with reservoir development characteristics. It can provide a theoretical guide for the development of heavy oil reservoirs. Full article

Freshwater shortages in coastal regions are intensifying due to rapid urbanisation, economic growth, and climate variability, particularly in deltaic areas where rivers meet the sea. This study evaluates the feasibility of implementing a Coastal Reservoir (CR) as an innovative solution to increase freshwater availability without relying on desalination. Using the Brisbane River Estuary (BRE), Australia, as a case study, the research examines critical factors such as freshwater inflow, seawater intrusion, and reservoir volume requirements. A three-dimensional hydrodynamic model (MIKE 3) was calibrated and validated using observed data from the 2008 and 2011 flow events. Simulation results indicate that a freshwater discharge of 150 m³/s during a spring-neap tidal cycle effectively pushes saline water out of the estuary. The CR can store 300 GL/year of freshwater with 92% reliability, meeting Southeast Queensland’s (SEQ) annual water demand of 440 GL during drought conditions combined with existing infrastructure. During its initial filling phase, the CR can flush 95% of saltwater within 240 days, using a steady inflow of 150 m³/s. The findings demonstrate the technical feasibility of CRs as a sustainable and practical water management strategy for mitigating freshwater shortages in BRE and other similar coastal regions. Full article

Nitrogen injection technology has become an important production technology after water injection development in the karst fracture-vuggy reservoir in Tahe Oilfield. However, due to the influence of reservoir heterogeneity and the high mobility of gas fluid, nitrogen easily forms a dominant channel and gas channeling occurs, and the recovery effect time is short. Based on this, a visual surface karst model is designed and created to study nitrogen foam-assisted gas drive. The results show that after gas channeling occurs in the dominant channel of nitrogen flooding, foam injection-assisted gas flooding can improve oil recovery. In the longitudinal direction, foam-assisted gas drive mainly displaces the remaining oil because of gravity differentiation and the reduction of oil–water interfacial tension. In the horizontal direction, foam-assisted gas drive is mainly used to block the large pore cracks and dominant channels, promote the gas to turn into large tortuous and small cracks, and expand the swept efficiency of the gas. After forming the dominant channel, injecting 0.3 pv salt-sensitive foam with a gas–liquid ratio of 2:1 in the middle of the gas channel can improve the recovery rate of the model from 4% to about 25%, and the recovery rate can be increased by about 20%, which improves the effect of gas flushing and improves the development efficiency of the oil field at the same time. Full article

The intricate geological characteristics of tight oil reservoirs, characterized by extremely low porosity and permeability as well as pronounced heterogeneity, have led to a decline in reservoir pressure, substantial gas expulsion, an accelerated decrease in oil production rates, and the inadequacy of traditional water injection methods for enhancing oil recovery. As a result, operators encounter heightened operational costs and prolonged timelines necessary to achieve optimal production levels. This situation underscores the increasing demand for advanced techniques specifically designed for tight oil reservoirs. An internal evaluation is presented, focusing on the application of molecular deposition film techniques for enhanced oil recovery from tight oil reservoirs, with the aim of elucidating the underlying mechanisms of this approach. The research addresses fluid flow resistance by employing aqueous solutions as transmission media and leverages electrostatic interactions to generate nanometer-thin films that enhance the surface properties of the reservoir while modifying the interaction dynamics between oil and rock. This facilitates the more efficient displacement of injected fluids to replace oil during pore flushing processes, thereby achieving enhanced oil recovery objectives. The experimental results indicate that an improvement in oil displacement efficiency is attained by increasing the concentration of the molecular deposition film agent, with 400 mg/L identified as the optimal concentration from an economic perspective. It is advisable to commence with a concentration of 500 mg/L before transitioning to 400 mg/L, considering the adsorption effects near the well zone and dilution phenomena within the reservoir. Molecular deposition films can effectively reduce injection pressure, enhance injection capacity, and lower initiation pressure. These improvements significantly optimize flow conditions within the reservoir and increase core permeability, resulting in a 7.82% enhancement in oil recovery. This molecular deposition film oil recovery technology presents a promising innovative approach for enhanced oil recovery, serving as a viable alternative to conventional water flooding methods. Full article

At present, the methods for sulfur solubility testing of high-sulfur natural gas generally use laboratory proportioning gas samples and then connect equipment to test the sulfur solubility of the gas samples based on the adsorption deposition mechanism. However, these testing methods generally have the following problems: (1) The equipment used in these test methods has safety hazards such as leakage at pipe and valve connections. (2) The sulfur solubility of real gas samples cannot be measured directly. (3) The equipment is difficult to clean, and it is especially difficult to clean the sulfur deposited at pipe elbows and valve connections. This will lead to low sulfur solubility test results. (4) The thermal insulation performance during the test process is not good, and temperature changes have a great impact on gas volume measurement. In order to solve the above problems, a testing method and comprehensive experimental device for the solubility of elemental sulfur in high-sulfur natural gas were established. This test method wraps the entire experimental device with a metal shell, which has good safety and thermal insulation performance, and it uses customized pipeline connections, which have high flushing efficiency, less sulfur deposition, and more accurate experimental results. The upgraded filtration system can directly measure the sulfur dissolution of real gas samples, and a CS₂ solution recovery process is added to reduce the risk of leakage and environmental pollution. This method and equipment were used to test the elemental sulfur solubility determination of real gas samples from a high-sulfur gas well. The research results show that the solubility of elemental sulfur is related to temperature, pressure, and H₂S concentration and increases with the increase in temperature, pressure, and H₂S concentration. Compared with the previous method, this method has less residual sulfur during the test process, the measured sulfur solubility is 2.13% greater, and the test results are more accurate and reliable. This research result provides important basic data support for accurately measuring the elemental sulfur solubility of real gas samples in high-sulfur gas reservoirs and dealing with sulfur deposition problems. Full article

Conventional Carbon Capture and Storage (CCS) operations use the direct injection of CO₂ in a gaseous phase from the surface as a carbon carrier. Due to CO₂ properties under reservoir conditions with lower density and viscosity than in situ brine, CO₂ flux is mainly gravity-dominated. CO₂ moves toward the top and accumulates below the top seal, thus reinforcing the risk of possible leakage to the surface through unexpected hydraulic paths (e.g., reactivated faults, fractures, and abandoned wells) or in sites without an effective sealing caprock. Considering the risks, the potential benefits of the interplay between CO₂ and an aqueous solution of formate ions (HCOO¯) were evaluated when combined to control CO₂ gravity segregation in porous media. Three combined strategies were evaluated and compared with those where either pure CO₂ or a formate solution was injected. The first strategy consisted of a pre-flush of formate solution followed by continuous CO₂ injection, and it was not effective in controlling the vertical propagation of the CO₂ plume. However, the injection of a formate solution slug in a continuous or alternated way, simultaneously with the CO₂ continuous injection, was effective in slowing down the vertical migration of the CO₂ plume and keeping it permanently stationary deeper than the surface depth. Full article

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. Full article

Excessive sedimentation in sand-laden rivers significantly hinders the normal operation and overall effectiveness of reservoirs. This is observed particularly in plain-type sand-laden reservoirs where weak hydraulic conditions in the reservoir area contribute to sediment deposition. Water–sediment regulation is essential in reducing sedimentation and prolonging the lifespan of such reservoirs. Taking the plain-type reservoir of the primary stream of the Yellow River—Haibowan Reservoir as an example, based on a two-dimensional shallow water equation, a two-dimensional mathematical model of water and sediment in the reservoir area is established, the corresponding boundary conditions are improved, and the reliability of the model is verified. Under the premise of ensuring the flood control safety of the reservoir dam, considering the impact on the power generation of the reservoir and the downstream river, and maintaining the long-term large effective storage capacity of the reservoir as the basic principle, the water–sediment regulation scheme is proposed. A two-dimensional kinetic model of sediment transport and representative water–sediment series are employed to simulate the erosion and sedimentation processes in the reservoir under different schemes. The optimisation and comparison of multiple schemes reveal that the sediment-flushing scheme, which lowers the water level to 1072 m above sea level when the inflow discharge is 1500–2760 m³/s and inflow sediment concentration is 5–10 kg/m³, can yield an effective reservoir capacity of 97 million m³ and an average annual hydropower generation of 389.5 million kWh after 15 years of operation. This scheme outperforms the existing sediment-flushing scheme and is recommended as an optimised approach for water–sediment regulation in reservoirs. The results of this study provide technical support for the application of water–sediment regulation in the Haibowan Reservoir and may be useful in the exploration and management of water–sediment regulation for plain-type reservoirs on sand-laden rivers. Full article