Search Results (59)

The development of shale gas relies on hydraulic fracturing technology and requires the injection of a large amount of fracturing fluid. The well shut-off period after fracturing can promote water infiltration and suction. Optimizing the well shut-off time is crucial for enhancing the recovery rate. Among existing methods, the dimensionless time model is widely used, but it has limitations because it does not represent the length of on-site scale features. In this study, we focused on the shut-in time for a deep shale gas well (Lu-A) in Luzhou and a medium-deep shale gas well (Wei-B) in Weiyuan. By integrating the spontaneous seepage and aspiration experiments in the laboratory and the post-pressure backflow data (including mineralization degree, liquid volume recovery rate, etc.), a multi-scale well shutdown time prediction model considering the characteristic length was established. The experimental results show that the spontaneous resorption characteristic times of Lu-A and Wei-B are 3 h and 22 h, respectively. Based on the inversion of crack monitoring data, the key parameters such as the weighted average crack width (1.73/1.30 mm) and crack spacing (0.20/0.32 m) of Lu-A and Wei-B were obtained. Through the scale upgrade calculation of the feature length (0.10/0.16 m), the system determined that the optimal well shutdown times for the two wells were 14.5 days and 16.7 days, respectively. The optimization method based on a multi-parameter analysis of backflow fluid proposed in this study not only solves the limitations of the traditional dimensionless time model in characterizing the feature length but also provides a theoretical basis for the formulation of the well shutdown system and nozzle control strategy of shale gas wells. Full article

The challenge of water shutoff in carbonate reservoirs is complicated by the presence of fractures, which cannot be effectively blocked using conventional hydrogel screens designed for granular reservoirs. To reliably seal fractures, fibrous and dispersed fillers are added to hydrogels. These fillers must exhibit affinity for the matrix to ensure the composites can effectively isolate water. Given the wide variability in fracture apertures, it is evident that water shutoff composites should incorporate fibers and dispersed fillers of varying geometric sizes. This study presents a range of hydrogel composites reinforced with mono-, bi-, and tri-component fibers, as well as dispersed fillers, designed for water shutoff in fractured carbonate reservoirs with varying fracture apertures. Oscillation test results demonstrated a twofold increase in the elastic modulus (40–45 Pa) for compositions with various fillers compared to the base composition (23 Pa). Filtration studies revealed the effectiveness of the optimized compositions under different fracture apertures. Specifically, even at a fracture aperture of 650 μm, the residual resistance factor (RRF) reached 82.3 and 9.76 at water flow rates of 0.1 cm³/min and 0.5 cm³/min, respectively. The conducted rheological and filtration tests, along with field trials, confirmed the validity of the selected approach. Full article

In the field of enhanced oil recovery (EOR), particularly for water control in high-temperature reservoirs, there is a critical need for effective in-depth water shutoff and conformance control technologies. Polymer-based in situ-cross-linked gels are extensively employed for enhanced oil recovery (EOR), yet their short gelation time under high-temperature reservoir conditions (e.g., >120 °C) limits effective in-depth water shutoff and conformance control. To address this, we developed a hydrogel system via the in situ cross-linking of polyacrylamide (PAM) with phenolic resin (PR), reinforced by silica sol (SS) nanoparticles. We employed a variety of research methods, including bottle tests, viscosity and rheology measurements, scanning electron microscopy (SEM) scanning, density functional theory (DFT) calculations, differential scanning calorimetry (DSC) measurements, quartz crystal microbalance with dissipation (QCM-D) measurement, contact angle (CA) measurement, injectivity and temporary plugging performance evaluations, etc. The composite gel exhibits an exceptional gelation period of 72 h at 130 °C, surpassing conventional systems by more than 4.5 times in terms of duration. The gelation rate remains almost unchanged with the introduction of SS, due to the highly pre-dispersed silica nanoparticles that provide exceptional colloidal stability and the system’s pH changing slightly throughout the gelation process. DFT and SEM results reveal that synergistic interactions between organic (PAM-PR networks) and inorganic (SS) components create a stacked hybrid network, enhancing both mechanical strength and thermal stability. A core flooding experiment demonstrates that the gel system achieves 92.4% plugging efficiency. The tailored nanocomposite allows for the precise management of gelation kinetics and microstructure formation, effectively addressing water control and enhancing the plugging effect in high-temperature reservoirs. These findings advance the mechanistic understanding of organic–inorganic hybrid gel systems and provide a framework for developing next-generation EOR technologies under extreme reservoir conditions. Full article

This study addresses the water hammer protection challenges in the JH gravity-fed bifurcated pipeline network system in Xinjiang, China. A hydraulic transient numerical model is developed using the one-dimensional method of characteristics and implemented in Bentley HAMMER software to systematically analyze the transient response characteristics under different valve closure schemes, with a focus on revealing pressure fluctuation patterns in branch and main pipelines under various shutdown modes. Key findings include the following: Single-valve linear slow closure reduces the maximum water hammer pressure by 54.7%, while the two-stage closure strategy suppresses pressure extremes below safety thresholds with 73.1% higher efficiency than linear closure. For multi-valve conditions, although two-stage closure eliminates negative pressure risks, most of nodes exhibit transient overpressure exceeding 1.5 times the working pressure. By integrating overpressure relief valves into a composite protection system, the maximum transient pressure is strictly controlled within 1.5× rated pressure, and the minimum pressure remains above −2 mH₂O, successfully resolving protection challenges in this complex network. These results provide technical guidelines for the safe operation of gravity-fed pipeline systems in high-elevation-difference regions. Full article

This study presents the formulation and evaluation of a dual molecular weight polymer gel system composed of partially hydrolyzed polyacrylamide (HPAM) and crosslinked with polyethyleneimine (PEI) for water shut-off applications. A soft gel, designed for deep reservoir penetration, was formulated using 5000 ppm high-molecular-weight HPAM, while a rigid gel for near-wellbore blockage combined 5000 ppm high- and 5000 ppm low-molecular-weight HPAM. The gel system was designed at 65 °C, with an initial gelation time exceeding 8 h and viscosity values below 15 cP before gelation, ensuring ease of injection. Laboratory assessments included bottle testing, rotational and oscillatory rheological measurements, and core flooding to determine residual resistance factors (RRFs). The soft gel achieved a final strength of Grade D (low mobility), while the rigid gel reached Grade G (moderate deformability, immobile), according to Sydansk’s classification. RRF values reached 93 for the soft gel and 185 for the rigid gel, with both systems showing strong washout resistance and water shut-off efficiencies above 95%. These results demonstrate the potential of the HPAM/PEI gel system as an effective solution for conformance control in mature reservoirs with active aquifers. Full article

To address the rapid crosslinking reaction and short stability duration of polyacrylamide gel under high salinity and temperature conditions, this paper proposes utilizing urea to delay the nucleophilic substitution crosslinking reaction among polyacrylamide, hydroquinone, and formaldehyde. Additionally, urea regulates the precipitation of calcium and magnesium ions, enabling the in situ preparation of an organic/inorganic composite gel consisting of crosslinked polyacrylamide and carbonate particles. With calcium and magnesium ion concentrations at 6817 mg/L and total salinity at 15 × 10⁴ mg/L, the gelation time can be controlled to range from 6.6 to 14.1 days at 95 °C and from 2.9 to 6.5 days at 120 °C. The resulting composite gel can remain stable for up to 155 days at 95 °C and 135 days at 120 °C. The delayed gelation facilitates longer-distance diffusion of the gelling agent into the formation, while the enhancements in gel strength and stability provide a solid foundation for improving the effectiveness of profile control and water shut-off in oilfields. The urea-controlling method is novel and effective in extending the high-temperature cross-linking reaction time of polyacrylamide. By converting calcium and magnesium ions into inorganic particles, it enables the in situ preparation of organic/inorganic composite gels, enhancing their strength and stability. Full article

During natural gas development, the gas–water two-phase flows in upward and horizontal wellbores are complex and variable. The accurate calculation of the water holdup in each production layer using appropriate methods based on the logging data collected by fluid identification instruments can enable the precise identification of primary oil-producing and water-producing layers and facilitate subsequent water shutoff operations. In this study, we first investigated the measurement techniques and calculation methods for gas–water two-phase holdups both in China and internationally. Second, we conducted gas–water two-phase simulation experiments in upward and horizontal large-diameter wellbores using a Triangular Arm Array Imager (TAAI) equipped with six fiber-optic probes in a multiphase flow simulation laboratory. We then categorized the flow patterns observed in the physical simulation experiments based on typical theoretical classifications of gas–water two-phase flow patterns. Subsequently, we calculated the spatial positions of the fiber-optic probes and the local water holdup in the wellbore cross-section from the data collected by TAAI and compared the results obtained by Gaussian radial basis function (GRBF) or inverse distance weighted (IDW) interpolation algorithms. We processed the experimental data and found significant discrepancies between the holdup calculated by the two algorithms and the actual wellbore holdup. Therefore, we applied the Levenberg–Marquardt (L-M) algorithm to optimize these interpolation algorithms and discovered that the holdup obtained from the optimized algorithms aligned more closely with the actual wellbore holdup with reduced errors. Finally, we applied the optimized algorithms to the processing of measured data from a gas–water two-phase horizontal well. The results indicate that the L-M algorithm can improve the accuracy of 4–5% of holdup calculations. In the actual production process, the output situation of each production layer can be more accurately judged to provide important opinions for the subsequent actual production by this study. Full article

This study analyzed the physical and hydrodynamic characteristics of various horizons in the Kumkol and East Kumkol oil fields by special core analysis to integrate strategies for controlling water cuts and well-intervention procedures for a more effective oil flow rate in mature oil fields in Kazakhstan. The results indicated that the recovery factor (RF) for Horizon I is 48.3% (98.7% water cut), while Horizon II has an RF of 45.5% (97.9% water cut). Horizon III has an RF of 52.7% (98.8% water cut), and Horizon IV has an RF of 32.6% (98.6% water cut) in the Kumkol Field. In the East Kumkol Field, Horizon I has an RF of 49.5% (96.7% of water cut), and Horizon II has an RF of 31% (94.9% of water cut). The average increase in oil flow rate from well optimization ranges from 5.3 to 6.4 tons per day in the Kumkol Field and 5.22 tons per day in the East Kumkol Field. The maximum increase in oil flow rate is 10.8 tons/day for Horizon I in the Kumkol Field and 6.9 tons/day for Horizon II in the East Kumkol Field. The well-intervention procedures are more effective in the Kumkol Field than in the East Kumkol Field. Given the high water cut observed in these mature reservoirs, this study also examines polymer flooding as an enhanced oil recovery (EOR) technique to improve oil displacement efficiency and reduce water production. Polymer flooding has been successfully implemented in high water-cut reservoirs, including the Uzen field in Kazakhstan, demonstrating its ability to modify fluid filtration profiles and enhance oil recovery. The feasibility of applying polymer flooding in the Kumkol and East Kumkol fields is analyzed, along with a comparison of its effectiveness against conventional water shut-off and well-intervention methods. Additional research is needed to assess polymer retention, reservoir compatibility, and the economic feasibility of large-scale implementation. Full article

To investigate the impact of different valve closure strategies on water hammer pressure variations in pipelines and terminal valves under accident conditions, this study focuses on the Xinlongkou Hydropower Station water conveyance project. The Bentley Hammer calculation software was used to simulate the changes in water hammer pressure in the pipeline and unit terminal valves under various valve closure scenarios. Additionally, computational fluid dynamics (CFD) was applied to analyze the dynamic effects of different factors on the water hammer in the branch pipelines of the station. The results showed that shorter valve closure times resulted in higher peak water hammer pressures, with the maximum pressure occurring at the terminal valve. Extending the valve closure time effectively reduced both the peak pressure and number of pressure oscillations at the terminal valve, with pressure fluctuations stabilizing within approximately 30 s. Two-stage valve closures led to water hammer pressures 8–14.1% higher than those from one-stage linear closures. Based on these findings, it is recommended that stations adopt a valve closure time greater than 9 s during load shedding or implement a combined strategy of fast closure (60%) and slow closure (40%). The study also revealed that the primary factors influencing the water hammer are valve closure time, number of valves, valve diameter, and valve distance, in that order, with the distance having a relatively minor impact. The results of this study provide valuable insights into valve closure strategies for water conveyance projects. Full article

The application of nanocomposites based on polyacrylamide hydrogels as well as silica nanoparticles in various tasks related to the petroleum industry has been rapidly developing in the last 10–15 years. Analysis of the literature has shown that the introduction of nanoparticles into hydrogels significantly increases their structural and mechanical characteristics and improves their thermal stability. Nanocomposites based on hydrogels are used in different technological processes of oil production: for conformance control, water shutoff in production wells, and well killing with loss circulation control. In all these processes, hydrogels crosslinked with different crosslinkers are used, with the addition of different amounts of nanoparticles. The highest nanoparticle content, from 5 to 9 wt%, was observed in hydrogels for well killing. This is explained by the fact that the volumes of injection of block packs are counted only in tens of cubic meters, and for the sake of trouble-free workover, it is very important to preserve the structural and mechanical properties of block packs during the entire repair of the well. For water shutoff, the volumes of nanocomposite injection, depending on the well design, are from 50 to 150 m³. For conformance control, it is required to inject from one to several thousand cubic meters of hydrogel with nanoparticles. Naturally, for such operations, service companies try to select compositions with the minimum required nanoparticle content, which would ensure injection efficiency but at the same time would not lose economic attractiveness. The aim of the present work is to develop formulations of nanocomposites with increased structural and mechanical characteristics based on hydrogels made of partially hydrolyzed polyacrylamide crosslinked with resorcinol and paraform, with the addition of commercially available nanosilica, as well as to study their thermal degradation, which is necessary to predict the lifetime of gel shields in reservoir conditions. Hydrogels with additives of pyrogenic (HCSIL200, HCSIL300, RX380) and hydrated (white carbon black grades: ‘BS-50’, ‘BS-120 NU’, ‘BS-120 U’) nanosilica have been studied. The best samples in terms of their structural and mechanical properties have been established: nanocomposites with HCSIL200, HCSIL300, and BS-120 NU. The addition of hydrophilic nanosilica HCSIL200 in the amount of 0.4 wt% to a hydrogel consisting of partially hydrolyzed polyacrylamide (1%), resorcinol (0.04%), and paraform (0.09%) increased its elastic modulus by almost two times and its USS by almost three times. The thermal degradation of hydrogels was studied at 140 °C, and the experimental time was converted to the exposure time at 80 °C using Van’t Hoff’s rule. It was found that the nanocomposite with HCSIL200 retains its properties at a satisfactory level for 19 months. Filtration studies on water-saturated fractured reservoir models showed that the residual resistance factor and selectivity of the effect of nanocomposites with HCSIL200 on fractures are very high (226.4 and 91.6 for fracture with an opening of 0.05 cm and 11.0 for porous medium with a permeability of 332.3 mD). The selectivity of the isolating action on fractured intervals of the porous formation was noted. Full article

Polyacrylamide-based gel plugging agents are extensively utilized in oilfields for water shutoff. However, their thermal stability, salt tolerance, and shear resistance are limited, making it difficult to achieve high-strength plugging and maintain stability under high-temperature and high-salinity reservoir conditions. This study proposes the use of chitosan (CTSs), a polysaccharide with a rigid cyclic structure, as the polymer. The organic cross-linker N,N′-methylenebisacrylamide (MBA) is incorporated via the Michael addition reaction mechanism to develop an ultra-stable, organically cross-linked chitosan gel system. The CTS/MBA gel system was evaluated under various environmental conditions using rheological testing and thermal aging to assess gel strength and stability. The results demonstrate significant improvements in gel strength and stability at high temperatures (up to 120 °C) and under high-shear conditions, as the increased cross-linking density enhanced resistance to thermal and mechanical degradation. Rapid gelation was observed with increasing MBA concentration, while pH and salinity further modulated gel properties. Scanning electron microscopy revealed the formation of a three-dimensional microstructure after gelation, which contributed to the enhanced properties. This study provides novel insights into optimizing polymer gel performance for the petroleum industry, particularly in high-temperature and high-shear environments. Full article

Silicate gels have long been utilized as water shut-off agents in petroleum fields to address excessive water production. In recent years, nano-silica gel has emerged as a promising alternative to traditional silicate gels, offering potentially improved plugging performance. However, the long-term effectiveness of these gels remains uncertain, posing challenges to sustained profitability. Therefore, a comprehensive study spanning 6 months was conducted on fractured and induced channel samples treated with nano-silica gel of 75/25 wt% (silica/activator) at 200 °F. A comparative analysis was performed with samples treated using polyacrylamide/polyethyleneimine PAM/PEI gel (9/1 wt%) to compare the performance of both systems. Throughout the aging period in formation water at 167 °F, endurance tests were conducted at regular intervals, complemented by computed tomography (CT) scans to monitor any potential degradation. The results revealed nano-silica gel’s superior long-term performance in plugging fractures and channels compared to PAM/PEI gel. Even after 6 months, the nano-silica gel maintained a remarkable 100% plugging efficiency at 1000 psi, with a maximum leak-off rate of 0.088 cc/min in the mid-fractured sample and 0.027 in the induced channel sample. In comparison, PAM/PEI gel exhibited a reduction in efficiency to 99.15% in the fractured sample (5.5 cc/min maximum leak-off rate) and 99.99% in the induced channel sample (0.036 cc/min maximum leak-off rate). These findings highlight the potential of nano-silica gel as a more durable water shut-off agent for managing water production in fractures and channels. Full article

Gel treatment is an economical and efficient method of controlling excessive water production. The gelation of in situ gels is prone to being affected by the dilution of formation water, chromatographic during the transportation process, and thus controlling the gelation time and penetration depth is a challenging task. Therefore, a novel gel system termed preformed particle gels (PPGs) has been developed to overcome the drawbacks of in situ gels. PPGs are superabsorbent polymer gels which can swell but not dissolve in brines. Typically, PPGs are a granular gels formed based on the crosslinking of polyacrylamide, characterized by controllable particle size and strength. This work summarizes the application scenarios of PPGs and elucidates their plugging mechanisms. Additionally, several newly developed PPG systems such as high-temperature-resistant PPGs, re-crosslinkable PPGs, and delayed-swelling PPGs are also covered. This research indicates that PPGs can selectively block the formation of fractures or high-permeability channels. The performance of the novel modified PPGs was superior to in situ gels in harsh environments. Lastly, we outlined recommended improvements for the novel PPGs and suggested future research directions. Full article

Polymer-plugging agents are widely employed in profile control and water-plugging measures, serving as a crucial component for efficient reservoir development. However, quantitatively monitoring the emplacement depth of polymer-plugging agents in low-permeability and high-permeability layers remains a challenging bottleneck. Presently, insufficient attention on shear thinning, a critical rheological property for water shut-off and profile control, has limited our understanding of polymer distribution laws. In this study, polymer shear-thinning experiments are firstly conducted to explore polymer variations with flow rate. The novelty of the research is that varying polymer viscosity is implemented instead of the fixed-fluid viscosity that is conventionally used. The fitted correlation is then integrated into the 2D and 3D heterogeneous numerical models for simulations, and a multivariate nonlinear regression analysis is performed based on the simulation results. The results show that lower polymer emplacement depth ratios corresponded to higher viscosity loss rates under the same flow rate. An increase in the initial permeability ratio corresponds to a decrease in the emplacement ratio, along with a reduction in the fraction of the plugging agent penetrating the low permeability formations. The model was applied to the Kunan Oilfield and demonstrated a polymer reduction of approximately 3000 tons compared to traditional methods. Despite the slightly complex nature of the multivariate nonlinear mathematical model, it presents clear advantages in controlling plugging agent distribution and estimating dosage, laying good theoretical ground for the effective and efficient recovery of subsurface resources. Full article

Gas inflow control in oil wells is one of the most challenging types of repair and sealing operations, the success rate of which does not exceed, as a rule, 30%. Conventional shutoff methods are often ineffective for this purpose. For instance, cement solutions cannot be injected into wells in the required volumes, while gel screens can only temporarily block the breakthrough zones, as gas easily seeps through the gel, forming new channels for gas inflow. Technology for the two-stage injection of gas-insulating gel systems for gas control in horizontal wells was developed. At the first stage, a self-generating foam gel composition (FGC), consisting of gel-forming and gas-forming compositions, was used. A foam gel structure with enhanced rheological and flow characteristics was formed over a controlled time as a result of the interaction between the gel-forming and gas-forming compounds. A PAM-based hydrogel crosslinked with an organic crosslinker was added to the FGC at the second stage of treatment. The laboratory experiments substantiated the technology of well gas and water shutoff by the sequential injection of self-generating foam gel composition and hydrogel. Field tests confirmed the correctness of the chosen concept. It is very important to clearly identify the sources of gas inflow for the success of this well intervention and take into account the well design, as well as the reservoir geological structure and characteristics. The gas shutoff operation can be properly designed for each well only by comparing all these factors. The validity of the selected technology was tested through a series of laboratory experiments. Successful laboratory tests allowed for the application of the studied technology in a field setting, where the gas shutoff agent was injected into three horizontal wells. As a result of the field application, the gas inflow was successfully isolated in two wells. However, the application of the technology failed in the third well which gave an opportunity to revisit the technology’s design and to review the sources of gas inflow. Overall, the achieved success rate of 66% demonstrated the high efficiency of the studied technology and supported its wider application in the field. Full article