Plugging Performance Research Articles

Experimental investigation on the oxidation of printing ink wastewater under hydrothermal flames

Printing ink wastewater has a strong color and contains high salinity and high concentrations of complex organic compounds, posting a severe threat to the ecological environment and human health. In this work, supercritical water oxidation of printing ink wastewater is performed within a transpiring wall reactor (TWR) to avoid corrosion and salt plugging issues. The high concentration of organic matter in printing ink wastewater is used to form hydrothermal flames for enhanced degradation. Flame temperatures, gaseous and aqueous products characteristics, as well as the anti-corrosion and salt plugging performance of the reactor, are obtained. A remarkable temperature fluctuation due to the multi-component systems indicates the instability of hydrothermal flame. The salt recovery rate of 94.56% and the integrity of the porous tube inner wall indicate that TWR has a good performance in terms of anti-corrosion and salt plugging. Under typical conditions, the removal rates for chemical oxygen demand, total nitrogen, and color are 99.52%, 70.07%, and 97.89%, respectively. Alkanes, nitrogenous compounds, benzodiazepines, and heterocyclic compounds in the aqueous products, and CO, H2, NH3, and CH4 in the gaseous products are the main intermediate products of printing ink wastewater under hydrothermal flames. Ammonia nitrogen, as the main intermediate product, inhibits the complete oxidation of nitrogenous organic compounds. Additionally, higher KNO3 concentrations promote the complete oxidation of nitrogenous organic compounds, while higher NaOH concentrations can increase the pH value and slightly facilitate degradation. In addition, higher feed flow rates prevent deposition and adhesion of additives that occur at high concentrations.

Drilling Fluid Technology for Horizontal Well in Ecuador Tambococha Oilfield

The Tambococha Block in Ecuador is an oil field with high porosity and high permeability reservoir characteristics, the lower formation is broken and micro-fractures are developed too. For this reason, utilizing Polyalcohol XCS-III and emulsified paraffin G325 as the main two agents, then optimizing other environmentally friendly agents, a strong plugging reservoir protection water-based drilling fluid is formed finally, which is suitable for the Tambococha oil field in Ecuador. The drilling fluid utilizes the synergistic plugging effect of emulsified droplets, cloud point effect, micron particles and rigid particles to reduce the oil-water interfacial tension and prevent the drilling fluid from entering the formation to finally achieve the purpose of anti-collapse plugging and reservoir protection. Laboratory experiments show that the drilling fluid has strong inhibitory properties, and the linear expansion rate of cuttings in it is reduced by 64.8% compared with that in clean water; the plugging performance is good, and its particle size distribution can fit the ideal filling curve better; the damage to reservoir is a little, with an average damage rate of 10.25% to the cores of the U layer of the Napo formation; the drilling fluid has good environmental performance, and the content of heavy metals meets the requirements of sewage discharge standards. The drilling fluid system has been successfully applied to 15 horizontal wells in the Tambochocha Oilfield. The main performance is with wellbore stability and smooth tripping. The average daily crude oil output of a single well neers 300 t, which is nearly 90% higher than that of offset wells, and the environmental indicators of drilling fluid and drilling cuttings meet the requirements of EPA1311 standards. The research results show that the water-based drilling fluid can meet the drilling safety and reservoir protection requirements of horizontal wells of the Tambococha oil field in Ecuador.

Core-nano-emulsion used in the laboratory study of plugging micro–nano cracks in southwestern Tarim

The southwestern Tarim area is rich in oil and gas resources and has good exploration and development potential. However, due to the widespread occurrence of micro–nano cracks and pore leakage during the drilling process, it is difficult to solve the problem, resulting in the loss of drilling fluid and the swelling of clay minerals as the filtrate enters the pore throat. This has severely restricted the exploration and development process of oil and gas resources in this area. In order to improve the complexity and frequency of southwestern Tajikistan, this article analyzes the development of wellbore formation fractures in this area, and on this basis, through comparison and screening, the drilling fluid core-nano-emulsion independently developed by the University of China. Finally, use the core-nano-emulsion for drilling fluid independently developed by China University of Petroleum (Beijing). This new material is a nano-emulsion with nano-SiO2 as the core, and its D50 is about 100 nm. Experiments show that by adding 5% nano-core emulsion for optimization, the water loss of the drilling fluid under high temperature and high pressure is 4 ml, and the thickness of the mud cake is 1.5 mm. The pressure conduction method was used to evaluate the plugging performance of the micro–nanopore cracks, and the results showed that the optimized pressure was reduced by 0.337 Mpa compared with the optimized pressure. Practice has proved that the inner core nanoemulsion can be used as an additive for water-based drilling fluids to realize the optimization of drilling fluids.

Application of carboxylated cellulose nanocrystals as eco-friendly shale inhibitors in water-based drilling fluids

Shale hydration, swelling, and dispersion are the main reasons causing wellbore instability in oil and gas drilling operations. In this research, carboxylated cellulose nanocrystals(C-CNC) were prepared and developed as a shale inhibitor in water-based drilling fluids (WBDF). The inhibitive property of C-CNC was evaluated through immersion experiments, linear swelling measurements and a shale recovery test. The potential inhibition mechanism was studied by observing the external morphology through the scanning electron microscope (SEM), transmission electron microscopy (TEM), and measuring the zeta potential and particle size distribution, and evaluating the plugging performance through filtration test and BET test. The inhibition evaluation results showed that the expansion of 1%C-CNC was 1.41 mm, and the recovery rate of shale of 3%C-CNC can reach 78.8%. C-CNC has better inhibition properties than the widely used potassium chloride(KCl), polyester amine(PA) and polyether(PEA). The mechanism study revealed that these nanoparticles can form a core-shell structure with clay through electrostatic interaction, thereby suppressing the hydration of clay. Furthermore, the free water content of C-CNC suspension is low, and it is easy to form a gel. Through the action of drilling pressure and capillary pressure, C-CNC is squeezed into and filled in the pores and cracks of the shale, forming an adsorption layer and preventing water intrusion. In addition, C-CNC could considerably decrease the filtrate volume of the drilling fluid, while KCl and PEA had negative influences on the properties of the drilling fluid. C-CNC performed great potential to be an effective and biodegradable shale inhibitor in drilling fluids.

Study on the loss control performance of smart adhesive lost circulation materials with Ethylene Vinyl Acetate Copolymer (EVA)

The conventional lost circulation materials (LCMs) particles of seal in the formation are in linear contact. Therefore, there is no cohesive force interaction, which is susceptible to pressure fluctuations, resulting in lost circulation and control failure. In response to these problems, this paper tested the high-temperature adhesion properties of EVA in the viscous flow transition zone through high-temperature adhesion experiments; then a smart adhesive LCMs is prepared using thermoplastic EVA resin with conventional LCMs; finally, through the high-temperature and high-pressure plugging experiment, the system's performance for sealing fractures was tested. The experiment results show that the smart adhesive LCMs have good plugging performance and can bond LCMs in the fracture to form a high-strength sealing with a pressure-bearing capacity of up to 9.3MPa.

A new method for plugging the dominant seepage channel after polymer flooding and its mechanism: Fracturing–seepage–plugging

AbstractAfter polymer flooding, a low-resistant dominant seepage channel forms at the bottom of the high-permeability reservoir, which is extremely disadvantageous for further enhanced oil recovery. In this study, we proposed a new method to plug the dominant seepage channel after polymer flooding, through fracturing–seepage–plugging using a solid-free plugging agent, which can achieve deeper and further regional plugging. This method involved dissolving the crosslinking agent and stabilizer in the water-based fracturing fluid (hereinafter referred to as the fracturing plugging agent) and transporting it to the target reservoir through hydraulic fractures. The fracturing plugging agent percolated into the deep part of the reservoir under the action of fracture closure pressure and gelled with the residual polymer in the formation to achieve deep regional plugging of the advantageous channel. To study the percolation law of fracturing plugging agent in the dominant channel, high-pressure displacement experiments were conducted using natural cores under different permeability and concentration conditions of the fracturing plugging agent. The results showed that the percolation rate of the fracturing plugging agent was almost linearly related to reservoir permeability. Due to the formation of micro-fractures and crosslinking reactions, the percolation rate first increased and then decreased to a stable state. After a certain period, the pores were blocked, resulting in a sharp decrease in the percolation rate and then decayed. In addition, the higher the concentration of fracturing plugging agent, the better the core plugging performance. Moreover, when the concentration of fracturing plugging agent injected into the core exceeded 3,000 mg/L, the core permeability increased, and the breakthrough pressure evidently increased three to four times. On the basis of this, rheometer tests, scanning electron microscopy (SEM) observations, and mercury intrusion tests were performed to evaluate gelation performance, shear effect, and pore retention morphology of the crosslinking system made by mixing the injected plugging agent and residual polymer in the reservoir. The results showed that the shear action could reduce the gelling property, and the concentration of fracturing plugging agent should be >3,000 mg/L to meet the requirements of gelling. Furthermore, the viscosity of the crosslinking system reached the peak value at approximately 72 h, forming a network space structure of layered superposition, thereby increasing viscosity by 40–50 times. Finally, SEM images revealed that after the fracture plugging agent was injected into the core, the micelles were mostly concentrated in the front and middle sections. The average pore radius of the core decreased by 8.620 μm, and the average porosity decreased by 54.85%.

Experimental Study on the Optimization of Multi-level Nano-Microsphere Deep Profile Control in the Process of Gas Injection in Fracture-Type Buried-Hill Reservoirs.

Fracture-type buried-hill reservoirs refer to dual media which have a fast breakthrough speed and a low sweep efficiency in the process of gas injection displacement. In order to overcome this problem, in this paper, a new profile control and oil displacement technology of pre-slug deep plugging by injection of different levels of nano–microspheres and natural gas was proposed. The mercury intrusion experiments were used to compare the fractal characteristics of the pore structures of the matrix and artificial fractured cores in the buried-hill reservoir. The results show that the heterogeneous characteristics of pores and fractures are the main factors leading to excessive gas breakthrough. Three nano–microsphere systems (WJ1, WJ2, and WJ3) with good temperature resistance, salt resistance, swelling properties, and stability were prepared using the inverse emulsion method. Core plugging performance tests show that WJ3 has the best plugging effect among the three nano–microsphere systems, followed by WJ2 and WJ1. According to the scanning electron microscopy observations, it was found that the sealing mechanism of nano–microspheres includes direct sealing, bridging sealing, adhesive sealing, direct pass, deformed pass, and crushing pass. Finally, the displacement experiments with a composite fractured core showed that compared with pure natural gas injection, the breakthrough time of the combined displacement process of nano–microspheres and natural gas was greatly extended, and the final oil displacement efficiency was increased to greater than 80%.

Experimental Study of CO 2 Responsive Enhanced Foam System

The channeling of CO2 seriously affects the development effect of CO2 flooding technology. In response to this problem, the construction of the CO2 responsive enhanced foam system and the evaluation of its channeling performance have been carried out. The foaming agent is optimized by the stirring method, the CO2 responsive enhanced foam system is constructed based on the optimization of foam agent, and the rheological performance test and the enhanced oil recovery experiment are carried out to study the stability mechanism and channeling plugging performance of the responsive enhanced foam system. The developed responsive enhanced foam system formula is 0.1 wt% AOS foaming agent + 4 wt% small molecule amine. The viscosity of this system is close to that of water before exposure to CO2, and the viscosity can increase by more than 18 times corresponding to CO2. The CO2 responsive enhanced foam system has obvious shear thinning characteristics, and its rheological equation conforms to the power law fluid rheological model. The enhanced foam system has stronger viscoelasticity than conventional foams. The foam comprehensive value of the enhanced foam system can reach more than 11 times that of the conventional foam system, which can effectively inhibit the CO2 channeling of heterogeneous low permeability reservoirs and improve the development effect of CO2 flooding in low permeability reservoirs.

Using 1,2 dimethylimidazole to improve gel thermalstability for wellbore plugging in ultra-high temperature fractured reservoirs

Working fluid loss as well as formation damage is usually encountered as a big challenge during well completion and workover for fossil-fuel production. Polymer gel is widely used for wellbore plugging to isolate the working fluid and the reservoir for controlling fluid loss and protecting the reservoir. However, with the increasing number of ultra-high temperature well (>180 °C) operations, the thermal stability of the gel plug is increasingly required. In this paper, 1,2 dimethylimidazole (C5H8N2) is first used to prepare a gel plug. The effects of C5H8N2 on gel gelation at dynamic heating mode, viscosity, elasticity, thermal stability and temporary plugging performances are evaluated at 190 °C. It is found that the addition of C5H8N2 does not affect the gelation, while a slightly viscosity-reducing effect is exhibited. At 190 °C, the gel without C5H8N2 broke down within 4 hours and lost its temporary plugging performance, while the gel with 20% imidazole remained unbroken after 60 hours. For the fractured core (5 cm in length) plugging experiments, the addition of 15% C5H8N2 significantly increased the breakthrough pressure of gels from 0.2 MPa to 1.9 MPa compared to pure gels (without C5H8N2). The enhancement mechanism of C5H8N2 is investigated. Recommendations for the application of gels with C5H8N2 are given in the paper. This paper provides an avenue for the development of gel plug to deal with wellbore temporary plugging jobs in ultra-high temperature fractured reservoirs.

Novel modified nano-silica/polymer composite in water-based drilling fluids to plug shale pores

ABSTRACT The rapid growth of global energy demand necessitates high-performance water-based drilling fluids (WDFs) with excellent-plugging performance in the deep excavation of shale gas formation. Herein, we report an organic-inorganic nanocomposite (NS-D) as a plugging agent in WDFs to plug the nanoporous of shale and abate the hydration expansion of shale by integrating the advantages of inorganic and polymer nano plugging agents. The results of Fourier Transform infrared spectroscopy (FTIR) and proton nuclear magnetic resonance (H-NMR) revealed that NS-D had been successfully obtained. Additionally, thermogravimetric analysis (TGA) showed that the thermal degradation temperature of NS-D occurred after 354 °C. The results of plugging theory analysis showed that the presence of rich amide groups and rigid material silica not only made NS-D adhere to shale efficiently by hydrogen bonding, but also firmly blocked the nanoporous of shale. The plugging ability was evaluated by pressure transfer test and nitrogen adsorption test. The results showed that WDFs with NS-D can significantly improve plugging efficiency and reduce fluid invasion. On the other hand, NS-D sharply abated the fluid loss of WDFs due to its positive plugging performance. The filtrate volume of WDFs decreased by 90.5% and 88.3%, respectively, before and after hot rolling at 150°C for 16 h. Moreover, the plugging performance of NS-D for WDFs was significantly better than polymer plugging agent crosslinked polyacrylamide microspheres and inorganic plugging agent silica nanoparticles. This work provides a novel strategy to plug the nanoporous of shale in the process of shale gas exploration.

Laboratory Experimental Optimization of Gel Flooding Parameters to Enhance Oil Recovery during Field Applications.

The profile-control technique is one of the most important enhanced oil recovery (EOR) methods to maintain oil production in the medium and late stages of water flooding. It is necessary to conduct laboratory experiments based on the reservoir parameters from specific oil reservoirs to optimize the operation parameters during the profile-control process. In this work, based on the reservoir properties from Daqing Oil Field (China), we employed three parallel core holders and a square core with one injection well and four production wells to conduct profile-control experiments, and the operational parameters in the field scale were obtained using the similarity principle. The results show that the selected gel system has a good plugging performance and the best injection volume and profile-control radius are 0.3 PV and 6 m, respectively. Additionally, we show the optimized injection speed under different injection pressures when the profile-control radius is in the range of 6–9 m. The optimized displacing radius of the field is in the range of 3–6 m. When the radius is 6 m, the pressure decreases 90% and the corresponding plugging ratio is 81%. The optimized plugging proportion of the fracture length is 50%, and further increase of the proportion has a negligible effect on the production performance. Good field response has been achieved after the implementation of the optimized parameters in the target reservoir. This work, for the first time, systematically studies the operational parameters for the profile-control technique using experimental methods, and it provides the fundamental understandings and implications for enhancing oil recovery in similar types of high-water-cut reservoirs.

The Utilization of Steelmaking Industrial Waste of Silicomanganese Fume as Filtration Loss Control in Drilling Fluid Application

Abstract Drilling fluid is considered the backbone of drilling operations in the oil and gas industry to unlock hydrocarbon from subterranean formations. Maintaining the drilling fluid properties, for example, flow properties such as rheology, plastic viscosity (PV), yield point (YP), gel strength (GS), and circulation loss, is the challenge for fluid/mud engineers to carry out successful drilling operations. A variety of chemicals have been added to improve the drilling fluid properties by introducing new chemicals or optimizing the existing chemicals without affecting the other essential fluid properties. The present study for the first time employs the eco-innovation concept to explore the utilization of steelmaking industry waste, i.e., silicomanganese fume (SMF), as a bridging material. The objective of this article is to design an eco-friendly framework that comprehensively explains and utilizes SMF as a bridging material in water-based fluid (WBF). The eco-innovation/eco-friendly framework includes the steps required for processing and understanding the new material and evaluating its effects on flow and the bridging properties of WBF. A scanning electron microscope (SEM), X-ray fluorescence (XRF), and particle size distribution (PSD) were used to understand the physicochemical properties of SMF. The flow properties were studied using a Fann rheometer before and after hot rolling at 120 °F. A high-pressure high-temperature (HPHT) filter press equipment was used to investigate the bridging capability of seepage losses following conditions of 190 °F and 300 psi differential pressure. Minimal cleaning and disintegration with a mortar and pestle are enough to prepare SMF to be incorporated in drilling fluid. The SEM and XRF results showed that SMF contains oxides of manganese, silicon, potassium, calcium, and magnesium, while the PSD revealed a natural bimodal distribution with an average grain size of D50 of around 29 μm. SMF showed a noticeable and measurable enhancement of flow properties and bridging capability in WBF. The SMF-based WBF showed improved rheological properties, plastic viscosity, and yield point compared with marble-based WBF. Adding SMF to WBF with and without marble showed a ten-fold superior plugging performance compared with marble-based WBF using 20-μm ceramic discs. The findings revealed the successful utilization of SMF in WBF by improving the rheology, plastic viscosity, yield point, and bridging capability.

Novel chemical flood combination of CSA particles and strong emulsifying surfactant in heterogeneous reservoirs

In-depth profile control agents and surfactant have been successfully applied to control excess water production and extend the lifetime of oilfields. In this study, a novel chemical flood combination composed of controllable self-aggregating particles (CSA), and a surfactant with strong emulsifying capability was designed for heterogeneous reservoirs. A series of physical experiments were performed to investigate the injection ability, plugging performance and plugging mechanisms of CSA particles. Besides, the dominating behavior of surfactant and the effect of heterogeneity degree variation were conducted in a 2D heterogeneous model and artificial cores. More importantly, the synergistic effect of chemical flood combination and adaptability on heterogeneity were explored. The results show, the emulsifying capability of surfactant plays a key role to the oil recovery, and its enhanced oil recovery (EOR) performance is controlled by the heterogeneity degree variation. Meanwhile, CSA particles exhibit an outstanding injection ability for in-depth penetration, and a promising plugging performance with an effective flow-resistant distribution because of its physical and chemical action. Moreover, the synergism of chemical flood combination, CSA particles improving in-depth swept volume and a highly efficient surfactant, contributes to EOR potentials and adaptability on heterogeneity degree variation. Therefore, the findings of this study would provide a novel method for EOR in heterogeneous reservoirs, which can be a candidate with great potentials for field application.

One-Dimensional Convolutional Neural Network with Adaptive Moment Estimation for Modelling of the Sand Retention Test

Stand-alone screens (SASs) are active sand control methods where compatible screens and slot sizes are selected through the sand retention test (SRT) to filter an unacceptable amount of sand produced from oil and gas wells. SRTs have been modelled in the laboratory using computer simulation to replicate experimental conditions and ensure that the selected screens are suitable for selected reservoirs. However, the SRT experimental setups and result analyses are not standardized. A few changes made to the experimental setup can cause a huge variation in results, leading to different plugging performance and sand retention analysis. Besides, conducting many laboratory experiments is expensive and time-consuming. Since the application of CNN in the petroleum industry attained promising results for both classification and regression problems, this method is proposed on SRT to reduce the time, cost, and effort to run the laboratory test by predicting the plugging performance and sand production. The application of deep learning has yet to be imposed in SRT. Therefore, in this study, a deep learning model using a one-dimensional convolutional neural network (1D-CNN) with adaptive moment estimation is developed to model the SRT with the aim of classifying plugging sign (screen plug, the screen does not plug) as well as to predict sand production and retained permeability using a varying sand distribution, SAS, screen slot size, and sand concentration as inputs. The performance of the proposed 1D-CNN model for the slurry test shows that the prediction of retained permeability and the classification of plugging sign achieved robust accuracy with more than a 90% value of R2, while the prediction of sand production achieved 77% accuracy. In addition, the model for the sand pack test achieved 84% accuracy in predicting sand production. For comparative model performance, gradient boosting (GB), K-nearest neighbor (KNN), random forest (RF), and support vector machine (SVM) were also modelled on the same datasets. The results showed that the proposed 1D-CNN model outperforms the other four machine learning models for both SRT tests in terms of prediction accuracy.

Experimental study of degradable preformed particle gel (DPPG) as temporary plugging agent for carbonate reservoir matrix acidizing to improve oil recovery

Preformed particle gel (PPG) is an effective technique for conformance improvement in petroleum reservoirs. It can selectively penetrate high-permeability channels to form effective plugging and divert the chasing injection fluid to low-permeability unswept oil zones. However, conventional PPG would be dehydrated under acidic conditions and could not be easily degraded, which will cause a certain amount of damage to the target formation. Therefore, this study proposed to introduce acid-resistant functional groups and a self-degradable cross-linking structure into the conventional PPG's compositions to develop a degradable PPG (DPPG). The influence mechanism of the chemical composition, swelling performance, and temporary plugging performance of DPPG was studied. Results show that the DPPG can swell up to 70 times its original size by absorbing water, and swollen DPPG can finally self-degrade to a water-like fluid in acid solution. After injecting of DPPG swelled by 20 times its original volume, the injection pressure could reach 1250 psi. Even during the chase acid treatment period, the average pressure was around 130 psi, which shows excellent plugging performance. Subsequent injection of acid would react with carbonate rocks around the plugging zones, increasing the swept volume. In addition, after acid treatments, the DPPG could be self-degraded into a dilute solution like water, so it has very little damage to the reservoir matrix. Therefore, the DPPG has good temporary plugging and acidizing steering performance in acidizing operations. The research in this article can provide the experimental basis and reference for expanding the further application of DPPG in petroleum reservoir stimulation. • Acid-resistant and self-degradable cross-linking structures were introduced to develop a degradable PPG. • The swelling and degradation performance can be adjusted by changing its component concentration. • Coreflooding test reveals that DPPG has a good acid diversion function. • DPPG can undergo self-degradation in a wide range of acidity.

Effectiveness of Copolymer of Polymethylmethacrylate and Styrene as a Plugging Agent in Water-Based Drilling Fluids

In the development of shale gas, it is important to ensure the stability of the borehole wall. The stability of the borehole wall depends on the plugging ability of the drilling fluid, while the stabilizing ability of the drilling fluid is provided by adding the plugging agent to the fluid. Conventional plugging agents are characterized by a relatively high volume and do not allow one to effectively plug micropores and microcracks in shale rock. In this work, the PMMA-St copolymer was synthesized by emulsion polymerization of methyl methacrylate and styrene. The characteristics of the PMMA-St copolymer were studied by FT-IR, TGA, and phase analysis optical scanning methods. The results show that the size of PMMA-St nanoparticles ranges from 34 to 58 nm, and the average diameter is about 40.6 nm. The decomposition temperature of PMMA-St nanoparticles is 374.8°C, which indicates the good thermal stability of the copolymer. The PMMA-St nanoparticles have little affect on the rheological properties of water-based drilling fluids. The mud cake simulation method was used to evaluate the plugging performance of PMMA-St nanoparticles. The permeability of mud cake is 2.24 × 10-5 m2, which is close to the permeability of shale formation. When 0.5 wt % of the PMMA-St copolymer is added to the solution, the blocking rate is 70.27%. With increase in PMMA-St concentration, the blocking rate of the mud cake increases. The best stabilizing effect is achieved when the PMMA-St copolymer concentration is 1.0%. The results of the core experiments are consistent with the mud cake simulation, which indicates the excellent sealing ability of the PMMA-St copolymer. Therefore, PMMA-St nanoparticles can be effectively used as a plugging agent to ensure borehole stability in the shale formation.

CO2-responsive agent for restraining gas channeling during CO2 flooding in low permeability reservoirs

Hydraulic fracturing and CO2 flooding are extensively used in low-permeability reservoirs to enhance oil recovery (EOR). However, due to the serious heterogeneity of the formation, CO2 is prone to break through the oil-bearing zone prematurely, which leads to the decrease of the swept volume. Conventional blocking agents have some defects such as difficult injection, poor stability and weak sealing strength. Therefore, it is critical to developing a new type of channeling blocking agent for low-permeability fractured reservoirs. In this study, ten kinds of chemicals with tertiary amino groups are filtered for the most effective CO2-responsive agent, which turns out to be N, N-Dimethyl erucamide tertiary amine (DMETA). Subsequently, rheological properties, response performance, and microstructure of the optimum agent are researched systematically through rheological experiments, CO2-response processes and Cryo-TEM. The results show that the viscosity of the DMETA solution can increase to nearly 605,700 mPa·s by self-assembly into wormlike micelles (WLMs). And it can be reversibly circulated between low viscosity and high viscosity by alternately introducing and removing CO2, which endows it with the ability to healing its viscoelasticity under an environment full of CO2. A new method based on optical microrheology is proposed to study the viscoelastic properties of WLMs under no external force. The experiments prove that the network structure is not stable after formation, but remains in a continuous process of separation and reconstruction as “a living polymer.” Furthermore, the plugging performance and EOR capacity are evaluated using fractured tight cores. The experiments demonstrate that the optimum agent can effectively restrain gas channeling and enhance recovery factor by 21.7%. We expect our work can provide insights for the synthesis of CO2-responsive WLMs and guidance for retarding gas channeling during CO2 flooding in low permeability reservoirs.

Intelligent sustained‐release microgel for reduced permeability of fluid channels: Synthesis and properties

AbstractPolymer microspheres as fluid diverting agents have been applied for profile control in deep reservoirs. However, its reservoir adaptability strictly requires the matching between the particle size and the pore radius, which are hard to realize due to uncertainty of pore radius caused by long‐term water flooding. That behavior has severely reduced their plugging performance to the large channel. The objective of this study was to prepare a kind of intelligent sustained‐release microgel to solve the problem, which could slowly release of sodium silicate during migration, form the larger aggregates and plug high permeability reaching deep reservoir. We developed a novel blocking agent, which is an amphoteric microgel (OICMS) synthesized by light‐initiated polymerization followed by the adsorption of a sodium silicate solution. The microgel properties, including the adsorption and release properties of a sodium silicate solution, and its influencing factors were investigated. The results showed that the OICMS had larger adsorption and release ratio of sodium silicate than conventional polymer microspheres, influenced by the ionic degree, molecular weight, amount of pore‐forming agent, and cross‐linking density.

Oil Displacement Performance Using Bilayer-Coating Microspheres

We systematically investigate the plugging performance and oil-displacement efficiency of the novel bilayer-coating microspheres (BCMS) designed for in-depth conformance control within heterogeneous hydrocarbon reservoirs. Visualization experiments on various glass models, as well as one- and two-phase core floods have been carried out at reservoir temperature and fluid salinity. Our results demonstrate that the rigid outer layer of BCMS can successfully protect its adhesive inner coating, enabling BCMS to transport deeply into porous media. Increasing particle concentration yields higher collision probability, leading to the formation of particle assembly that could effectively block pore throats in high-permeability channels and achieve more oil recovery in the low-permeability zones. It is also shown that as the BCMS slug size increases, the oil recovery asymptotically reaches a maximum value. A larger slug size cannot highly enhance the plugging performance yet significantly increase the resistance factor. A smaller permeability ratio of parallel cores leads to a narrower difference between the fractional flow rates. When the permeability ratio is two or lower, the fractional flow rates of parallel cores are both around 50%, yielding the best oil-displacement efficiency. BCMS exhibits promising application potential in production enhancement under reservoir conditions.

Laboratory evaluation on temporary plugging performance of degradable preformed particle gels (DPPGs)

In recent years, granular temporary plugging agents (TPA) have been widely studied, especially in repeated fracturing operations, to stimulate oil and gas production in unconventional petroleum reservoirs. They can divert the hydraulic fracturing energy to form more complex fractures that make oil and gas more easily flow into production well. Pre-formed particle gels (PPGs), as deformable particles, are often used in petroleum reservoir water management operations because of their high strength, simple fabrication process, and environmental friendliness. However, their application as TPA is rarely reported. In this paper, degradable PPGs (DPPGs) were employed, and their temporary plugging performance was studied in the laboratory. Bottle tests were first conducted to investigate the swelling and degradation performance. Results show that DPPGs exhibit good swelling ability in an extended range of brine salinity (20000 to 400000 ppm), and DPPGs can be fully degraded, and the degradation time increase with temperature. According to the temporary plugging performance by core flooding experiments, the plugging strength increased with the injection pressure, dry particle size, and swelling ratio (less than 20 times). However, the addition of smaller size particles will prevent large particles from forming deformable blockage on the matrix end surface, and subsequent water flow channels will be easily created, so the plugging performance of the DPPGs will decrease. The above experimental results can provide an experimental and theoretical basis for the application of DPPGs in repeated fracturing operations in unconventional reservoirs.