Plugging Capacity Research Articles

Synthesis and characterization of natural rosin-modified silica nanocomposite and its green multifunctional applications for drilling fluid

The increasing energy demand and environmental pressure require the utilization of high-performance and eco-friendly drilling fluid materials for oil/gas exploration. Herein, a green nanocomposite involving the core structure of silica (SiO2), the resin shell structure of rosin dehydroabietic acid (DHAA) derivative [poly(DHAA-co-styrene) (PDS)], and the crown structure of hydrophilic layer [crosslinked poly(2-acrylamido-2-methyl-1-propanesulfonic acid-co-N, N-dimethylacrylamide) (CAD)] was prepared through semi-continuous emulsion polymerization and utilized as a high-performance and multifunctional additive for drilling fluid. The optimal composition of core, shell and crown was determined to be 0.3: 10: 2 in mass, and the DHAA component accounted for 50 wt% in the shell structure and the molar ratio of 2-acrylamido-2-methyl-1-propanesulfonic acid and N, N-dimethylacrylamide in the crown was 3:7. The core-shell-crown nanocomposite (SiO2-PDS-CAD) exhibited a well-organized multi-layered nanostructure with an effective encapsulation of PDS on nano-SiO2 and CAD on PDS, facilitating a uniform nano-dispersion of SiO2-PDS-CAD. The bulky copolymerized rosin-based segments coupled with nano-SiO2 resulted in high thermal stability of SiO2-PDS-CAD and broadened the softening point of raw rosin from 87°C to 141°C. Meanwhile, the environmental assessments of acute toxicity and biodegradability showed that SiO2-PDS-CAD was nontoxic and readily biodegradable, and the higher incorporation of rosin components enabled SiO2-PDS-CAD more biodegradable in contrast to the non-biodegradability of the analog without rosin. Moreover, SiO2-PDS-CAD showed versatile functions in bentonite-based drilling fluid by maintaining high yield points, lowering fluid loss and enhancing nano-porous plugging capacity (100–400 nm), especially at elevated temperatures (140–180°C). A maximum increment of 1200 % on yield point occurred after aging 170°C, and the highest improvement of approximately 72 %-75 % on fluid loss occurred at 150–180°C. It also could effectively inhibit clay swelling and decrease the lubrication coefficient. The enhancement mechanism was revealed to be the core-shell-crown synergistic effects, in which the hydrophilic crown contributed to the dispersion stability of SiO2-PDS-CAD and affinity with bentonite clay, and the rigid bridging of core and flexible deformation of rosin shell strengthened the interparticle interactions. The study highlighted a novel strategy for preparing high-value-added rosin-based biomass material for green multifunctional applications in water-based drilling fluids.

Research and application of the low-damage temperature-controlled phase change temporary plugging agent

Ultra-deep dense sandstone reservoirs are characterized by high stress, large stress difference, high temperature, etc. Compared with conventional fracturing techniques, temporary plugging fracturing techniques are more capable of increasing fracture complexity and improving the stimulation reservoir volume (SRV). Phase-change temporary plugging agent has received wide attention due to its easy injection and return characteristics, etc. However, the temporary plugging mechanism of phase-change temporary plugging agent on shot-holes and fractures is still unclear. Therefore, this study aimed to develop a temperature-controlled phase change temporary plugging agent (STPA). The main properties of STPA, such as gel formation time and plugging capacity, are studied. The results show that STPA completes the transition behavior of solution-gel-solution at different temperatures; the gel formation time and gel breaking time of STPA decrease with increasing temperature; the pressure-bearing capacity of the plugging increases with the width of the fracture; the pressure-bearing capacity of STPA is more than 20 MPa in the fracture, and more than 18 MPa in the “shot-hole + fracture”; the rate of injury to core permeability by STPA is about 1.2%. In addition, STPA was successfully applied in fracturing field practice, and the maximum injection pressure increment was about 12.08 MPa, with remarkable temporary plugging effect. These results help to reveal the plugging mechanism of phase change plugging agent, which is of guiding significance for the field application of STPA.

Potential application of wet-phase modified expandable graphite particles as a novel in-depth profile control agent in carbonate reservoirs

Novel wet-phase modified expandable graphite (WMEG) particles were developed for in-depth profile control in carbonate reservoirs. The harsh environment of carbonate reservoirs (≥ 130 °C, ≥ 22 × 104 mg/L) brings significant challenges for existing profile control agents. WMEG particles were developed to address this problem. WMEG particles were synthesized via intercalation with ultrasound irradiation and chemical oxidation. The critical expansion temperature of WMEG particles is 130 °C, and these particles can effectively expand 3–8 times under high temperature and high salinity water. The core flow experiments show that WMEG particles exhibit a good plugging capacity, profile control capacity, and a better-enhanced oil recovery (EOR) capacity in deep carbonate reservoirs. WMEG particles can be expanded in the formation and form larger particles that bridge the upper and lower end faces of the fracture. Then the high-permeability zones are effectively plugged, and the heterogeneity is improved, resulting in an obvious increase in oil recovery. This research provides a novel insight into future applications of profile control agents for in-depth profile control treatment in carbonate reservoirs.

High-Temperature, Salt-Resistant, and High-Strength-Controlled Consolidated Resin Slurry for Fracture Plugging during Oil and Gas Well Drilling

Summary The temperature and pressure of deep and ultradeep plugging are gradually increasing, resulting in higher requirements for the performance of plugging materials. In this study, a resin slurry plugging system that can be used to plug lost channels of fractures of different scales in the process of oil and gas exploitation was prepared, and the factors affecting the consolidation of the system under different conditions were studied. The resin slurry plugging system was initially consolidated in 2 hours and completely consolidated in 6–9 hours. It exhibited good viscosity recovery ability and excellent thixotropy characteristics of shear thinning and static thickening, which help realize strong residence and plugging in the fracture. The resin slurry plugging system prepared with 200 000 mg/L salinity water could still achieve good consolidation at 140°C, and the consolidating strength was higher than 5.0 MPa. In addition, the 7.10-MPa consolidation strength of the resin slurry plugging system with aging at 140°C for 15 days could satisfy the long-term plugging needs. Furthermore, the pressure-bearing plugging capacity and degradability of the resin slurry plugging system were investigated. The resin slurry plugging system could be fully filled in the steel wedge-shaped fractured core at 140°C, and the pressure-bearing plugging capacity was up to 13.07 MPa. The resin slurry plugging system could achieve a strong residence in the sand-filling pipe model, forming a high-strength plugging layer, and the pressure-bearing plugging capacity could reach 10.73 MPa. The acid dissolution degradation rate at 140°C was 97.69%, indicating a low degree of damage to the reservoir and meeting the requirements for subsequent plug removal. The excellent properties of the resin slurry plugging system, such as high temperature, high salt resistance, and pressure plugging, provide a new solution for plugging lost formations of fracture cave carbonate rocks.

Experimental Study on the Effect of Rock Mechanical Properties and Fracture Morphology Features on Lost Circulation

Summary At present, lost circulation remains a complicated drilling problem in fractured formations that needs to be addressed urgently. However, the influence of actual rock mechanical properties (RMP) and fracture morphological features (FMF) on lost circulation is easily ignored in the current research on leakage mechanism and evaluation, which may lead to deviation from the analysis results, thus affecting the success rate of plugging treatments. Therefore, the complicated effects have been investigated using the improved plugging experimental instruments in this paper. The results indicate that both RMP and FMF have a prominent influence on the plugging and sealing effects of plugging slurries. This research suggests that the bridging and plugging capabilities of the slurry can be improved by increasing the type and amount of lost circulation materials (LCM). Moreover, depending on the fracture morphology difference, the same plugging slurry will have different plugging effects on the same width-size opening fracture channel. In addition, a novel evaluation method is developed to assess the effective sealing ability of plugging slurry against formation fractures, which has been successfully applied in the field. To the best of our knowledge, this is the first evaluation method that investigates simultaneously the mechanical properties of rocks and fracture characteristics of formations. The novel evaluation method incorporates the critical parameters of the lost circulation effect into the design of the plugging evaluation model. Thus, the proposed method can be used to quantitatively evaluate the plugging capability of the LCM and slurries and the loss capacity of the loss channels. However, the higher plugging coefficient (λ) of the slurry does not necessarily mean that the plugging slurry has a stronger plugging capacity (SP). Adopting the suitable fracture channel model can avoid overestimating or underestimating the plugging capability of the LCM slurries. Therefore, it is necessary to improve the formula design of the LCM slurry in combination with the geological engineering background. This perception has significant implications for the analysis of the lost circulation mechanisms and the optimization formula design of the plugging slurries.

Curing kinetics and plugging mechanism of high strength curable resin plugging material

Lost circulation, a recurring peril during drilling operations, entails substantial loss of drilling fluid and dire consequences upon its infiltration into the formation. As drilling depth escalates, the formation temperature and pressure intensify, imposing exacting demands on plug materials. In this study, a kind of controllable curing resin with dense cross-network structure was prepared by the method of solution stepwise ring-opening polymerization. The resin plugging material investigated in this study is a continuous phase material that offers effortless injection, robust filling capabilities, exceptional retention, and underground curing or crosslinking with high strength. Its versatility is not constrained by fracture-cavity lose channels, making it suitable for fulfilling the essential needs of various fracture-cavity combinations when plugging fracture-cavity carbonate rocks. Notably, the curing duration can be fine-tuned within the span of 3–7 h, catering to the plugging of drilling fluid losing of diverse fracture dimensions. Experimental scrutiny encompassed the rheological properties and curing behavior of the resin plugging system, unraveling the intricacies of the curing process and establishing a cogent kinetic model. The experimental results show that the urea-formaldehyde resin plugging material has a tight chain or network structure. When the concentration of the urea-formaldehyde resin plugging system solution remains below 30%, the viscosity clocks in at a meager 10 mPa·s. Optimum curing transpires at 60 °C, showcasing impressive resilience to saline conditions. Remarkably, when immersed in a composite saltwater environment containing 50000 mg/L NaCl and 100000 mg/L CaCl2, the urea-formaldehyde resin consolidates into an even more compact network structure, culminating in an outstanding compressive strength of 41.5 MPa. Through resolving the correlation between conversion and the apparent activation energy of the non-isothermal DSC curing reaction parameters, the study attests to the fulfillment of the kinetic equation for the urea-formaldehyde resin plugging system. This discerning analysis illuminates the nuanced shifts in the microscopic reaction mechanism of the urea-formaldehyde resin plugging system. Furthermore, the pressure bearing plugging capacity of the resin plugging system for fractures of different sizes is also studied. It is found that the resin plugging system can effectively resident in parallel and wedge-shaped fractures of different sizes, and form high-strength consolidation under certain temperature conditions. The maximum plugging pressure of resin plugging system for parallel fractures with outlet size 3 mm can reach 9.92 MPa, and the maximum plugging pressure for wedge-shaped fractures with outlet size 5 mm can reach 9.90 MPa. Consequently, the exploration and application of urea-formaldehyde resin plugging material precipitate a paradigm shift, proffering novel concepts and methodologies in resolving the practical quandaries afflicting drilling fluid plugging.

Rheological properties and gas channeling plugging ability in CO2 flooding of a hydrophobic nanoparticle-enhanced smart gel system constructed with wormlike micelles

Carbon Dioxide capture, oil displacement and Storage (CCUS-EOR) projects inject captured carbon dioxide into developed reservoirs suitable for gas displacement. However, due to the strong heterogeneity of the reservoir, the CO2 channeling is seriously. In this study, using tung oil as renewable chemical raw material, environmentally friendly surfactants and hydrophobic nano-SiO2 were synthesized as the main components of smart gel system. Fourier transform infrared (FT-IR), nuclear magnetic resonance spectrum (NMR) and thermogravimetric analysis (TGA) were used to characterize the chemical structure. The smart gel system was obtained through the CO2 response experiment. The system can cycle back and forth between low and high viscosity multiple times, and a good temperature resistance and salt resistance. The results of rheological experiments and dynamic light scattering show that the nanoparticles promote the growth and entanglement of WLMs. The plugging capacity and auxiliary CO2-EOR performance of the system were evaluated through the laboratory displacement test. The intelligent response system has good gas channeling plugging ability, plugging efficiency reaches 97 %, and CO2 flooding oil recovery efficiency increases by 22.2 %. In addition, in the acute toxicity assessment, the bio-based gel system from plants showed slightly toxic, which is expected to become a new generation of green oilfield chemicals.

Establishment of temperature‐strength response prediction model of supramolecular gel temporary plugging agent by response surface method analysis

AbstractIn this study, response surface methodology (RSM) was applied to optimize the preparation of a supramolecular gel temporary plugging agent. According to single‐factor experiments, results showed that the gelling temperature was preset at 100°C, and the gelling strength reached the maximum. Three‐factor RSM model prediction was carried out to explore the determination coefficient (R2) of the gelling temperature and strength and their degree of influence, and the predicted results were verified by experiments. No difference was found between the experimental results and the predicted results, indicating that this model could be used to optimize the preparation of DMF supramolecular gels. DSC, FT‐IR, XRD, and SEM were used to investigate the formation mechanism of the optimized supramolecular gel temporary plugging agent (CD‐Da), and its compatibility, stability, rheology, and plugging performance were evaluated. Experimental results showed that CD‐Da has the characteristics of good injectability in low‐permeability rock cores, strong plugging capacity, self‐breaking, and less damage to the formation. Therefore, this study not only provides a stable and efficient supramolecular gel plugging agent for tight oil and gas reservoirs, but also establishes a prediction model between each component and supramolecular gel, providing a new optimization method for the preparation of supramolecular gel.

Experimental investigation on using CO2/H2O emulsion with high water cut in enhanced oil recovery

CO2 emulsions used for EOR have received a lot of interest because of its good performance on CO2 mobility reduction. However, most of them have been focusing on the high quality CO2 emulsion (high CO2 fraction), while CO2 emulsion with high water cut has been rarely researched. In this paper, we carried out a comprehensive experimental study of using high water cut CO2/H2O emulsion for enhancing oil recovery. Firstly, a nonionic surfactant, alkyl glycosides (APG), was selected to stabilize CO2/H2O emulsion, and the corresponding morphology and stability were evaluated with a transparent PVT cell. Subsequently, plugging capacity and apparent viscosity of CO2/H2O emulsion were measured systematically by a sand pack displacement apparatus connected with a 1.95-m long capillary tube. Furthermore, a high water cut (40 vol%) CO2/H2O emulsion was selected for flooding experiments in a long sand pack and a core sample, and the oil recovery, the rate of oil recovery, and the pressure gradients were analyzed. The results indicated that APG had a good performance on emulsifying and stabilizing CO2 emulsion. An inversion from H2O/CO2 emulsion to CO2/H2O emulsion with the increase in water cut was confirmed. CO2/H2O emulsions with lower water cuts presented higher apparent viscosity, while the optimal plugging capacity of CO2/H2O emulsion occurred at a certain water cut. Eventually, the displacement using CO2/H2O emulsion provided 18.98% and 13.36% additional oil recovery than that using pure CO2 in long sand pack and core tests, respectively. This work may provide guidelines for EOR using CO2 emulsions with high water cut.

Novel polymeric organic gelator as lost circulation material for oil-based drilling fluids

With the exploitation of unconventional oil and gas resources towards deep and ultra-deep formations, oil-based drilling fluids (OBDFs) with white oil as a base oil have been increasingly employed in China to achieve safe, efficient, and fast drilling operations. However, due to the lack of effective lost circulation material (LCM), drilling time and drilling fluids are severely delayed and extra consumed, respectively. Herein, we innovatively propose and successfully develop a polymeric organic gelator using an emulsifier-free emulsion polymerization method and find that it achieves remarkable plugging ability in OBDF, superior to commercial LCMs, including asphalt, fine calcium carbonate, elastic graphite, and rubber particles. In detail, SMHDV with a branched C8 pendant group, benzene ring, isopropyl, and acetate groups is homogeneously dispersed in OBDF after hot rolling and capable of blocking permeable porous formations, resulting in a reduction of the cumulative filtration by 68 % at a concentration as low as 1 wt%. When added at a high concentration above 10 wt%, SMHDV turned into an organogel which can block cracks and prevent severe lost circulations together with other bridging materials. Furthermore, SMHDV maintains considerable plugging capacity in a wide temperature range of 80–150 °C, which meets most requirements of oil wells. The superior performance is attributed to the formation of supramolecular network structure in white oil due to the self-assembly behavior, which originated from the appropriate hierarchical polarities. In addition, the material can maintain stable rheological properties after hot rolling, improving the electrical stability of the drilling fluid. It is expected to form a set of scientific and efficient OBDF plugging technology to solve the leakage problems encountered during drilling.

Preparation and Characterization of a Biobased Temporary Plugging Material: Self-Healing and Degradable.

Due to the low success rate in high-temperature gas well drilling or workover operations, a new type of biobased temporary sealing material was synthesized using vanillin, succinic anhydride (SA), cellulose, and acetylacetone zinc hydrate (AZH) as catalysts. Infrared analysis proved the synthesis of vanillin-derived epoxy and the formation of a vitrimer with hydroxyl ester. The results of thermodynamic properties tests show that it has excellent thermal stability with a high glass transition temperature (Tg). The dynamic mechanical test results show that the characteristic relaxation time of the material at 120 °C is 3500 s and the self-healing rate can reach 61% within 20 min. The test results of mechanical properties show that under 10 MPa pressure, it has good elastic deformation performance, the rebound rate is more than 36%, and the crushing rate is less than 17%. The degradation performance results show that the decomposition increases to 80% under 120 °C and 1.2% NaOH. The comprehensive performance evaluation results show that the new temporary plugging material has good compatibility, and its plugging performance is better than those of a gel, composite material, and shape memory polymer. The maximum fracture plugging capacity is 5 × 4 mm, with a pressure up to 10 MPa.

Preparation and Degradation Performance Study of P(AM/GG/PEGDA) Nanocomposite Self-Degradation Gel Plugging Material.

Lost circulation is a world-class problem, and the contradiction between plugging and unplugging in reservoirs is a problem that needs to be solved urgently. The traditional LCM is not suitable for reservoirs and the complex subsequent operations. Currently, a self-degrading plugging material is proposed. In this paper, a new self-degradation plugging material, CKS-DPPG, was prepared by AM, GG, nano silica, and PEGDA. The effects of reactant concentration, pH, mineralization, etc., on the swelling and degradation performance of CKS-DPPG were investigated. The plugging capacity was tested by fracture plugging equipment, and the mechanism of self-degradation was revealed. The results show that the CKS-DPPG reached a 50% degradation rate in 54 h and complete degradation in 106 h at 80 °C and pH = 8. Low temperatures, high mineralization, and weak alkaline conditions prolong the complete degradation time of CKS-DPPG, which facilitates subsequent operations. The simulation of the 3 mm opening fracture plugging experiment showed that the pressure-bearing capacity reached 6.85 MPa and that a 0.16 MPa pressure difference could unplug after degradation. The ester bond of PEGDA is hydrolyzed under high-temperature conditions, and the spatial three-dimensional structure of CKS-DPPG becomes linear. The CKS-DPPG can effectively reduce subsequent unplugging operations and lower production costs.

Influence mechanism and optimization of the plugging capacity of temporary plugging zones with different particle sizes based on pore structure

Reducing the temporary plugging zone permeability is the key to the success of temporary plugging and diverting fracturing. The pore structure of the plugging zone determines the permeability of the temporary plugging zone. This paper introduces a new method based on micro-computed tomography (micro-CT) to quantitatively characterize the pore structure of temporary plugging zones with different particle size. The permeability of temporary plugging zone was measured, and seepage simulation was carried out based on pore network model (PNM). The particle compound method and formula were proposed to reduce the permeability of the temporary plugging zone. Finally, a permeability prediction model of temporary plugging zone based on pore structure was established. The results show that the porosity and tortuosity of the temporary plugging zone are independent of particle size under natural accumulation, and the pore radius decreases with the decrease in particle size. After compaction, the pore structure of the temporary plugging zone changes more obviously with smaller particle size. The seepage simulation shows that the number of flow channels in the temporary plugging zone formed by 2–3 mm particles is only 23.5% of the 0.6–1 mm flow channels. However, several obviously dominant channels are found in the 2–3 mm particles, resulting in a higher permeability. The 0.6–1 mm particles are used to fill the pores formed by 2–3 mm particles so that the dominant channel is divided into several small flow channels to significantly decrease the permeability of the 2–3 mm particles. When 2–3 mm and 0.6–1 mm particles are mixed according to the established particle size recombination formula, the pore radius and permeability of the temporary plugging zone decreased by 42.3% and 53.2% compared with 2–3 mm particles. The permeability prediction model can predict the permeability of temporary plugging zone well, and the average error is 9.145%. The sample preparation methods, pore structure testing and permeability prediction model were established in this work, providing a new method for the selection and design of temporary plugging agents.

A New Coated Proppant for Packing Fractures in Oil Reservoirs

The method of packing conventional proppant into fractures is used to maintain high liquid permeability. In this study, by coating a hydrophobic material on the surface of a proppant, the layer packed with this coated proppant was endowed with water-plugging and oil-permeability capacities. Moreover, several research experiments were carried out to verify the proposed method: a water plugging capacity (WPC) test of the coated proppant layer, compression and temperature resistance tests of the coated proppant (temperature range from 90 to 210 °C; pressure range from 5.9 to 91.4 MPa), and a 3D test of the oil recovery enhancement. The results show that the proppant coating has good compression resistance, and the proppant begins to break at 27.3 MPa. The upper limit of the temperature resistance of the coating is 170 °C. The WPC of the layer packed with coated proppant was still reliable during fracture, which was enhanced by at least 20% compared with that of the layer packed with a conventional proppant. The fracture packed with the coated proppant had superior working performance compared with that packed with a conventional proppant. It can reduce the flow capacity of the water phase breaking into the dominant flow passage so as to delay the rise in the water production of the oil well and prolong the duration of oil production. In this way, oil recovery could be increased by about 7.7%. In conclusion, the technology proposed in this paper has particular water-plugging and oil-permeating characteristics, with remarkable technical advantages, thus providing a new idea for the development of water control in fracture reservoirs.

Investigation of the plugging capacity and enhanced oil recovery of flexible particle three-phase foam

In the later stage of water flooding in reservoirs, the oil production decreases. The stability of three-phase foam system is strong, enhancing oil displacement effects of ultrahigh water cut reservoirs. In this paper, the flow state of the foam system was studied by using a microscopic visualization model. Second, sandpack flooding experiments were performed to analyze the optimal plugging conditions of three-phase foam through resistance factors. Finally, single and parallel sandpack flooding experiments were carried out to analyze plugging effect and production conditions under different injection systems and permeability ratios. The research shows that three-phase foam is more stable and capable of plugging. The stable residual resistance factor after injection of the three-phase foam system is 172.75. When the foam and particles are injected simultaneously, the gas–liquid ratio is 1:1, the formation permeability is 5526.5 mD, and the plugging effect of three-phase foam is the best. The oil recovery increases by 24.9% after the injection of three-phase foam system. The three-phase foam system combines Jamin effect of foam and dynamic plugging characteristics of flexible particles. The highest oil recovery factor of 80.87% is achieved at a permeability ratio of 9.99. Three-phase foam flooding has broad application prospects.

Improved oil recovery in sandstone reservoirs with deep profile control technology: A comparative study between modified starch gel and polymer gel

Deep profile control technology was implemented to alleviate the issue of oil recovery in sandstone reservoirs caused by varying permeability. Rheological tests, injection and plugging capacity experiments, core flooding experiments combined with Computed Tomography (CT) analysis were performed to study the mechanisms of profile control, oil displacement, rheology, and plugging properties of modified starch gel and polymer gel. Moreover, a comparison was made regarding the oil recovery, sweep efficiency, and displacement efficiency for both the starch gel and polymer gel. The results show that the ease of injection and plugging properties of the modified starch gel are superior to those of the viscoelastic polymer gel. The visual and quantitative distribution profiles and migration characteristics of water, oil, and gels are characterized. During the gel flooding stage, the modified starch gel maintained a rigid shape compared to the lax behavior observed with polymer gel. During the subsequent water flooding stage, the modified starch gel became immobile. It plugged the high permeability layer of the core plug, increasing the sweep efficiency of the low permeability layer by 60.00%. The sweep efficiency of the low permeability layer increased by 37.26% as the polymer gel continued to flow through the core plug. In addition, the high permeability layer is easily swept clean, so enhancing the displacement efficiency is the key to maximizing recovery. The displacement and relatively easy sweep efficiencies must be improved simultaneously to maximize the recovery in the low permeability layer. The study's findings shed light on the significance of modified starch gel in enhancing oil recovery in sandstone reservoirs with varying permeability.

Bead and necklace-like silica-based hybrid materials for controlling montmorillonite dispersion filtration

Taking the advantage of well dispersing ability and unique pore plugging capacity, nanomaterials have been extensively used as filtration control additives in water-based drilling fluids (WBDFs). However, nanomaterials are seldom robust when exposed to high temperature and salinity which restricts their applications. Herein, we synthesize two inorganic/organic hybrid nanomaterials using silica as the core and grafted with zwitterionic polymer on the surface (ZSHNM-1 and ZSHNM-2), and conduct in-depth research on their filtration performance. ZSHNM exhibits bead- and necklace-like structures, adsorbs onto and promotes the homogenous dispersion of montmorillonite irrespective of the presence of salt, and facilitates the formation of filter cake with remarkably low permeability, according to experimental results and DFT simulation results. Notably, ZSHNM-2 has significantly stronger thermal resistance up to 250 °C, salt tolerance as high as 11 wt%, which is expected to use in filed applications of ultra-deep wells. It is attributed to the more appropriate particles size distribution and longer polymer tails, efficiently plugging the pores. In addition, these nanomaterials had high polyamine rejection, whereas had little influence on KCl, which should be paid attention to selecting shale inhibitors. This study can be a guide to technically related areas where nanomaterials are used extensively.

Research and Application Progress of Wet-Phase Modified Expandable Graphite as a Steam Plugging Agent in Heavy Oil Reservoirs

Wet-phase modified expandable graphite (WMEG) particles have been successfully developed for in-depth steam channeling control in heavy oil reservoirs. WMEG particles can expand 4 to 7 times in a wet-phase environment and form a worm-like structure at steam temperature. The sand-pack flowing experiments demonstrated that WMEG particles have good injection, steam erosion resistance, and selective plugging capacity characteristics. By directly plugging and bridge plugging after expansion, WMEG particles can effectively plug steam channels. This paper also analyzes the EOR potential of WMEG particles through oil displacement experiments, proving that WMEG particles can further enhance oil recovery of heavy oil reservoirs. To better explain the steam plugging mechanism, the energy changes during WMEG particle expansion were also analyzed. The release of gas at different stages is the source of energy for WMEG particle expansion. WMEG particles have been successfully applied to 12 wells of four typical heavy oilfields in China. The results from these applications confirm that the injection of WMEG particles is an effective steam channeling control treatment. The success of these oilfield tests can also serve as a reference for similar steam injection heavy oilfields.

Experimental Study on Conformance Control Using Acidic Nanoparticles in a Heterogeneous Reservoir by Flue Gas Flooding

Flue gas flooding has been applied in many oilfields for its accessibility and low cost. However, the problem of gas channeling during flue gas flooding is significantly more serious due to reservoir heterogeneity and gravity override, and the traditional profile control agent is inapplicable because of flue gas acidity. In order to solve this challenge, a novel acidic nanoparticle was presented first; then, the profile control performance of both water slugs and this novel nanoparticle for flue gas flooding in heterogeneous reservoirs was studied using core samples with different rhythms. The results show that the stability of the acidic nanoparticles is good, and the viscosity of the nanoparticle solution increases as the pH decreases, which is suitable for acidic flue gas flooding. The oil recovery of flue gas flooding in a positive rhythm core is 5–10% greater than that in a reverse rhythm core. The water slug can improve oil recovery by 5% in the reverse rhythm core, and oil recovery was less than 2% in the positive rhythm core. The effect of a nanoparticle slug is much better than the water slug. It improved the oil recovery by 10% in the positive rhythm core by continuing flue gas flooding after nanoparticle slug treatment, which was more than the 20% in the reverse rhythm core. The ultimate oil recovery of both positive and reverse-rhythm cores by acidic nanoparticle slug treatment was around 50%, which was 10% greater than the water slug treatment. The conformance control using acidic nanoparticles is more suitable for reverse rhythm formation due to its plugging capacity, deformation characteristic, and viscosity increment in an acidic environment. This research demonstrated that these novel acidic nanoparticles could be effectively applied to conformance control during flue gas flooding in heterogeneous reservoirs.

Double network self-healing hydrogel based on hydrophobic association and ionic bond for formation plugging

Self-healing hydrogels have attracted tremendous attention in the field of oil and gas drilling and production engineering because of their excellent self-healing performance after physical damage. In this study, a series of double network self-healing (DN SA ) hydrogels based on hydrophobic association and ionic bond were prepared for plugging pores and fractures in formations in oil and gas drilling and production engineering. The mechanical, rheological, and self-healing properties of the DN SA hydrogels were investigated. Results revealed that the DN SA hydrogels exhibited excellent mechanical properties with a tensile stress of 0.67 MPa and toughness of 7069 kJ/cm 3 owing to the synergistic effect of the double network. In addition, the DN SA hydrogels exhibited excellent compression resistance, notch insensitivity, and self-healing properties. The DN SA -2 hydrogel was granulated and made into gel particles with different particle sizes and used as a plugging agent. The self-healing mechanism of DN SA -2 hydrogel particles in fractures was explored, and it's plugging effect on fractures of different widths and porous media of different permeabilities were investigated. Experimental results revealed that the plugging capacity of the DN SA -2 hydrogel particles for a fracture with width of 5 mm and a porous medium with a permeability of 30 μm 2 was 3.45 and 4.21 MPa, respectively, which is significantly higher than those of commonly used plugging agents in the oilfield. The DN SA hydrogels with excellent mechanical and self-healing properties prepared in this study will provide a new approach for applying hydrogels in oil and gas drilling and production engineering.