Imbibition Oil Recovery Research Articles

Nanoparticle size: A critical role in enhancing oil recovery

In recent years, nanomaterials have shown great potential in the enhanced oil recovery (EOR) process due to their superior properties. However, the influence of particle size on EOR is not clear and hinders the application. Therefore, it is vitally important to investigate the effect of the particle size on the EOR performance. In this work, Fe3O4 nanoparticles with different sizes, including 20 nm, 100 nm, 200 nm, and 300 nm, were controllably synthesized and used to innovatively clarify the critical role of nanoparticles size in enhancing oil recovery. The effects of sizes on the recovery were investigated by combining the experimental results of interfacial tension, wetting angle, and spontaneous imbibition. The results revealed that Fe3O4 nanoparticles with smaller size, which have the stronger ability to reduce the interfacial tension and change the wetting angle, exhibit a favorable capacity to enhance oil recovery. Compared with the spontaneous imbibition oil recovery (24.36 %) of standard brine, the nanofluid containing 0.1 wt% Fe3O4 with the size of 20 nm can increase the recovery to 30.87 %. Based on the results of nuclear magnetic resonance, the spontaneous imbibition mechanism was proposed and the effect of size on recovery was analyzed. In addition, the superparamagnetism of Fe3O4 was utilized for recycling, avoiding the issue of significant losses of nanofluids in the existing research after injection. The secondary spontaneous imbibition was carried out, showing good environmental friendliness.

Secondary utilization of self-suspending proppant's coating polymer: Enhance oil recovery

Fracturing is associated with significant economic costs, and the loss of the utility of the self-suspending proppants' coating polymer after fracturing appears highly wasteful. To enhance the utilization of the self-suspending proppant's coating polymer, we propose a novel concept: the secondary utilization of coating polymer, enabling the coating polymer to gel-breaking within the reservoir and generate surface-active substances, thereby enhancing the oil recovery efficiency. To realize this concept, this study designed and synthesized a hydrophobic associative polymer, which was combined with ceramic proppant to form self-suspending proppant. Using the surface-active monomer octadecyl dimethyl allyl ammonium chloride (DMDAAC-18), acrylamide (AM), acrylic acid (AA), and 2-acrylamido-2-methylpropane sulfonic acid (AMPS) via aqueous free-radical copolymerization synthesized the PAAAD (Polymer (AM/AA/AMPS/DMDAAC-18)). PAAAD has demonstrated excellent thickening properties, with a viscosity of 240.01 mPa s at a concentration of 6 g/L in shear rate 170s−1. Its solution exhibits high viscoelasticity, and a loss factor (tan δ) < 1 over the frequency range of 0–20 Hz at a shear stress of 0.56 Pa indicates that it behaves like a viscoelastic solid with gel-like characteristics, which is beneficial for proppant suspension. The gel-breaking solution of PAAAD reduced surface tension (29.33 mN/m at a PAAAD concentration of 6 g/L), converted oil-wet rocks to water-wet conditions (reducing the contact angle of oil-wet shale to 46.7° and of oil-wet sandstone to 19.9°), and enhanced shale imbibition oil recovery efficiency in 16.5%. The basic properties of self-suspending proppants meet the Chinese Petroleum Industry Standard SY/T 5108-2014 and exhibit good suspension properties, with sedimentation of 1.7 mm in 40 min at a sand ratio of 15%. This study is the first to propose the secondary utilization of the self-suspending proppant's coating polymer, significantly enhancing their utilization value.

Janus SiO2-surfactant dispersion designed for enhanced imbibition oil recovery in ultra-low permeability reservoirs

The use of nanofluids in formations with high temperatures and high salinity is currently encountering significant obstacles. Therefore, a Janus SiO2-surfactant dispersion consisting of Janus nanoparticles and surfactants was constructed in the current study. The Janus SiO2-surfactant dispersion is resistant to both high temperatures and high salinity. The Janus SiO2-surfactant dispersion, consisting of Janus SiO2 nanoparticles and the non-ionic surfactant Tween80, is abbreviated as JASN-T80 hereafter. The system can be dispersed and kept stable for one week at a salinity of 30,000 mg/L and a temperature of 85 ℃. The concentration of f nanoparticles and surfactant in the system was optimized at 0.02 wt% Janus SiO2 nanoparticles + 0.04 wt% Tween80 based on the particle size. An assessment was conducted to measure the system's capacity to decrease interfacial tension and alternate wettability. The interfacial tension between oil and water was reduced to 1.21 mN/m. The JASN-T80 system demonstrates a notable capacity to change wettability by decreasing the contact angle of water on an oil-wet rock surface from 100.6° to 70.5°. The combination of nanoparticle and surfactant leads to a synergistic effect, resulting in an imbibition recovery of 44.28 % for ultra-low permeability core. This work provides a novel concept for the advancement and utilization of nanofluid imbibition system for unconventional reservoir.

Synthesis of amphiphilic silicon quantum dots and its application in high efficiency imbibition oil recovery in low permeability reservoirs

In this work, a novel three-step method was used to modify the surface of silicon quantum dots to synthesize amphiphilic silicon quantum dots (A-SiQDs) with higher interfacial activity. The particle size of A-SiQDs was only 3.5 nm. By adding a small amount of dodecyl dimethyl betaine (BS-12), the performance of A-SiQDs was further improved. Through particle size and zeta potential testing, it can be seen that the mixed system of A-SiQDs and BS-12 had good temperature and salinity resistance, and can be stable at 120 °C and 50,000 mg/L NaCl. Meanwhile, the mixed system exhibited superior interfacial activity compared with individual A-SiQDs and BS-12. The mixed system can lower the interfacial tension from 32.15 mN/m to 1.82 mN/m and transform the rock surface from an oil-wet to a strong water-wet state. This ensured the excellent imbibition ability of the mixed system, which can increase the oil recovery to 35.7 %. Finally, from the perspective of force, the influence of nanofluids on oil stripping and migration was analyzed to reveal the imbibition mechanism. This paper proposes a facile three-step method for synthesizing A-SiQDs, and also provides a novel nanomaterial for high efficiency imbibition in low-permeability reservoirs.

Experimental Investigation on the Interfacial Characteristics of Tight Oil Rocks Induced by Tuning Brine Chemistry.

Currently, research on enhancing imbibition oil recovery in tight oil reservoirs through the ion-tuning technique remains limited. Two critical parameters for capillary imbibition are the wettability and interfacial tension between oil and water. In this investigation, we manipulate the properties of two types of formation water for both aged and unaged samples by diluting brine and altering ion composition. Subsequently, we employ captive and pendant-drop methods to assess rock wettability and interfacial tension under varied brine conditions. Additionally, we elucidate the primary mechanisms underlying changes in rock wettability and interfacial tension. Meanwhile, we analyze capillarity characteristics and assess the relative significance of wettability and interfacial tension. Results indicate that there is a critical interfacial tension with progressive dilution of two types of formation water. However, modifying ion composition leads to a complex trend in interfacial tension, which can be explained qualitatively through the Gibbs adsorption isotherm. For unaged samples, the contact angle demonstrates a pronounced water-wet characteristic, showing a nonmonotonic trend with respect to dilution times. Remarkably, the rock surface exhibits the strongest water-wet, particularly evident in the case of FW-10, largely influenced by variations in interfacial tension. Conversely, aged samples demonstrate strong oil-wet, with a critical salinity resulting in the lowest contact angle, while altering brine ion types can alter rock wettability from strongly oil-wet to intermediate-wet, which is not sufficient to result in the wettability alteration. The removal of multivalent cations is proposed as the most effective method for wettability modification. Furthermore, capillarity variations among different brine cases are primarily contingent upon contact angle changes, and interfacial tension does not have a significant change when regulating the brine properties. Consequently, we emphasize the significance of wettability in the adoption of ion-tuned brine techniques for tight oil reservoirs. Overall, our study underscores the potential of reasonably regulating brine properties to enhance capillarity and, thereby, improve imbibition oil recovery.

An efficient method for imbibition in asphaltene-adsorbed tight oil-wet reservoirs

Spontaneous imbibition (SI) has been proposed as a crucial approach to enhance oil recovery in unconventional reservoirs. Previous research suggests that wettability alteration rather than oil-water interfacial tension (IFT) reduction is the key mechanism for imbibition oil recovery enhancement. However, our experimental results indicate that for asphaltene-adsorbed oil-wet surfaces it's challenging to substantially modulate wettability. In such oil-wet pores, the negative capillary force cannot function as an imbibition driving force, and hence, the method of altering wettability and maintaining the oil-water IFT at relatively high values to enhance imbibition efficiency is insufficiently applicable. When the capillary cannot work, reducing the IFT to ultra-low levels to induce the transformation of the imbibition pattern may be more effective for imbibition efficiency enhancement. In this paper, low-field nuclear magnetic resonance (NMR) was employed to monitor the SI process. The results suggested that for the asphaltene-adsorbed oil-wet tight sandstone, the surfactants combined system with ultra-low oil-water IFT possessed the highest oil recovery, followed by the medium-IFT systems and high-IFT systems. The spontaneous formation of emulsion was observed when the IFT value was reduced to the ultra-low level. Oil droplets can pass through the small pores easily since the deformability of oil is greatly enhanced. The ultra-low IFT system transforms the imbibition pattern from capillary force-driven to gravity-driven, and exhibits the highest oil utilization rate in micropores, mesopores, and macropores among all imbibition agent systems, thereby having the highest total oil recovery. Consequently, the imbibition-enhancing potential of the ultra-low IFT system is considerable and deserves more attention, especially for the oil-wet pores that can hardly be altered to the water-wet state.

Comparative study of nanoemulsion and micelle formed by surfactants containing benzene ring for spontaneous imbibition displacement

Nanoemulsion has a wide range of applications in oilfield chemistry due to its unique nanoscale size, excellent kinetic stability and high specific surface area. In this paper, a novel nanoemulsion oil flooding system was prepared using anionic surfactant sodium dodecyl benzene sulfonate (SDBS), the nonionic surfactant alkylphenol ethoxylates (OP-10), kerosene, n-butanol and deionized water. The particle size, Zeta potential, interfacial tension (IFT) and wettability properties were evaluated in the laboratory. The displacement performance of nanoemulsion was evaluated by the spontaneous imbibition experiment. Meanwhile, it compared with the same concentration of SDBS + OP-10 + n-butanol (SOB) system. The results showed that the particle size of the nanoemulsion was 70 ∼ 100 nm. When the concentration of nanoemulsion was 0.10 %, the oil–water IFT could reach 0.091 mN/m. The spontaneous imbibition oil recovery of the nanoemulsion (0.10 wt%) could reach 33.20 %, which was 23.02 % higher than that of SOB system. We also research the spontaneous imbibition displacement mechanism of nanoemulsion and micelle in low-permeability reservoirs. This paper will help to select the best oil displacement agent for the design of enhanced oil recovery (EOR) projects and promote the application of oil displacement agent in oilfield.

Quantitative characterization of imbibition in fractured porous media based on fractal theory

In low-permeability reservoirs, such as shale and tight sandstone, imbibition is an important mechanism for enhancing oil recovery. After hydraulic fracturing treatment, these reservoirs create a network of fracture pathways for fluid flow. Therefore, understanding the imbibition mechanisms in fractured porous media and quantitatively characterizing oil–water distribution are crucial for the development of low-permeability reservoirs. In this study, a mathematical model of two-phase flow in porous media with branching fractures was established. The phase-field method was employed to track the oil–water interface, and quantitative characterization of imbibition was conducted based on fractal theory, and the effects of wetting phase injection rate, the number of disconnected fractures, fracture spacing, and fracture morphology on imbibition in branched fracture porous media were discussed. The research findings indicate that in branched fracture porous media, both co-current and countercurrent imbibition processes occur simultaneously, and there exists a diffusion interface layer with a certain thickness at the oil–water interface. The hydraulic pressure generated by the wetting phase injection rate provides the driving force for imbibition oil recovery, but it also affects the contact time between the wetting and non-wetting phases. The presence of disconnected fractures hinders the propagation of hydraulic pressure, reducing the effectiveness of imbibition. The imbibition displacement zone is limited and occurs only within a certain range near the fractures. As the number of branching fractures increases, the channels for the wetting phase to enter matrix pores are enhanced, resulting in higher efficiency of imbibition displacement of the oil phase. The results of this research can provide guidance for the design of fracturing programs and recovery prediction in low-permeability reservoirs.

Spontaneous imbibition of modified salinity brine into different lithologies: an improvement of comprehensive scaling used for fractured reservoir simulation

Spontaneous water imbibition into matrix blocks can be a significant oil recovery mechanism in fractured reservoirs. Many enhanced oil recovery methods, such as injection of modified salinity brine, are proposed for improving spontaneous imbibition efficacy. Many scaling equations are developed in the literature to predict spontaneous imbibition oil recovery. However, almost none of them included the impact of the diversity in ionic composition of injected and connate brines and the blending/interaction of a low salinity imbibing brine with a higher salinity connate brine. In this research, these two issues are included to propose new scaling equations for the scaling of spontaneous imbibition oil recovery by modified salinity imbibing brines. This study uses experimental data of the spontaneous imbibition of modified salinity brines into oil-saturated rock samples with different lithologies containing an irreducible high salinity connate brine. The collected tests from the literature were performed at high temperatures and on aged altered wettability cores. The results of 110 available spontaneous imbibition laboratory experiments (85, 12 and 13 tests on chalks, dolomites and sandstones, respectively) are gathered. This research initially shows the poor ability of three selected convenient scaling equations from the literature to scale imbibition recovery by modified salinity brine. Then, our newly proposed technique to find the scaling equation for spontaneous imbibition recovery by modified salinity brine, during the abovementioned conditions in limestones (Bassir et al. in J Pet Explor Prod Technol 13(1): 79–99, 2023. https://doi.org/10.1007/s13202-022-01537-7) is used in chalks, dolomites and sandstones to develop the three new scaling equations. Finally, a new general equation to scale imbibition recovery by modified salinity brine for all four lithologies is presented. Moreover, for each of the four datasets (chalk, dolomite, sandstone and all the four lithologies), the scaled data by the new equations is matched by two mathematical expressions based on the Aronofsky et al. model and the Fries and Dreyer model. These mathematical expressions can be used to develop transfer functions in reservoir simulators for a more accurate prediction of oil recovery by spontaneous imbibition of modified salinity brine in fractured reservoirs.

Preparation and performance evaluation of a novel temperature-resistant anionic/nonionic surfactant

Aiming at oil extraction from a tight reservoir, the Jilin oil field was selected as the research object of this study. Based on the molecular structures of conventional long-chain alkyl anionic surfactants, a new temperature-resistant anionic/nonionic surfactant (C8P10E5C) was prepared by introducing polyoxyethylene and polyoxypropylene units into double-chain alcohols. The resulting structures were characterized by Fourier transform infrared spectroscopy (FT-IR), nuclear magnetic resonance spectroscopy (1H-NMR), and electrospray ionization mass spectrometry (ESI–MS). Then, based on surface tension, interfacial tension, adsorption resistance, wettability, and emulsification performance tests, the performance of C8P10E5C was evaluated. The FT-IR, ESI–MS, and NMR spectra confirmed that C8P10E5C was successfully prepared. The critical micelle concentration (CMC) of C8P10E5C in water was 2.9510 × 10−4 mol/L (the corresponding mass concentration is 0.26%), and the surface tension of the aqueous C8P10E5C solution at this concentration was 30.5728 mN/m. At 0.3% concentration, the contact angle of the C8P10E5C solution was 31.4°, which is 60.75% lower than the initial contact angle. Under high-temperature conditions, C8P10E5C can still reduce the oil–water interfacial tension to 10−2 mN/m, exhibiting good temperature resistance. At 110 °C, upon adsorption to oil sand, the C8P10E5C solution could reduce the oil–water interfacial tension to 0.0276 mN/m, and the interfacial tension can still reach the order of 10−2 mN/m, indicating that C8P10E5C has strong anti-adsorption capability. Additionally, it has good emulsifying performance; upon forming an emulsion with crude oil, the highest drainage rate was only 50%. The forced imbibition oil recovery of C8P10E5C is 65.8%, which is 38.54, 24.22, and 27.25% higher than those of sodium dodecyl benzene sulfonate, alkyl polyoxyethylene ether carboxylate, and alkyl ether carboxylate, respectively.

Surfactant slug assisting CO2 huff and puff in enhancing shale oil reservoir recovery

Focusing on problems of rapid production decline and poor development effect after volume fracturing of the shale oil reservoir, a production method of SC-HNP (surfactant slug assisting CO2 huff and puff) was proposed. Taking CQ block (CQ, the reservoir block name) as an example, laboratory experiments were carried out using typical oil samples and core samples, and a numerical simulation model of SC-HNP was established based on the experimental results. The production performance and oil recovery mechanism were analyzed, and the oil production by SC-HNP of a typical well was predicted. The results showed that (1) the oil recovery degree of the surfactant imbibition experiment is 34.5%, showing good imbibition oil recovery effect. CO2 has good swelling effect and viscosity reduction ability to the oil. (2) SC-HNP combines the effects of the surfactant and CO2, and it has the best replenishing formation energy ability and the highest oil production level. Its improved recovery degree is about 2.4% (one cycle), showing the best development effect. (3) Compared with SF-HNP (surfactant huff and puff), SC-HNP can improve the oil displacement effect in the far-well fractured area, and compared with CO2-HNP (CO2 huff and puff), SC-HNP can improve the oil displacement effect in the near-well fractured area. (4) Using SC-HNP, it is predicted that the oil recovery degree of well CQP-32 (CQP-32, the well name) can be increased by 1.84%, which significantly improves the development effect, and the CO2 storage percent is about 32%.

Study on the imbibition production mechanism and main controlling factors of low-permeability reservoir.

With high water cuts and high permeability reservoirs entering the middle and late stage, many old oil fields in China are facing the dilemma of oil and gas resource exhaustion, while low-permeability reservoir resources remain very rich. As an oil recovery technology, imbibition displacement plays an important role in the exploitation of low-permeability reservoirs and prolongs the production cycle of old oil fields. Based on the imbibition kinetic equation, the mechanism and process of oil displacement in imbibition recovery are explained in this paper. Based on the characteristics of small particle size and high activity, the influence of temperature, viscosity, permeability, and salinity on the degree of imbibition recovery was studied. The results show that the imbibition production of low-permeability reservoirs mainly depends on capillary force, which firstly drains oil from small pores to large pores, and then drains it by buoyancy. Using nanofluids for imbibition oil recovery, a higher recovery effect of up to 45.59% can be achieved. The change in different external conditions will affect the imbibition recovery effect. The imbibition recovery efficiency increases with the increase in temperature, decreases with the increase in oil viscosity, and increases with the increase in core permeability. The increase in salinity has an inhibiting effect on the imbibition recovery efficiency. Based on the multivariate analysis of variance, the change in permeability has the greatest influence on the degree of imbibition recovery, and the change in viscosity has the least influence on the degree of imbibition recovery.

Imbibition oil recovery from tight reservoir cores using microemulsion: Experiment and simulation

Imbibition oil recovery from tight reservoir cores using microemulsion: Experiment and simulation

Experimental study on countercurrent imbibition in tight oil reservoirs using nuclear magnetic resonance and AFM: Influence of liquid–liquid/solid interface characteristics

Countercurrent imbibition of the fracturing fluid is of much significance for enhancing oil production in tight oil reservoirs during the shut-in period after hydraulic fracturing. The addition of enhanced imbibition agents such as surfactants and nanoparticles into the polymer-based fracturing fluid is conducive to oil production. How different types of imbibition agents affect oil recovery and the applicable conditions for different imbibition agents, however, still need to be clarified. In this article, we used low-field nuclear magnetic resonance (NMR) to measure the one-dimensional (1D) oil signal profiles along the imbibition direction during the countercurrent imbibition process and determine the imbibition distance and water saturation of different imbibition agents including polymer, surfactant, nano-silica (NS) and NS-surfactant complexes. Moreover, by measuring oil–water interfacial tension (IFT), and the adhesion forces between alkanes and the hydrophobic surfaces before/after the imbibition agent treatments by atomic force microscope (AFM), the IFT reduction and wettability alteration abilities of these agents were evaluated. After the NS-surfactant complexes treatment, the adhesion force which represents the force required to pull off oil from the rock surface became the lowest (15.81 pN), merely a quarter of that of NS (73.48 pN) and surfactant (70.01 pN), indicating a superior capability of NS-surfactant to improve wettability. The imbibition efficiency of the four systems in terms of imbibition distance and oil recovery was: NS-surfactant complexes: 38.43 mm 13.2 % > nonionic surfactant: 32.15 mm 9.0 % > NS: 25.88 mm 7.6 % > polymer: 17.64 mm 4.9 %. NS-surfactant nanofluid displayed the longest imbibition distance and highest water saturation, thus possessing the highest imbibition oil recovery. Nonionic surfactant with an IFT of 4.19 mN/m could greatly reduce the IFT compared with NS (35.98 mN/m), but the recovery enhancement induced by IFT reduction was not significant. In contrast, the increase in oil recovery by wettability alteration was distinctly higher than that by IFT reduction, as indicated by the recovery difference between NS-surfactant complexes and surfactant. Accordingly, wettability alteration is the primary mechanism to enhance imbibition oil recovery when ultralow IFT cannot be achieved. This research provides guidance on which type of imbibition agent should be selected to improve imbibition efficiency.

Effect of nanomaterials functionality on the acidic crude oil: Wettability and oil recovery studies

Chemical enhanced oil recovery often involves the injection of chemicals, such as surfactants, polymers, nanoparticles, and macromolecules. These chemicals are to alter the rock-oil-water interactions and mobilize the oil towards the production well. However, they often pose considerable challenges in the harsh environment of the oil-wet reservoirs, such as chemical instability, and high retention/adsorption of chemicals in the near-wellbore. Herein, we investigated the effect of functionalized silica nanofluids on improving oil recovery in the carbonate reservoir as a function of the oil acidity. To do so, we synthesized two types of silica nanofluids functionalized with sulfonate and carboxylate groups. We used two crude oils with different total acid numbers (TAN) of 0.4 and 5.7 mg/KOH. All experiments were ran at 100 °C and salinity of 67–240 kppm to simulate the harsh reservoir conditions of the Saudi Arabia. Spontaneous imbibition oil recovery studies were conducted to assess their effects on oil recovery. Contact angle and interfacial tension were performed at different conditions to examine the oil recovery mechanism. Further, in order to corroborate the previous research and comprehend the principles underlying the oil recovery, we also examined the electrokinetic zeta potential in parallel. Also, to better understand how oil and nanofluid functional groups interact, we conducted a surface complexation model study. In addition, molecular simulation (density functional theory and molecular dynamics) are employed to gain atomistic insights on the implicated molecular interactions between nanosilica particles with calcite surface in seawater brine. DFT simulations predicted that both functionalized nanosilica can form thermodynamically stable complexes with a dry and hydrated calcite surface. Further, MD simulations reveal that a good amount of both functionalized nanosilica are interacting with calcite surface in the diffuse electric double layer of the calcite-brine interface. However, the carboxylated functionalized nanosilica particles interact with rock stronger than sulfonated ones. Further, the carboxylated nanosilica could form stable complexes with naphthenic acids mediated by calcium ions, which supports the synergy effect observed experimentally. The results shed light on much more complex mechanisms behind the oil recovery rather than the common peripheral understanding. This work provides a good insight into the applicability of nanofluids for enhanced oil recovery for further research and field trials.

Development of a Novel High-Temperature Microemulsion for Enhanced Oil Recovery in Tight Oil Reservoirs.

This work focuses on the development of a novel high-temperature microemulsion for enhanced oil recovery in tight oil reservoirs. Microemulsions are a type of mixture that has properties of both liquids and solids; they have shown significant potential for improving oil recovery through spontaneous imbibition. Herein, a high-temperature-tolerant lower-phase microemulsion using a microemulsion dilution method was developed. The properties and morphological characteristics of the microemulsion were evaluated and proposed a mechanism for enhanced spontaneous imbibition oil recovery using imbibition tests and CT scanning technology. The results of the study showed that the optimum concentration of the microemulsion was 0.2 wt% and that it had good thermal stability, small droplet size, lower interfacial tension, good wettability alteration ability, and minimum adsorption loss. The imbibition and CT experiments demonstrated that the reduction in oil/solid adhesion was due to the synergistic effect of IFT reduction and wettability alteration and the ability to increase the imbibition distance through a larger self-driving force. The study concludes that the solubilization coefficient and self-driving force were defined and calculated to quantitatively analyze the imbibition mechanisms and the results showed that the reduction in oil/solid adhesion was due to the synergistic effect of IFT reduction and wettability alteration and the ability to increase the imbibition distance through a larger self-driving force.

Analysis on the mechanism of the enforced imbibition effect of tight oil reservoir by the activated water

Based on the parallel rock samples of tight oil reservoirs, the imbibition comparison experiments respecting to formation water and active water under different experimental conditions have been initiated. With adoption of the experimental measures i.e. Nuclear Magnetic Resonance (NMR), the micro-production mechanism of the enforcement of the imbibition oil recovery effect by the active agent has been analyzed. Surfactant may promote the imbibition effect of samples with different wettability, different water saturation and different sizes. The imbibition recovery ratios of No. 1 hydrophilic core in formation water and active water are respective 15.79% and 17.68%, and the active water imbibition increased by 1.88%, with an enforcement ratio of 11.97%. The imbibition recovery ratios of No. 3 lipophilic core in formation water and active water are respective 10.64% and 13.26%, and the active water imbibition increased by 2.62%, with an enforcement ratio of​ 24.62%. The enforcement effect of surfactant on the lipophilic core is higher than that on the hydrophilic core. The enforcement ratio of No. 1 core in macropores is 8.78%, and that of No. 3 rock is 36.14%, indicating that the surfactant can effectively reduce the seepage resistance of the lipophilic cores and enhance the imbibition recovery ratio of macropores. The increase magnitude and the enforcement ratio of the imbibition recovery of No. 4 low water-contained core are lower than those of No. 6 high water-contained core, indicating that the surfactant has a greater impact on the imbibition of high water-contained cores. The enforcement ratio in active water imbibition in core No. 4 is 28.59% in micropores and 15.46% in macropores; and respective 1460.74% and 9.56% for No. 6 core. The enforcement ratios of micropores in the two cores are both higher than those in macropores. It shows that the surfactant has a great influence on the permeability of micropores in the core. The increment magnitude in active water imbibition of small No. 2 core is 22%, and that of No. 2 large core is 26.93%, indicating that the surfactant has a greater impact on the imbibition of large cores.

A comprehensive mathematical model for spontaneous imbibition in oil-saturated fractured tight sandstones: Incorporating fracture distribution, displacement pressure, gravity, and buoyancy effects

This paper presents a generalized mathematical model that comprehensively characterizes the flow behavior of matrix nanopores and natural/hydraulic fractures in tight oil reservoirs during spontaneous imbibition. The model incorporates various influencing factors such as fracture distribution, displacement pressure gradient, gravity, and buoyancy. The complex pore structure of tight oil reservoirs, including nanopores and natural microfractures, presents a challenge in developing an accurate mathematical model for predicting flow behavior. The proposed model considers the fractal characteristics of pores and fractures and accounts for many factors to predict cumulative oil production, oil flow rate, and oil recovery factor during imbibition flow. Experimental data on fractured tight sandstones are used to validate the model, and sensitivity analyses are conducted to assess the influence of pore structure parameters, fracture distribution, and fluid properties on imbibition behavior. The findings reveal that gravity and buoyancy effects become more prominent under low interfacial tension. Fracture distribution significantly impacts imbibition behavior, with critical values for fractal dimensions, fracture numbers, and apertures determining the extent of their influence. Higher contact angles and increased oil phase viscosity result in reduced imbibition efficiency. In pressure-driven displacement processes, larger fractures preferentially produce crude oil, and the higher pressure gradients result in shorter imbibition processes. The proposed model offers insights into the imbibition oil recovery mechanism in tight oil reservoirs and can contribute to improved recovery factors.

NMR-Based Analysis of Fluid Occurrence Space and Imbibition Oil Recovery in Gulong Shale

The Gulong shale oil reservoir is situated in freshwater to slightly saline lacustrine basins mainly consisting of a pure shale geological structure, which is quite different from other shale reservoirs around the world. Currently, the development of Gulong shale oil mainly relies on hydraulic fracturing, while the subsequent shut-in period for imbibition has been proven to be an effective method for enhancing shale oil recovery. To clarify the characteristics of the fluid occurrence space and the variation in the fluid occurrence during saltwater imbibition in Gulong shale, this paper carried out porosity and permeability tests on Gulong shale cores and analyzed the fluid occurrence space characteristics and imbibition oil recovery based on nuclear magnetic resonance (NMR). In the porosity and permeability tests, T2 distributions were used to correct the porosity measured by the saturation method to obtain the NMR porosity. Combined with the identification of fractures in shale cores using micro-CT and the analysis of porosity and permeability parameters, it was found that the permeability of the shale cores was related to the development of fractures in the shale cores. Through the testing and analysis of T1-T2 maps of the shale cores before and after saturation with oil, it was found that the shale mainly contained heavy oil, light oil, and clay-bound water, and they were distributed in different regions in the T1-T2 maps. Finally, the T1-T2 maps of the shale cores at different imbibition stages were analyzed, and it was found that saltwater mainly entered the minuscule inorganic pores of clay minerals during the imbibition process and squeezed the larger-sized inorganic pores containing light oil through the hydration expansion effect, thus expelling the light oil from the shale core and achieving the purpose of enhanced oil recovery.

Novel silicon quantum dots for efficient imbibition oil recovery in low permeability reservoirs

In this work, the active sulfonated silicon quantum dots (S-SiQDs) nanofluid composed of S-SiQDs nanoparticles and bitetradecyl sulfobetaine (BS) was prepared to enhance oil recovery of low permeability reservoir by spontaneous imbibition. Firstly, a facile hydrothermal synthesis method was proposed to fabricate silicon quantum dots (SiQDs), followed by sulfonated modification of SiQDs to obtain S-SiQDs. The average particle size of S-SiQDs was 5.4 nm and it can remain stable at 120 °C and 5 wt% NaCl for 7 days. In addition, the active S-SiQDs nanofluid had better abilities in interfacial tension reduction, wettability alteration, and oil detachment than single surfactants and single S-SiQDs due to the synergistic effect. Compared with single S-SiQDs (12.8 %) and BS surfactant (17.5 %), the active S-SiQDs nanofluid can significantly improve the imbibition recovery to 29.9 %. Finally, the spontaneous imbibition mechanism of this active S-SiQDs nanofluid was proposed through nuclear magnetic resonance and theoretical analysis. This work develops an active S-SiQDs nanofluid with ultra-small size, excellent temperature and salinity resistance, and high interfacial activity, which can efficiently improve oil recovery of low permeability reservoirs.