Imbibition Efficiency Research Articles

Effects of Silica Nanoparticle after Modification with (3-Aminopropyl) Triethoxysilane and Its Combination with Surfactant for Enhanced Oil Recovery

Silica nanoparticle (SNP) shows exceptional characteristics and therefore attracts much attention in enhancing the oil recovery factor. However, it tends to agglomerate in the water phase due to the presence of tremendous surface free energy, which limits greatly application in oil fields. To this end, it is essential to perform the modification of the SNP surface to increase its dispersibility. In this work, (3-aminopropyl) triethoxysilane (KH550) was used to modify the SNP surface, and the structural characterization of the KH550-SNP was carried out using FT-IR and TGA. Then, a composite system (KH550-SNP/SDBS) was prepared by integrating negatively charged sodium dodecylbenzene sulfonate (SDBS) and positively charged KH550-SNP under the action of the electrostatic attraction force, and its interface properties and imbibition efficiency were further evaluated. The characterization results indicated that the modification process of the SNP surface by KH550 was successful. Besides, the interfacial tension (IFT) of the composite system (KH550-SNP: SDBS = 0.05%: 0.05%) was 0.6 mN/m and the water contact angle (CA) of the core slice treated with the composite system (KH550-SNP: SDBS = 0.05%: 0.01%) was 36.5° compared to the KH550-SNP of 15.1 mN/m and 42.6°, which stated that the composite system had better interface properties than the KH550-SNP. Finally, the imbibition recovery factors were 24.7% and 30.8% when the KH550-SNP and composite system (KH550-SNP: SDBS = 0.05%: 0.01%) was used.

Study on the Flow Mechanism of Shale Oil with Different Injection Media

Chinese shale oil has high recoverable resources and great development potential. However, due to the limitation of development technology, the recovery rate of shale oil is not high. In this paper, the effects of different injection media on the development of shale oil reservoirs in Dongying formation, Qikou depression, Huanghua depression, and Bohai bay basin, were studied by means of imbibition and nitrogen flooding. Combining nuclear magnetic resonance (NMR) technology with imbibition and gas displacement experiments, the mechanism of shale injected formation water, active water (surfactant), and nitrogen was reproduced. The displacement process of crude oil under different injection media and injection conditions was truly demonstrated, and the relationship between different development methods and the pore boundaries used was clarified. A theoretical basis for the effective development of shale oil was provided. At the same time, Changqing tight oil cores with similar permeability to Dagang shale oil cores were selected for comparison. The results showed that, as the imbibition time of shale samples increased, the imbibition efficiency increased. Pores with T2 < 10 ms contributed the most to imbibition efficiency, with an average contribution greater than 90%. 10 ms < T2 < 100 ms and more than 100 ms pores contributed less to imbibition efficiency. Active water can change the wettability of shale, increase its hydrophilicity, and improve the efficiency of imbibition. The imbibition recovery ratio of injected active water was 17.56% higher than that of injected formation water. Compared with tight sandstone with similar permeability, the imbibition efficiency of shale was lower. As the nitrogen displacement pressure increased, the oil displacement efficiency also increased. The higher the shale permeability was, the greater the displacement efficiency would be. T2 > 100 ms pore throat of shale contributed to the main oil displacement efficiency, with an average oil displacement efficiency contribution of 63.16%. And the relaxation interval 10 < T2 < 100 ms pore throat displacement efficiency contributed to 28.27%. T2 < 10 ms pore throat contributed the least to the oil displacement efficiency, with an average oil displacement efficiency contribution of 8.58%. Compared with tight sandstone with similar permeability, shale had lower oil displacement efficiency. The findings of this study can help for better understanding of the influence of different injection media on shale oil recovery effect.

Study on the Production Mode of Horizontal Well from Water Huff and Puff to Segmented Injection and Production in Tight Reservoir

Water huff and puff in horizontal wells in tight reservoirs has achieved good results in replenishing formation energy. However, after multiple rounds of treatment, a rapid decrease in formation pressure takes place making it difficult to maintain stable production. To improve the oil recovery rate of tight reservoirs, it is imminent to change the development mode. In this work, the stress distribution characteristics at fracture tips were analyzed based on Irwin theory and elastic theory. A model of propagation and closure length of fractures was established based on the propagation mechanism of water injection-induced natural fracture and the energy balance principle of fracture mechanics. Surfactant imbibition experiments were carried out according to the imbibition principle of surfactant system, and the propagation law of natural fractures was described with numerical simulation to analyze the seepage characteristics of dynamic fracture network. On the basis of the above works, alternating water huff and puff into segmented injection and production was proposed according to the distribution law of dynamic fracture network. The developing process of an actual well case by these two developing modes was simulated to predict 18 years of cumulative recovery, pressure distribution, and recovery rate. Results showed that when stress intensity factor exceeds the fracture toughness, the natural fractures will extend along their original directions and get connected, forming an irregular fracture network. The lengths of fractures after propagation and closure will not bring about water channeling for they are far shorter than well and interval spacing. Surfactant could diminish the resistance of boundary layer by reducing the wetting contact angle, ending up with an improvement in imbibition efficiency. Radial displacement and dynamic imbibition occur simultaneously in a dynamic fracture network during the early stage of water injection, while static imbibition mainly occurs during injection shutdown period and well soaking. According to comparison, the swept area of segmented injection and production was larger, ending up with a continuous increase of simulated recovery rate and cumulative recovery. The findings of this study show alternating water huff and puff after to segmented injection and production in fractured tight reservoir can allow full play of dynamic fracture network’s potential and achieve effective enhancement in oil recovery rate.

Effect of Dynamic Imbibition on the Development of Ultralow Permeability Reservoir

To explore the methodology for improving ultralow permeability reservoir recovery, cores of ultralow permeability reservoirs in China’s Ordos Basin were selected to study the dynamic imbibition micromechanism of crude oil in nanopore throat through core-flooding laboratory experiment and nuclear magnetic resonance (NMR) observation. In the meantime, the microimbibition characteristics and dynamic discharge of oil between matrix and fracture in partially closed boundary reservoirs were simulated to utmostly reflect the actual reservoir conditions. Our findings suggest that dynamic imbibition between fracture and matrix serves the core technology for improving the recovery of ultralow permeability reservoirs, while the main factors affecting dynamic imbibition efficiency include wettability, permeability, injection rate, fracture, water huff and puff cycles, and soaking time. Wettability, in particular, weighs the most, and imbibition can take place either on water-wet rocks or transformed oil-wet rocks with an imbibition agent added in during the waterflooding process. Meanwhile, the higher the permeability is in place, the greater the dynamic imbibition recovery might achieve. The experiments indicate that the dynamic imbibition recovery of a fractured core is 16.26% higher than that of a nonfractured core. Additionally, fractures can not only enhance imbibition recovery but also accelerate the occurrence of dynamic imbibition. The optimal water injection rate of dynamic imbibition is 0.1 mL/min; the reasonable huff and puff cycle of the ultralow permeability reservoirs tends to be two to three cycles; the optimal soaking time of ultralow permeability reservoir is speculated to be 30 days. Finally, the field practice shows that after Stimulated Reservoir Volume (SRV) and dynamic imbibition in 5 horizontal wells in An83 oilfield, there is a remarkable drop in water cut and a noticeable rise in oil production. This research underpins the significance of a dynamic imbibition effect in the development of ultralow permeability oilfield.

Preferential imbibition in a dual-permeability pore network

Abstract

Microscopic mechanism of fracturing fluid imbibition in stimulated tight oil reservoir

The imbibition of fracturing fluid is of great significance to improve the development of fractured tight oil reservoirs. Understanding the micro-characteristics of fracturing fluid imbibition is necessary to improve the imbibition efficiency. In this work, the experiments of the spontaneous imbibition under simulated in-situ condition is conducted to understand the micro-characteristics of fracturing fluid imbibition, and the Nuclear magnetic resonance (NMR) and high-resolution X-rays computed tomography (CT) scanning are applied to monitor the process and the liquid distribution of spontaneous imbibition. The experimental results indicate that the spontaneous imbibition is mainly occurred in macropores at the initial stage, and the velocity of fracturing fluid is lower than that of formation water in spontaneous imbibition due to the weaker motivity generated from the lower oil-fracturing fluid interfacial tension. The fracturing fluid can promote the spontaneous imbibition due to it can decrease the kinetic energy loss when it transforms into the interfacial free energy. Thus, the oil recovery obtained from the fracturing fluid imbibition increased to 20.7% from 15.8% by formation water imbibition. The main reason accounts for it is that the wettability of fracturing fluid is stronger than that of formation water, thus can promote the whole process of spontaneous imbibition, and the lower viscosity would reduce the flow resistance at the latter stage. A higher oil-water interfacial tension (IFT) can accelerate the velocity of spontaneous imbibition at the initial stage, while a proper interfacial tension is favorable at the latter stage.

Impacts of mineral composition and pore structure on spontaneous imbibition in tight sandstone

Spontaneous imbibition is a fundamental mechanism to figure out the rock-fluid interplay during waterflooding and hydraulic fracturing. Mineral composition and pore structure play significant roles in imbibition efficiency, but how these parameters influence the oil production efficiency still is a myth. This research conducted the spontaneous imbibition experiments combined with low-temperature adsorption and nuclear magnetic resonance to (1) study how minerals and pore structures impact fluid movement features for tight sandstones; (2) systematically investigate the contribution to oil recovery of different pores' types and the impact of pore connectivity on spontaneous imbibition. The results show that the brine is inclined to attach hydrophilic minerals because of the wettability, increasing the imbibition efficiency. Additionally, with the tiny pores’ development, the oil is more easily replaced by the brine due to strong capillary pressure. Last, as the mainstream imbibition area grows, the oil is preferentially displaced by the brine. The research provides insights into how mineral compositions and pore structures can influence spontaneous imbibition efficiency and improves the understanding of the complicated interaction between fluid and minerals in tight sandstones.

Study of a low-damage efficient-imbibition fracturing fluid without flowback used for low-pressure tight reservoirs

The oil production from the low-pressure tight reservoirs in China decreases sharply after fracturing under natural depletion. To supply the formation energy and displace oil through imbibition instead of flowback, a novel nanoparticle-enhanced supramolecular fracturing fluid (NESF) was developed. It consisted of 0.10 wt% hydrophobically modified hydroxypropyl guar (HMHPG), 1.00 wt% synthesized hydrophilic gemini surfactant (HGS), and 0.05 wt% hydrophobically fumed nanosilica (HNS). A series of experiments were conducted to characterize the molecular structure of HGS and evaluate the heat/shear resistance, rheological property, proppant suspension and transportation, formation damage, and imbibition efficiency of NESF. Finally, the oilfield practical application of NESF fracturing without flowback was carried out. The results showed that the heat resistance and the interfacial property of NESF were improved by HNS and HGS respectively. Besides the favorable common properties, a low oil permeability loss rate of 9.40%, a high fracture conductivity retainment rate of 95.11%, and a high imbibition recovery factor of 19.43% were realized by NESF. The accumulative oil production of the well stimulated by NESF without flowback was increased by 13.55% and the decline rate of oil production was reduced from 14.70% to 5.22% in the first 6 months.

Experimental study of spontaneous imbibition for oil recovery in tight sandstone cores under high pressure high temperature with low field nuclear magnetic resonance

Spontaneous imbibition (SI) plays a key role in production mechanism of unconventional reservoirs. Trivially, with the goal of getting higher efficiency there always has been an incessantly research activities to develop the technology progressively. In this regard, thermodynamic variables (i.e. pressure and temperature) can directly influence the process performance of SI. Thus, numerous papers have been published by considering normal conditions (e.g. 20 °C, 0.1 MPa), high pressure (HP) or high temperature (HT). To bridge an existing gap in the literature, an inhouse built imbibition experimental setup was used to carry out the SI under high pressure-high temperature (HPHT) conditions (50 °C, 10 MPa). The core samples used in this study were tight sandstone taken from Yanchang formation, Ordos Basin. Experimental conditions were: 1) simulated formation conditions (50 °C, 10 MPa), 2) normal condition (20 °C, 0.1 MPa), 3) pulse imbibition (20 °C, 8/4 MPa in cyclic alteration) and 4) simulated formation conditions (50 °C, 10 MPa) for fractured cores (1/3 and 2/3 length). Moreover, NMR was employed to characterize the dynamic behavior of imbibition for each sample. It was found, samples tested under HPHT conditions yielded higher imbibition efficiency (average of 63.49%) compared to ambient conditions (27.31%). and imbibition efficiency of HPHTSI (max, 73.47%, min, 55.23%) showed early imbibition with higher rate. Ultimately, micropores had the largest imbibition efficiency and matrix core samples exhibited lower recovery than fractured ones (74.6%). Collectively, this study presents the importance of fracture-matrix interaction in tight sandstones which is a crucial component for higher recovery rates.

QEMSCAN-Assisted Interpretation of Imbibition Capillary Pressure for Multiporosity Carbonate Rocks

Summary In this paper, we present an experimental study that explores the potential links between the imbibition capillary pressure Pci and the pore systems and/or mineralogy for carbonate reservoirs undergoing waterflood. A systematic workflow has been formulated to ensure the data quality of Pci, minimize uncertainty in deriving Pci from centrifuge tests, and analyze the data considering the pore-size distribution from mercury injection capillary pressure (MICP) and mineralogy from Quantitative Evaluation of Minerals by Scanning Electron Microscopy (QEMSCAN). The workflow starts with assessing the centrifuge production data for gravity-capillary equilibrium at each speed. Then, the quality-checked data are used to generate six different Pci curves using analytical and numerical models. The resulting curves provide a measure of the variability in solutions for various rock types and assist in the selection of the most-representative Pci curve. Finally, the representative Pci curves of all rock samples are analyzed together with the MICP and QEMSCAN data to examine the change in Pci curves as a result of changes in the number and character of rock types, pore systems, dominant pore-throat radii, and mineralogy. Findings from this study shed light on the impact of mineralogy and pore systems on Pci. From the mineralogy perspective, the presence of dolomite, microporous calcite, or rutile and anatase (TiO2) within the rock composition is found to affect the Pci of the carbonate samples used in this study. The rock samples with these minerals should be separated from other bimodal samples before attempting to obtain a correlation between Pci and pore systems. The data analysis further reveals that some bimodal samples of medium permeability yield a better waterflood imbibition efficiency than those of the high-permeability samples. This observation is attributed to a better communication between the micropore and macropore systems, and a closer proximity of the peak radii of the micro- and macropore systems of the medium-permeability samples.

Investigation on the Mechanisms of Spontaneous Imbibition at High Pressures for Tight Oil Recovery.

Water flooding is widely used for recovering crude oil from unconventional reservoirs due to its economic feasibility. At reservoir conditions, the injected water is usually imbibed into fractured rocks, so-called spontaneous imbibition, providing a considerable driving force for enhancing oil recovery. In this work, spontaneous imbibition on a rock surface is investigated at high-pressure conditions, and its influence on tight oil recovery is revealed from a pore-scale perspective. Specifically, three typical core samples are selected and characterized to obtain their pore-size distribution by applying the NMR technique. These core samples are then saturated with crude oil and are submerged in formation water, which is filled in a high-pressure vessel. Oil recovery efficiency as well as the imbibition rate is consequently calculated for specific pores during spontaneous imbibition. Test results indicate that oil recovery from spontaneous imbibition is different in different pores depending on the petrophysical properties of the tight cores. That is, the difference in imbibition efficiency between small and large pores decreases as permeability and porosity increase in the core samples. In addition, as for core samples #1 and #2, the imbibition rate usually reaches a maximum at the initial imbibition stage. However, as for core sample #3, the maximum imbibition rate is far delayed due to high capillarity. This work may reveal the fundamental mechanism of the influence of spontaneous imbibition on a rock surface at high-pressure conditions on tight oil recovery from a pore-scale perspective.

Impacts of pore structure and wettability on distribution of residual fossil hydrogen energy after imbibition

Due to the heterogeneity of the pore structure, there is still much residual fossil hydrogen energy in the pore space. In this study, the distribution of residual fossil hydrogen energy after imbibition with liquid nanofluid (LNF) has been studied through the. Firstly, relevant properties of the LNF were tested, including particle size, wettability alteration, and interfacial tension (IFT). Then, one micromodel under both oil-wet and water-wet conditions was used to elucidate the difference of residual oil after imbibition. Moreover, the difference of imbibition processes with oil-wet and water-wet models was further studied. Finally, the influence of dimensions and coordination numbers of pores was investigated. Besides, the impact of fluid type on imbibition efficiency was also compared through microfluidic experiments. Results show that the residual oil saturation is significantly higher in the oil-wet micromodel than in the water-wet micromodel, even the wettability alteration additive was used. There are four kinds of locations for residual oil after imbibition in water-wet micromodel, while only three kinds of locations for residual oil in oil-wet micromodel. The imbibition rate and residual oil saturation in small pores are higher than the larger ones. Due to the unbalanced force at pore throats, a micromodel with a high coordination number has lower residual oil saturation. Besides, the lower residual oil saturation is obtained by adding the LNF. This paper provides a micro-visual method to understand the imbibition process under different wettability and pore structures in fossil hydrogen reservoirs.

Experimental Study of Imbibition with Normal Fracturing Fluid in Low-permeability Reservoirs

As the volume of fracturing fluid injected in the formation is getting larger and larger, there is more attention paid to the imbibition efficiency of the broken fracturing fluids. The fracturing fluids, including water-base gel fracturing fluid, thickened water fracturing fluid, slippery water fracturing fluid, emulsified fracturing fluid and clean fracturing fluid were chosen to do the spontaneous imbibition experiment with natural core samples from the Ordos Basin. Furthermore, the correlation between the parameters including viscosity, interfacial tension and contact angle and the recovery ratio was studied respectively. The result showed that the broken fracturing fluids of water-base gel and thicken water performed the highest recovery ratio of spontaneous imbibition, which were 23.1% and 20.6% respectively. Meanwhile, the correlations between those parameters and recovery ratio were contact angle, viscosity of broken fluids and interfacial from in turn in the experimental situation. What’s more, both the contact angle and the viscosity showed negative correlation to imbibition recovery ratio while the interfacial tension showed positive correlation. This study provides help to the researchers to understand the mechanism of fracturing fluids imbibition in low permeability reservoirs.

Enhancement of capillary imbibition by Gamma-Alumina nanoparticles in carbonate rocks: Underlying mechanisms and scaling analysis

Due to the oil-wet nature of carbonate reservoirs, performance of capillary imbibition is relatively weak in these reservoirs. One of the possible solutions to promote capillary imbibition is using nanoparticles (NPs) for wettability alteration purposes. In this study, imbibition efficiency of Gamma-Alumina (Ɣ-Al) NPs with different concentrations was investigated in low permeable, oil-wet carbonate rocks at 80 °C. The underlying mechanisms of Ɣ-Al NPs to enhance imbibition oil recovery were explored by analyzing dynamic contact angle profile, interfacial tension (IFT) of crude oil/Ɣ-Al nanofluid, size distribution of Ɣ-Al NPs and the inverse bond number. Results showed that Ɣ-Al NPs increased oil recovery to as much as 11.5% of the original oil in place (OOIP), while no oil was obtained by water imbibition in the native rock. The increase of Ɣ-Al concentration from 0.01 to 0.3 wt% showed a positive impact on the oil recovery, while further increase to 0.5 wt% provided lower incremental oil. The oil recovery results were consistent with dynamic contact angle profiles in which Ɣ-Al NPs successfully altered rock wettability from oil-wet to more water-wet conditions, but a less water-wetness was obtained for 0.5 wt% Ɣ-Al nanofluid. Also, scanning electron microscopy and energy dispersive X-ray analyses verified that the rock wettability alteration occurs mainly due to the adsorption of Ɣ-Al NPs on the carbonate surface. It was found that Ɣ-Al NPs exhibited a slight reduction in IFT from 15 to 11 mN/m, which provided a weak contribution in the oil recovery. Also, a new scaling equation was proposed to describe capillary imbibition process influenced by rock wettability alteration. The scaling equation successfully captured the oil imbibition recovery with different wettability conditions. This study supports the EOR potential of Ɣ-Al NPs in oil-wet carbonates and also emphasizes the important role of wettability function to upscale capillary imbibition processes from core to field scale.

Features and imbibition mechanisms of Winsor I type surfactant solution in oil-wet porous media

The relationship between NaCl concentration and the phase change behavior of microemulsion of anionic surfactant was characterized by the salinity scan experiments. The wettability of Winsor I type surfactant solution (WI solution) and the effect of NaCL concentration on phase change behavior of WI solution and imbibition in oil-wet porous media were investigated by microfluidic experiments in this study. The WI solution and Winsor I type microemulsion are similar in wetting phase with stronger wettability than other phases. Two main mechanisms of WI solution enhancing imbibitions recovery in oil wet porous media are the wetting phase drive and residual oil solubilization. Under the salinity condition of Winsor I type microemulsion, the NaCl concentration has strong impact on the imbibition mechanism of WI solution, the higher the NaCl concentration, the complex the imbibition process and the higher the imbibition efficiency will be. The NaCl concentration has strong impact on the solubilization ability to oil of the WI solution, the higher the NaCl concentration, the stronger the solubility of the WI solution to residual oil will be.

New insights into spontaneous imbibition in tight oil sandstones with NMR

Previous research has confirmed that substantial yield has been recovered in the soaking period after hydraulic fracturing. Spontaneous imbibition (SI) is the primary mechanism responsible for the enhanced oil production and has become an effective oil recovery method with regards to unconventional reservoirs. Despite the importance of SI, an in-depth understanding of the features of SI in tight reservoirs is still inadequate. In this article, nuclear magnetic resonance (NMR) T2 was employed to study the dynamic behavior of imbibition in tight sandstone samples from Yanchang formation, Ordos Basin. Additionally, high-pressure mercury intrusion (HPMI) and the initial T2 of a core sample were combined to characterize pore structures of tight rocks and oil distributions in various pores at different imbibition stages. Then, the effects of gravity, anisotropic pore structure, and non-wetting phase (NWP) viscosity on imbibition recovery were determined via the variations in T2 spectra for each sample. The results show that the tight cores feature a multiscale pore structure. Sub-micropores is the dominant type providing the major contribution to oil recovery, while nanopores have largest imbibition efficiency due to the larger capillary force. Gravity of fluids has a non-trivial effect on SI and cannot be neglected in tight samples under two-ends-open (TEO) or one-end-open (OEO) conditions; this seemingly counterintuitive finding is because the capillary force is weakened by the resistance force caused by the intricate flow paths and other possible surface forces at the nanoscale. Imbibition performance in a tight medium is strongly related to its pore structure. The variations in directional permeabilities, relative permeabilities and capillary pressure functions resulting from highly anisotropic samples greatly affect both the ultimate oil recovery and imbibition rate for tight samples under TEO condition, but only impact imbibition rate under all-faces-open (AFO) condition. Furthermore, because tight oil has a narrow range of viscosity, the imbibition behavior in tight samples may not be sensitive to the oil viscosity. It would be hoped that the insights gained from this study can help to improve our understanding of imbibition characteristics in tight reservoirs and develop new scaling models for the predication of oil recovery.

Mechanisms of imbibition enhanced oil recovery in low permeability reservoirs: Effect of IFT reduction and wettability alteration

Imbibition has been proposed as an important means by which to recover oil from low permeability reservoirs. However, the mechanism of imbibition enhanced oil recovery (IEOR) remains controversial. In this study, we attempted to explore these mechanisms using three of the most commonly used chemical systems (surfactant, brine based nano-silica, and surfactant based nano-silica solutions). First, the imbibition efficiency of the three systems was investigated through imbibition tests using Amott cells at 80 °C. Then, the interfacial tension (IFT) and contact angle were measured to explore the potential characteristics that may play important roles in IEOR. Finally, the dynamic inverse Bond number was introduced to further analyze the mechanisms of IEOR. The results show that oil recovery can be enhanced by 5.36% when using an ultra-low IFT surfactant solution, which has less ability to alter wettability; up to 4% using brine based nano-silica solutions, which can only alter wettability to more water-wet but cannot reduce the IFT; and 8.78% using surfactant based nano-silica solutions, which can both reduce the IFT and alter wettability effectively. Thus, both low IFT and good wettability alteration are desirable, and the highest recovery was achieved when both characteristics were combined, and maximizing their contributions to IEOR. This work firstly investigated the contribution of IFT reduction and wettability alteration on IEOR separately, and a novel system that produced excellent IEOR efficiency was formulated. This study provides fundamental information to the selection of IEOR chemicals.

The Relationship Equation Between the Properties of Imbibition Agent and Imbibition Efficiency

Based on a large number of physics simulation experiment data, mathematics relationship problems of the correlation of imbibition efficiency influence factors have been solved, and the correlation equation have been established. Field ML and field YT was chosen to represent the extra-low permeability field, Field JY and field QX was chosen to represent the ultra-low permeability field. The impact trend of imbibition efficiency with interfacial tension, emulsion stability, penetration force and viscosity has been found. A result has been found through the R factor analysis by common factor variance and coefficient of variation method, the impact order on imbibition efficiency of oil-wet core or oil sand is interfacial tension, emulsion stability, viscosity ratio and penetration force ratio. The four factors and three factors structural equation models have been established, and passed the model test. The impact of cross term is considered. This study has great significance in analyzing the factors affecting the imbibition efficiency.

Experimental study of boundary condition effects on spontaneous imbibition in tight sandstones

The main objectives of this study were to investigate the effects of boundary condition and pore size on spontaneous imbibition in tight sandstones, and to simulate and interpret the flow process. In this study, scanning electron microscopy (SEM), mercury injection capillary porosimetry (MICP) and nuclear magnetic resonance (NMR) T2 were combined to investigate the pore systems of the tight sandstone outcrop from Yanchang formation, Ordos Basin. Five parallel sets of imbibition experiments were also carried out, respectively using NMR and imbibition cell to guarantee the reliability of recovery data. Furthermore, a study was conducted to validate the linear model of recovery versus the square root of time in tight sandstones under different boundary conditions. The radial countercurrent flow encounters the linear flow, and causes mutual interference in the late stage of imbibition, which is probably the main reason for a lower recovery of all-face-open (AFO) imbibition than two-ends-closed (TEC) imbibition. Imbibition efficiency decreased with the increase in pore radii around the immovable peak, while it increased with increasing pore radii around the movable peak. The linear relationship between the imbibition recovery and the square root of time was best fitted by TEC imbibition, whereas the relationship in two-ends-open (TEO) imbibition is poor. In addition, different behaviors between TEO imbibition and the other four types indicate that gravity cocurrent flow dominates in the former one.

Effects of Imbibing Agents on Oil Displacement Efficiency by Imbibitions

The imbibition efficiency influence factors, such as interfacial tension, emulsification, viscosity, and so on were evaluated for the extra/ultra low permeability outcrop cores and fine oil sands. The experimental results show that for the ordinary low permeability and ultra-low permeability cores, the static imbibition efficiency increases with the decrease of permeability and size of throat and pore radius. At the same time, the emulsification and viscosity of the imbibing agent system should not be higher than a certain value, and the turbidity should be low. The interfacial tension has a suitable range for spontaneous imbibition. Reservoir wettability affects the direction of capillary force. The pore radius and curvature radius of pore port determines the value of capillary force. Thus, the reversion and adjustment of reservoir wettability is an important factor for imbibition oil recovery