Imbibition Of Fracturing Fluid Research Articles

Microscopic characteristics of tight sandstone reservoirs and their effects on the imbibition efficiency of fracturing fluids: A case study of the Linxing area, Ordos Basin

The Linxing area within the Ordos Basin exhibits pronounced reservoir heterogeneity and intricate micro-pore structures, rendering it susceptible to water-blocking damage during imbibition extraction. This study delved into the traits of tight sandstone reservoirs in the 8th member of the Shihezi Formation (also referred to as the He 8 Member) in the study area, as well as their effects on fracturing fluid imbibition. Utilizing experimental techniques such as nuclear magnetic resonance (NMR), high-pressure mercury intrusion (HPMI), and gas adsorption, this study elucidated the reservoir characteristics and examined the factors affecting the imbibition through imbibition experiments. The findings reveal that: ① The reservoir, with average porosity of 8.40% and average permeability of 0.642 × 10−3 μm2, consists principally of quartz, feldspar, and lithic fragments, with feldspathic litharenite serving as the primary rock type and illite as the chief clay mineral; ② Nano-scale micro-pores and throats dominate the reservoir, with dissolution pores and intercrystalline pores serving as predominant pore types, exhibiting relatively high pore connectivity; ③ Imbibition efficiency is influenced by petrophysical properties, clay mineral content, and microscopic pore structure. Due to the heterogeneity of the tight sandstone reservoir, microscopic factors have a more significant impact on the imbibition efficiency of fracturing fluids; ④ A comparative analysis shows that average pore size correlates most strongly with imbibition efficiency, followed by petrophysical properties and clay mineral content. In contrast, the pore type has minimal impact. Micropores are vital in the imbibition process, while meso-pores and macro-pores offer primary spaces for imbibition. This study offers theoretical insights and guidance for enhancing the post-fracturing production of tight sandstone reservoirs by examining the effects of these factors on the imbibition efficiency of fracturing fluids in tight sandstones.

Investigating the Influencing Factors of Imbibition of Fracturing Fluids in Tight Reservoirs

Tight reservoirs are the focus of unconventional oil and gas resource development, but most tight reservoirs exhibit complex pore structures, strong non-homogeneity, and limited water drive development. Fracturing fluid imbibition is a critically important way to improve the recovery of tight reservoirs. In this paper, an NMR experimental device was used to conduct imbibition experiments in tight reservoirs, and the relationship between temperature, pressure, matrix permeability, and imbibition recovery was investigated. Based on the fracturing fluid imbibition recovery curve, the imbibition process is divided into the fast imbibition stage, slow imbibition stage, and imbibition equilibrium. In addition, based on the pore structure division, the recovery changes of each pore under different experimental conditions were quantitatively analyzed. The results indicate that the highest imbibition recovery is achieved at an experimental pressure of 5 MPa within the range of 0 MPa to 15 MPa. Increasing the experimental pressure can increase the imbibition rate but will not increase imbibition recovery. Within the investigated range in this paper, fracturing fluid imbibition increases with rising temperature and matrix permeability. Moreover, the recovery of each pore gradually increases with the experimental pressure ranging from 0 MPa to 5 MPa. The recovery of each pore is positively correlated with matrix permeability and temperature. During the experiment, micropores contributed the most to the recovery, while macropores contributed the least. The study in this paper guides the efficient development of tight reservoirs.

Insights into CO2 huff-n-puff mechanisms from laboratory experiment and single-well pilot test in the Lucaogou tight oil reservoir, Jimsar sag, China

CO2 huff-n-puff has been accepted as an effective technique to improve oil recovery in tight oil reservoirs. Even though CO2 EOR mechanisms were extensively investigated from laboratory experiments, the links of experimental results to field-scale performance have not been widely investigated as few pilot tests were conducted. In this study, laboratory experiments and CO2-huff-n-puff pilot test were performed. First, phase behaviors of the Lucaogou crude oil and oil-CO2 mixtures were investigated via Pressure-Volume-Temperature (PVT) tests including flash evaporation, constant composition extension (CCE), and CO2 injection and slim tube tests, respectively. Experimental results showed that due to the higher concentration of the intermediate components, the saturation pressure of the Lucaogou crude oil is 6.18 MPa, which is much smaller than the initial and current formation pressures. The oil viscosity decreased from 24.8 mPa s to 3.0 mPa s and swelling factor increased to 1.848 after about 85 mol% CO2 dissolved. Moreover, slim tube test showed the minimum miscible pressure of the Lucaogou crude oil is 24.28 MPa, which is smaller than the current formation pressure, indicating multi-contact miscibility could be reached easily. Second, fracturing fluid imbibition and CO2 huff-n-puff experiments were carried out to evaluate the performance of CO2 EOR after fracturing. The oil recovery factor increased after imbibition time and the number of huff-n-puff cycles, and was impacted by petrophysical properties, like porosity and pore structure. In addition, performance of CO2 huff-n-puff pilot test in the J30 well was reported. Approximately 1.9% of original oil in place was recovered after one huff-n-puff cycle, showing a significant potential of CO2 EOR in the Lucaogou tight formation. Analysis of oil production rate, composition and density of produced oil shows the dominant EOR mechanisms in the early production stage were miscibility and CO2 vaporization, then viscosity reduction. Findings from this study will provide insights on CO2 EOR in tight oil reservoirs.

Effects of Fracturing Fluids Imbibition on CBM Recovery: In Terms of Methane Desorption and Diffusion

Summary Hydraulic fracturing technology has been widely used to improve the productivity of the coalbed methane (CBM) reservoir, during which tons of fracturing fluids infiltrate the coal seam. However, the effects of fracturing fluids imbibition on CBM recovery are still unclear. In this study, spontaneous and forced water imbibition experiments in methane-bearing low-volatile bituminous (LVB) coal were conducted at various gas adsorption equilibrium pressures, following which methane desorption and diffusion experiments were performed. These experiments simulated the complete process of fracturing fluid imbibition during well shut-in and subsequent methane production upon reopening, which is helpful in understanding the impact of fracturing fluid imbibition on CBM production. The results show that water imbibition displaces adsorbed methane in the coal matrix, and with reservoir pressure increasing, the displaced effect decreases. Furthermore, the forced imbibition (FI) displaces less methane than the spontaneous imbibition (SI) due to water rapidly filling fractures and blocking methane migration out of the matrix in the FI. In the initial stages of gas production following spontaneous or forced water imbibition, the displaced methane diffuses out of the coal at a rapid rate and then slows down. Furthermore, in the case of FI, a significant amount of residual gas remains after desorption and diffusion due to the water blocking effect. However, the water blocking effect has a minimal impact on coal undergoing SI. In terms of desorption and diffusion, this study provides a comprehensive understanding of the effects of fracturing fluids imbibition on recovery of CBM, which is useful for practical shut-in operations following hydraulic fracturing in LVB coal seams.

Insights into in-situ imbibition behavior of fracturing fluid in propped shale fractures based on nuclear magnetic resonance: A case study from Longmaxi Formation shale, Sichuan Basin, China

Shale gas is an important component of unconventional oil and gas resources. Studying the imbibition behavior is helpful to optimize flowback parameters and enhance gas recovery. Recent imbibition studies have focused on shale matrix, and the pressure conditions discussed were mostly atmospheric. The initial imbibition behavior begins from propped fractures to matrix, but there are few studies working on explaining the imbibition behavior in propped fractures or the phenomenon of many shale wells exhibit higher productivity after a “soaking” period. Therefore, propped fracture samples were designed for imbibition and migration experiments. In order to accurately study the mechanism and main influencing factors of fracturing fluid imbibition and migration in propped and unpropped shale fractures under high temperature and high pressure, a series of experiments based on nuclear magnetic resonance (NMR) were carried out. Results showed that NMR T2 spectra of all samples exhibited a bimodal distribution. The final imbibition volume of fracturing fluid was positively related to pressure and fracture width. The imbibition effect of fracturing fluid was more evident in matrix pores under high pressure. In the migration during soaking stage, the fracturing fluid gradually migrated from large pores to small pores and gradually displaced the shale gas from the matrix, thus allowing the water blocking in propped fractures to self-unlock to some extent. Gas permeability decreased in the imbibition stage, while it recovered in the migration stage to some extent.

Fracturing fluid imbibition impact on gas-water two phase flow in shale fracture-matrix system

A large amount of fracturing fluid in hydraulic fracturing is imbibed into the shale fracture/matrix, which leads to significant uncertainty in gas recovery evaluation. The mechanism of imbibition impact on the gas–water flow is not well understood. In this study, systematic comparative experiments are carried out to simulate imbibition in fractured shale samples obtained from the Wufeng-Longmaxi shale reservoirs in China, and the imbibition effect in the fracture–matrix system is qualitatively and quantitatively investigated. Nine cores are collected to measure their porosity and permeability using a helium porosimeter and nitrogen pulse–decay tests. Gas/liquid single-phase flow experiments are then carried out using methane and KCl solution, respectively. Subsequently, dynamic imbibition experiments are carried out on three samples in a visual cell. The gas–water interfacial tension, water imbibition amount, and displacement velocity are recorded. A single-phase gas/liquid flow test shows a high linear correlation between the fluid displacement velocity and pressure gradient in the fractured samples as the fracture is the main flow channel, dominantly determining the flow behavior. Moreover, the capillary force was introduced in the cross-flow term of the triple-medium model to characterize the imbibition effect, and a two-phase flow simulation model considering the fracturing fluid imbibition retention was developed, and the two-phase flow behavior by considering the imbibition effect of the fracturing fluid retention in the shale gas reservoir was analyzed. Valuable experiment data in this work are provided, which can be used to validate analytical equations for gas/water flow in the shale fracture–matrix system.

A new method to calculate the effect of fracturing fluid imbibition on adsorbed gas content for shale gas reservoir

In-situ methane occurrence in shale gas reservoirs is seriously affected by the massive imbibed fracturing fluid. However, it is difficult to quantify the impact degree due to the complexity of pore connectivity. In this study, we firstly evaluated the ratio of through and blind pores by a proposed method firstly. Then the different influences of imbibition on gas occurrence in through and blind pores were demonstrated through designed experiments and a visual computational simulation. Finally, a new analytical model was proposed to calculate the effect of imbibition on adsorbed gas content, based on the ratio of through and blind pores and their different imbibition phenomenon. The comparison of the calculation and experimental results showed: (1) the new method can accurately predict the impact degree of imbibition on adsorbed gas; (2) imbibition in through pores leads to the co-current and countercurrent imbibition, and imbibition in blind pores leads to a compression of free gas.

Stress sensitivity of multiscale pore structure of shale gas reservoir under fracturing fluid imbibition

Stress sensitivity of multiscale pore structure of shale gas reservoir under fracturing fluid imbibition

考虑压裂液渗吸的压后压裂液返排的数值模拟

Fracturing fluid flowback is a key step in the process of hydraulic fracturing, and the imbibition of fracturing fluid in unconventional tight reservoirs cannot be ignored. Based on the oil-water two-phase seepage theory, Bernoulli equation and the continuity equation, we establish a numerical simulation model of post-fracturing flowback by considering the effect of fracturing fluid imbibition and obtain the pressure and flowback rate during the flowback process through programmed numerical calculation. The critical flow rate of fracturing fluid when the proppant starts to reflux is calculated according to the proppant backflow model. Then an optimization design method of flowback working system is formed based on the principle of controlling proppant backflow and rapid fluid flowback. The numerical simulation results are compared with the actual flowback data of LX3 well, and the flowback working strategy of M87 well is designed, and the effects of formation fluid viscosity and initial formation pressure on fracturing fluid flowback are analyzed. The results show that a phenomenon of formation fluid seepage to fractures is observed during the flowback, and the change of original formation pressure has a significant impact on fracturing fluid flowback, but the formation produced fluid has minor effects. The numerical results of flowrate and wellhead pressure of LX3 well are consistent with the field monitor data, with average errors of 13.8% and 15.5% respectively. It is verified that the flowback numerical model has high accuracy and can be used to guide the on-site fracturing flowback construction design in oilfield.

Experimental study on unstable imbibition characteristics of fracturing fluids at high pressures and temperatures in the tight continental reservoir

Enhanced oil recovery by imbibition (IEOR) is the key technology to effectively develop tight reservoirs with “three lows” characteristics. It can be valuable for practical development to investigate the process of fracturing fluid imbibition in steady and unsteady states and quantitatively assess the impact of fracturing fluid imbibition in various pores under various circumstances. By combining NMR technology with indoor physical simulation experiments, this paper quantitatively evaluates the differences in imbibition characteristics of various pores in different conditions under high temperature and high pressure. Further research is done into how the imbibition effect is affected by permeability, pore size, imbibition duration, steady-state, and unsteady-state (pressure change). The results indicate that micropore (0.1–1 ms) imbibition efficiency is the fastest at the early stages, though it initially tends to be stable. Throughout the process of unsteady imbibition, it typically becomes stable at 48 h. However, in the steady-state imbibition process, the stabilization time lags far behind and tends to be stable at 108 h. Additionally, the mesopore (1–10 ms) has a faster imbibition rate, which is the main contributor in the middle and late stages of imbibition. As well, imbibition occurs mainly in nanopores (0.01–0.1 ms) and micropores (0.1–1 ms), followed by mesopores (1–10 ms), and finally macropores (>10 ms). For permeability <0.1 × 10−3 μm2, micropores (0.1–1 ms) are the main contributors. For the permeability of 0.1–1 × 10−3 μm2, micropores (0.1–1 ms) and mesopores (1–10 ms) are the main contributors. And for permeability >1 × 10−3 μm2, the mesopores (1–10 ms) make up the majority of the contribution. In addition, Imbibition productivity is positively associated with permeability and differential pressure in both steady and unsteady imbibition. As differential pressure and permeability increase, imbibition occurs more effectively.

Shale Formation Damage during Fracturing Fluid Imbibition and Flowback Process Considering Adsorbed Methane

Hydraulic fracturing of shale gas reservoirs is characterized by large fracturing fluid consumption, long working cycle and low flowback efficiency. Huge amounts of fracturing fluid retained in shale reservoirs for a long time would definitely cause formation damage and reduce the gas production efficiency. In this work, a pressure decay method was conducted in order to measure the amount of fracturing fluid imbibition and sample permeability under the conditions of formation temperature, pressure and adsorbed methane in real time. Experimental results show that (1) the mass of imbibed fracturing fluid per unit mass of shale sample is 0.00021–0.00439 g/g considering the in-situ pressure, temperature and adsorbed methane. (2) The imbibition and flowback behavior of fracturing fluid are affected by the imbibition or flowback pressure difference, pore structure, pore surface properties, mechanical properties of shale and mineral contents. (3) 0.01 mD and 0.001 mD are the critical initial permeability of shales, which could be used to determine the relationship between the formation damage degree and the flowback pressure difference. This work is beneficial for a real experimental evaluation of shale formation damage induced by fracturing fluid.

Evaluation of fracturing fluid imbibition and water blocking behavior in unconventional reservoir

Imbibition is believed to be beneficial to the production. However, the load recovery is low, and water blocking can have a marked impact on the production This study aims to evaluate imbibition and water blocking behavior in tight reservoir, and reveal the impact of micro pore structure on imbibition and water blocking. Low-pressure nitrogen gas adsorption (LP-N2GA), high-pressure mercury injection (HPMI), rate-controlled mercury injection, nuclear magnetic resonance (NMR), imbibition experiments and centrifugal experiments were comprehensive used. Micro pore structural characteristics and the distribution of fracturing fluid in pores were examined. The fluid can enter the small mesopores first or the mesopores first. Imbibition recovery (IR) range is 35.82% to 94.17%, and average is 63.63%. After centrifugation, irreducible water saturation (Swir) range is 3.43% to 57.84%, with an average of 17.28%. Permeability damage rate range is 15.19% to 97.86%, with an average rate of 51.88%. Factors that affecting IR include average pore throat ratio (APTR), specific surface area (SSA), permeability, porosity, pore volume (PV), average throat radius (ATR) and average pore radius (APR). Factors affecting water blocking include permeability, APR, ATR, porosity, PV, APTR and SSA. Permeability has the maximum impact on fluid distribution and flow, followed by APTR, porosity, and APR.

Influencing Factors and Application of Spontaneous Imbibition of Fracturing Fluids in Tight Sandstone Gas Reservoir.

This work is based on high-precision fluid spontaneous imbibition experiments to quantitatively study the imbibition rate, imbibition capacity, and imbibition curve characteristics of fracturing fluids in tight sandstone reservoirs. The objective of the work is to explore the influence of tight sandstone physical characteristics, fracturing fluid composition, salinity, viscosity, surface tension on fracturing fluid imbibition, and further analyze its main controlling factors. To evaluate imbibition characteristics more deeply, the pore throat structure and micromorphology of tight sandstone before and after imbibition were described by mercury intrusion test and scanning electron microscope test, respectively. Furthermore, the mineral composition and dilatation characteristics of the tight sandstone samples were identified by XRD and a linear dilatometer, respectively. The results show that the drilled tight sandstone samples from the Shaximiao Formation reservoir have strong heterogeneity, high clay mineral content, more developed micro/nanopores, less developed fractures, and strong hydration expansion. Since the average pore throat radius of tight sandstone samples is between 0.1 and 0.2 μm, the imbibition driving force is strong. The imbibition rate is fast, and the imbibition basically reaches a steady state within 24 h, which makes the imbibition capacity basically greater than 50%. Based on the analysis of the main control factors of imbibition, the surface tension of the fluid properties has the greatest impact on the imbibition recovery factor. The result not only helps to understand the absorption mechanism of fracturing fluid in tight sandstone reservoirs and then evaluates the degree of interaction between fluid and tight sandstone but it is also crucial for the prediction of flowback rate.

Study on the Imbibition Damage Mechanisms of Fracturing Fluid for the Whole Fracturing Process in a Tight Sandstone Gas Reservoir

Tight sandstone gas is a significant unconventional natural gas resource, and has been exploited economically mostly through the application of hydraulic fracturing technology in recent decades. However, formation damage occurs when fracturing fluid percolates into the pores inside sandstones through imbibition driven by capillary pressure during fracturing operations. In this work, the formation damage resulting from the whole operation process composed of fracturing, well shut-in and flowback, and the degree of damage at different moments were investigated through core flow experiments and the low-field Nuclear Magnetic Resonance (NMR) technique. The results show that imbibition damage occurs starting from the contact surface between the formation and the fracturing fluid, which penetrates into an increasingly deep position with time down to a certain depth. The T2 spectra of NMR at different moments indicates that fracturing fluid initially enters the small pores, followed by the large pores due to the larger capillary pressure in the former. Thus, the sandstone cores with low permeability incur a higher degree of damage due to their stronger capability of retaining fracturing fluid compared to high-permeability cores. The front position of the fracturing fluid imbibition at different moments, along with the degree of damage, were characterized through the one-dimensional encoding processing of the NMR signal. These results underlie the effective strategy to relieve formation damage resulting from imbibition during hydraulic fracturing operations.

Numerical Simulation Study on Optimal Shut-In Time in Jimsar Shale Oil Reservoir

The volume fracturing technology along with horizontal well is the main technology to obtain commercial oil flow in shale reservoirs because of the low porosity and low permeability. Whether the fracturing fluid has the potential of shale matrix imbibition oil recovery after a large amount of slickwater injected into the reservoir is a research hotspot at present. Therefore, it is of great significance to study the law of imbibition and replacement during the shut-in time. Aiming at the Jimsar area, there are several steps in this study in order to explore the new law of fracturing fluid imbibition and oil recovery in shale reservoirs. Primarily, the distribution of pressure and saturation during fracturing time and shut-in time is accurately described by the numerical simulation method. Furthermore, the sensitivity analysis is carried out from two aspects of geological and fracture factors. Eventually, the evaluation of optimal shut-in time is taken by imbibition replacement balance. According to the numerical simulation results, the pressure diffuses rapidly among the matrix during the shut-in time in the hydrophilic reservoir. After 65 days of well shut-in, the whole reservoir tends to be at the same pressure and reaches the equilibrium of imbibition replacement. Contrarily, the pressure of the lipophilic reservoir diffuses slowly and only propagates in the secondary fracture or the matrix near the fractures. The fracture system remains a “high-pressure area” for a long time during shut-in. Additionally, the optimal shut-in time chart of different geological parameters and fracture parameters is drawn to optimize the shut-in time. This research work has a certain reference value for the optimization of shut-in time after fracturing in Jimsar and similar shale oil wells.

Experimental study of the fracture initiation through the synergy of spontaneous imbibition and hydration of residual fracturing fluids in shale gas reservoirs

Shale gas wells often experience shut-in. However, the positive and negative effects of shut-in are not yet clear. The success or failure of shut-in is focused on the effects of fracturing fluid and its function in the subsurface. The current studies on the hydration of shale and fracturing fluid and the imbibition of residual fracturing fluids have ignored the fact that hydration and imbibition of fracturing fluids can occur simultaneously and affect each other. With full consideration of the interaction between the spontaneous imbibition and hydration of fracturing fluid, this paper innovatively reveals the fracture initiation through the synergy of spontaneous imbibition and hydration of residual fracturing fluids in shale gas reservoirs and puts forward suggestions for improving the recovery of shale gas. The results show that the imbibition of shale can weaken the mechanical strength of shale and produce micro-fractures and defects in shale. The energy required to destroy the micro-fractures is reduced, which will promote the initiation and propagation of micro-fractures, change the spontaneous imbibition path, expand the volume of spontaneous imbibition, and carry out continuous micro-stimulation of shale gas reservoir. The fracturing fluid can dissolve soluble salts filled in the pores and fractures, resulting in more induced fractures along the direction of beddings and natural fractures. The induced fracture reduces the water saturation of the hydraulic fractures and natural fractures. The fluid in pores can disperse under the action of capillary force, which can further reduce the water saturation of the imbibition intrusion zone, thus greatly restoring the permeability of the shale gas reservoir.

An understanding of oil–water replacement mechanism based on interfacial tension gradient during the well shut-in

Spontaneous imbibition behavior of fracturing fluid retained in reservoirs is considered to be one of the important mechanisms of spontaneous oil–water displacement in tight reservoirs. However, the mechanism of imbibition displacement in oil-wet rocks remains unclear. Inspired by the principle of the Marangoni effect, a mathematical model of oil displacement driven by an interfacial tension gradient in an oil-wet capillary tube was established, and the effects of osmotic pressure and hydraulic mechanical dispersion were coupled in the model. The results show that the key component of this mechanism is the breakdown of the initial capillary equilibrium state due to the diffusion of solute, which changes the pressure distribution in the capillary and drives the water to drive oil out of the pores. This can explain the spontaneous imbibition of low-salinity fracturing fluid into the oil-wet tight sample and displace oil without any external force, despite its low permeability. In addition, the related factors were analyzed, including initial concentration, contact angle, solute type, osmotic behavior, and size of the capillary. The results show that for an oil wet reservoir with high salinity, the connate water interfacial tension gradient plays an important role in oil displacement, and the coupling effect of osmotic pressure and hydromechanical dispersion considerably improves recovery. This can provide new insight into the mechanism of spontaneous imbibition of fracturing fluid.

An analytical model for shut-in time optimization after hydraulic fracturing in shale oil reservoirs with imbibition experiments

Shut-in after hydraulic fracturing can make full use of fracturing fluid imbibition and improve well productivity. However, how to determine a scientific shut-in time is an important problem for reservoir engineers. Therefore, an efficient model was proposed in this paper to fill this gap and then applied in the shale oil reservoirs. An analytical model of pressure distribution and stimulation reservoir volume was first developed, which includes the process of fracturing fluid injection and well shut in. A good agreement was obtained between the calculated pressure data and field data. Afterward, the imbibition experiments of 15 core samples from shale oil reservoir were carried out and the imbibition equilibrium time was observed. Finally, we calculated the shut-in time by summation of the time of fracturing fluid volume stabilization (stimulation volume stabilization) and imbibition equilibrium time. Results show that pressure diffuses during fracturing fluid injection and the pressure balance during well shut-in both impact the time of fracturing fluid volume stabilization (stimulation volume stabilization). Furthermore, a higher permeability can increase fluid flow capacity and accelerate the time of fracturing fluid volume stabilization. A scientific shut-in time should include pressure balance time and fracturing fluid imbibition equilibrium time. This work can provide a strong basis for optimization the shut-in time and useful insights into fracturing operation in shale oil reservoirs. • A model to optimize the shut-in time is proposed considering the process of fracturing fluid injection and well shut in. • Fracturing fluid injection model is established to analyze the pressure distribution considering two-dimensional leak-off. • The shut-in time can be reasonably evaluated by summation of swept volume equilibrium time and imbibition equilibrium time. • For this specific block, the optimized shut-in time is obtained with the range from 63 to 75 days using this proposed method.

Experimental study of spontaneous imbibition and CO2 huff and puff in shale oil reservoirs with NMR

The shale oil in the Jimsar sag, Junggar Basin, NW China is developed by horizontal wells and volume fracturing, and has the characteristics of a high initial production rate followed by a rapid decline and a low oil recovery factor. Therefore, it is necessary to find effective methods for enhancing shale oil recovery rates. The shale formations in the Jimsar sag, Junggar Basin are classified into three different types: types I, Ⅱ and Ⅲ. Fracturing fluid imbibition, surfactant imbibition and CO2 huff and puff experiments were conducted to evaluate the EOR potential of different types of shale formations. The oil distribution inside the shale core samples with time before, during and after the experiments is monitored using low-field NMR. The experimental results show that the CO2 huff and puff method had the highest ultimate oil recovery rate, followed by the surfactant imbibition method; the fracturing liquid imbibition method preformed without the addition of a surfactant had the lowest oil recovery rate. Surfactants improved the oil recovery of spontaneous imbibition by approximately 18% more in the type Ⅱ and Ⅲ shale formations compared to that of the fracturing liquid imbibition method. Field applications also demonstrated that adding a surfactant into the fracturing liquid significantly improved the oil production in type Ⅱ and Ⅲ oil formations relative to the common slick water fracturing liquid without an added surfactant.

Evaluation of Fracturing Fluid Imbibition and Water Blocking Behavior in Unconventional Reservoir

Evaluation of Fracturing Fluid Imbibition and Water Blocking Behavior in Unconventional Reservoir