Ultra-low Permeability Research Articles

Study of thermally-induced enhancement in nanopores, microcracks, porosity and permeability of rocks from different ultra-low permeability reservoirs

Improving permeability is the crucial mechanism for further enhancing oil and gas recovery of ultra-low permeability reservoirs. To investigate the temperature sensitivity and stress sensitivity of permeability under an actual reservoir condition, heating treatment and real-time measurement of pulse-decay gas permeability (PDP) of cores collected from three different ultra-low permeability reservoirs were conducted in our self-developed high-temperature pseudo-triaxial core holder. To clarify the intrinsic relationship between the microstructure development and porosity-permeability enhancement, stereo light microscope (SLM) observation, computerized tomography (CT) scan and nuclear magnetic resonance (NMR) test were used to quantitatively characterize the dynamic variations in thermal cracks, nanopores and porosity. Based on the lithology analysis and thermal analysis, the primary mechanisms of nanopore evolution and thermal cracking for different ultra-low permeability rocks were analyzed in detail. The experimental results show that the permeability of Chang 8 ultra-low permeability sandstone and Longmaxi shale cores only increased by about one order of magnitude above the threshold temperature of 500 °C, while the permeability of Jimsar shale cores increased significantly by two orders of magnitude above the threshold temperature of 300 °C. Above their threshold temperatures, the permeability showed stronger stress sensitivity. The SLM observation and CT scan revealed that thermal cracks propagated rapidly above the threshold temperatures, which resulted in a substantial increase in temperature sensitivity and stress sensitivity of permeability. NMR test shows that the porosity of ultra-low permeability cores performed an increasing trend as the temperature rose. However, the nanopore structure in Chang 8 ultra-low permeability sandstone monotonously developed toward larger micron-sized pores, while the Longmaxi shale and Jimsar shale eventually re-evolved into smaller nanopores. We found that kerogen pyrolysis was the most critical mechanism leading to the microstructure, porosity and permeability enhancement in organic-rich shale. For organic-poor ultra-low permeability sandstone and shale, the quartz phase transition from α to β was considered as the key reaction for the thermal cracking and permeability improvement. By comparison, heating treatment has a higher thermal stimulation potential in shale cores from medium-to-low maturity shale oil reservoirs.

Analysis of precursor information for coal and gas outbursts induced by roadway tunneling: A simulation test study for the whole process

The diversity of precursor information is significant for providing accurate early warnings of outbursts. However, the existing research mainly focuses on noncontact indicators, which cannot fully and accurately reflect the outburst risk. To capture the precursor information of the key contact indicators, a simulation test for the whole process of outbursts was carried out. In the test, the newly developed similar materials of gassy coal and ultralow permeability rock and a simulation system were used to simulate the occurrence environment and disturbance conditions of the coal mass. The results show that the outburst phenomenon and gas concentration evolution are similar to the real phenomenon on site, which proved the accuracy of the test results. The abnormal characteristics of a number of physical aspects before outburst were detected: an obvious relief stress zone appeared in the in situ stress curve for coal seam; the gas concentration in the roadway exceeded the safety standard (0.3%) and continued to increase to 3%; the pressure of coal seam and roadway surrounding rock changed from stable to declining, with a total amplitude of 10 kPa; the temperature in coal seam and roadway changed from steady to fluctuating up and down, with fluctuations reaching 3.4 °C and 4.7 °C, respectively. According to the abnormal occurrence time and identification level, the sensitivity priorities of the above information were temperature, gas concentration, in situ stress, and gas pressure. In addition, the moving average, deviation rate, and dispersion rate of the gas concentration, gas pressure, and temperature versus time curve had more advantages than the signal itself. This study provides guidance for the realization of accurate and effective real-time warnings.

Quantitative characterization of pore size and structural features in ultra-low permeability reservoirs based on X-ray computed tomography

The pore structure of ultra-low permeability sandstone (0.1 mD < K < 1 mD) is complex and has high heterogeneity, which leads to great challenges in reservoir characterization and effective evaluation. To study the effect of the heterogeneity of ultra-low permeability sandstone on permeability, a digital core model was established using X-ray computer tomography (CT) technology. Then a three-dimensional pore network model (PNM) in core samples was created using the “maximum ball method” algorithm. Finally, the geometric topology features of ultra-low permeability reservoirs were quantitatively characterized. According to the physical properties and test results of samples, the porosity distribution of targeted area ranged between 5.92% and 10.08%, and the permeability distribution range was 0.145 mD–0.75 mD, which was typical for an ultra-low permeability reservoir. The distribution of pore throat radii ranged from 0.27 μm to 1.29 μm, the shape factor was 0.04–0.06, the disconnected pores of the four samples made up between 16.89% and 58.71% of all pores, and the fractal dimension fluctuated between 1.05 and 1.5. Plane porosity also showed certain fractal characteristics. Correlation analysis showed that the disconnected isolated pores and the micron-scale pore throat radii of the reservoir sandstone were the main factors resulting in ultra-low permeability. The above-mentioned quantitative characterization parameters can be subsequently used to conduct microscopic seepage simulation studies of such reservoirs. • Build digital core based on CT scanning system. • Extract the core pore network model, and render the pore pressure, throat flowrate, and electricity conductivity. • A digital core pore structure evaluation method for Utral-low permeability sandstones was developed.

Productivity model of shale gas fractured horizontal well considering complex fracture morphology

Shale gas reservoir is characterized by complex pore structure, ultra-low permeability and a large number of natural fractures. Therefore, it is necessary to apply horizontal well drilling with hydraulic fracturing to stimulate the shale gas reservoirs by forming complex fractures network composed of main fractures (i.e., hydraulic fractures) and branch fractures (i.e., activated natural fractures). During shale gas fracturing, hydraulic fractures will initiate simultaneously, deflect under the stress interference with each other, activate adjacent natural fractures and connect with them. These complex behaviors of fractures propagation would greatly complicate the production prediction after shale gas fracturing. Currently, the majority of the production prediction models neglect the complexity of fractures network. Therefore, based on Fick's diffusion law, Langmuir isothermal adsorption equation and dual-medium seepage theory, this paper derived a productivity prediction model by considering complexity of fractures network, stress-sensitive effect and ad-desorption by using point source method, Duhamel principle and Laplace transform, and solved the model with perturbation theory, discrete superposition and Stehfest numerical inversion. Then, the production prediction model was verified by a field example analysis, and the influence of the morphology of main fractures and branch fractures on productivity is explored. It indicates that the main fracture shape has a great influence on the production, and the trapezoidal mode is closer to the production practice. The large deflection of main fractures, the high conductivity and large approaching angle of branch fractures are beneficial to improving the production of fractured shale gas horizontal wells.

Study on asynchronous injection and production of horizontal Wells in ultra-low permeability thin layer low abundance oil field

The ultra-low permeability, thin layer and low abundance GLN area is developed by waterinjection with horizontal and straight combined well pattern. With the extension of development time, the water appears in multiple sections and directions in horizontal Wells, and the well area gradually enters the stage of medium and high water cut, which shows the characteristics of rising when water is injected, falling when liquid is stopped, and limiting the profile control pressure in multiple rounds of Wells. Therefore, developing the “note when mining, mining without note” asynchronous injection-production adjustment of horizontal well technology, make full use of the artificial fracture of high permeability channel and matrix suction effect between low permeable formation permeability, increase the crack near the matrix suction swept volume, to achieve the purpose of the horizontal well steady liquid water control, up to the level of the special low permeability thin layer low abundance wellblock improve recovery factor. Through the mechanism of injection-production, the use of pore throat boundaries, the respect such as injection-production timing and parameter optimization research, combined with the reservoir numerical simulation and theoretical formula, conduct asynchronous injection-production field practice, improved the development effect of horizontal well, and have achieved good economic benefits, for the next class of reservoir level wellblock middle and high water cut stage to explore a new way of governance.

Petrophysical/geophysical approaches to identify ISIP variability in the Eagle Ford shale

Understanding geomechanical properties is essential for an optimal completion strategy that ensures commercial productivity in shale reservoirs with ultra-low permeability. This study provides details to identify the variability of Instantaneous Shut-In Pressure (ISIP) in multidisciplinary approaches using petrophysical and geophysical data. ISIP is one of the input data required for well completion design. Operators commonly ignore the variability of ISIP and use uniform geomechanical assumptions due to cost and time constraints. In the case study, the variability of ISIP was observed up to 30 % in a single horizontal well, which could lower the efficiency of hydraulic fracturing with uniform geomechanical assumptions along a horizontal well trajectory. We propose practical approaches to identify the variability of ISIP from a case study in the Eagle Ford shale. MWD (Measurement While Drilling) Gamma Ray log, which is commonly acquired for a geosteering purpose, was utilized to prove its correlation with actual ISIP data gained at frac-stages in horizontal production wells. Correlation between ISIP and microseismic data was analyzed to identify the integrated relationship among the variability of Gamma Ray, ISIP, and hydraulically-induced fracture. In addition, practical approaches using a series of seismic inversion and attribute data were proposed to help identify geological variabilities affecting ISIP. This study was designed to provide operators hands-on approaches to capturing the variability of ISIP under limited data accessibility. We suggest multifunctional ways using the basic datasets commonly available at field sites. It can be applied to mitigate risks concerning well planning, drilling, and completion design in where operators face frequent challenges from geomechanical heterogeneity in global shale plays.

Practice and cognition of effective water-flooding development mode in Gaotaizi block of ultra-low permeability reservoir

During nearly 25 years of water injection development in Gaotaizi reservoir of LHP oilfield, due to poor reservoir physical properties, poor adaptability of well pattern and difficulty in establishing effective displacement between oil and water Wells, linear water injection, infill adjustment and refracturing tests have been carried out successively. Although certain effects have been seen, the effects are short and unsatisfactory. In this paper, the microscopic pore structure, sensitivity and seepage characteristics of ultra-low permeability high platform reservoir are studied through core laboratory experiments. New technology of nonlinear test and low permeable physical simulation experiment, the research on the rules of the nonlinear characteristics of the reservoir fluid and the characteristics of movable oil through research has been clear about the dragon bubble oilfield high effective displacement distance platform layer, and the new fracturing technology and the development of the technology to adjust the organic combination, the displacement between well and well past into displacement between Wells and joint network, explore the ultra-low permeability reservoir to improve the single well production, new ways to improve the development effect, with the types of low permeability oilfield development effectively.

Characteristics of heterogeneous diagenesis and modification to physical properties of Upper Paleozoic tight gas reservoir in eastern Ordos Basin

To correctly evaluate reservoir quality and determine promising tight gas zones, the characteristics of heterogeneous diagenesis and modifications to physical properties in the Upper Paleozoic tight gas reservoir in the eastern Ordos Basin (UPTGREOB) were assessed by comprehensively analyzing lithology, petrophysics, and organic geochemistry data. It was found that the types of sandstones in UPTGREOB mainly include (feldspathic) detritus sandstones and detritus feldspathic sandstone in low–ultralow porosity and permeability, with complex pore structure. Sandstone pores can be divided into two types: primary (primary intergranular and residual primary intergranular pores), secondary (intercrystalline, dissolved intragranular, dissolved intergranular, and dissolved cementing pores and microfractures). The main types of diagenesis are compaction, cementation, dissolution, and metasomatic alteration. Shiqianfeng Formation and Upper Shihezi Formation belong to period B of the syndiagenesis stage and period A1 and A2 of the mesodiagenesis stage; Lower Shihezi Formation and Shanxi Formation are entirely in the mesodiagenesis stage; Taiyuan Formation can be regarded to be in periods A2 and B of the mesodiagenesis stage and period A of the telodiagenesis stage. The original porosity of UPTGREOB was approximately 34%. Compaction was the primary destructive diagenesis rather than cementation, while dissolution was found to be the primary constructive diagenesis. The heterogeneous diagenesis played different roles in the UPTGREOB: in syndiagenesis B, the UPTGREOB began to densify under the compaction and early cementation; in mesodiagenesis A, dissolution and metasomatic alteration produced massive secondary dissolved pores and intercrystalline pores, improving the porosity and permeability; in mesodiagenesis B, dissolved pores were filled by new cements, resulting in decreased porosity and permeability; in telodiagenesis A, intensified compaction and cementation made the UPTGREOB retain extra low porosity and permeability. In general, the reservoirs of Shiqianfeng Formation and Upper/Lower Shihezi Formation in the mesodiagenesis stage A have preferable physical properties for tight gas accumulation.

Research and application of large-scale fracturing imitating horizontal well technology in vertical well

Hailaer Basin is rich in geological reserves, but the proportion of undeveloped reserves is high, accounting for 30% of the proved reserves. In order to improve the production degree of reserves and single well production, and realize the purpose of high and stable production of the oilfield. Taking the ultra-low permeability reservoir of oilfield B in Hailaer Basin as an example, this paper puts forward the large-scale fracturing of vertical wells and water injection development technology of imitating horizontal wells. By forming directional ultra long fracturing fractures in the oil layer, this technology can effectively increase the reservoir conductivity, increase the oil well drainage area and water well control area, reduce the well pattern density and improve the production of single well. The research shows that the undeveloped reserves in Hailaer oilfield have the characteristics of low thickness, low permeability and low reservoir quality index. There are 55 large-scale mold fracturing wells in Hailaer oilfield, with an initial oil increase of 2.2 times. The sand amount of large-scale fracturing is 2.5 times that of ordinary fracturing, and the fluid amount and sand intensity are 4.5 times that of conventional fracturing. The vertical well large-scale fracturing imitating horizontal well technology is adopted in Oilfield B. The designed vertical well fracturing fracture is 600m long and 120m wide, and the production effect is good after fracturing. The research results are of great significance to the high and stable production of undeveloped reserves block in Hailaer oilfield and other similar oilfields.

Field test practice and understanding of effective utilization technology for dense and refractory reservoir in block A

In view of the ultra-low permeability reservoirs in Block A of Hailar Oilfield, it is difficult to establish an effective driving system between oil and water wells due to the influence of many oil-bearing strata, poor reservoir physical properties and large vertical span of oil layers. With the deepening of development, it is more difficult to use reservoirs. In order to realize the effective utilization of low permeability reservoirs in Beier Oilfield, the successful experiences of tight oil and Hailar large-scale fracturing in peripheral oilfields are summarized, and the effective utilization technology of large-scale fracturing supplementary energy development is explored. The large-scale fracturing evaluation of ultra-low permeability reservoirs and the optimization of potential well areas are carried out, so as to fully tap the

Research on the Technology of Profile Control and Flooding in JY Oilfield to Stabilize Production

JY oilfield is mainly an ultra-low permeability reservoir with low reservoir permeability. As the permeability decreases, the starting pressure gradient rises sharply, and the establishment of an effective displacement pressure system is slow. The main reservoir has entered the medium water-cut development stage. On the plane, water flooding intrudes along the dominant channels such as fractures and high-permeability strips, resulting in plane contradictions; on the profile, the production degree decreases, and the injection-production profile is unbalanced. In this paper, through the study of reservoir physical properties, water flooding and control and flooding mechanism and the implementation of fine profile control and flooding on a large scale, the well selection conditions of different reservoirs are obtained, and differentiated countermeasures are formulated. Four optimizations of injection mode to ensure continuous improvement of injection effect and economic benefits.

Evaluation and Potential Analysis of Fracture Network Fracturing in Oil Production X Plant

The oilfields developed by our factory are mainly ultra-low permeability reservoirs, and the problems of non-injection and non-production are prominent. When conventional oil well fracturing is used, there are problems such as insufficient water injection energy, low oil increase rate after fracturing, and short validity period, and it is difficult to achieve benefit management. To this end, since 2013, while controlling the under-injected wells, the application of fracture network fracturing has been gradually increased, and a total of 116 wells have been fractured. The contribution reached 4.13%, and the annual mitigation comprehensive decrease contribution was 3.62%.

Research on Ultra-low Permeability Oil Development System Based on Oilfield Fracturing Water Displacement System

In order to realize the effective water injection development of oilfield reservoirs, large-scale fracturing technology was introduced. The simulation confirmed that the large-scale fracturing well has the characteristics of high initial production, fast water injection effect, and rapid water cut rise after the effect., the research results show that compared with elastic development, water injection development can solve the problem of rapid formation energy depletion, and at the same time increase the reservoir producing area and displacement time. The final water content of water injection huff and puff is about 25% lower than that of conventional water injection, and advanced water injection can increase the production of conventional elastic development by about 30% in the early stage. It can be seen that these two new development methods are conducive to suppressing water flooding and improving oil recovery.

Prediction Method of Well Pattern Infilling Effect in Ultra-low Permeability Reservoir of X Oilfield

In this paper, firstly, the introduction of well pattern infill in ultra-low permeability reservoir is analyzed in detail, and then combined with the change law of well pattern infill in ultra-low permeability reservoir and the prediction process of well pattern infill in ultra-low permeability reservoir, the prediction results of well pattern infill in ultra-low permeability reservoir are summarized.

ON CO2 SEQUESTRATION: CHANGES IN CO2 ENTRY PRESSURE AND ADSORPTION CAPACITY BY HEAT

Geological sequestration of CO2 requires a deep permeable geological formation where captured CO2 can be stored and an overlying impermeable caprock that prevents buoyant CO2 from leaking upward to the surface. Shale formations are good seals due to their abundancy and typically ultralow permeability. Shale's excellent sealing ability makes it a good caprock formation. The correct evaluation of the CO2 sequestration ability of shale caprocks, also referred to as sealing capacity, must be conducted under high-pressure and high-temperature conditions representative of in situ conditions. The CO2 sequestration quality of shale caprocks, sealing capacity, is usually evaluated through measurements of CO2 capillary entry pressure into shale caprocks. In this work, CO2 capillary entry pressure in different shales under a wide range of temperatures (298-428 K) is measured using an incremental pressure transmission methodology. The impact of temperature on the physicochemical and petrophysical properties of shale is addressed, and their indirect effect on CO2 capillary entry pressure is analyzed. Furthermore, the influence of temperature on interfacial tension between CO2 and shale's pore fluid and contact angle is examined. Also, the effect of temperature on CO2 sorption on clay sites is analyzed. The experimental outcome exhibited that capillary entry pressure increases steadily and appreciably for shales (A and B) up to a certain temperature (around 358.15 K), after which the behavior of capillary entry pressure of CO2 for both shales changes markedly. For shale (A), the increase in measured capillary entry pressure for temperatures above 358.15 K slows down significantly, ranging between 841 and 851 psi compared to its measured value of 835 psi at 358.15 K. As for shale (B), the reaction is completely different, where measured capillary entry pressures of CO2 for temperatures above 358.15 K decreased noticeably as measured capillary entry pressures dropped from 534 psi at 358.15 K to 473 psi at 428.15 K. Results show that temperature has a profound impact on CO2 capillary entry pressure when interacting with shales through the alteration of shale's physicochemical and petrophysical properties. Data suggests that pore throat size could be altered by heat through a phenomenon called pore dilation. It was also clearly shown that higher temperature causes higher interfacial tension, which indeed causes higher capillary entry pressures when CO2 interacts with shale. Moreover, results indicate that high temperature could energize active swelling clays and invoke a transition of inactive clays to active swelling clays. High temperature causes clay swelling and may produce hydrational and expansive stresses in shale, especially when confined, which could induce fissures and microfractures. The creation of fissures and microfractures could enhance shale's average pore radii and permeability, thus reducing the capillary entry pressure. In addition, results suggest that the adsorption capacity of CO2 on clay sites decreases with increasing temperature and that the presence of smectite clay greatly enhances the swelling potential of shale upon exposure to CO2.

Submergence depth modeling of oil well reservoirs and applications

In oilfield production, it is important to be able to acquire the reservoir status of oil wells in real time, especially for low or ultra-low permeability oil wells. In this paper, based on the reservoir percolation characteristics of the oil layer and combined with the oil well permeability, liquid pressure and oil well pressure formulas, the non-homogeneous linear differential equation for oil well pressure is derived, based on which a submergence depth model of oil well reservoirs is established. The parameter merging is applied to reduce the parameter dimension of the submergence depth model; this approach substantially reduces the parameter dimension and application complexity and effectively improves the model application range. The model not only conforms to the reservoir percolation law of the oil layer but also applies to the balance laws of other substances with potential energy balancing ability. The application methods studied (namely, the extraction of the greatest common divisor, the weighted dichotomy and least-squares curve fitting) successively reduce the calculation error and expand the application scope. The least-squares curve fitting method causes the submergence depth error to reach the minimum of the 2-norm, and the number of iterations can be accurately assessed by the convergence speed of halving the numerical calculation error in every iteration. This method is suitable not only for the zero submergence depth case in the initial state but also for non-zero submergence depth cases. The experimental results show that the proposed submergence depth model for oil well reservoirs accurately reflects the change laws of submergence depth and time. Combined with the proposed application methods, the corresponding submergence depth can be obtained at any time point. The model and application methods provide strong support for formulating scientific oil production plans and implementing reasonable production methods for oil wells.

Huff-n-puff gas injection or gas flooding in tight oil reservoirs?

Because of the ultra-low permeability of tight formations, gas injection is believed to be an effective method to enhance oil recovery (EOR). However, it has two modes: huff-n-puff injection (HNP) and continuous flooding. Which mode is more efficient? This study aims to answer this question through an experimental and simulation study. In the experimental study, tight core samples of permeabilities of 0.16 mD, 0.045 mD, 0.001 mD, and 0.00029 mD were used to compare the oil recovery from huff-n-puff gas injection with flooding. The gas used was nitrogen. Both flooding and huff-n-puff experiments were conducted on the same core in each core sample. Experimental results show that gas flooding had higher recovery in the cores than HNP with the permeability above 0.001 mD, but lower when the permeability was lower 0.00029 mD. To further analyze the gas injection performance, a numerical simulation was performed. The conducted experiments were used to validate the numerical models by historically matching the experimental data. Based on the validated simulation models, HNP is optimized. Simulation results show that optimized HNP is superior to gas flooding when the permeability is lower than 0.001 mD core. Finally, based on published data, a filed-scale model consisting of two well-propped fractures was established to compare the performance of the two gas injection modes. Filed-scale simulation results show that gas flooding can achieve a higher recovery when the matrix permeability is above 0.01 mD, while HNP injection can yield more oil when the matrix permeability is lower than 0.001 mD. However, from an economic point of view, the HNP performance is more justified than the corresponding flooding when the permeability is higher than 0.01 mD, and it is difficult to be economic for both HNP and flooding when the permeability is lower than 0.001 mD. • Two injection modes are compared by experiments and numerical simulation. • Gas huff-n-puff can yield more oil in a low-k reservoir (<0.001 mD). • Gas flooding performs better in a high-k reservoir (e.g., >0.01 mD). • Neither HNP nor flooding is economical in a reservoir <0.001 mD. • HNP shows better economic superiority in a reservoir of <0.01 mD.

Injectivity and Plugging Characteristics of Co2-Responsive Gel Particles for Enhanced Oil Recovery in Fractured Ultra-Low Permeability Reservoirs

Injectivity and Plugging Characteristics of Co2-Responsive Gel Particles for Enhanced Oil Recovery in Fractured Ultra-Low Permeability Reservoirs

Eor Mechanism of Fracture Oil Displacement Agent for Ultra-Low Permeability Reservoir

Eor Mechanism of Fracture Oil Displacement Agent for Ultra-Low Permeability Reservoir

Nanoemulsions stabilized by anionic and non-ionic surfactants for enhanced oil recovery in ultra-low permeability reservoirs: Performance evaluation and mechanism study

Nanoemulsions stabilized by surfactant have a high application potential in enhancing oil recovery in ultra-low permeability reservoirs. In this work, a new nanoemulsion flooding system were prepared by microemulsion dilution method using D-limonene, non-ionic surfactant fatty alcohol polyoxyethylene ether (AEO), anionic surfactant Sodium dodecyl sulfate (SDS), n-amyl alcohol and NaCl solution. The displacement performances of nanoemulsions were evaluated by spontaneous imbibition and displacement experiments, and the enhanced oil recovery (EOR) mechanisms were studied by Zetasizer Nano Z instrument, interfacial tensiometer, and contact angle meter. The results showed that the nanoemulsion system with optimal mass fraction (0.30 wt%) could get an additional oil recovery of 20.32% and reduce the injection pressure by 10.62%. Besides, the spontaneous imbibition recovery could reach 51.39%, which was 10.04% higher than that of SDS+AEO. The greater EOR effects of the nanoemulsion system can attribute to three perspectives. Firstly, nanoemulsions with particle sizes ranging from 80 nm to 100 nm make it possible to enter small pore throats of ultra-low permeability reservoirs to start-up crude oil without increasing insert pressure. Secondly, the nanoemulsion system exhibits ultra-low IFT (less than 1 ×10−2mN/m) and can change the core surface from hydrophobic to hydrophilic, which could roll up the crude oil and separate them from the rock surface. Finally, the dissolving effect of the oil phase can disperse crude oil to enhance the solubilization effect of the micelles and extract more crude oil. The findings of this study can help for better understanding of the application of nanoemulsions to enhance oil recovery in ultra-low permeability reservoirs.