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Characteristics and Influencing Factors for Forced Imbibition in Tight Sandstone based on Low-field Nuclear Magnetic Resonance Measurements Guoqing XU, Yang Shi, Yun Jiang, Chen Jia, Ying Gao, Xiuling Han, and Xinhang Zeng Energy Fuels, Just Accepted Manuscript • DOI: 10.1021/acs.energyfuels.8b01608 • Publication Date (Web): 06 Jul 2018 Downloaded from http://pubs.acs.org on July 7, 2018
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Characteristics and Influencing Factors for Forced Imbibition in Tight Sandstone based on Low-field Nuclear Magnetic Resonance Measurements
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Guoqing Xu 1,*, Yang Shi 1,*, Yun Jiang 1,*, Chen Jia 1, Ying Gao 1, Xiuling Han 1 and XinHang Zeng 2
1 2
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1
Research Institute of Petroleum Exploration & Development, PetroChina, Beijing 100083, China;
[email protected] (G.X.);
[email protected]; (Y.S.);
[email protected] (Y.J.);
[email protected] (C.J.); gaoying69@ petrochina.com.cn (Y.G.); hanxiuling@ petrochina.com.cn (X.H.); 2 Key Laboratory of Petroleum Engineering of the Ministry of Education, China University of Petroleum, Beijing 102249, China;
[email protected] (H.Z.) * Correspondence:
[email protected];
[email protected] (Y.J.);
[email protected] Tel.: +86010-8359-5982
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Abstract: Spontaneous imbibition (SI) generally occurs under a forced pressure (the difference between
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hydraulic fluid pressure and original pore pressure) during shut-in time. However, the experimental study
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of SI is commonly performed at atmospheric pressure and the effect of the forced pressure is often neglected.
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How the forced pressure influencing the SI behaviors under different factors is still not clear. In this paper,
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low-field nuclear magnetic resonance (LF-NMR) was adopted to study the mechanism of SI in the tight
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sandstone rock sample under forced pressure (FI). The effects of boundary conditions, initial water
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saturation, bedding plane (BP) direction and fluid salinity on oil recovery were also systematically
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investigated. Results showed that the ultimate oil recovery (UOR) varied from different boundary
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conditions. An inverse correlation also exists between the water uptake and salinity. As osmotic pressure
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exist, more water was imbibed into core samples with the decrease of KCL salinity. The rock sample with
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perpendicular BP direction has higher UOR than that with parallel BP direction. Moreover, the initial water
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saturation has a great effect on UOR. Higher water saturation would result in a lower UOR. This study aims
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to provide some insights in understanding the mechanism of FI in UOR enhancement.
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Keywords: tight reservoir; nuclear magnetic resonance; ultimate oil recovery; influencing factors;
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dimensionless time model 1
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1. Introduction
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Tight oil is a significant unconventional resource that distributed all around the world. Multistage
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hydraulic fracturing has been proved to be an effective way to exploit tight reservoirs [1,2]. Due to the
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existence of abundant nano-micro pores, tight oil reservoir is characterized with low permeability and
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porosity which will result in the low flow back efficiency of fracturing fluid. Hence, a large percentage of
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fluid is retained in the formation. The increased water saturation in the vicinity of the fracture would cause a
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fast decline of production as well as low oil recovery [3-5]. However, some water/oil production data of the
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early time indicates that wells with low flow back efficiency usually have a high early time oil production [6-
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7]. Some studies have proved that SI (mainly counter-current imbibition) of fracturing fluid into shale or
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tight formation is one of the most important factors that contribute to the oil recovery enhancement [9-13].
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Therefore, this phenomenon has been considered as a new technique to improve the development of
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unconventional oilfields. So wells are shut down for days to promote oil recovery enhanced by imbibition
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after hydraulic fracturing.
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Capillary pressure is regarded as the main driving force for water imbibition and oil displacement [14-
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17]. Published research studies have contributed to understanding the complex interactions between
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capillary pressure and factors that dominate the SI process, such as permeability, formation heterogeneity,
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clay mineral, fluids properties (viscosity, salinity and surfactant) [18-21]. To enhance UOR, some surfactants
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have been used to achieve wettability alteration(from oil-wet to water-wet) or to increase interfacial tension,
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thus the capillary force can be increased to promote water imbibition. However, this may also increase the
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difficulty of the flow back and the flow back efficiency can be further decreased [13, 22-24]. On the other
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hand, SI is also beneficial to increase the permeability as micro-fractures can be created during the imbibition
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process [25, 26]. In addition, the imbibition experiment is often carried out by using an Amott imbibition cell
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or a precision balance which is the most common method to measure the volume of the imbibed fluids.
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However, the physical limitations of these two methods would increase the difficulty in core internal
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observations of the phase distribution [14-17, 25, 26]. LF-NMR, an effective auxiliary tool in pore structure
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identification, has been widely used in oil and gas engineering field to provide more information about
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phase distribution, wettability, and phase saturations. Furthermore, LF-NMR has been proved to be a more
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accurate method to evaluate the amount of the attracted water as a series experiments have been performed
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to investigate UOR study affected by SI phenomenon [27-29, 40].
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In addition to experimental research, several models are presented to simulate the SI process. Mattax et
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al. [30] firstly proposed the dimensionless time(tD) model, then much of the research is modified based on his
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work to improve the applicability of the model [31-35]. The data used for these models mainly comes from
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laboratory experiments. Core plugs used in the experiment are generally much smaller than matrix blocks in
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oil-producing fractured reservoirs where the block is of different sizes and shapes after hydraulic fracturing.
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Thereby, the aforementioned models cannot be scaled up to the field application and the optimization for
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shut-in time cannot be determined correspondingly.
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Current studies on SI in tightsand formation mainly focus on the exploration of the relationship
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between the soaking time and the imbibition rate [36-38]. However, saturation variation and its distribution
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in different pore size cannot be observed by using this method. Besides, these experiments are carried out at
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atmospheric pressure which is inconsistent with real reservoir situation where the block is under a forced
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fluid pressure. Although we have investigated the effect of forced pressure on SI in our latest research [27],
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the study of influencing factors for SI under forced pressure is still deficient. In particular no study, to our
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knowledge, has considered the effect of initial water saturation on SI in tight oil reservoir. Only Li et al. [43]
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has studied the effect of initial water saturation on SI in gas reservoirs.
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In the light of this information, the objective of this study is to characterize the law and the mechanism 3
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of UOR enhancement during spontaneous imbibition under different influencing factors. First, the oil
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saturation distribution from the laboratory test was presented. Thereafter, factors that affect the UOR under
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the forced pressure, such as boundary condition, fluid salinity, bedding plane direction and initial water
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saturation, are studied in detail. The results from this paper will help to provide some insights on oil
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recovery improvement. And some special recognition to UOR enhanced by SI has been quantitively
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renewed.
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2. Materials and Methods
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2.1. Core samples
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In this study, tight sandstone core samples were taken from Upper Triassic Yanchang formation in
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Ordos Basin, China. The porosities of the target rock samples were determined by using a helium
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porosimeter. Due to the ultra-low permeability, the pulse-delay technique was used to measure the
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permeability. Before the measurements, core samples need to be treated as follows:
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1. The core samples were cleaned by using toluene and methanol for 30 days to remove the residual oil.
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2. All samples were dried at 105 °C for 48 hours until the weight stays constant.
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3. The core samples were saturated with oil at confining pressure of 20 MPa for 5 days.
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The measured values of porosity and permeability are in the same order of magnitude which supposed to
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be the key factor to influence the FI process. Therefore, the petrophysical properties of the core samples are
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similar. The detailed information of the rock samples is listed in Table 1.
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The core samples were classified into five sets. Core samples in the first set (A12) were used for FI
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measurements to make comparisons with other study group. Based on the results of FI in first set, the
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influencing factors, such as boundary condition (A21, A22, A23), initial water saturation (A24, A25, A26),
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bedding plane direction (A27, A28) and fluid salinity (A27, A28), were further investigated to reveal their 4
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roles in FI. To investigate the effect of initial water, the following experimental procedure was used to make initial water saturation to varying degrees.
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1. The core samples were saturated with DT water at confining pressure of 20 MPa for 5 days.
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2. Standing in D Twater at atmospheric pressure for 48 h.
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3. The core samples were displaced at 0.5 MPa by displacement system at constant pressure model for 0-96 h. 4. T2 distribution of saturated core sample was measured at selected time point to calculated the initial water saturation by using Eq. 1. 5. The FI experiment is carried out in the same manner as Section 2.3 shows:
( ∑ Ai − ∑ A j ) × 0.125 × 1.11 × 100% S wi = 1 − 0.8 × ( m1 − m0 ) Where S wi is initial water saturation, %;
∑ Ai
and
∑ Aj
(1)
are the cumulative amplitude of T2 before and
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after the oil flooding, a.u.; mi and m0 are the mass of the sample before and after saturation, g; the value of
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1.11 and 0.8 are the density of DT water and No.3 Jet kerosene; g/cm3.
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X-ray diffraction was used to obtain the mineral component in the core samples (Fig. 1 and Table 2). The
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quartz and feldspar account for the majority mineral content in the target formation with values around
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26.8-33.9 wt% and 39.37-53.3 wt%, respectively. The clay minerals mainly consist of Illite-smectite mixed-
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layers and chlorite with the mean values of 25-48 wt % and 42-60 wt %, respectively.
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2.2. Fluid and Sealing Material Properties
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Oil used in oil-saturation process (No.3 Jet kerosene) with a purity of 99% was purchased from Beijing
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Unicorn Co. Deuterium (DT) water (signal cannot be detected by LF-NMR) used in FI measurements with a 5
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purity of 99.9% was purchased from Cambridge Isotope Laboratories. The physicochemical properties of the
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fluids used for imbibition experiments were listed in Table 3.
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The sealing material used for boundary conditions is fluorinated ethylene propylene (FEP) and
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EPONTM Resin 828 epoxy resin. FEP heat shrink tube (0.2mm thickness) is used for seal in radial face and
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FEP gasket (2mm thickness) is used for seal in end face (Fig. 2).
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To ensure that the sealing material has no effect on the results of the low field nuclear magnetic signal, it
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is necessary to determine the T2 spectra of the saturated oil core samples before and after the boundary
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treatment. The reliability of the experimental results of FI can be ensured only if the T2 spectra are basically
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consistent (Fig. 3).
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The results show that: the T2 spectra of the core samples after boundary treatment are basically
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consistent with that before the boundary treatment which means the influence of the material used to
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construct the boundary conditions on the FI can be neglected.
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2.3. Experimental Procedure and Apparatus
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FI of oil-saturated core sample was placed in a sealed and pressurized system (Fig. 4). The experimental procedure is listed as follows.
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1. T2 distribution of oil-saturated core sample was measured before placing into pressurized system.
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2. Core sample and 100 mL DT water were put in the piston accumulator, and the valves in the
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upstream and downstream were kept open. 3. Distilled water was pumped to the bottom of piston accumulator continuously until all the gas in the accumulator was removed; 4. The valve in the upstream was closed and the ISCO pump started to work in the mode of constant pressure. The forced pressure in each accumulator was kept 5 MPa; 5. The pressure in the accumulator was removed at selected measurement time point and the core was 6
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taken out to remove liquid on the surface by using cotton yarn.
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6. The core sample was measured immediately with the LF-NMR machine to identify the T2
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distribution, then the core sample was put back to the pressurized system to continue the FI process
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until the next measurement time point.
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7. Step 6 to 9 were repeated until the end of the experiment, which lasted for 25 days.
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8. Recovery of forced imbibition at different time interval was calculated using the following equation:
Roil =
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m0 − mi × 100% m0
(2)
Where Roil is oil recovery, %; m0 is oil mass before FI measurements, g; mi is oil mass displaced by DT water at a selected time interval, g; An LF-NMR core analysis system (MesoMR-060H-HTHP-I) with a magnetic field intensity of 0.5T was
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used to perform the T2 measurement by using Carr-Purcell-Meiboom-Gill (CPMG) pulse sequences.
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3. Results and Discussion
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The FI and NMR experimental results are presented in this section. To investigate the effects of different
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influencing factors, the blank group A12 was first performed with FI experiment, then the influencing
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factors, including boundary condition, initial water saturation, bedding plane direction, and salinity, were
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analyzed to make comparisons and corresponding results were also discussed.
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3.1. Oil Distribution in Tight Cores
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According to LF-NMR T2 distribution of core samples before imbibition experiments, the average
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frequency of T2 at five ranges was obtained (Fig. 5). More than 96% oil was distributed in pores where T2
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ranged from 0.1 ms – 100 ms. To be more specific, T2 distribution between 0.1 ms and 100 ms is classified into
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three groups: nano-micro-pores (0.1 ms ≤T2 < 1 ms), nano-meso-pores (1 ms ≤ T2
