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Article

Investigation on Imbibition Recovery Characteristics in Jimusar Shale Oil and White Mineral Oil by NMR

by
Dunqing Liu
*,
Chengzhi Jia
and
Keji Chen
Faculty of Petroleum, China University of Petroleum (Beijing) at Karamay, Karamay 834000, China
*
Author to whom correspondence should be addressed.
Energies 2025, 18(15), 4111; https://doi.org/10.3390/en18154111
Submission received: 23 June 2025 / Revised: 20 July 2025 / Accepted: 31 July 2025 / Published: 2 August 2025
(This article belongs to the Special Issue New Progress in Unconventional Oil and Gas Development: 2nd Edition)
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Abstract

Recovering oil by fracturing fluid imbibition has demonstrated significant potential for enhanced oil recovery (EOR) in tight oil reservoirs. White mineral oil (WMO), kerosene, or saturated alkanes with matched apparent viscosity have been widely used as “crude oil” to investigate imbibition mechanisms in light shale oil or tight oil. However, the representativeness of these simulated oils for low-maturity crude oils with higher viscosity and greater content of resins and asphaltenes requires further research. In this study, imbibition experiments were conducted and T2 and T1–T2 nuclear magnetic resonance (NMR) spectra were adopted to investigate the oil recovery characteristics among resin–asphaltene-rich Jimusar shale oil and two WMOs. The overall imbibition recovery rates, pore scale recovery characteristics, mobility variations among oils with different occurrence states, as well as key factors influencing imbibition efficiency were analyzed. The results show the following: (1) WMO, kerosene, or alkanes with matched apparent viscosity may not comprehensively replicate the imbibition behavior of resin–asphaltene-rich crude oils. These simplified systems fail to capture the pore-scale occurrence characteristics of resins/asphaltenes, their influence on pore wettability alteration, and may consequently overestimate the intrinsic imbibition displacement efficiency in reservoir formations. (2) Surfactant optimization must holistically address the intrinsic coupling between interfacial tension reduction, wettability modification, and pore-scale crude oil mobilization mechanisms. The alteration of overall wettability exhibits higher priority over interfacial tension in governing displacement dynamics. (3) Imbibition displacement exhibits selective mobilization characteristics for oil phases in pores. Specifically, when the oil phase contains complex hydrocarbon components, lighter fractions in larger pores are preferentially mobilized; when the oil composition is homogeneous, oil in smaller pores is mobilized first.

1. Introduction

China possesses abundant shale oil resources within its territory, with continental shale oil emerging as a critical domain for enhancing domestic hydrocarbon production [1]. In recent years, multiple national-level continental shale oil demonstration zones have been progressively established. Current shale oil production primarily derives from medium–high-maturity strata, where horizontal well drilling combined with volumetric fracturing techniques delivers industrial productivity [2]. Beyond these medium–high-maturity shale oil resources, substantial low-maturity shale oil reserves are also widely distributed across China. For instance, the Lucaogou Formation in the Junggar Basin contains shale oil reserves approaching one billion tons in geological resources [3]. However, the crude oil from the Jimusar area exhibits distinctive challenges due to its low thermal maturity, including elevated resin–asphaltene content, low gas–oil ratios in situ, and poor fluid mobility [4,5]. Conventional development approaches employing horizontal wells with volumetric fracturing demonstrate limited success in achieving satisfactory single-well productivity. Consequently, complementary measures such as post-fracturing well soaking and cyclic fluid injection become essential to enhance production efficiency in these reservoirs [6,7].
The imbibition-driven oil displacement serves as the critical mechanism responsible for enhanced oil recovery (EOR) during post-fracturing well soaking or cyclic fluid injection [8]. The capillary force acting at the oil–water–pore interface can induce a pressure gradient that substantially exceeds the production pressure differential, thereby rendering imbibition displacement a highly promising method for oil recovery [9,10,11,12,13]. Many reservoirs benefit from the imbibition process, including fractured reservoirs, conventional reservoirs developed by water-injection or huff-n-puff mode, and unconventional reservoirs developed via hydraulic fracturing [14]. Laboratory imbibition experiments have, in some instances, achieved a remarkable maximum oil recovery rate of up to 40% [15,16,17]. Moreover, the implementation of post-fracturing shut-in operations to facilitate imbibition displacement has demonstrated significant enhanced oil recovery effects in certain fractured tight oil reservoirs [18,19].
However, most existing studies employ light oils—including kerosene, dodecane, hexadecane, or artificially diluted crude oils predominantly composed of saturated hydrocarbons—to simulate real crude oil [20,21]. This approach may not accurately replicate low-maturity shale oil. Taking the Jimusar shale oil as an example, its average resin and asphaltene content is around 38%, with some wells exhibiting over 70% resin content, and its viscosity ranges from 5 to 300 mPa·s at 50 °C [22,23,24,25,26]. Whlie simulated oils used in most imbibition oil displacement experiments typically consisted of alkane, and their viscosities are usually below 3 mPa·s. Related studies have demonstrated that resins and asphaltenes exhibit complex interfacial interactions and significant wettability alteration effects in porous media, suggesting their critical role in imbibition-driven oil displacement processes [27,28], while simulated crude oil cannot adequately replicate these complex interactions due to the absence of critical chemical components. Field applications in the Jimusar region have further revealed that fracturing fluid additive systems designed based on light oil imbibition findings underperformed in displacing complex, high-viscosity crude oil [29,30,31]. However, current research on the imbibition mechanisms and influencing factors specific to such compositionally complex, high-viscosity oils remains limited.
To clarify the imbibition-driven oil displacement behavior of resin–asphaltene-rich shale oil, as well as the representativeness of the existing simulated oils, we designed a systematic study investigating how crude oil components influence these processes. Spontaneous imbibition experiments were conducted on core samples from both bottom-hole and outcrop sources. Through a combination of NMR spectroscopy and systematic variations in oil composition, viscosity, interfacial tension, and wettability, we quantified imbibition recovery efficiency and pore-scale oil mobilization patterns. Furthermore, the potential effects of hydrocarbon component interactions and their occurrence state on recovery rates were evaluated. This work may advance the mechanistic understanding of imbibition in complex shale oil systems and provides practical guidelines for improving experimental designs in unconventional reservoir studies.

2. Materials and Methods

2.1. Core Samples

Three bottom-hole cores were drilled from a wax-sealed full-size core from an exploration well in Jimusar using liquid nitrogen, and then the end faces of the samples were trimmed flat to fabricate them into plug-shaped specimens with a diameter of 2.5 cm and a length of approximately 5 cm. To streamline the experimental workflow while preserving the original properties of the bottom-hole samples, two untreated bottom-hole samples and their cut end-face sections were directly saturated in crude oil under 30 MPa pressure for four weeks. The third bottom-hole sample underwent solvent cleaning and oven-drying for porosity–permeability measurement. Given their closely spaced sampling locations, the porosity–permeability data of the third bottom-hole sample was used as representative values for the two oil-saturated bottom-hole samples. In addition to the bottom core samples, five outcrop plug samples were prepared, which were first cleaned with solvent before their porosity and permeability measurements were conducted.
Porosity was measured using a helium expansion porosimeter (KXD II model), and permeability was determined via pulse decay method (PDP-200 system). Prior to analysis, all samples were vacuum dried at 80 °C for 48 h to remove residual fluids (organic solvents and water). Tests were conducted under 7.5 MPa pore pressure and 10 MPa confining pressure with nitrogen as the medium. The size, porosity and permeability results of the samples are listed in Table 1.

2.2. Fluids Characteristics

In this study, imbibition experiments were conducted using two aqueous phases and three oil phases. The aqueous phases consisted of deuterium oxide (D2O, 99.9 atom% D, supplied by Shanghai Macklin Biochemical Technology Co., Ltd., Shanghai, China) and simulated fracturing fluid prepared with 0.1 wt.% AEO-9 surfactant (BASF) dissolved in D2O. The oil phases included crude oil extracted from the Lucaogou Formation of Jimusar shale oil reservoir, along with industrial-grade #7 and #25 WMOs (Qingdao Enji Chemical Co., Ltd., Qingdao, China). Gas chromatographic analysis revealed that the #7 WMO is primarily composed of normal and iso-alkanes (C11-C27), whereas #25 WMO contains primarily C17-C30 alkanes. A four-component analysis (performed according to SY/T 5119-2016 [32]) indicated that crude oil used in this paper contains 59.76% saturated hydrocarbons, 20.97% aromatic hydrocarbons, 14.58% resins, and 4.69% asphaltenes.
WMO grades are determined by their kinematic viscosity at 40 °C. #7 measures 7 mPa·s, and Grade #25 measures 25 mPa·s at 40 °C. Since our imbibition experiments were conducted at 25 °C, the viscosities of the oil and aqueous phases were measured using a Brookfield DV2T viscometer at 25 °C, and the results are listed in Table 2.
Besides viscosity, the interfacial tensions between different liquids were also measured via a KRÜSS SDT spinning drop tensiometer at 25 °C. The surface tension results are listed in Table 3.
Among the outcrop samples, sample O5 and the remaining end-face portions of sample O5 were immersed in a hydrophobic agent (HB-G40, 0.1 wt.%, Shan Dong Foamix New Material Co., Ltd., Qingdao, China) for 48 h to render them hydrophobic and then they were dried by an oven under 85 °C. Then all the outcrop samples and their remaining end-face portions were saturated with WMO under 30 MPa and aged for 4 weeks. After saturation and aging, the contact angles of different phases on the remaining end-face portions of the samples were measured by a KRÜSS DSA25E drop shape analyzer, and the contact angle results are listed in Table 4. The plug samples were used to conduct imbibition experiments. Notably, the initial contact angle of outcrop sample O5 in the 1‰ AEO-9-#7 WMO system was 105.8°, and after the sample immersion in 1‰ AEO-9 for 24 h, the contact angle decreased to 70.9°. This variation in contact angle may be related to the wettability reversal effect of AEO-9.
Upon completion of the fluids and core property analyses, the plug samples were subjected to spontaneous imbibition experiments. The specific fluids used for saturation and imbibition in each plug sample are detailed in Table 5.

2.3. NMR and Imbibition Methods

Imbibition displacement refers to the process in which a wetting phase infiltrates oil-bearing pores under capillary forces, displacing crude oil from the pores [33]. Traditional imbibition displacement experiments are typically performed using the Amott cell-a specialized glass device incorporating a graduated glass tube to quantify displaced oil volume during imbibition [34]. Although this method is operationally convenient, it provides limited information on pore-scale fluid saturation evolution. Furthermore, surface adsorption of oil droplets and in-situ oil emulsification during imbibition may misestimate displacement recovery efficiency. In this study, NMR was employed to investigate imbibition displacement processes. In contrast to direct volumetric measurements, NMR-based methodologies provide a non-invasive approach to quantify pore-scale oil–water redistribution through monitoring proton relaxation dynamics in porous media [35]. This technique inherently avoids systematic errors associated with conventional volumetric measurement artifacts.
Two distinct relaxation mechanisms govern NMR responses in porous media: longitudinal relaxation (T1) describing spin–lattice energy dissipation parallel to the static magnetic field, and transverse relaxation (T2) reflecting spin–spin decoherence perpendicular to the field. The T2 relaxation mechanism, being particularly sensitive to fluid–pore interactions, can be described as follows [36]:
1 T 2 = 1 T 2 B + ρ S V + D ( G T E γ ) 2 12
Here, T2B represents the bulk fluid relaxation time, ρ denotes the surface relaxation rate of the pore surface, D is the diffusion coefficient, γ corresponds to the gyromagnetic ratio of the proton nucleus, and G indicates the average internal magnetic field gradient. The parameter S/V represents the specific surface area of the pore system. Under standardized measurement conditions characterized by homogeneous magnetic fields (G ≈ 0), sufficiently short echo times, and high surface relaxation rate ρ, the diffusion term becomes negligible. For light hydrocarbon components confined within pores, Equation (1) can therefore be simplified to [37]
1 T 2 ≈ 1 T 2 S = ρ F s r
where Fs represents the dimensionless pore geometry factor, and r corresponds to the characteristic pore radius. Equation (2) demonstrates that T2 amplitude distribution directly quantifies proton population density at specific relaxation times, establishing a proportional relationship between NMR signal intensity and fluid volume within corresponding pore dimensions [38].
In our imbibition displacement experiments, D2O was selected as the substituted aqueous phase. The deuterium nucleus (2H), containing one proton and one neutron, exhibits distinct nuclear spin properties from protium (1H), thereby suppressing proton magnetic resonance detection in NMR measurements [39]. As a result, the NMR signals acquired during imbibition displacement processes originate exclusively from protons in the oil phase within pores. This characteristic enables quantitative determination of oil phase distribution and volumetric changes during imbibition through analysis of T2 spectrum peak positions and amplitude evolution.
However, the resin and asphaltene components in crude oil employed in this study exhibit viscosity much greater than water, resulting in significantly reduced T2B relaxation times. This viscosity effect invalidates the conventional pore-size correlation described in Equation (2). Crucially, the fundamental proportionality between total T2 signal amplitude and intrapetrous proton density remains preserved. To accurately characterize the variation of crude oil within the pores, additional collection of T1–T2 signals is necessary. Figure 1 illustrates the behavior of T1 and T2 as a function of correlation time (τc), where the molecular correlation time τc can be mathematically described by [40]
τ c = 4 π μ a 3 3 k T
where μ is the liquid viscosity, a is the molecular radius, k is Boltzmann’s constant, and T is the absolute temperature. The NMR instrument utilized in this study is a low-field NMR instrument (SPEC-RC035, SPEC Technology Development Co., Ltd., Beijing, China). As depicted in Figure 1, components in crude oil with higher viscosity and larger molecular size exhibit a higher T1/T2 ratio. By analyzing the variations in signal intensity within different T1/T2 regions, the recovery of distinct components can be evaluated.
The NMR instrument employed in this study operates at a main frequency of 14 MHz and the probe size is 25.4 mm. To optimize the signal acquisition parameters and achieve a balance between acquisition time and signal-to-noise ratio, preliminary experiments were conducted on oil-saturated core samples. Based on these experiments, the detailed NMR measurement parameters were determined and summarized in Table 6. In the subsequent formal imbibition displacement tests, any free fluids on the sample surfaces were carefully removed using nonwoven fabrics moistened with the corresponding fluid. All imbibition experiments were conducted under ambient room temperature conditions.

3. Results

3.1. T1–T2 Spectra of White and Crude Oil in Test Tube and Cores

To eliminate the influence of pore structure on the NMR spectra and verify the initial position of the oil phases in T1–T2 spectra, we measured the T1–T2 spectra of WMO and crude oil inside test tube, as well as the oil-saturated cores. The results are as shown in Figure 2. For enhanced analytical clarity, we stratified the T1–T2 spectra into four distinct quadrants demarcated by threshold values of T1 = 1 and T2 = 1, with boundary definitions visually indicated by yellow dashed lines in all T1–T2 spectra.
As shown in Figure 2a,c,e, the T1–T2 spectra exhibit distinct differentiation between WMO and crude oil despite their comparable apparent viscosities. The WMO signal concentrates in the upper-right quadrant with a characteristic T1/T2 ratio of 1~2. In contrast, the crude oil spectrum resolves into three distinct clusters: two located in the upper-right quadrant and one in the upper-left quadrant, with centroid T1/T2 ratios measuring 5, 10, and over 100, respectively. The #25 WMO occupies a position closer to the lower-left quadrant compared to the #7 WMO, owing to its longer carbon chain composition, higher apparent viscosity, and accelerated relaxation dynamics [42]. Based on existing 2D NMR research findings in the Jimusar region, combined with compositional analysis of crude oil samples in this study and fundamental principles of NMR spectroscopy, it can be inferred that signals in the upper-right quadrant originate from saturated hydrocarbons and aromatic hydrocarbons with varying carbon chain lengths in the crude oil, while signals in the upper-left quadrant are attributed to resin and asphaltene components [43].
The relaxation process of oil in a test tube primarily reflects intermolecular interactions, whereas that in core samples demonstrates combined effects of intra-oil molecular interactions and oil–pore surface interactions. These oil–pore surface interactions typically accelerate the relaxation process, reducing T2 relaxation times. Consequently, T1–T2 spectral distributions of crude oil and WMO in core samples show significantly greater complexity compared to those observed in test tubes. As illustrated in Figure 2b,d,f, the three-part signal of crude oil becomes more dispersed and shifts towards the left of the spectrum due to the interactions between oil phase and pore surface. For the crude oil in core, the T1/T2 ratio of the signal on the upper-right region does not change much, and the corresponding T2 value expands from 7~70 ms to about 1~100 ms; the T1/T2 ratio of the signal in the middle part increases from 10 to about 40; and the T1/T2 ratio of the signal on the left side expands from about 100 to the range of 1 to 1 hundreds. While, for #7 and #25 WMO in core, the T1/T2 ratio of the main part of the signal slightly increased, and a minor population of signals exhibiting T1/T2 ratios (5–100) emerges as distinct satellite clusters, demonstrating absorption behavior between pore surface and certain component in WMO.
Current research demonstrates that in porous media, hydrocarbon components with elevated T1/T2 ratios exhibit low mobility, while those with lower ratios display higher flow capability [44]. The disparities observed in the T1–T2 spectra between oil in core and test tube imply that previous research on the impact of apparent viscosity on pore fluid mobility during imbibition may lack comprehensiveness. Using Jimusar crude oil as a case study, variations in the mobility of different components within pores can lead to discrepancies in both the sequence and extent of recovery during the capillary-driven displacement processes.

3.2. T1–T2 Spectrum of Crude Oil Before and After Imbibition

Figure 3 demonstrates T1–T2 spectral variations in crude oil-saturated bottom-hole cores pre- and post-imbibition. Three regions emerge in the spectral distributions: upper-left, upper-right, and lower-left quadrants. The upper-right quadrant dominates with maximum signal intensity, contrasting sharply with the weakest responses observed in the lower-left quadrant. Considering the existence of formation water in bottom hole cores and applying established T1–T2 interpretation protocols for fluid typing, we propose the following phase assignments: Lower-left quadrant signatures predominantly reflect irreducible water confined within pores. The upper-left signals may correspond to resin or asphaltene components, whereas the predominant upper-right signals are characteristic of saturated and aromatic hydrocarbons with varying carbon chain lengths and mobility.
Although bottom-hole core samples were retrieved from adjacent locations, the lithology of the Jimusar reservoir exhibits significant heterogeneity, with centimeter-scale vertical variations manifesting as distinct pore structure modifications and lithofacies transitions. These microstructural disparities may consequently induce detectable variations in hydrocarbon distribution and pore-network characteristics among the cores.
As shown in Figure 3a,b, it is evident that the T1–T2 spectra of two oil-saturated bottom-hole core samples exhibit dissimilarities, the distribute range of the signal with T1/T2 larger than 100 in B1 is wider than that in B2, and the signal corresponding to the moveable oil in pores (signal in white dotted box in Figure 3a) is much higher, which suggests that there is more mobile oil in sample B1. The signal in B1 exhibited only minor fluctuations after D2O imbibition, with the primary reduction concentrated in the region corresponding to mobile oil in upper-right quadrant. According to the correlation between the T1/T2 ratio and oil composition as well as mobility, in conjunction with the distribution range of T2, it can be inferred that this part of the signal corresponds to lightweight components in small pores (saturated hydrocarbons or aromatic hydrocarbons). Capillary forces within small pores exhibit relatively higher magnitudes, while the interaction between light components such as saturated hydrocarbons/aromatic hydrocarbons and the pore surfaces is comparatively weaker than that of asphaltenes or resins [45]. Consequently, imbibition is more likely to displace the lightweight components residing within small pores.
Based on the basic principles of NMR, under the same measurement parameters, the total relaxation signal of a sample is linearly related to its total hydrogen atom content. Since the fluid used in imbibition is D2O (which produces no NMR signal), and the 0.1% AEO solution prepared with D2O has an extremely low concentration (with minimal fluid entering the rock core), its NMR signal is negligible. Thus, nearly all detected NMR signals come from the oil phase in the pores. Consequently, the change in total NMR signal before and after imbibition directly correlates with the change in oil volume within the sample [46,47]. Using this linear relationship, the oil recovery rate after imbibition can be calculated by total NMR signals before and after the imbibition. Based on this principle and method, the recovery rate of sample B1 after imbibing D2O was calculated to be approximately 7%.
Compared to B1, the signal variation observed in B2 before and after imbibition were more pronounced. As shown in Figure 3b,d, the signal in the upper-left region becomes nearly imperceptible, while the T1/T2 distribution of the signal area in the upper-right quadrant contracts from a range of 2–20 to 2–10, accompanied by a decline in amplitude from approximately 6000 to around 4000, indicating that this part of the oil has been effectively recovered. The interfacial tension between AEO-9 (0.1 wt.%) and crude oil is reduced by approximately 50-fold compared to that between D2O and crude oil. This significant reduction in interfacial tension may enhance the dispersion of oil in water, leading to the fragmentation of the coherent oil phase into smaller droplets [48]. Additionally, AEO-9 increases the hydrophilicity of pore surfaces, thereby improving the mobility of the pore-bound oil phase. The observed decrease in signal intensity in the upper-left region suggests that, upon AEO-9 (0.1 wt.%) imbibition, a portion of the adsorbed components within the core may have been desorbed. Due to both the desorption of adsorbed groups and changes in pore wettability, lightweight components present in macropores can also be partially recovered through imbibition, resulting in a notable reduction in signal intensity in the upper-right region. Consequently, the oil recovery rate for sample B2 after imbibing AEO-9 (0.1 wt.%) was found to be 15%, which is approximately twice that of sample B1.
The characteristics of samples B1 and B2 demonstrate selective recovery of crude oil components within pore networks during imbibition. The recovered components exhibit reduced T1/T2 ratios and shorter T2 relaxation times, indicative of preferential extraction of lighter hydrocarbons from smaller pores. Crucially, the marked disparity in recovery enhancement between D2O and AEO-9 imbibition (15% vs. 7%, respectively) reveals that wettability–evidenced by contact angle reduction from 96.7° to 76.8°–exerts greater control over displacement efficiency than interfacial tension (19.09 mN/m to 0.36 mN/m). This implies that for reservoirs with complex crude compositions, particularly those rich in resin–asphaltene aggregates, optimizing pore surface hydrophilicity constitutes the primary strategy for improving spontaneous imbibition efficacy. Subsequent interventions, such as interfacial tension modulation to enhance capillary forces or extended well shut-in durations to prolong imbibition time, should only be effective following successful hydrophilicity enhancement.
In many cases, resins or asphaltenes in crude oil are adsorbed on the pore surface [49]. To enhance the pore hydrophilicity, it is necessary to either minimize the presence of these adsorbed components to enable direct contact between mineral surfaces and fracturing fluid or induce wettability inversion on these adsorbed components to render them hydrophilic [50,51]. The utilization of 0.1 wt.% AEO-9 in this study to achieve wettability inversion and stripping of adsorbed components does not imply the universality of AEO-9, and AEO-9 is not the only surfactant that can achieve wettability reversal or stripping of adsorbed components in Jimusar. For specific reservoirs and crude oil types, a series of experiments should be conducted to screen the type and concentration of additives for achieving effective adsorbed component striping or wettability inversion. However, this is not the focus of this paper, and therefore, we will not delve into the differences in types and effects of surfactants in imbibition in this paper.

3.3. Imbibition Recovery Characteristics of WMO

3.3.1. T2 Spectrum of the WMO-Saturated Samples

Previous investigations have demonstrated significant variations in oil phase recovery dynamics across different components during imbibition displacement. However, the resin and asphaltene content in Jimusar crude oil prevents T2 from accurately reflecting the scale characteristics of the pores. Therefore, to investigate the oil recovery mechanisms with higher viscosity at different pore scales during the imbibition process, #7 and #25 WMO were utilized. The WMO samples can remain consistent with the relationship described by Equation (2). Consequently, pore-scale oil phase variations can be quantitatively analyzed through systematic monitoring of T2 spectral distribution variations. As evidenced by Figure 4, crude oil-saturated bottomhole cores exhibit both an absence of double-peak characteristics and a leftward shift in their overall T2 distributions. In contrast, after cleaning and saturation with #25 WMO, the core demonstrated distinct double-peak characteristics.
The T2 spectra of WMO-saturated outcrop cores show similar patterns, confirming consistent pore structures across samples. Both #25 and #7 WMO-saturated samples exhibit two distinct peaks (“bimodal” distributions) in their T2 spectra. However, the exact peak positions differ because higher-viscosity WMOs (like #25 WMO) relax faster than lower-viscosity ones (like #7 WMO), leading to smaller T2 values in similar pores. This explains why #25 WMO samples (sample O2 and O4) have T2 spectra shifted leftward compared to #7 WMO-saturated samples. For sample O5, silane-based hydrophobic pretreatment strengthens the oil-attracting properties of pore surfaces. This accelerates white oil relaxation and shortens T2 times, causing the T2 spectrum of #7 WMO-saturated sample O5 to also shift left relative to the untreated samples (sample O1 and O3).

3.3.2. T1–T2 Spectrum of WMO Before and After Imbibition

The T1–T2 spectra of outcrop samples saturated with same WMO exhibit substantial overlap due to their consistent pore architecture and saturation condition; therefore a representative spectrum is selected for detailed analysis. Gas chromatography results reveal that the WMO composition is predominantly composed of saturated hydrocarbons with varying carbon chain lengths. Specifically, #7 WMO contains hydrocarbons with chain lengths ranging from C11 to C27, while #25 WMO exhibits a broader distribution from C17 to C30.
As shown in Figure 5a,b, the T1–T2 signals of core samples saturated with #7 and #25 white oils are predominantly distributed in the upper-right quadrant, with T1/T2 ratios in the central region approximately ranging from 1 to 2. This distribution indicates that the majority of white oil exists in a freely mobile state within the core samples. Additionally, a minor fraction of weak signals (white dash-line box) exhibits T1/T2 ratios between 5 and 10, corresponding to white oil components adsorbed on the pore surfaces. As marked by the green dashed-line box, the weak signal observed in the lower-left corner corresponds to background noise. According to theoretical principles, fluid signals originating from pore spaces should not appear in regions with T1/T2 ratios below 1 [52].
As shown in Figure 5c,d, the T1–T2 spectra of WMO-saturated core samples exhibit significant broadening in the primary signal distribution regions after imbibing D2O. Specifically, the main signal range expands from 30–300 ms to 1–300 ms for the #7 white oil-saturated sample, while the #25 white oil-saturated sample shows expansion from 10–200 ms to 1–200 ms. A notable enhancement of signals in the short-relaxation component is observed post-imbibition. Additionally, all spectral peak amplitudes of the primary signals demonstrate significant attenuation. As shown in Figure 5e,f, compared with the samples subjected to D2O imbibition, those treated with AEO-9 imbibition exhibit more dispersed signal distributions outside the primary region, with some signals demonstrating T1/T2 ratios reaching 100. Additionally, a greater reduction in spectral peak amplitudes is observed, accompanied by the emergence of additional noise signals.
The weak signal observed in the short relaxation time region is likely associated with the emulsification of WMO. The reduced interfacial tension between 0.1 wt.% AEO-9 and white oil facilitates the dispersion of WMO into fine oil droplets during the imbibition process. The combination of small droplet dimensions and the significant oil–water interfacial area created after emulsification likely contributed to the observed signal characteristics of short T2 and high T1/T2 ratio [53].
Besides, the difference in signal distribution before and after imbibition is presumed to be caused by variations in the spatial distribution of different components within pore networks, as well as alterations in the thickness of both oil and water phase films absorbed on pore surfaces. For heavier components adsorbed on large pore surfaces, their thickness might decrease after imbibition, while for the light component film, they might be stripped off by D2O or AEO-9, which may result in oil–water inversion and form new water films on the pore surface with different thicknesses. As shown in Figure 5g, after being treated with hydrophobic agents, the signal variation of #7 WMO-saturated samples was much smaller than the untreated one (as shown in Figure 5e). However, the total signal intensity located in the upper-right quadrant still shows a marked decrease.
The crude oil-saturated cores exhibit more pronounced differences in T1–T2 spectra between imbibition of D2O and 0.1 wt.% AEO compared with WMO-saturated cores. In the latter, the absence of colloids and asphaltenes results in smaller spectral differences and a more centralized distribution of the signal. Aside from complex variations in short relaxation signals attributed to emulsification, the signal variations corresponding to the movable oil fraction demonstrate a simplified pattern and a notable reduction in amplitude. The differences observed in T1–T2 spectra between WMO and crude oil indicate that relying solely on apparent viscosity is far from sufficient to comprehensively characterize the imbibition displacement behavior of crude oils (particularly complex-component crude oils) in experimental systems employing kerosene, dodecane, hexadecane, or WMOs.

3.3.3. T2 Spectrum Characteristics During Imbibition

In addition to the T1–T2 spectra obtained before and after imbibition, T2 spectra were systematically acquired during the imbibition process to characterize the mobilization behavior of WMO within pores of distinct sizes.
As shown in Figure 6, the spectra of WMO-saturated outcrop samples demonstrated a bimodal feature, with the right-wing signal amplitude being higher. The boundary between the left peak and right peak of the #7 WMO-saturated sample is approximately at T2 = 10 m, while the value is around 3 ms for the #25 WMO-saturated sample. The maximum T2 value of the right peak of #25 WMO-saturated samples is around 200 ms, while the value of the #7 WMO-saturated samples is around 600 ms. The T2 spectra of #25 WMO-saturated samples are narrower compared to that of #7 WMO-saturated samples, primarily due to the higher viscosity and faster relaxation rate exhibited by the former. During the imbibition, significant changes in amplitude primarily occur at the entire left peak and the left side of the right peak. This observation suggests that, under conditions of pore hydrophilicity, spontaneous imbibition tends to preferentially recover oil in smaller pores. The amplitude exhibited significant changes within the initial 48 h, followed by a limited decrease during the subsequent imbibition process, primarily observed in the left peak. It is worth noting that the right edge of the right peak in the #7 WMO-saturated sample showed a significant rightward shift during the imbibition process, while the #25 WMO-saturated sample remained almost unchanged during the whole imbibition process.
This rightward shift phenomenon may be associated with the displacement of oil films in larger pore surfaces by D2O or AEO-9, and this discrepancy may be attributed to the occurrence states of WMO within macroscopic pores. The average carbon chain length of #7 WMO is shorter than that of #25 WMO, resulting in weaker interfacial interactions with pore surfaces. During imbibition, adsorbed #7 WMO on larger pore surfaces may be more easily displaced by D2O or AEO-9. The presence of an interfacial water film between WMO and pore surfaces will lead to slower relaxation processes between #7 WMO and pore surfaces, which may consequently prolong T2 relaxation times and inducing rightward shifts in relaxation spectra. However, due to the longer carbon molecular chains and stronger interfacial interactions of #25 WMO with pore surfaces, effective separation using D2O or AEO-9 becomes more challenging. Consequently, no rightward spectral shift occurs in the T2 spectrum during imbibition.
Due to the hydrophobic treatment, the hydrophilicity of pore surfaces in sample O5 is much lower than that of sample O1 and O3. Consequently, after being saturated with #7 WMO, the interaction strength between pore surfaces and WMO increases, resulting in a shorter relaxation time and narrower T2 spectrum compared to those of sample O1 and O3. As shown in Figure 6a,c,e, the T2 value of the right boundary of sample O1 and O3 is 600 ms, while the value is 300 ms for sample O5. During the first 23 h of the imbibition, there was hardly any change in the right peak of O5 sample, while the amplitude of the left peak showed a significant decrease. Only later in the imbibition process did the amplitude of the right peak show a more noticeable decrease. Additionally, the right peak of the O5 sample also slightly shifted to the right. This phenomenon may be attributed to the weak hydrophilicity of the O5 sample’s pore surface under initial conditions, coupled with inadequate capillary forces in larger pores to effectively extract #7 WMO, while smaller pores demonstrate partial extraction capabilities due to their narrower radii and inherently stronger capillary forces. Consequently, only a reduction in left peak amplitude was observed during the initial stages of imbibition. As the imbibition progressed, AEO-9 gradually enhanced the hydrophilicity of the pore surface, thereby strengthening the capillary force within the large pores and effectively replacing the #7 WMO within the large pores. It may even manage to peel off some of the WMO adsorbed on the pore surface, resulting in a significant reduction in the right peak amplitude and a slight right shift of the T2 spectrum.
Based on the total signal of WMO within the core during the imbibition process, the recovery factor variations during the imbibition process were calculated and the specific results are shown in Figure 7. The imbibition recovery rates of D2O and 0.1 wt.% AEO-9 on the #7 WMO saturated samples were calculated to be 36.31% and 38.53%, respectively, while for #25 WMO saturated samples, the values were 31.7% and 30.66%. When comparing the two, 0.1 wt.% AEO-9 exhibited a slightly higher oil recovery rate than D2O under similar oil phase conditions, which can be attributed to differences in distribution, occurrence state, and capillary force between the oil and water phases within the pores during the imbibition process. Despite D2O having higher interfacial tension with WMO, AEO-9 enhances hydrophilicity of the pore surface while its lower interfacial tension facilitates dispersion of WMO into smaller droplets, thereby enhancing mobility of WMO.
For hydrophilic core samples, both D2O and AEO-9 reached equilibrium within approximately 50 h with comparable equilibrium times observed for #7 and #25 WMO as well. Subsequently, their recovery rates remained relatively stable over time. In contrast, hydrophobic samples O5 required an extended duration of around 75 h to achieve equilibrium. Furthermore, hydrophobic samples O5 demonstrated a gradual increase in imbibition rate prior to reaching equilibrium whereas hydrophobic samples exhibited a progressive decrease in imbibition rate before attaining equilibrium.
The observed disparity can be attributed to the variation in the driving force of imbibition within the samples. Specifically, as imbibition progresses, water saturation within the hydrophilic sample increases while parameters such as pore wetting and interfacial tension remain constant. Consequently, the driving force of imbibition gradually decreases. Regarding sample O5, its hydrophilicity gradually increases with the imbibition time, and the capillary force also strengthens accordingly, resulting in a characteristic where the imbibition rate gradually increases before reaching equilibrium. However, the final imbibition recovery rate has not yet reached the level before the hydrophobic treatment, and the corresponding imbibition recovery rate is 31.1%. This may be associated with the limited diffusion distance of surfactants within the core pores.

4. Discussion

In this study, we systematically monitored the imbibition processes of Jimusar crude oil and #5, #25 WMO using T2/T1–T2 NMR spectroscopy, elucidating pore-scale fluid mobilization characteristics under varying conditions of oil composition, apparent viscosity, interfacial tension, and wettability. The disparities in imbibition characteristics between crude oil and WMO indicate that simulating solely based on apparent viscosity is insufficient to reflect the occurrence and mobilization mechanisms of complex components in crude oil, particularly the resin and asphaltene fractions. These components exhibit high molecular weights and intricate structures, demonstrating strong interactions with pore surfaces. Their occurrence patterns in porous media fundamentally differ from those of saturated or aromatic hydrocarbons, leading to significant variations in mobility during imbibition processes. Furthermore, the adsorption of these components on pore surfaces substantially alters wettability characteristics, which show distinct responses to surfactants compared with systems dominated by saturated hydrocarbons in WMO or long-chain alkanes. Consequently, imbibition experiments employing WMO, kerosene, or long-chain alkanes with matched apparent viscosity as crude oil analogues tend to overestimate oil recovery rates, potentially leading to inflated assessments of reservoir production potential.
In addition to the differences in overall recovery efficiency, the disparities observed in T1–T2 spectra before and after imbibition reveal variations in the mobilization of different pore-scale components. Imbibition preferentially mobilizes light components within small pores, while demonstrating negligible effectiveness in displacing adsorbed heavy components. Furthermore, these adsorbed components significantly reduce pore hydrophilicity, substantially limiting the efficiency of oil displacement through spontaneous imbibition. Consequently, imbibition-driven oil recovery may demonstrate suboptimal applicability for crude oils rich in resin and asphaltene. Additionally, experimental results from WMO under varied viscosity, interfacial tension, and wettability conditions demonstrate that interfacial tension exerts a weaker influence on imbibition recovery efficiency compared to oil-phase apparent viscosity and wettability. Though reducing interfacial tension may decrease capillary pressure at the pore scale, it concurrently alters flow mechanisms of the oil phase through effects such as emulsification—a process that transforms continuous oil phases into dispersed oil droplets, thereby enhancing oil mobility. Consequently, surfactant impacts on imbibition-driven oil recovery arise from the combined effects of interfacial tension modification, flow mechanism transitions, and wettability alterations. This complexity renders interfacial tension alone an inadequate selection criterion for surfactant optimization in imbibition displacement applications.

5. Conclusions

Through NMR monitoring of imbibition displacement processes involving Jimusar resin–asphaltene-rich crude oil and two viscosity-grade WMOs, the following conclusions were drawn:
(1)
WMO, kerosene, or decanes with matched apparent viscosity may not comprehensively replicate the imbibition behavior of resin–asphaltene-rich crude oils. These simplified systems fail to capture the pore-scale occurrence characteristics of resins/asphaltenes and their influence on pore wettability alteration, and consequently may overestimate the intrinsic imbibition displacement efficiency in reservoir formations.
(2)
Surfactant optimization must holistically address the intrinsic coupling between interfacial tension reduction, wettability modification, and pore-scale crude oil mobilization mechanisms. The alteration of overall wettability exhibits higher priority over interfacial tension reduction in governing displacement dynamics.
(3)
Imbibition displacement demonstrates preferential mobilization characteristics, selectively targeting oil phases in smaller pores or lighter hydrocarbon components prior to larger-pore/heavier-fraction extraction.

Author Contributions

Conceptualization, D.L. and C.J.; methodology, D.L. and C.J.; software, D.L.; validation, C.J. and K.C.; formal analysis, K.C.; investigation, C.J. and K.C.; resources, D.L.; data curation, D.L. and C.J.; writing—original draft preparation, D.L.; writing—review and editing, D.L.; visualization, C.J. and K.C.; supervision, D.L.; project administration, D.L.; funding acquisition, D.L. All authors have read and agreed to the published version of the manuscript.

Funding

This research was funded by the Natural Science Foundation of Xinjiang Uygur Autonomous. Region, grant number 2022D01B144; Youth Doctoral Project of the Tianchi Talent Introduction Program; Research Foundation of China University of Petroleum-Beijing at Karamay, grant number XQZX20230011.

Data Availability Statement

All data in the paper is available upon request.

Conflicts of Interest

The authors declare no conflicts of interest.

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Figure 1. Relationships between viscosity or molecular size and the T1 and T2 relaxation times (data are adopted from Korb [41]).
Figure 1. Relationships between viscosity or molecular size and the T1 and T2 relaxation times (data are adopted from Korb [41]).
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Figure 2. T1–T2 spectra of crude and WMO. (a) Crude oil in tube, (b) Crude oil in core, (c) #7 WMO in tube, (d) #7 WMO in core, (e) #25 WMO in tube, and (f) #25 WMO in core.
Figure 2. T1–T2 spectra of crude and WMO. (a) Crude oil in tube, (b) Crude oil in core, (c) #7 WMO in tube, (d) #7 WMO in core, (e) #25 WMO in tube, and (f) #25 WMO in core.
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Figure 3. T1–T2 spectra of the crude oil saturated bottom-hole cores before and after imbibition. (a) B1 before imbibe D2O, (b) B2 before imbibe 0.1 wt.% AEO-9, (c) B1 after imbibe D2O, (d) B2 after imbibe 0.1 wt.% AEO-9.
Figure 3. T1–T2 spectra of the crude oil saturated bottom-hole cores before and after imbibition. (a) B1 before imbibe D2O, (b) B2 before imbibe 0.1 wt.% AEO-9, (c) B1 after imbibe D2O, (d) B2 after imbibe 0.1 wt.% AEO-9.
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Figure 4. T2 spectra of the saturated cores, 7-H-AEO stands for hydrophobic treated sample O5 saturated with #7 WMO and imbibe 0.1 wt.% AEO-9. B3 were saturated with #25 WMO after porosity and permeability measurement.
Figure 4. T2 spectra of the saturated cores, 7-H-AEO stands for hydrophobic treated sample O5 saturated with #7 WMO and imbibe 0.1 wt.% AEO-9. B3 were saturated with #25 WMO after porosity and permeability measurement.
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Figure 5. T1–T2 spectra of the WMO saturated samples before and after imbibition.
Figure 5. T1–T2 spectra of the WMO saturated samples before and after imbibition.
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Figure 6. T2 spectra variation of the WMO saturated samples during imbibition. (a) Sample O1 imbibe D2O, (b) Sample O2 imbibe D2O, (c) Sample O3 imbibe 0.1% wt. AEO-9, (d) Sample O4 imbibe 0.1% wt. AEO-9, (e) Sample O5 imbibe 0.1% wt. AEO-9.
Figure 6. T2 spectra variation of the WMO saturated samples during imbibition. (a) Sample O1 imbibe D2O, (b) Sample O2 imbibe D2O, (c) Sample O3 imbibe 0.1% wt. AEO-9, (d) Sample O4 imbibe 0.1% wt. AEO-9, (e) Sample O5 imbibe 0.1% wt. AEO-9.
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Figure 7. Oil recovery rate variation of the 5 samples during imbibition.
Figure 7. Oil recovery rate variation of the 5 samples during imbibition.
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Table 1. The size, porosity and permeability results of the samples.
Table 1. The size, porosity and permeability results of the samples.
Core NoLength (mm)Diamter (mm)Poroity (%)Permeability (mD)
B136.2725.13~8.98~0.09
B237.1425.10~8.98~0.09
B338.1325.148.980.09
O155.2225.1611.150.11
O256.3125.1411.630.13
O355.2425.0911.250.12
O455.1925.1311.530.14
O554.1625.1411.140.12
Table 2. The viscosity (25 °C) of the fluids used in this study.
Table 2. The viscosity (25 °C) of the fluids used in this study.
Crude Oil#7 WMO#25 WMOD2O0.1 wt.%AEO-9 in D2O
Viscosity (mPa·s)10.78.528.71.11.1
Table 3. The interfacial tension (25 °C) of fluids system used in this study.
Table 3. The interfacial tension (25 °C) of fluids system used in this study.
Surface Tension (mN/m)Crude Oil#7 WMO#25 WMO
D2O19.092720.4
0.1 wt.% AEO-9 in D2O0.363.32.4
Table 4. The contact angle (25 °C) of fluids system used in this study.
Table 4. The contact angle (25 °C) of fluids system used in this study.
Contact Angle (°)#7 WMO
Outcrop Sample		#25 WMO
Outcrop Sample		Cruel Oil
Bottom-hole Sample
D2O77.479.896.7
0.1 wt.% AEO-9 in D2O7068.367.8
Table 5. Specific fluids for saturation and imbibition of each plug sample.
Table 5. Specific fluids for saturation and imbibition of each plug sample.
Core NoSaturated FluidsImbibed Fluids
B1crude oilD2O
B2crude oil1‰ AEO-9 in D2O
B3#25 WMO/
O1#7 WMOD2O
O2#25 WMOD2O
O3#7 WMO1‰ AEO-9 in D2O
O4#25 WMO1‰ AEO-9 in D2O
O5#7 WMO1‰ AEO-9 in D2O
Table 6. Parameters used in NMR signal acquisition.
Table 6. Parameters used in NMR signal acquisition.
Signal TypeSequenceTE (μs)Tw (ms)Echo NumberScan NumberGain (dB)TiMin (μs)TiMax (μs)
T2CPMG60300040961620//
T1–T2IR-CPMG10055004096123010020,000,000
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Liu, D.; Jia, C.; Chen, K. Investigation on Imbibition Recovery Characteristics in Jimusar Shale Oil and White Mineral Oil by NMR. Energies 2025, 18, 4111. https://doi.org/10.3390/en18154111

AMA Style

Liu D, Jia C, Chen K. Investigation on Imbibition Recovery Characteristics in Jimusar Shale Oil and White Mineral Oil by NMR. Energies. 2025; 18(15):4111. https://doi.org/10.3390/en18154111

Chicago/Turabian Style

Liu, Dunqing, Chengzhi Jia, and Keji Chen. 2025. "Investigation on Imbibition Recovery Characteristics in Jimusar Shale Oil and White Mineral Oil by NMR" Energies 18, no. 15: 4111. https://doi.org/10.3390/en18154111

APA Style

Liu, D., Jia, C., & Chen, K. (2025). Investigation on Imbibition Recovery Characteristics in Jimusar Shale Oil and White Mineral Oil by NMR. Energies, 18(15), 4111. https://doi.org/10.3390/en18154111

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