Petroleum Exploration and Development >

2024 , Vol. 51 >Issue 2: 394 - 402

DOI: https://doi.org/10.1016/S1876-3804(24)60031-5

Nuclear magnetic resonance experiments on the time-varying law of oil viscosity and wettability in high-multiple waterflooding sandstone cores

  • JIA Hu , 1, * ,
  • ZHANG Rui 1, 2 ,
  • LUO Xianbo 3 ,
  • ZHOU Zili 1 ,
  • YANG Lu 2
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  • 1. Nation Key Laboratory of Oil and Gas Reservoir Geology and Exploitation of Southwest Petroleum University, Chengdu 610500, China
  • 2. China Oilfield Services Ltd., Tianjin 300459, China
  • 3. Tianjin Branch of CNOOC Ltd., Tianjin 300459, China
*E-mail:

Received date: 2023-02-13

  Revised date: 2024-03-11

  Online published: 2024-05-10

Supported by

Original Exploration Project of National Natural Science Foundation of China(5215000105)

Young Teachers Fund for Higher Education Institutions of Huo Yingdong Education Foundation(171043)

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Abstract

A simulated oil viscosity prediction model is established according to the relationship between simulated oil viscosity and geometric mean value of T2 spectrum, and the time-varying law of simulated oil viscosity in porous media is quantitatively characterized by nuclear magnetic resonance (NMR) experiments of high multiple waterflooding. A new NMR wettability index formula is derived based on NMR relaxation theory to quantitatively characterize the time-varying law of rock wettability during waterflooding combined with high-multiple waterflooding experiment in sandstone cores. The remaining oil viscosity in the core is positively correlated with the displacing water multiple. The remaining oil viscosity increases rapidly when the displacing water multiple is low, and increases slowly when the displacing water multiple is high. The variation of remaining oil viscosity is related to the reservoir heterogeneity. The stronger the reservoir homogeneity, the higher the content of heavy components in the remaining oil and the higher the viscosity. The reservoir wettability changes after water injection: the oil-wet reservoir changes into water-wet reservoir, while the water-wet reservoir becomes more hydrophilic; the degree of change enhances with the increase of displacing water multiple. There is a high correlation between the time-varying oil viscosity and the time-varying wettability, and the change of oil viscosity cannot be ignored. The NMR wettability index calculated by considering the change of oil viscosity is more consistent with the tested Amott (spontaneous imbibition) wettability index, which agrees more with the time-varying law of reservoir wettability.

Key words： sandstone; high-multiple waterflooding; nuclear magnetic resonance; oil viscosity; rock wettability; time-varying law

Cite this article

JIA Hu , ZHANG Rui , LUO Xianbo , ZHOU Zili , YANG Lu . Nuclear magnetic resonance experiments on the time-varying law of oil viscosity and wettability in high-multiple waterflooding sandstone cores[J]. Petroleum Exploration and Development, 2024 , 51(2) : 394 -402 . DOI: 10.1016/S1876-3804(24)60031-5

Introduction

The permeability, wettability and residual oil viscosity of waterflooding reservoirs gradually change after long- term water flooding, and especially during the high water cut period of medium-high permeability reservoirs, the time-varying phenomena of reservoir parameters are more apparent. The changes of rock wettability and oil viscosity in the process of waterflooding development have greater influence on waterflooding efficiency and remaining oil distribution [1]. There are many literatures on the time-varying laws of rock wettability and oil viscosity during long-term water flooding in medium-high permeability sandstone reservoirs [2⇓⇓⇓-6]. Among them, the researches on the time-varying of wettability mainly adopt the contact angle method, imbibition method (Amott), and centrifugation method (United States Bureau of Mines, USBM). The imbibition method and centrifugation method are both difficult and time-consuming when characterizing the changes in wettability of cores. The contact angle method not only damages the core, but also cannot reflect the overall wettability of the core but local of it.
The variation in oil viscosity is mainly characterized by the data of oil viscosity obtained from the interpretation of NMR logging data at different water cut stages. However, the viscosity of oil at different positions between injection and production wells exhibits heterogeneous distribution characteristics due to differences in flooding degree. The oil viscosity interpreted from logging data is an average value, not the value at different positions in the reservoir. It is unable to accurately characterize the time-varying laws of oil viscosity at different locations in the reservoir during long-term water flooding. At present, there have been no reports on the application of high multiple waterflooding experiments to analyze the time-varying law of oil viscosity. This is mainly because the volume of produced oil decreases with the increase of displacing water multiple, and the commonly used viscosity measurement method (rotation method) in the laboratory is difficult to effectively measure the oil viscosity.
Nuclear magnetic resonance technology (NMR) plays an important role in reservoir pore structure evaluation [7⇓⇓-10] and fluid analysis [11⇓⇓-14]. The nuclear magnetic resonance relaxation signal is only related to the hydrogen atoms in the formation, so that the T2 spectral response characteristics can reflect the pore and fluid characteristics unrelated to the formation lithology. Significant progress has been made in characterizing rock wettability and oil viscosity using NMR. Looyestijn et al. [15] defined the NMR wettability index based on hydrophilic and oleophilic surface areas, while Fleury et al. [16] established a formula for calculating the NMR wettability index based on nuclear magnetic resonance relaxation theory. Although this formula has been gradually improved with the development of NMR technology [17⇓⇓⇓-21], there are still problems: (1) T2 spectra need to be measured in four states of saturated oil, saturated water, irreducible water and residual oil; (2) The derivation of the wettability index formula assumes that the rock wettability remains unchanged during water flooding, which is inconsistent with reality; (3) Calculating the wettability index requires calculating the water oil surface relaxation ratio first, which is a complex process.
The viscosity of oil characterized by NMR is measured by placing the oil in a test tube [22⇓⇓-25], not the viscosity of oil in porous medium. However, when predicting the viscosity of oil in porous medium by NMR, it is assumed that the rock is completely water wet, and the time variation of rock wettability is not considered. In addition, it is assumed that the relaxation type of water and oil in the process of prediction are surface relaxation and bulk relaxation respectively. Under actual mixed wet conditions, however, the relaxation type of some oil attached to the pore surface in the core is surface relaxation, resulting in significant errors in the prediction of oil viscosity [26-27].
It can be seen that the current method of characterizing rock wettability and oil viscosity by NMR is difficult to meet the needs in researching the time-varying laws of rock wettability and oil viscosity during high multiple waterflooding process. Therefore, this paper analyzed the relationship between the oil viscosity and the geometric mean of T2 spectrum and established a simulated oil viscosity prediction model based on the geometric mean of T2 spectrum. In addition, it derived a new wettability index calculation formula based on NMR relaxation theory, achieving the quantitative characterization of the time-varying law of oil viscosity and rock wettability in high multiple waterflooding cores.

1. Design of NMR experiment

1.1. Materials

The experimental fluids include 26# white oil, kerosene, simulated formation water and manganese water. The viscosity of 26# white oil is 52.4 mPa·s, and the density is 0.847 g/cm3; the viscosity of kerosene is 1.56 mPa·s, and the density is 0.798 g/cm3; the salinity of simulated formation water (prepared with NaCl) is 9 000 mg/L; the mass concentration of MnCl2 in manganese water (prepared by simulated formation water) is 5 000 mg/L, and the density is 1.012 g/cm3. The cores used in the experiment are one Berey sandstone core and one natural outcrop sandstone core, numbered B600-1 and T600-1, respectively. Their physical parameters are shown in Table 1.
Table 1. Physical property parameters of experimental cores
Core No. Length/
cm		 Diameter/
cm		 Permeability/
10−3 μm2		 Porosity/
%
B600-1 5.01 2.51 639 20.7
T600-1 4.98 2.53 667 18.2

1.2. Equipment

It includes BROOLFIELD viscometer (DVNext), high- temperature and high-pressure online flooding NMR imaging system (SPEC-RC035), and multi-functional core flooding device (from Chengdu Core Technology Company Ltd.).

1.3. Process

All routine fluid analysis tests, core flooding, and NMR analysis experiments in this paper were conducted under normal atmospheric temperature (25 °C).
Oil viscosity experiment. Prepare simulated oil with different mass ratios of white oil and kerosene, and then measure the viscosity of the simulated oil (Table 2). Use CPMG (Carr-Purcell-Meiboom-Gill) sequence to measure the NMR T2 spectrum of oil with different viscosities, and obtain the empirical relationship between oil viscosity and NMR T2 spectrum. The measurement parameters of NMR T2 spectrum are as follows. The main frequency is 15.14 MHz, the number of echoes is 4 096, the waiting time is 3 000 ms, the pulse interval is 0.3 ms, and the scanning frequency is 64 times.
Table 2. Composition ratio and viscosity data of simulated oil
No. Mass ratio of white oil to kerosene Viscosity/
(mPa·s)		 No. Mass ratio of white oil to kerosene Viscosity/
(mPa·s)
1 1:1 6.62 6 3:1 16.7
2 11:9 7.87 7 4:1 20.8
3 3:2 9.31 8 17:3 25.6
4 13:7 11.5 9 9:1 32.3
5 7:3 13.8
High multiple waterflooding NMR experiment. Referring to the industry standard GB/T28912-2012 [28], set the flooding speed to 1.0 mL/min. To accurately reflect the actual flooding degree of the reservoir, the maximum water displacing multiple was set according to Reference [5], increasing from the industry standard of 30 PV (pore volume multiple) to 2 000 PV. The experiment on the time-varying law of rock wettability and oil viscosity during high multiple waterflooding mainly considers the cumulative flooding effect of injected water, that is, the relationship of rock wettability and oil viscosity with displacing water multiple. The experimental steps are: (1) Measure the T2 spectrum of the core saturated with manganese water; (2) Use 3# simulated oil (density of 0.826 g/cm3) to displace the core saturated with manganese water until there is no water at the outlet, and establish irreducible water state; (3) Measure the T2 spectrum of the core in the irreducible water state, and scan and image the cross-section of the core; (4) Use manganese water to displace oil, close the inlet and outlet gate valves when the injection volume reaches 30, 300, 500, 700, 1 000, 1 300, 1 600, 2 000 PV, and measure and image the T2 spectrum of the core, while measuring the T2 spectrum of the produced liquid; (5) Record the displacement pressure difference and the volume of oil and water at the outlet during the flooding processes.

2. Dynamic production of high multiple waterflooding core

Fig. 1 shows the T2 spectrum curves of two cores under different displacing water multiples and the relationship between the recovery degree and displacing water multiple in the core flooding experiment. It can be seen that: (1) As the displacing water multiple increases, the water peak gradually increases; the oil peak exhibits the opposite characteristic, that is, the larger the displacing water multiple, the lower the oil peak. (2) Whether it is an oil peak or a water peak, as the displacing water multiple increases, the area enveloped by the T2 spectrum curve and the irreducible water T2 spectrum curve gradually expands, indicating that the water saturation in the core is increasing and the amount of produced oil is increasing. (3) As the displacing water multiple increases, the expansion rate of the area enveloped by the two T2 spectral curves decreases. Under the long-term flooding effect of injected water, the oil in the core will continue to be displaced and produced with the increase of displacing water multiple, but the amount will decrease, and the increasing amplitude of the recovery degree will decrease (Fig. 1c).
Fig. 1. T2 spectrum and the simulated oil recovery degree curves of cores at different displacing water multiples.
Fig. 2 shows the NMR imaging results of core under different displacing water multiples. From the figure, it can be seen that as the displacing water multiple increases, the NMR image gradually becomes lighter from the initial red color to a light blue color, and the residual oil saturation of the core continues to decrease, resulting in a continuous increase of simulated oil recovery degree. The B600-1 core has strong homogeneity, with uniform advance of waterfront and uniform color change in the image. The color difference is small at the same displacing water multiple (Fig. 2a). T600-1 has strong heterogeneity and dominant flow channels, with uneven advance of waterfront and uneven color change in the image. The color difference is significant at the same displacing water multiple (Fig. 2b). When the displacing water multiple exceeds 1 000 PV, the increasing amplitude of simulated oil recovery degree is lower than that of B600-1 core.
Fig. 2. NMR images of core at different displacing water multiples.

3. Time-varying characteristics of oil viscosity in high multiple waterflooding

The geometric mean of T2 spectrum can characterize the change characteristics of T2 spectrum, and the extraction of the geometric mean can be done using the following formula [29]:
$T_{2,\text{g}}^{{}}={{\left( \prod\limits_{i=1}^{N}{T_{2,i}^{^{{{M}_{i}}}}} \right)}^{{1}/{M}\;}}$
Fig. 3 shows the T2 spectrum curves of simulated oil with 9 different Composition ration. It can be seen that as the viscosity of the simulated oil increases, the T2 spectrum curve shifts to the left. The geometric mean value of T2 spectrum is extracted through Eq. (1) and fitted with the viscosity of simulated oil. It is found that the viscosity of simulated oil in log-log plot has a good linear correlation with the geometric mean value of T2 spectrum (Fig. 4). The fitting relationship is:
${{\mu }_{\text{o}}}=8\ 613{{T}_{\text{bo,g}}}^{-1.237}$
Fig. 3. T2 spectral curves of simulated oil with different viscosities.
Fig. 4. Relationship between simulated oil viscosity and T2 spectral geometric mean.
Fig. 5 shows the variation curve of viscosity of simulated oil with displacing water multiple predicted through Eq. (2), based on the T2 spectrum of simulated oil in core and produced fluid. It should be noted that Eq. (2) is obtained by the direct measurement of viscosity of simulated oil and the fitting of T2 spectrum. The simulated oil mainly shows bulk relaxation, while the remaining oil in the incomplete water-wet core has surface relaxation [27]. The predicted results of the remaining oil viscosity in the core will be biased compared with that of the produced liquid, but the deviation between the two is not large, and the direct calculation with Eq. (2) will not have great influence. It can be seen that: (1) As the displacing water multiple increases, the viscosity of simulated oil increases. When the displacing water multiple is low, the increase speed is higher, while when the displacing water multiple is high, the increase speed slows down. The analysis shows that lighter components in the oil are more likely to be washed away by injected water. As the displacing water multiple increases, the proportion of displaced lighter components in the simulated oil decreases, resulting in an increase in viscosity. Similarly, the proportion of heavier components in the residual simulated oil increases, resulting in a higher viscosity. (2) Under the same displacing water multiple, there is a difference in the viscosity of simulated oil in the core and produced liquid, as the viscosity of simulated oil in the core is higher than that of simulated oil in the produced liquid. This difference decreases with the increase of displacing water multiple. Compared with B600-1 core, the viscosity prediction difference of T600-1 core is smaller after high-multiple waterflooding, because the viscosity of simulated oil is related to bulk relaxation. The relaxation time of oil in T600-1 core after 2 000 PV is mainly bulk relaxation, while the surface relaxation of oil has little influence on the relaxation time of the core as a whole. (3) The variation of simulated oil viscosity is related to the heterogeneity of the reservoir. B600-1 core has strong homogeneity and uniform advance of waterfront, and the flooding degree at different positions in pores is high and similar (Fig. 2a). The higher the flooding degree of core, the greater the viscosity of simulated oil, so the overall viscosity of B600-1 core is higher. The T600-1 core has strong heterogeneity, uneven advance of waterfront and dominant channels. The flooding degree at different positions in the pores varies greatly and is relatively low (Fig. 2b). Therefore, the overall viscosity of T600-1 core is relatively low.
Fig. 5. Viscosity change curve of remaining simulated oil in core and simulated oil in produced fluid.

4. Time-varying characteristics of rock wettability in high multiple waterflooding

4.1. The time-varying phenomenon of rock wettability in experiment

In actual experiments, the original T2 spectra of the core and produced liquid measured by NMR both have two peaks. Due to the separation of oil and water nuclear magnetic resonance signals, the water peak signal has no effect on the change of the oil peak. For the convenience of comparative analysis, only the oil peak signal is displayed. Fig. 6 shows the normalized T2 spectrum curves of oil in the cores and produced fluid under different displacing water multiples of two cores. Based on this, Eq. (1) is used to calculate the geometric mean value of T2 spectrum in Fig. 6 (Table 3). Through comparison, it is found that the geometric mean value of T2 spectrum of simulated oil in core is smaller than that in produced fluid, mainly because the bulk relaxation of simulated oil is basically the same whether it is in produced fluid or remaining in core. The relaxation type of simulated oil in produced fluid is bulk relaxation, while in addition to the bulk relaxation of simulated oil in core, there is a part of surface relaxation of simulated oil attached to pore surface in core. The difference between the two data indicates the existence of surface relaxation of simulated oil in the core and the surface relaxation changes with the increase of displacing water multiple, confirming the existence of wettability time-varying in the core. In the residual oil state after low multiple water flooding (displacing water multiple less than 30 PV), the two cores are not completely water wet and exhibit mixed wetting. As the displacing water multiple increases, the oil attached to the surface of the pores in the core is washed out by the flooding water for a long time, resulting in a decrease in the oleophilic surface area and a weakening of the surface relaxation of the oil in the core. The difference in the geometric mean of T2 spectrum of the oil in the core and the oil in the produced fluid becomes smaller. The water-wetting degree of the core increases with the increase of displacing water multiple.
Fig. 6. Normalized T2 spectral curves of oil in core and produced liquid at different displacing water multiples.
Table 3. T2 spectrum geometric mean value of oil in core and oil in produced liquid at different displacing water multiples
Core No. Geometric mean value of T2 spectrum of oil in core/ms Geometric mean value of T2 spectrum of oil in produced liquid/ms Geometric mean difference value of T2 spectra
of oil in core and produced liquid/ms
Injected by
30 PV		 Injected by
300 PV		 Injected by 0-30 PV Injected by
30-300 PV		 Injected by 30 PV Injected by 300 PV
B600-1 176.8 169.7 253.9 182.7 77.1 13.0
T600-1 193.4 180.9 251.3 190.0 57.9 9.1

4.2. Time-varying characterization method for wettability

According to the relaxation mechanism of nuclear magnetic resonance, the observed transverse relaxation time T2 is represented with surface relaxation, bulk relaxation and diffusion relaxation [30]. In a uniform magnetic field, diffusion relaxation can be ignored [31], then there is:
$\frac{1}{{{T}_{2}}}=\frac{1}{{{T}_{2\text{b}}}}+{{\rho }_{2}}\frac{A}{V}$
When there is a two-phase fluid of oil and water in the pores and the rock is mixed wet, the T2 of water and oil in the pores can be expressed as follows according to Eq. (3):
$\left\{ \begin{matrix} \frac{1}{{{T}_{2,\text{w}}}}=\frac{1}{{{T}_{2\text{b},\text{w}}}}+{{\rho }_{2,\text{w}}}\frac{{{A}_{\text{w}}}}{V{{S}_{\text{w}}}} \\ \frac{1}{{{T}_{2,\text{o}}}}=\frac{1}{{{T}_{2\text{b},\text{o}}}}+{{\rho }_{2,\text{o}}}\frac{{{A}_{\text{o}}}}{V{{S}_{\text{o}}}} \\\end{matrix} \right.$
Looyestijn et al. [15] demonstrated that the wettability of rocks can be quantitatively characterized by NMR wettability index:
${{I}_{w}}=\frac{{{A}_{w}}-{{A}_{\text{o}}}}{{{A}_{w}}+{{A}_{\text{o}}}}$
The range of NMR wettability index is [−1.0, 1.0], where −1.0 indicates completely oil wetting, 0 indicates neutral wetting, and 1.0 indicates completely water wetting.
Fleury et al. [16] used the peak relaxation time of cores in the states of saturated water, saturated oil, irreducible water and residual oil to calculate the NMR wettability index:
${{I}_{\text{w}}}=\ \frac{{{S}_{\text{w}}}\left[ \frac{1}{{{T}_{\text{w},\text{m}}}\left( {{S}_{\text{or}}} \right)}\ \ -\ \ \frac{1}{{{T}_{\text{bw,m}}}} \right]\ \ -\ \ {{C}_{\rho }}{{S}_{\text{o}}}\left[ \frac{1}{{{T}_{\text{o},\text{m}}}\left( {{S}_{\text{wc}}} \right)}\ \ -\ \ \frac{1}{{{T}_{\text{bo,m}}}} \right]}{{{S}_{\text{w}}}\left[ \frac{1}{{{T}_{\text{w},\text{m}}}\left( {{S}_{\text{or}}} \right)}\ \ -\ \ \frac{1}{T_{\text{bw,m}}^{{}}} \right]\ \ +\ \ {{C}_{\rho }}{{S}_{\text{o}}}\left[ \frac{1}{{{T}_{\text{o},\text{m}}}\left( {{S}_{\text{wc}}} \right)}\ \ -\ \ \frac{1}{{{T}_{\text{bo,m}}}} \right]}$
${{C}_{\rho }}=\frac{{{\rho }_{\text{2,w}}}}{{{\rho }_{\text{2,o}}}}=\frac{\frac{1}{{{T}_{\text{w},\text{m}}}\left( {{S}_{\operatorname{w}1}} \right)}-\frac{1}{{{T}_{\text{bw,m}}}}}{\frac{1}{{{T}_{\text{o},\text{m}}}\left( {{S}_{\text{o}1}} \right)}-\frac{1}{{{T}_{\text{bo,m}}}}}$
This method selects the T2 spectrum at extreme oil/water saturation to calculate the NMR wettability index, as the peak relaxation time of the main fluid at extreme fluid saturation is reliable, but this value is weakly dependent on the presence of another fluid.
In the high multiple waterflooding NMR experiment, manganese water is used for flooding. The difference between the T2 spectrum of the core saturated with manganese water and the bulk relaxation time of manganese water is very small (Fig. 7), and Tw,m and Tbw,m are quite close and easily affected by the concentration of manganese chloride. The surface relaxation ratio calculated via. Eq. (7) is close to 0. It indicates that when Fleury method is applied, the T2 spectrum of manganese water presents instable performance when it is used to analyze the water-oil surface relaxation ratio and the NMR wettability index. It indicates that the T2 spectrum of manganese water is not suitable for this wettability analysis method. In this experiment, the NMR signals of oil and water measured during the flooding are separated, and the T2 spectrum of the core saturated with oil is more different from the bulk relaxation time of oil, so rock wettability can be analyzed directly based on the T2 spectrum characteristics of oil.
Fig. 7. Comparison of T2 spectrum of core saturated with manganese water and oil with the bulk relaxation of manganese water and oil.
Based on the experimental characteristics of this article, we calculated the NMR wettability index using the geometric mean values of T2 spectra of saturated oil and oil in pores under different displacing water multiples. The geometric mean value of T2 spectrum of saturated oil in pores can be expressed as follows according to Eq. (3):
$\frac{1}{{{T}_{\text{o},\text{g}}}\left( {{S}_{\text{o1}}} \right)}=\frac{1}{{{T}_{\text{bo,g}}}\left( {{S}_{\text{o1}}} \right)}+{{\rho }_{\text{2,o}}}\frac{A}{V}$
According to Eq. (3), the T2 spectrum of oil in pores under different displacing water multiples during high multiple waterflooding processes can be expressed as follows:
$\frac{1}{{{T}_{\text{o},\text{g}}}\left( R \right)}=\frac{1}{{{T}_{bo,g}}\left( R \right)}+{{\rho }_{\text{2,o}}}\frac{{{A}_{\text{o}}}\left( R \right)}{V{{S}_{\text{o}}}\left( R \right)}$
The auxiliary equation is:
$A={{A}_{\text{w}}}\left( R \right)+{{A}_{\text{o}}}\left( R \right)$
The calculation formula for the NMR wettability index under different displacing water multiples can be obtained by combining Eqs. (8), (9) and (10) and substituting them into Eq. (5).
${{I}_{\text{w}}}\left( R \right)=\frac{\frac{1}{{{T}_{\text{o},\text{g}}}\left( {{S}_{o1}} \right)}\ -\ \frac{1}{{{T}_{\text{bo,g}}}\left( {{S}_{\text{o1}}} \right)}\ \ -\ \ 2{{S}_{\text{o}}}\left( R \right)\left[ \frac{1}{{{T}_{\text{o},\text{g}}}\left( R \right)}\ -\ \frac{1}{{{T}_{\text{bo,g}}}\left( R \right)} \right]}{\frac{1}{{{T}_{\text{o},\text{g}}}\left( {{S}_{\text{o1}}} \right)}\ -\ \frac{1}{{{T}_{\text{bo,g}}}\left( {{S}_{\text{o}1}} \right)}}$

4.3. Time-varying analysis of NMR wettability index

According to Eq. (11), the NMR wettability index is calculated. When the time-varying of oil viscosity is not considered, the geometric mean of the transverse bulk relaxation time of oil under different displacing water multiples is constant and equal to the geometric mean of the transverse bulk relaxation time of oil in the core saturated with oil. When considering the time-varying of oil viscosity, the geometric mean of the transverse bulk relaxation time of oil under different displacing water multiples is a variable, which can be calculated using the time-varying data of oil viscosity (Fig. 5) and the fitted formula of Eq. (2).
Fig. 8 is the change curve of NMR wettability index under different displacing water multiples. Analysis shows that: (1) When the water is injected by 30 PV, the NMR wettability index of B600-1 core is 0.61, and the tested Amott wettability index is 0.65; the NMR wettability index of T600-1 core is 0.72, and the tested Amott wettability index is 0.78. When the water is injected by 2 000 PV and considering the time-varying of oil viscosity, the NMR wettability index of B600-1 core is 0.90, and the tested Amott wettability index is 0.92; the NMR wettability index of T600-1 core is 0.98, and the tested Amott wettability index is 0.99. It can be seen that the predicted results in this article are in good agreement with the test results, and the method proposed in this article can be used to characterize the wettability of rocks with high accuracy. (2) According to the Amott wettability index evaluation standard [32]: [−1, −0.7] represents for strong oil wet, [−0.7, −0.3] represents for oil wet, [−0.3, −0.1] represents for weak oil wet, [−0.1, 0.1] represents for neutral wet, (0.1, 0.3) represents weak water wet, (0.3, 0.7) represents for water wet, and (0.7, 1) represents for strong water wet. It is suggested that during high multiple waterflooding process, the B600-1 core gradually transforms from initial water-wet to strong water-wet, and the T600-1 core gradually transforms from initial strong water-wet to nearly complete water-wet. (3) When the viscosity change of simulated oil is not considered, the NMR wettability index first rapidly decreases with the increase of displacing water multiple, and then fluctuates slightly around a certain value. When the water is injected by 2 000 PV, the NMR wettability index of B600-1 core is 0.48, and that of T600-1 core is 0.69, which is significantly different from the tested Amott wettability index. (4) When considering changes in simulated oil viscosity, the NMR wettability index continuously increases with the increase of displacing water multiple, and the hydrophilicity of the core is gradually stronger. When the displacing water multiple is lower than 300 PV, the NMR wettability index increases faster and its increase rate gradually slows down when the displacing water multiple is higher than 300 PV.
Fig. 8. Change of NMR wettability index at different displacing water multiples.
The coring data of medium-high permeability sandstone reservoirs and the results of long-term indoor waterflooding experiments [1] indicate that after water injection, the oleophilic reservoirs change into hydrophilic mostly, while the hydrophilic reservoirs have stronger hydrophilicity. This is because during water injection process, the flooding of water flow increases the water saturation, and at the same time, the oil film on the oleophilic surface becomes thinner or is washed away, leading to the gradual increase of the hydrophilic surface area. And thus the wettability changes into hydrophilic or the hydrophilicity gets enhanced. Considering the simulated oil viscosity changes, the calculated NMR wettability index is more consistent with the tested Amott wettability index, which is more in line with the time-varying law of reservoir wettability and can better explain the mechanism of wettability changing towards hydrophilic after long-term waterflooding. It can be seen that there is a high correlation between the time-varying of oil viscosity and the time-varying of wettability, and the change of oil viscosity cannot be ignored.

5. Conclusions

The remaining oil viscosity in the core is positively correlated with the displacing water multiple. The remaining oil viscosity increases rapidly when the displacing water multiple is low, while it increases slowly when the displacing water multiple is high. The variation of remaining oil viscosity is related to the reservoir heterogeneity. The stronger the reservoir homogeneity, the higher the content of heavy components in the remaining oil and the higher the viscosity.
The reservoir wettability will change after water injection. The oil-wet reservoir will be changed to water-wet reservoir, and the water-wet reservoir will be more hydrophilic, whose degree of change will be enhanced with the increase of displacing water multiple.
There is a high correlation between the time-varying of oil viscosity and the time-varying of wettability, and the change of oil viscosity cannot be ignored. The NMR wettability index calculated by considering the change of oil viscosity is more consistent with the tested Amott wettability index, which is more consistent with the time-varying law of reservoir wettability.

Nomenclature

A—pore surface area, µm2;
Aw, Ao—pore area wetted by water and oil, µm2;
Aw(R), Ao(R)—pore area wetted by water and oil at different displacing water multiples, µm2;
Cρ—water-oil surface relaxation ratio, dimensionless;
i—index of the component in the T2 spectrum;
Iw—NMR wettability index, dimensionless;
Iw(R)—NMR wettability index at different displacing water multiples, dimensionless;
M—total amplitude of all T2 components, dimensionless;
Mi—amplitude of the ith T2 component, dimensionless;
N—total number of the components in the T2 spectrum;
R—displacing water multiple, dimensionless;
Sw, So—water and oil saturation, %;
So(R)—oil saturation at different displacing water multiples, %;
T2—transverse relaxation time of fluid, ms;
T2,i —transverse relaxation time of the ith component of T2 spectrum, ms;
T2,g—geometric mean value of the T2 spectrum, ms;
T2b—transverse bulk relaxation time of fluid, ms;
T2,w, T2,o—transverse relaxation time of water and oil, ms;
T2b,w, T2b,o—transverse bulk relaxation time of water and oil, ms;
Tw,m(Sor), To,m(Swc)—peak relaxation time of water and oil in remaining oil and irreducible water state, ms;
Tw,m(Sw1), To,m(So1)—peak relaxation time of water and oil in saturated water and saturated oil state, ms;
Tbo,m, Tbw,m—peak bulk relaxation time of oil and water, ms;
To,g(So1)—geometric mean of T2 spectrum of oil in core saturated with oil, ms;
Tbo,g—geometric mean of T2 spectrum of simulated oil, ms;
Tbo,g(So1)—geometric mean of transverse bulk relaxation time of oil in core saturated with oil, ms;
To,g(R)—geometric mean of T2 spectrum of oil at different displacing water multiples, ms;
Tbo,g(R)—geometric mean of transverse bulk relaxation time of oil at different displacing water multiples, ms;
V—pore volume, µm3;
µo—oil viscosity, mPa·s;
ρ2—transverse surface relaxation rate of rock, µm/ms;
ρ2,w, ρ2,o—transverse surface relaxation rate of water and oil to rock, µm/ms.

References

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