Experimental Investigation of Countercurrent Spontaneous Imbibition

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Experimental Investigation of Counter-Current Spontaneous Imbibition in Tight Sandstone Using Nuclear Magnetic Resonance Zhilin Cheng, Qing Wang, Zhengfu Ning, Mingqi Li, Chaohui Lyu, Liang Huang, and Xiaojun Wu Energy Fuels, Just Accepted Manuscript • DOI: 10.1021/acs.energyfuels.8b00394 • Publication Date (Web): 09 May 2018 Downloaded from http://pubs.acs.org on May 12, 2018

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Experimental Investigation of Counter-Current Spontaneous Imbibition in Tight Sandstone Using Nuclear Magnetic Resonance Zhilin Cheng1,2,*, Qing Wang1,2, Zhengfu Ning1,2, Mingqi Li1,2, Chaohui Lyu1,2, Liang Huang1,2, Xiaojun Wu1,2 1. State Key Laboratory of Petroleum Resource and Prospecting, China University of Petroleum, Beijing, 102249; 2. Key Laboratory of Petroleum Engineering, Ministry of Education, China University of Petroleum, Beijing, 102249

Abstract Tight oil reservoirs are an unconventional hydrocarbon resource with great potential to help meet energy demands. Horizontal drilling and hydraulic fracturing has been extensively used for the exploitation of these unconventional resources, and fracturing fluids absorbed into formations by spontaneous imbibition (SI) is an important mechanism of oil production. In this paper, imbibition experiments combined with Nuclear Magnetic Resonance (NMR) were conducted to study the characteristics of fluid displacement in an oil/water system for tight sandstone. In addition, the relative contribution to oil recovery of different types of pores, effects of boundary conditions, and different surfactants on imbibition recovery were all determined via the T2 spectra of each sample. The results show that the tight sandstone features a multi-scale pore structure, which is dominated by micropores and small mesopores. As the imbibition process begins, white oil is preferentially displaced from these relatively small pores by water and a large amount of oil production comes from the micropores. Boundary conditions are shown to have a significant impact on imbibition rate and ultimate recovery. Both are higher as the areas available for water imbibition increase. Deionized water with low concentrations of surfactants altered the wettability of the samples, from weakly water-wet to a strongly water-wet on the rock surfaces, while lowering interfacial tension (IFT) at the oil-water interface. Therefore, a higher oil recovery could be obtained to some extent, but enough IFT is still needed to ensure a large capillary force. Because conventional scaling equations do not account for the effect of wettability alteration, such as the addition of surfactants to a system, they cannot be employed to scale imbibition data well. This research demonstrates the imbibition characteristics of tight sandstone and several relevant affecting factors, providing crucial theory foundations for the development of tight oil formations.

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Keywords: tight sandstone; spontaneous imbibition; NMR; boundary conditions; surfactants

1. Introduction With increasing demand for energy and continuing exploitation of unconventional oil and gas resources, tight oil reservoirs have become a crucial alternative energy source1, 2. Horizontal well fracturing is broadly used to exploit shale gas and tight oil reservoirs3. A large volume of fracturing fluid is injected into the formation to create a complex fracture network, but the flowback rate is quite low (usually less than 30%)4 due to aqueous phase trapping5. Spontaneous imbibition (SI) of fracturing fluids into the matrix can be partially responsible for the water retention6. On the other hand， when fluids penetrate into a formation, oil and gas in the matrix is expelled into the fractures. SI has been regarded as an effective enhance oil recovery method for tight reservoirs7, 8. Simply put, SI is when the non-wetting phase fluids (NWP) are displaced out of a porous media by wetting fluids (WP) through capillary force9, 10. According to the flow direction of the wetting phase and nonwetting phase, this process can be divided into cocurrent (same direction) and countercurrent (opposite direction) configuration 11. In general, the rock matrix is surrounded by fracturing fluids where countercurrent imbibition tends to occur, while the cocurrent imbibition is less likely to occur, which depends on the gravity contribution12. Countercurrent SI has been regarded as the most important mechanism of recovery between the two modes. Previous studies have mainly focused on the countercurrent imbibition in porous media because of its importance 13, 14. SI is affected by the properties of the porous medium, types of fluids and the interaction between fluids and solids. All the influencing factors involved include pore structure, sample shape and size, boundary conditions, fluid viscosity, initial water saturation and wettability.15 Among which, the effect of boundary conditions on SI has been the subject of many studies within the field of conventional reservoir rocks. Babadagli and Qaboos 16 tested the applicability of scaling formulations in Berea sandstone cores with different shapes, sizes and boundary conditions. Standnes17 systematically investigated the effect of boundary conditions and sample shape on cocurrent and countercurrent imbibition. Boundary conditions included the all faces open (AFO), two ends open (TEO), two ends close (TEC) and one end open (OEO). He


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concluded that the scaling model cannot be applied to irregular rocks, and the surface areas of rock exposed to water had a significant effect on imbibition rate but only minor effects on recovery. Likewise, small-scale SI tests on reservoir rock samples by Yildiz et al.18 reached similar conclusions, finding no difference in ultimate oil recovery under different boundary conditions, while characteristic length had an inverse effect on the rate of SI with the same shape of cores, and an increased total surface open to imbibition promoted the rate of SI. However, several recent studies19, 20 have showed that boundary conditions not only play a role in controlling the rate of fluids displacement but also affect the ultimate oil recovery since there is a difference in oil recovery between one-dimensional and multi-dimensional concurrent imbibition. They suggested that the anisotropy of the porous media and the direction dependence of permeability, capillary and relative permeability could be responsible for the imparity. To date, there are few studies that have investigated the impact of boundary conditions on SI in unconventional reservoir rocks. Lai et al. 21 studied the influence of pore structure, wettability, boundary conditions and temperature on gas/water and oil/water systems for tight sandstones. They pointed out boundary conditions have no significant effect on the gas/water/rock imbibition recovery. However, they did not explain the reasons for the clear difference in oil recovery on the oil/water/rock system. The inconsistency between boundary conditions and ultimate recovery for tight rocks requires further clarification. Wettability is a crucial factor controlling the location, flow, and distribution in a reservoir 22 and determining the outcome of any EOR technique such as waterflooding, CO2 flooding and SI. Understanding capillary imbibition mechanism under different wettability states of a matrix block is of major importance because many reservoirs are not water-wet, but weakly-wet, mixed-wet or even oil-wet23. Over the past several years, the imbibition mechanism of strongly water-wet rock has become comprehensively better understood but for weakly water-wet, mixed-wet and oil-wet circumstances, the understanding of the imbibition process is still far from adequate24. As a typical unconventional resource, shale comprises both organic and inorganic pores. The organic part of shale is normally hydrophobic, while the inorganic minerals can be hydrophilic, often exhibiting mixed-wet features25. Dehghanpour et al.26 measured water intake and imbibition of oil in dry organic shale samples through detailed experiments, and water adsorption by clay minerals and adsorption-induced


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microfractures were found to lead to excess water intake in shales. In addition, recent evidence suggests that strong adsorption of oil in fresh mixed-wet Montney ultra-tight sands during SI experiments, which is due to the majority of pores partly coated by pyrobitumen27, while in the presence of both oil and brine, the rock affinity to brine is higher than that to oil28. If a reservoir is water-wet, a large amount of oil will be recovered from formation rocks by SI. Adding surfactants to the fluids is a commonly used method for controlling wettability during laboratory experiments22. Wang et al.7 performed a series of wettability alteration and SI experiments on shale cores from the Bakken formation. They concluded that the wetting state of these cores can be altered from oil-wet or intermediate-wet towards water-wet, and the surfactants imbibed to displacement more oil than brine imbibition alone. To identify effective chemicals inducing brine imbibition into originally oil-wet tight sandstones with permeabilities from 0.01 to 0.1 mD, several anionic and nonionic surfactants were evaluated by Kathel and Mohanty29 in imbibition experiments to determine whether these surfactants could help SI and enhance oil recovery. Results showed that wettability alteration occurred in the samples where anionic surfactants were used. However, surfactants can also simultaneously lower the water-oil IFT, which might be detrimental to SI of water in porous rocks. Study of coupled effects of wettability and IFT alternation on SI, in particular for unconventional reservoirs, is necessary and needs considerable critical attention. Several studies by Alvarz et al. 30, 31 and Alvarz and Schechter32 examined the role of wettability and IFT alteration in unconventional liquid reservoir rocks including carbonate, siliceous and shale cores. The experiments included contact angle, zeta-potential, IFT measurements and SI tests with CT methods to evaluate and compare the efficiency of different surfactants in enhancing oil recovery for tight rocks. They demonstrated that the selection of surfactants depends on rock mineral composition and the addition of surfactants in SI experiments recovered more oil than fracturing water without surfactants due to the wettability alteration and moderate IFT reduction. However, the contribution of wettability shift and IFT reduction for favoring imbibition is still unclear and needs further investigation. Furthermore, low-field NMR has been widely used in the petroleum industry to analyze the petrophysical properties of various rocks, including nuclear magnetism logs33, pore size distributions in porous rocks34, 35, and surface wettability


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testing36, 37. Odusina et al.38 investigated the mixed-wet behavior in shales using NMR, determining that the volume of oil imbibed is affected by a combination of total organic carbon, thermal maturity, and organic volume and fractures influencing the brine imbibition. Also, the NMR T 2 spectra can be used to quantify the amount of imbibed fluids. Similar findings have also been concluded by other scholars39. Wang et al.40 examined the NMR response of oil and water on organic-rich shale cores from the Sichuan Basin and analyzed the relationships between the T2 spectra for oil and water and pore types, wettability and rock composition. Furthermore, NMR can also be used to monitor the saturation distribution and displacement features of oil or water in unconventional formations. Tinni et al.41 used NMR to evaluate the fluid content in shales saturated with brine, dodecane and methane. They found that two peaks generally appeared in the NMR T2 spectra representing the water-wet-porosity and oil-wet-porosity fraction. The water-wet section of the T2 spectra is always higher than oil-wet section, implying that brine can enter the entire pore spectrum and the main flow path is dominated by the water-wet section. Lin et al.42 compared the water saturation distribution within different tight samples through NMR experiments and qualitatively analyzed the relationship between the distance of the displacement front and clay content and salt concentration. Sun et al. 43 studied the flow patterns of oil and water in tight sandstones under dynamic imbibition conditions. The main aim of this study is to investigate the effects of boundary conditions and wettability shift on SI in tight oil sandstones. We conducted imbibition experiments with NMR testing to achieve this end. First, the experimental samples and methods are outlined, then the features of displacement of oil and water in different kinds of pores, characteristics of residual oil in pores, and effects of boundary conditions and surfactants on SI in tight oil sandstones are all described through NMR T2 spectra. Furthermore, the application of a scaling model to tight sandstone with a wettability shift is also discussed. This investigation enhances our understanding of imbibition behavior in tight sandstones.

2 Experimental Section 2.1 Materials The experimental materials include tight sandstone samples and fluids for imbibition tests. Seven sandstone samples were


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selected from outcrop cores taken from the Chang 8 Member of the Triassic Yanchang Formation located in the Ordos Basin, northern China. The samples were polished into cylindrical cores with a diameter of ~2.5 cm and length of ~5.0 cm. Firstly, helium porosity tests were performed. Then, permeabilities of these samples were obtained by pressure-pulse decay tests. The petrophysical properties of the rock samples are shown in Table 1. Table 1. Properties of rock samples and fluids for experiments Length, Sample

NWP

Diameter,

Porosity,

Permeability,

Boundary

Oil NB-1

WP cm

cm

%

10-3μm2

Conditions

Saturation, %

L2

WO

DIWm

5.081

2.524

12.55

0.5

AFO

95.32

624.9

L4

WO

DIWm

5.077

2.527

12.24

0.37

LEC

95.66

717.9

L5

WO

DIWm

5.093

2.556

12.23

0.5

TEO

94.97

615.4

L11

WO

DIWm

5.044

2.542

12.01

0.45

TEC

96.01

649.1

L6

WO

DIWm +SDS

5.041

2.531

12.25

0.47

AFO

95.68

274.3

L7

WO

DIWm +APG

5.072

2.553

11.9

0.56

AFO

96.22

89.6

L8

WO

DIWm +AES

5.087

2.531

11.96

0.48

AFO

94.87

269.1

NW: non-wetting phase; WP: wetting phase; WO: #5 white oil; DIWm: deionized water with MnCl2; NB-1: the inverse Bond number ; AFO: all faces

open; LEC: lower end close; TEO: two ends open; TEC: two ends close; SDS: sodium dodecyl sulfate; AES: alcohol ether sulphate; APG: alkyl

polyglycoside.

Mineralogy of the samples were determined through quantitative x-ray diffraction. The results are listed in Table 2. Quartz and feldspar account for the majority of mineral content (66.2%). The clay minerals are dominated by kaolinite (76%), and only comprise small amounts of illite and illite-smectite mixed layer (I/S). Dehghanpour et al.26, 44 reported that strong water adsorption by shales will induce microfractures and even break the samples, and the water intake is proportional to the clay content. Yang et al.45 compared the imbibition results of tight sandstone and mud shale and concluded that clay swelling is directly related to the concentration of montmorillonite and I/S minerals. The clay minerals of tight sandstone


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samples we used for SI experiments mainly contain kaolinite, which does not allow for easy hydration46, and consequently, clay swelling was neglected in our study. Table 2. Results of XRD mineralogy analysis Relative Abundance, %

Minerals Types and Content, %

Sample

I/S

Illite

Kaolinite

Clay

L

9

15

76

19.5

Feldspar

Dolomite

Calcite

Quartz

10.7

3.6

39.3

26.9

In NMR test, we only focused on the signal of hydrogen ion of oil, thus deionized water with 40%wt MnCl2 (DIWm) solutions was used as the WP fluid47 to block the signal of water during NMR T 2 scanning. 5# white oil (WO), a kind of mineral oil, was chosen as the NWP. The viscosity of the WP and NWP were 2.47 and 7.97 mPa·s respectively, and the measured density were 1320 and 854 kg/m3 at room temperature (25 ℃) and pressure, respectively. In addition, previous studies8, 29, 30, 32, 48 showed that the wetting state of unconventional cores can be altered from oil-wet or intermediate-wet towards water-wet by use of surfactants, in turn producing more oil than brine imbibition alone. In this study, three commonly used surfactants were used: sodium dodecyl sulfate (SDS), alkyl polyglycoside (APG), and alcohol ether sulphate (AES). All were added into the DIWm for preparing 0.5%wt surfactant solution respectively. Furthermore, polytetrafluoroethylene (PTFE) tape was used to seal the specific surface of samples to form different boundary conditions, as shown in Table 1 in detail.

2.2 Experimental Theory and Equipment The primary principle of NMR testing is that when a sample saturated with oil and water is placed in a static magnetic field, the tiny bar magnet will point to the same direction. The macroscopic magnetization vector represents the magnetic moment of each hydrogen nucleus. The signal intensity of the magnetic vectors is proportional to the number of hydrogen nuclei, also proportional to the volume of the fluid. In other words, the signal amplitude of the T2 spectra can reflect the fluid volume in rock samples at a corresponding time. Furthermore, the pore size distribution corresponds to the transverse relaxation time (T2), with a larger relaxation time indicating larger pores49. The saturation distribution of oil in cores was detected using medium-sized MesoMR23-60H-I nuclear magnetic resonance apparatus which also can generate oil saturation mapping at different positions in samples. The resonance


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frequency was set at 23.048 MHz, magnetic field intensity at 0.55T and 0.2ms for echo time, which avoids signals loss from smaller pores50. As the signals of water were blocked by high concentration of MnCl 2, variations of the T2 spectra at different times only indicated the change of oil volume in a sample. The area surrounded by the T 2 spectrum and X-axis can represent the volume of remaining oil in cores38. Therefore, oil recovery at different times in the saturation process was computed by the change of the curve area. The formula is as follows:

E 

S0  S1 S0

(1)

Where E is oil recovery in terms of any time, S0 is the initial area surrounded by T 2 spectrum and X-axis, S1 is the area corresponding to different stages of SI. In addition, contact angle measurements were performed on the POWEREACH equipment based on the sessile drop method. IFT measurements were carried out by use of a POWEREACH apparatus with the pendant-drop method.

2.3 Test Procedure In this study, these rock samples were not cleaned because using solvent might change the initial wetting affinity of the samples22, 28. The detailed procedure for imbibition experiments combined with NMR is as follows: (1) All rock samples were put into a thermotank at 105 ℃ for 48 h. The porosity and permeabilities of the samples were then immediately measured after the 48 h period. (2) The cores were then directly saturated with 5# white oil without being first waterflooding under a pressure of 25 MPa for 48 h and the weight of samples after saturation were recording to determine the amount of saturation. The initial oil saturations of all samples are listed in Table 1. (3) The samples were then immersed into white oil for another 48 h, after that, different boundary conditions were created with PTFE tape for various samples (Table 1). (4) The cores were placed into NMR analyzer to record the initial T 2 spectra distribution and magnetic resonance imaging (MRI) for oil saturation distribution in samples.


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(5) The cores were placed into a corresponding vessel containing 40 wt% MnCl 2 solutions vertically, ensuring that the total core was immersed into the solutions, and the starting time was recorded for each sample. The core was removed at a designated time and the surface fluids instantly removed using test paper. The T 2 spectrum and MRI images were recorded for each sample. After that, the core was placed back into the vessel for another predetermined amount of time and the above steps repeated until the measurement of all the designed test points were completed.

3 Results and Discussion 3.1 Displacement Characteristic of Fluids under Imbibition The T2 spectra quantitatively illustrates the remaining oil distribution in all types of pores, and the relaxation time for the T2 spectra indicates the pore size to some degree51. According to the results of Gao et al.52 and Lai et al.21, the relaxation time can be divided into four intervals, representing different pore types (Table 3). Table 3. Relationship between relaxation time and different types of pores T2 relaxation time, ms

pore type

pore radius, μm

≤1

micropore

≤2

1~10

small mesopore

2~10

10~100

mesopore

10~20

100~1000

macropore

20~200

The pore structure of tight sandstone is of high complexity with abundant micro- and nanopores 53, 54. Figure 1 shows the T2 spectrum of four core samples during imbibition, the relaxation time ranges from 0.01 ms to 1000 ms, which confirms the nature of the multiscale pore structure of these tight sandstones. The initial T 2 curves of all samples have the same trend, from which approximately three crests can be seen, as shown in L4 sample (Fig. 1b). The left peak is between 0.01 ms-8 ms and the area covered accounts for ~67%. The middle peak is distributed between10 ms-200 ms, representing roughly 33% of the entire region. The last peak only takes up less than 0.3%, which is negligible. Based on the classification of Table 3, there are few macropores in the L samples. Micropores and small mesopores are the dominated


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pores, accounting for about 67%, which agrees qualitatively with results reported by Zhao et al55. 1400

1400 (a)

L2

800 600 400

left peak

1200 1000

Signal intensity

Signal intensity

1000

(b)

0h 0.5h 1.5h 3h 6h 19h 27h 43h 73h 120h

1200

middle peak

L4

800 600

0h 0.5h 1.5h 3h 6h 19h 27h 43h 73h 120h

400

200

200 right peak 0.1

1

10 100 T2 (ms)

10000

0.1

1

10 T2 (ms)

100

1000

10000

1400

1400

0h 0.5h 1.5h 3h 6h 19h 27h 43h 73h 120h

(c) 1200 1000

1000

0 0.01

L5

800 600

(d)

0h 0.5h 1.5h 3h 6h 19h 27h 43h 73h 120h

1200 1000

Signal intensity

0 0.01

Signal intensity

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

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L11

800 600

400

400

200

200

small

micropores

mesopores

macropores

0 0.01

0.1

1

10 T2 (ms)

100

1000

10000

0 0.01

mesopores

0.1

1

10 T2 (ms)

100

1000

10000

Figure 1. Variations of T2 spectrum for different samples in different stages of imbibition experiments; (a) L2, (b) L4, (c) L5 and (d) L11. The oil in the pore space is gradually displaced by DIWm due to imbibition, thus a remarkable decrease in the signal intensity of T2 occurs. The three original crests evolve into a single peak when SI ceases, except for the L5 sample (Fig. 1c), which has the lowest recovery rate because of the effect of its boundary conditions discussed in the following section. Taking L2 as an example, the amplitude of T2 for the left peak declines faster than that for the middle peak, which slightly decreases. This implies that oil production mainly comes from the contribution of micropores. Capillary force not only depends on the fluid types, but also the pore structure of porous media56, 57. The smaller pore size directly equates to a stronger capillary force. Therefore, the water is preferentially imbibed into the smaller pores. However, Yang et al.45 stated that the smaller pores may have a higher frictional resistance caused by roughness along the


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pore walls, the water film thickness, boundary layer effects and poor connectivity of pore structure, amongst other minor causes58. Hence, the efficiency of imbibition hinges on the effective capillary force. From the figure 1, it can be safely concluded that the effect of resistance has negligible effects on SI in tight media because of the major contributions of smaller pores for oil recovery. Furthermore, the middle peak of the T 2 curve slowly declines and vanishes until imbibition reached 19 h. This trend mainly demonstrates the variation of oil in mesopores with relatively weak capillarity. However, the part of the T2 spectra representing the small mesopores changes only slightly, and the magnitude of variation is even smaller than that for mesopores. This finding is contrary to the traditional theory of SI. A possible explanation might be that various pores with different sizes are connected through narrow pore throats, and form a complex pore network. Considering that the wettability of the samples used here is classified as water-wet, the water flows along the surface of pores and the flow rate is faster than that of oil due to the lower viscosity, thus oil will be partly trapped in the center of the pores22. The oil forms an immobile residual oil when water flows out of the pore in advance, as illustrated in figure 2. Because the center parts of pore are filled with oil, the rock surfaces are coated by the wetting layers, that is to say, the size of larger pores are reduced indirectly and would be detected as smaller pores. Therefore, the ultimate T2 spectra evolve into a single peak which is mainly distributed in the interval of small mesopores. Another possible interpretation may be the consequence of snap-off of NWP in larger pores. Because the tight samples are highly heterogenous, during the imbibition process rates of meniscus in smaller pores are faster than that for larger ones, and the meniscus would advance into the larger pores through interconnected pore throats. This would readily lead to the occurrence of snap-off59, 60

. NWP trapped in larger pores will reduce the size of larger pores. In addition, snap-off also breaks up oil into blobs

during the displacement of oil from reservoir rocks61, 62. Therefore, the larger pores are further detected as smaller pores by NMR.


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(a) Oil

Oil

(b) Water

Oil

Figure 2. (a) Oil distribution in small and large pores at the beginning of imbibition; (b) Oil distribution in small and large pores after SI of water begins. Figure 3 shows oil content variation in all types of pores for different samples under different stages of SI. The original oil content in each type of pores correspond to the values of oil content at initial time. There is a gradual drop in oil volume within the micropore, small mesopores and mesopores for all samples, apart from L5 sample. This is similar to the above results, and is most liked due to the unique boundary condition of the L5 sample. In the early periods, only a small amount of water is imbibed into the rocks, and therefore the viscous resistance between WP and NWP is small, resulting in a high rate of imbibition. With more and more water penetrating into rock samples, the rate of water imbibition experiences a marked decrease which could be attributed to the decrease in the mobility of oil and the increase of viscous force between WP and NWP during the process of countercurrent imbibition. About 1,500 minutes later, the curves of oil content for all types of pores begin to steadily decrease. In this moment, except for the case of L5, approximately 40% of the total oil in the micropores is displaced by water, 14% within the small mesopores and 22% for mesopores. The results are consistent with the above conclusion, that oil production is controlled by the micropores. Also, the difference between the oil recovery within the mesopores and small mesopores can be clarified by the previous analysis (see figure 2).


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40

40 (b)

(a)

Micropores Small mesopores Mesopores Macropores

20

L2

10

0

30

Oil content (%)

Oil content (%)

30

0

1000


20

10

2000

3000 4000 5000 Time (min)

6000

0

7000

L4

0

40 35

1000

2000

3000 4000 5000 Time (min)

6000

7000

(d)

(c)

30

30

25

Oil content (%)

Oil content (%)


20 15 10


20

10

L5

L11

5 0

1000

2000

3000 4000 5000 Time (min)

6000

7000

0

0

1000

2000

3000 4000 5000 Time (min)

6000

7000

Figure 3. Oil proportion of various pores versus time for samples (a) L2, (b) L4, (c) L5 and (d) L11.

3.2 Effect of Boundary Conditions From the above, the boundary conditions allowing countercurrent flow have critical impacts on the entrapment of oil or ultimate recovery. In this section, this influencing factor is investigated through imbibition experiments with NMR testing. The recovery curves of SI for each sample versus time are shown in figure 4. 30 25

Recovery (%)

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

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L2 L4 L5 L11

(AFO) (LEC) (TEO) (TEC)

6000

7000

20 15 10 5 0

0

1000

2000

3000 4000 5000 Time (min)


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Figure 4. Recovery versus imbibition time under different boundary conditions The figure above presents the imbibition recovery under different boundary conditions. It is apparent that little oil is displaced by capillary imbibition for sample L5 with TEO boundary conditions, which has the lowest oil recovery with a value of 6.8%. Sample L2 with AFO boundary conditions has the highest recovery (31%), followed by the L4 (LEC) and L11 (TEC). There is no significant difference in oil recovery among the latter three conditions. However, the majority of oil in a sample under TEO conditions is entrapped in the pore space, which is been reflected in the T2 spectra and oil content distribution for sample L5 (Fig. 1 and 3). This is due to the lateral surfaces of samples being the essential channels for SI, while the end surfaces of the sample contribute little to the ultimate recovery of oil (see Table 4). However, this finding is contrary to the previous studies17, 18 which have suggested that boundary conditions has no significant effect on the ultimate oil recovery in SI. This rather contradictory result may be due to variation in directional relative permeability and capillary pressure functions under different boundary conditions. To be specific, there exist different modes of fluid displacement for counter current spontaneous imbibition. In our present study, these cases are AFO (three-dimensional linear and radial flows), TEO (one-dimensional linear flows), TEC (two-dimensional linear flows) and LEC (threedimensional linear and radial flows)13. The relative permeability along with permeability in the axial direction might be less than that for radial direction because the tight rocks are generally highly anisotropic. Similar findings have also been concluded by other authors19, 20, even though those imbibition experiments were performed in a cocurrent mode in their works. However, the hypothesis of permeability and relative permeability contrast need to be further investigated, and this is our future work. Furthermore, all samples have higher rates of SI in the early phases, and when the imbibition experiments reach 1,000 min, almost 70% of oil production is displaced.


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Table 4. Oil distribution in samples under various boundary conditions Time BC

Legend 0h

43h

120h

60000 TEO

50000 40000

TEC

30000 AFO

20000 10000

LEC

0 BC: boundary condition, other terms are the same as previous definitions.

The effect of boundary conditions on SI could be further elucidated through MRI technology, shown in Table 4, which illustrates the oil distribution of different stages. The dark color represents white oil and light-colored zone denotes deionized water. The surrounding light-colored parts occurring in the samples at the initial stage might be caused by signal noise. It is obvious that the change in oil saturation only appears in the two ends of the sample under TEO because the lateral surfaces are sealed and a large amount of oil remains in the sample. However, asymmetry in oil production under TEO is observed, and this ambiguous behavior cannot be explained through the assumption that oil will be evenly displaced by SI from the two ends with a no-flow boundary at the middle of the core. Meng et al. 63 indicated that the difference in capillary back pressure of the two ends of the core can cause asymmetrical oil production. The capillary back pressure is related to the pore size at the open faces of the sample, which may differ in the same core 64. Moreover, because the samples were placed in the containers vertically, gravity is a driving force, helping water enter the upper end of the core sample while, and a resisting force for the lower end. So we suggest that the difference in the driving force for two ends also causes the asymmetrical oil production, although gravity may be ignored in general, especially for low permeability media. For TEC boundary conditions, oil production by SI is uniformly displaced through the lateral parts


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of rock. Compared with the situation of TEC, there are extra one-end and two-end surfaces added for SI for LEC and AFO conditions, thus they have a higher imbibition rate and ultimate oil recovery.

3.3 Effect of Surfactants A tight sandstone is characterized by low porosity and permeability, thus oil recovery from SI is also low. For instance, the highest recovery for sample L2 was less than 31%. A considerable portion of oil is trapped in pores, particularly the small mesopores, and develops into residual oil. Research on methods for increasing the proportion of mobile oil under SI for tight rocks has become increasingly common. Often, surfactants are added into the displacing fluid to improve the properties of the reservoir rocks and fluids. Surfactants on rock medium and fluids can enhance the deformability of oil blobs to decrease the fraction of residual oil, while reducing the adhesion work of oil at the rock surfaces by altering the wettability conditions to promote imbibition efficiency. Surfactants are capable of altering wettability from weakly water-wet or oil-wet towards water-wet in tight sandstone samples, and their efficiency depends on surfactant type and mineral composition. In this section, three types of surfactant solutions were used to qualitatively study the effect on imbibition recovery. Among which, Alkyl Polyglycoside (APG) is a nonionic surfactant which can alter the rock wettability at low concentrations while enhancing oil recovery65. Alcohol Ether Sulphate (AES) is an anionic surfactant with high chemical stability that has had a reported a 35%-50% displacement amount of residual oil in Berea sandstones by injection fluids with only 0.2%wt of AES 66. Sodium dodecyl sulfate (SDS) is an anionic surfactant with good water solubility and emulsifying performance that has been broadly used in oil field operations66. DIWm with 0.5 wt% surfactants were used for performing the imbibition experiments on samples under AFO condition and the results are shown in Figure 5. It should be noted that the influence of concentration of surfactants on oil recovery is not the subject of our research here, but rather to observe differences between these surfactants.


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1400

40

1200

(a)

30

L6 (final) L7 (final) L8 (final) L2 (final) L6 (initial) L7 (initial) L8 (initial) L2 (initial)

(b)

1000

20

L6 L8

Signal intensity

Recovery (%)

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels

L7 L2

800 600 400

10 200 0

0

1000

2000

3000 4000 5000 Time (min)

6000

7000

0 0.01

0.1

1

10 T2 (ms)

100

1000

10000

Figure 5. (a) Imbibition recovery of cores versus time for different surfactants. (b) T2 spectra distribution of cores for different surfactants before and after imbibition The test for sample L2 without adding surfactants was used as a comparative experiment. As seen from Figure 6a, sample L8 has the highest oil recovery, which increases by more than 33% compared with sample L2 without any surfactants. L6 also has a higher imbibition recovery, with only a slight increase from the baseline of L2. But for sample L7 with added APG, the recovery (27.56%) is actually less than that of the baseline L2 without added surfactants. These phenomena can also be clearly shown by the T 2 spectra distribution for different samples (Figure 5b). Obviously, the T2 spectrum of sample L8 has the smallest signal intensity, thus the highest imbibition efficiency. As can be seen from the final T2 spectra of each sample, the amplitude of L7 even exceeds that for L2, indicating a higher portion of residual oil. Interestingly, the increase in oil recovery of sample L6 is mainly attributed to the higher utilization degree of unrecoverable oil in small mesopores. Compared with the case without surfactants, it appears that AES could enhance the utilization degree of the immobile oil in all pores, especially the small mesopores and mesopores.


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Table 5. Contact angles and IFT NWP

WP

θ, º

σ, mN/m

σ·cosθ

WO

DIWm

73.01

22.88

6.686

WO

DIWm +SDS

48.7

9.78

6.455

WO

DIWm +APG

28.07

3.56

3.141

WO

DIWm +AES

46.15

9.9

6.854

The wettability alteration of rocks and the lowered lower interfacial tension (IFT) at the interface of oil and water can be utilized to explain the increase of oil recovery (see Table 5). However, in terms of oil recovery by SI, the primary driving force is capillary pressure, and a relatively high IFT is needed to maintain enough pressure. For example, although the wettability of L7 was converted into strongly water-wet, the value of IFT for L7 is only 16% of L2, which might be beneficial to water flooding but cannot facilitate the process of SI. On the other hand, the strength of capillary force in the samples could be qualitatively reflected using the value of σ·cosθ to some degree; L8 has the largest value thus the largest recovery of imbibition, L6 has a comparable value with L2 thus a similar recovery is obtained. The capillary pressure in L7 is greatly weakened in contrary to L2, thus oil is mainly trapped in mesopores (see the T 2 spectra in Figure 5). However, there is a notable increase of oil recovery for L8 which has similar IFT reduction and wettability alteration to L6. To clarify the discrepancy in oil recovery between L6 and L8, we have added the extra initial T 2 distributions for each sample to figure 5b because the T2 spectra of the rock samples under 100 % fluid saturated state can represent the characteristics of pore structure for porous media. It can be clearly seen that, L2, L6 and L7 have exactly similar pore structures, thus a higher value of “σ·cosθ” corresponding to a higher oil recovery. In contrast to the case of L6, sample L8 has a larger proportion of micropores and lower proportion of mesopores. According to the conclusions in section 3.1, the main contribution for SI comes from the micropores. Consequently, L8 has a higher oil recovery than L6 even though they have a similar wetting state and IFT.

3.4 Scaling of Imbibition Data


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It is evident from the above analysis that oil recovery by SI is associated with multiple factors. Scaling groups play an important role in predicting oil recovery and recovery rates as well as analyzing the imbibition data 60. Over the past several decades, various dimensionless scaling models have been proposed based on capillary diffusion and Darcy’s law. The earliest scaling equation describing SI in a reservoir was developed by Mattax and Kyte67, and their scaling model is only valid under restricted conditions and has limited applications (see eq 2). Ma et al. 68 revised this model through taking the characteristic length for various boundary conditions and sample sizes, and the viscosity of NWP into account (eq 3). The definition of the characteristic length69 for a rock medium can be expressed as eq 4. Mason et al.70 modified the viscosity term in the model presented by Ma et al., and the new scaling group can be used for scaling imbibition data with a wider range of viscosity ratios (eq 5). Schmid and Geiger et al.14, 71 proposed a scaling group which was derived rigorously from the extract analytical solution for countercurrent SI in water-wet systems with arbitrary petrophysical properties and incorporated all parameters present in two-phase Darcy model. Later, based on the model proposed by Schmid and Geiger71, Mirzaei-Paiaman and Masihi13, 72 considered the consistency between the scaling equations and common practices, and developed a new scaling equation for countercurrent and cocurrent imbibition in water-wet reservoir rocks. However, these scaling models need accurate capillary pressure curves and relative permeabilities of porous media. These key parameters are generally determined by experimental methods that are time-consuming and hard to perform, especially for tight rocks. In this study, Equation 5 is used for analyzing the imbibition data.

K  1 t  w L2

t D, MK 

K

t D , MZM 

L2c 



 1 t w nw L2c

(2)

(3)

Vb n

Ai

i 1

i

(4)

l

t D, MFMR 

2 L2c

 t  w  w nw

K

(5)

Where σ represents oil-water IFT, N/m; K is absolute permeability, m2;  is porosity; L is the length of the sample, m;


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μw, μnw are the viscosity of WP and NWP, respectively, Pa·s; t is imbibition time, s; Lc denotes the characteristic length, m; Vb is the bulk volume of rock sample, m3; Ai is the area for the ith imbibition face, m2; li is the distance between the imbibition the ith face and no-flow boundary, m. The above scaling equation do not allow for the effect of gravity, Schechter et al. 12 proposed the inverse Bond number NB-1 to evaluate the ratio of gravity and capillary forces, which is defined as:

N B1  C

 /K  gL

(6)

Where C equals 0.4; Δρ is the density difference between WP and NWP, kg/m3; g represents gravity acceleration, m/s2; the remaining parameters are the same as before. If the NB-1 is greater than 5 the flow is capillary dominated. The NB-1 for every sample is listed in Table 1. It becomes apparent that the assumption of ignoring gravity for scaling models we used is valid. 40 L2 L4 L5 L11 L6 L7 L8

30

Recovery (%)

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

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20

10

0 1E+02

1E+03

1E+04 Time (s)

1E+05

1E+06

Figure 6. Recovery from imbibition versus time


Page 21 of 27

Recovery (fraction of pore volume)

40 L2 L4 L5 L11 L6 L7 L8

30

20

10

0 1E-01

1E+00

1E+01 1E+02 tD,MFMR

1E+03

Figure 7. Imbibition data plotted with dimensionless time where recovery is normalized by the pore volume of each sample 1.0

Recovery (fraction of recoverable oil)

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels

L2 L4 L5 L11 L6 L7 L8

0.8

0.6

0.4

0.2

0.0

1E-01

1E+00

1E+01 tD,MFMR

1E+02

1E+03

Figure 8. Imbibition data plotted with dimensionless time where recovery is normalized by the ultimate recovery of each sample The oil recovery by SI versus time of all samples, plotted in Figure 6, is used to assess the ability of scaling model. Based on the basic parameters listed in Table 1 and 5, the results of scaling are shown in Figure 7 and 8, where the y-axis are expressed as a fraction of pore volume and fraction of recoverable oil respectively. The plot where y-axis is indicated with fraction of initial NWP volume is not added because these samples have similar original oil saturation before imbibition experiments. The scatter of imbibition data amongst the various samples is significant in Figure 6, the scaling correlation in Figure 7 and 8 are slightly better than that in Figure 6. However, the results are still unacceptable because of the inconsistent trend for these curves, especially for L5. The reason for the deviation of L5 might be caused by the


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TEO boundary condition, where the characteristic length is calculated on the basis of the assumption that the no-flow boundary is at the center of the sample. However, this is not consistent with observations with MRI. On the other hand, the difference in permeability and relative permeability between TEO and other boundary conditions may also result in the failures in scaling all the imbibition data, as discussed in section 3.3. Furthermore, the scaling curves of L6, L7 and L8 deviate from the consistent trend line for L2, L4 and L5 notably. Such scatter is mainly because the scaling equation has been established according to the assumption that the samples have similar wettability. While based on the results of the contact angle measurements (Table 5), the wetting states of these samples we used are originally weakly water-wet which is close to intermediate-wet. With adding various surfactants to the wetting phase fluid, the wettability of the cores can be changed remarkably from weakly water-wet towards more water-wet (Table 5). Thus, the wettability for imbibition system with surfactants or without surfactants is different and this model is unable to capture the dynamic properties of SI when wettability alteration occurs in samples. Overall, the previous scaling models were developed for water-wet reservoirs, and the capability of these models was confirmed by imbibition experiments at core scale under water-wet conditions. The understanding for weakly water-wet reservoirs or the case when wettability shift occurs is far from adequate, as noted by Figures 7 and 8, and the scatter produced by applying those models to different types of systems. Furthermore, surfactant treatment is the most common method for improving the wettability of rocks, and to our best knowledge, there is still not an approximate scaling model that can be used for scaling imbibition data when the wettability of rocks has been changed. Characterizing the effect of wettability alteration on SI is complex and challenging because changes in wettability of rocks affect the relative permeability and capillary pressure functions. Scaling group coupled with wettability shift should be further studied. In addition, the feature of non-uniform oil production of two ends of samples at TEO should also be considered.

4 Conclusions In this paper, the characteristics of oil/water displacement in various pores and several relevant effects on SI in tight sandstones were investigated with imbibition experiments combined with NMR testing. The conclusions are as follows:


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Energy & Fuels

Tight sandstone exhibits a multiscale pore structure, which is dominated by micropores and small mesopores, and the corresponding relaxation times are less than 10 ms. Oil in micropores is preferentially expelled by water because of the larger capillary force, and the contribution of oil recovery mainly comes from these micropores. The imbibition rate and ultimate recovery of samples are significantly affected by boundary conditions, both of which will be higher if more surfaces are available for water imbibition. In addition, this paper suggests that the surfactants can be used for altering the wettability of a tight sandstone from weakly water-wet to strongly water-wet, lowering the IFT to enhance the imbibition efficiency. Although, a relatively high IFT is still needed to maintain a strong capillary force. Furthermore, the currently established scaling model for water-wet reservoirs is inadequate when applied to rocks with altered wettability.

AUTHOR INFORMATION Corresponding Author *E-mail: [email protected]. ORCID Zhilin Cheng: 0000-0002-7087-565X Notes The authors declare no competing financial interest

ACKNOWLEDGEMENTS The authors would like to thank National Natural Science Foundation of China (51504265) and PetroChina Innovation Foundation (2017D-5007-0205) for the financial support.

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Experimental Investigation of Countercurrent Spontaneous Imbibition

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