Experimental Investigation on Imbibition-Front Progression in Shale

Article pubs.acs.org/EF

Experimental Investigation on Imbibition-Front Progression in Shale Based on Nuclear Magnetic Resonance Lin Hun, Zhang Shicheng, Wang Fei, Pan Ziqing, Mou Jianye,* Zhou Tong, and Ren Zongxiao College of Petroleum Engineering, China University of Petroleum, Beijing, China ABSTRACT: Spontaneous imbibition is the main mechanism responsible for the retention of large amounts of fracturing fluid during the flowback period in shale gas development. Studying the mechanism of imbibition will help optimize flowback design and improve the accuracy of production prediction. Previous experiments have mainly focused on studying the relationship between the amount of liquid imbibed into shale samples and the time. However, these experiments could not describe visually the liquid saturation distribution along rock samples. In this paper, a chemical potential-dominated flow mechanism model is presented, and nuclear magnetic resonance is adopted to obtain the water saturation distribution curve in the shale rock sample during spontaneous imbibition. The tight sandstone sample is also investigated for comparison. The effects of clay mineral content, fluid salt concentration, and surfactant solution on the water saturation distribution curve are systematically investigated. Results show that the advancing distance of the water saturation front in shale rock is shorter than that in tight sandstone at the same time. Furthermore, the slope of the curve in shale rock is higher. A positive correlation also exists between the front forward distance and clay content. Front forward distance is longer in sample with high clay content. Given the existence of osmotic pressure, the shale rock sample imbibed with water has longer front forward distance than the one imbibed with 10 wt % KCL solution. The shale rock samples imbibed with surfactant solution have a shorter water saturation front advancing distance because of lower capillary pressure. This study aims to provide a new method for the analysis of spontaneous imbibition in shale rock. The water saturation distribution curves can be used as target-match data to get fitted capillary pressure curves in a numerical simulation model of shale gas and obtain an accurate production prediction.

1. INTRODUCTION Shale gas is an unconventional resource that has huge reserves all over the world. Studies have proven that multistage hydraulic fracturing in horizontal wells is the most effective technology for exploiting shale reservoirs currently available.1 Compared with hydraulic fracturing in conventional reservoirs, hydraulic fracturing in shale reservoirs is characterized by the low flowback efficiency of fracturing fluid, thus resulting in the retention of large amounts of fracturing fluid in shale formation.2 After investigating large amounts of production data on shale reservoirs, it is found that the flowback efficiency of the fracturing fluid is only between 10% and 40%.3,4 The retarded fracturing fluid significantly increases the water saturation in the vicinity of the fracture surfaces, thus resulting in the blockage of gas flow and reduction of postfracturing productivity. When water saturation is close to 40%∼50%, gas well production will be seriously damaged.5 The results of 3D simulations of liquid loading in hydraulic fractures in horizontal wells showed that low drawdown, low matrix permeability, or low initial gas rate aggravates the liquid loading problem inside the fracture.6 Meanwhile, analyses of early time water and gas production data from the field indicate that wells with low flowback efficiency generally have higher early time gas production.7 The spontaneous imbibition of fracturing fluids into the shale matrix is one of the most important factors that contribute to fracturing fluid retention. Capillary pressure in formation pores is the fundamental cause of fluid retention.2,8 Imbibition experiments performed on shale cubes demonstrated that the imbibition process plays an important role in fracturing fluid retention.9 The loss of fracturing fluid is affected by the © 2016 American Chemical Society

permeability, capillarity, and heterogeneity present in the formation.10 A surfactant can effectively reduce the imbibition rate of fracturing fluid and the fact that the driving force of imbibition is capillary pressure.11 On the other hand, spontaneous imbibition can help to clean up water in fractures, resulting in enhancing gas effective permeability.12 In addition to capillary pressure, chemical potential difference has a non-negligible effect on water spontaneous imbibition.13 By studying the spontaneous imbibition of different brine concentrations, it is considered that osmosis pressure can serve as a driving force for brine to enter the shale basin and enhance gas production temporarily.14 It is reported that the salinity of formation brine can be higher than 150000 ppm and that the salinity of a typical fracturing fluid, such as slick water, can be as low as 1000 ppm. This huge salinity difference induces a considerable chemical potential difference between fracturing fluid and formation brine.15 In the absence of a hydraulic pressure gradient, the movement of mud into shale is mainly governed by the chemical potential difference between the mud and pore fluid.16 In fact, the flow generated by osmosis pressure not only is controlled by chemical potential difference but is also influenced by diffusion behavior because of the ionic concentration imbalance in both sides of the semipermeable membrane.17 The experimental results show that shale often absorbs more distilled water than 10% KCL solution under the same conditions, thus indirectly proving the Received: July 15, 2016 Revised: September 27, 2016 Published: October 12, 2016 9097

DOI: 10.1021/acs.energyfuels.6b01739 Energy Fuels 2016, 30, 9097−9105

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Energy & Fuels presence of chemical potential difference and its influence on spontaneous imbibition.18 Current studies on spontaneous imbibition in shale rock mainly employ the method that explores the relationship between the time and amount of liquid imbibed into shale samples.18−20 On the basis of this method, imbibition behavior in gas shale impacted by fractures, surfactant, and clay content is investigated. However, this method cannot effectively describe the liquid saturation distribution along rock samples at different times during spontaneous imbibition. Therefore, this method cannot be used to integrate experimental results with numerical simulation results. In light of this information, this paper focuses on describing the liquid saturation distribution (distance vs saturation) during spontaneous imbibition in shale rock with nuclear magnetic resonance (NMR) technology. First, a chemical potentialdominated flow mechanism model is presented to explain the driving force of spontaneous imbibition. Thereafter, the liquid saturation distribution from the experimental results is analyzed at various conditions. Factors that affect the shape of liquid saturation, such as rock type, clay mineral, salt concentration, and surfactant solution, are examined in detail. Liquid saturation distribution maps from experiments conducted by NMR are used as target-match data to get a fitted capillary pressure curve in the shale gas numerical simulation model. The fitted curve is then applied to a predictive validation case. The results from this study will help visualize the effect of different types of influencing factors on water front progression and provide detailed quantitative information for numerical simulation.

μB (T , p1 , x1, aq) − μB (T , p2 , x 2 , aq) = μB (T , p1 , l) + RT ln x1 − [μB (T , p2 , l) + RT ln x 2] Equation 6 is derived by combining eqs 5 and 3: μB (T , p1 , x1, aq) − μB (T , p2 , x 2 , aq) = [μB (T , pΘ , l) + + RT ln

Θ

dμB =

∫p

μwf − μwm Vw

p

Θ

VB , mdp

(3)

where μB(T, p, aq) denotes the chemical potential of component B in the solution; aq denotes the solution system; pΘ denotes the standard pressure; μB(T,pΘ,aq) denotes the standard chemical potential of component B in the solution. If solution B is an ideal solution, the chemical potential of solution B can be expressed as follows: μB (T , p , aq) = μB*(T , p , l) + RT ln xB

(6)

∫p

p1

VBdp + RT ln

(8)

= pwf − pwm +

xf RT ln Vw xm

(10)

As shown in eq 10, the chemical potential of the solution is related to the solution component, solute concentration, and pressure. When the salinity difference between the formation water and injected water is disregarded, the driving force is the hydraulic pressure pf − pm, that is, the conventional viscous force equation. During the spontaneous imbibition process, pf − pm refers to capillary pressure. By contrast, if the difference between the salinities of both types of water is considered, the driving force is the right side of eq 10. Among xf RT all the terms on this side, V ln x refers to the osmotic pressure

(2)

∫p

VBdp]

where μfw and μmw refer to the chemical potential of the fracturing fluid and the chemical potential of the formation water in the matrix, respectively; Vw refers to the partial molar volume of water; pfw and pmw refer to the pore pressures in the fracture and matrix; xf and xm refer to the molar fraction of the water molecule in the fracturing fluid and formation water, respectively. The molar fraction of the water molecule in the salt solution can be calculated by analyzing the mineral salts and their concentration. A comparison of the chemical potential difference and pressure difference shows that they are both driving forces of water migration and that Δμ/V has a dimensional pressure. Therefore, eq 9 can be rearranged as follows:

that is, μB (T , p , aq) = μB (T , pΘ , aq) +

p2

Θ

If the fracturing fluid enters the shale matrix through the hydraulic fracture and if the original water exists in the matrix, then the chemical potential difference between the original water and fracturing fluid is expressed as follows: xf μwf − μwm = Vw(pwf − pwm ) + RT ln xm (9)

(1)

VB , mdp

∫p

x1 x2

μB (T , p1 , x1, aq) − μB (T , p2 , x 2 , aq) x = VB(p1 − p2 ) + RT ln 1 x2

p

Θ

VBdp] − [μB (T , pΘ , l) +

x1 x 2 2 (7) If the partial molar volume fraction does not change with pressure, the chemical potential difference between different solutions can be written as follows:

where μB refers to the chemical potential of component B; SB,m and VB,m refer to the partial molar entropy and partial molar volume of component B, respectively; T and p refer to the temperature and pressure of the system, respectively. Under an isothermal condition, the chemical potential of component B can be derived from the direct integration of eq 1:

∫p

p1

Θ

μB (T , p1 , x1, aq) − μB (T , p2 , x 2 , aq) =

For a multicomponent solution system, the differential formula for the chemical potential of component B can be expressed as follows21

p

∫p

Thereafter,

2. CHEMICAL POTENTIAL-DOMINATED FLOW MECHANISM MODEL

dμB = − SB , mdT + VB , mdp

(5)

w

m

caused by the difference in the molar fraction of water, that is, the force driving the water to flow from the low-salinity side to the highsalinity side.22,23 Numerous studies have shown that the pores of shale are extremely wide in scale and are distributed unevenly in the shale reservoir;24−26 thus, the inorganic clay on the surface shows a nonideal semipermeable membrane, which allows ions to pass through by diffusion. Generally, membrane efficiency λ is adopted to indicate the selective capacity of a semipermeable membrane.16 π λ= (11) Π

(4)

where μ*B (T,p,l) represents the chemical potential of the pure solution; R represents the ideal gas constant, i.e., 8.314 J/(mol·K); xB represents the molar fraction of B in solution. On the basis of eq 4, the chemical potential difference of solution B between two different contents (x1 and x2) under different pressures (p1 and p2) can be expressed as follows: 9098


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Energy & Fuels where λ refers to the membrane efficiency; π refers to the measured chemical osmotic pressure; Π refers to the ideal osmotic pressure. Experimental data indicated that the efficiency of the semipermeable membrane of shale is less than 5%.27 Therefore, the chemical potential-dominated water flow in shale can be expressed as follows:

μwf − μwm Vw

= pwf − pwm + λ

xf RT ln Vw xm

(2) After the rock samples cooled down, they are placed on the permeable stone in a beaker which contains sufficient corresponding fluid to conduct the spontaneous imbibition process (Figure 1). The fluid enters the rock sample from the bottom of it. (3) At one measurement point, the rock samples are removed and scanned in the radial direction with a low-magnetic-fieldintensity NMR machine (MscroMR12-150) to identify the saturation distribution. And then, the rock samples are put back immediately to continue the spontaneous imbibition process until the next measurement point. (4) After all measurements are finished, the rock samples are completely saturated by the corresponding fluid with centrifugal acceleration, and the NMR machine is used again for scanning. Low-field NMR (L-F NMR) is widely used in the petroleum industry at present, especially in the field of unconventional oil and gas development.31−34 The principle of NMR is that when the fluid in the

(12)

In the following sections, eq 12 will be used to explain each influencing factor that affects spontaneous imbibition.

3. EXPERIMENTAL SECTION 3.1. Rock Samples. In this study, experiments are conducted on rock samples of varying permeability and porosity. The shale outcrops used in this study are from the strata of the Lujiaping Formation and Xujiahe Formation in Sichuan Basin; meanwhile, the tight sandstones are collected from the Chang 7 Formation. The porosities of the target rock samples are measured with a helium porosimeter (KXD − 3 type) which was made by Jiangsu Hua’an Scientific Instrument Co. LTD in China. Conventional petrophysical measurement methods cannot estimate the permeability of unconventional rocks accurately because of low permeability and porosity.28−30 Thus, the ultralow permeability measuring instrument (pulse-decay technique) which was made by Beijing Yongruida Technology Co. LTD in China is used to measure the samples permeability. The measurement results are listed in Table 1. The values of permeability and porosity in shale rock are

Table 1. Physical Properties of Rock Samples for Experiments Label

Lithology

Formation

Porosity, %

Permeability, 10−3 μm2

LJP1 LJP2 LJP3 XJH SY

Shale Shale Shale Shale Tight Sandstone

Lujiaping Lujiaping Lujiaping Xujiahe Yanchang

1.5 1.4 1.2 1.0 4.8

0.0028 0.0025 0.0023 0.0033 0.067

Figure 1. Tested shale rocks on permeable stone in the beaker. formation is exposed to an applied magnetic field, the energy level transition associated with energy absorption and release will occur after absorbing one specific frequency of a radiofrequency pulse. In this study, the MscroMR12-150 NMR machine, which is a new generation measuring instrument, is used to analyze the water saturation distribution by acquiring NMR signal spectral lines. Compared with previous generation NMR machines, MscroMR12-150 (Figure 2) adopts a set of independent radiofrequency emission and reception systems to increase the ratio between the signal and noise. This feature significantly increases the accuracy of experimental data. MscroMR12-150 consists of five systems: the central control system, radiofrequency system, gradient system, magnetic body, and constant temperature system (Figure 3). The central control system is in charge of receiving orders from operators and delivering them to the remaining systems to increase operational efficiency. The radiofrequency system is mainly responsible for emitting radiofrequency pulses and receiving resonance signals, and the magnetic body generates a uniform and stable main magnetic field. The gradient system aims to provide a gradient magnetic field, whereas the constant temperature system guarantees the stable operation temperature of the magnetic body. The magnetic field intensity is 0.52 T, which is suitable for small-/middle-size cores. A NMR imager can be utilized to analyze the distribution of water saturation within shale in slicing ways (Figure

considerably lower than that of tight sandstone regardless of the origin of the shale rock formation. From the point of view of shale formation, the porosity values of the rock samples are all between 1% and 2%, whereas the rocks from Lujiaping have higher permeability than the ones from Xujiahe. LJP1, LJP2, and LJP3, which are supposed to determine the different imbibition influencing factors, originate from the same rock plug. Therefore, their petrophysical properties are similar. X-ray diffraction is used for mineral component analysis to obtain different results in terms of the predominant mineral in different shale samples (Table 2). The quartz in the LJP formation accounts for the highest mineral content with a value of 48.2%, followed by that in XJH at 43.1%. The content of clay minerals (predominantly in forms of smectite and Illite-smectite mixed-layers) in the XJH formation is 44.5%, whereas those in LJP and SY have mean values of 31.1% and 20.6%, respectively. 3.2. Experimental Procedure and Apparatus. (1) All rock samples are placed in an oven at 95 °C to dry until the weight stays constant.

Table 2. Results of XRD Mineralogy Analysis Relative abundance, % Label

Smectite

Illite

I/S

Chlorite

Kaolinite

Clay

Quartz

Feldspar

Calcite

Dolomite

other

LJP XJH SY

8.8 5.2 6

7.2 11.5 75

73.3 82.1 0

7.2 0 11

3.5 1.2 8

31.1 44.5 20.6

48.2 43.1 40.2

7.5 5.2 34

4.5 2.8 1.4

2.1 1.7 2.3

6.6 2.7 1.5

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signals of the targeted object instead of the water saturation. Therefore, the resonance signals should be transformed into water saturation. After spontaneous imbibition experiments, the rock samples are completely saturated by the corresponding fluid by centrifugal acceleration, whose speed is 7500 r/min, to increase the saturated speed, until the results of NMR scanning are unchanged any longer. As a result, saturation is assumed to be at 100% at any section in the whole rock sample. The NMR machine then scans the rock samples and receives the resonance signals at various positions 4 mm apart from each other. The results are used as the benchmark in the following calculation. The water saturation at different positions inside the rock can then be calculated from the corresponding amplitude, which is given by the following equation:

Figure 2. Photo of MscroMR12-150 NMR.

Sw(x) =

T (x ) T (x)100%

(13)

where x stands for the distance between the measuring section of the NWR and the imbibition surface, mm; T(x) and Sw(x) are the respective measured amplitude and predicted water saturation at the position at a distance of x from the imbibition surface; T(x)100% represents the measured amplitude at x distance when the rock sample is completely saturated. 4.2. Curve Characteristics. First, the LJP1 was imbibed with the water. Figure 5 shows the typical curve describing the

Figure 3. Schematic for MscroMR12-150 NMR.

Figure 5. Water saturation distribution at different times in LJP1.

water saturation distribution along the length of the rock sample in this study. The x-axis represents the distance from the imbibition surface, and the origin of the coordinates corresponds to the imbibition face of the rock sample, which represents the interface between the fracture and reservoir matrix. The y-axis represents the water saturation at each position. In the process of the whole spontaneous imbibition, the NMR apparatus scanned the rock sample at intervals of 12 h and 1, 3, and 7 d, respectively. Therefore, four water saturation values versus distance lines can be obtained on the plot. As the designed experimental method aiming to mimic the spontaneous spreading of water-based fracturing fluid during shut-in time conditions, a constant supply of water should be maintained into the rock sample. Hence, the initial position of the y-axis all starts from 100%. This condition is different from

Figure 4. Schematic diagram of water saturation measurement in NMR. 4). The testing samples are cylinders with a diameter of 25.4 mm. The thicknesses of the shale rock and tight sandstone are 30.0 and 50.0 mm, respectively. Meanwhile, the testing temperature is 18−22 °C.

4. RESULTS AND DISCUSSION 4.1. Data Processing. Although the NMR imager can detect the water saturation distribution trend inside the rock after imbibition, the machine directly receives the resonance 9100


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Energy & Fuels that in Experiment 2 in Dutta et al.,10 which starts from a leak off volume without constant water supply. The experimental result shows that water saturation decreases gradually from 100% to 0% with the increasing distance from the imbibition surface. Given the heterogeneity of the shale rock sample, such as tortuosity and pore size distribution,35 fluctuations in lines can be somehow observed in Figure 5. This result is consistent with the numerical analysis result stating that the degree of rock heterogeneity determines the speed and shape of the imbibition-front progression.36 After 12 h and 7 d, the water saturation front reached 15.5 and 24.6 mm, respectively. The closed area between each curve and axis represents the amount of imbibition water at each time. The area increases with increasing imbibition time. This result is in line with the results of Ge et al.18 However, the increasing area rate and the advancing water saturation rate decrease with increasing time, thus indicating that the imbibition process reaches equilibrium slowly.19 For tight sandstone sample SY (Figure 6), the water saturation front reached 33.3 mm at the first measurement

conduct a comparison experiment. Figure 7 shows the relationship between the distance and water saturation of

Figure 7. Water saturation distribution at different times in XJH.

shale rock sample XJH. The results show that, at each measurement point time, all front forwarding distances of XJH are longer than that of LJP1 without any exception. Moreover, for the area between each curve and axis, XJH is larger than LJP1. This result implies that a larger amount of water enters the XJH rock sample by spontaneous imbibition. The XRD results listed in Table 2 show that the clay content in rock sample XJH (44.5%) is higher than that in rock sample LJP (31.1%). From the perspective of clay type, rock sample XJH has no chlorite, whereas smectite and I/S are the main components of clay content. Obviously, a positive correlation exists between the front forward distance and clay content in the rock sample. Higher clay content corresponds to longer front forward distance. Water adsorption and clay swelling can induce microfractures in shale, resulting in enhancing the shale permeability and in turn the imbibition rate.12,41,42 Furthermore, high clay content lead to high capillary pressure. According to eq 12, the water saturation front can move forward further under the circumstance of high capillary pressure. High clay content can also result in large membrane xf RT efficiency λ. As a result, λ V ln x , which is a component of

Figure 6. Water saturation distribution at different times in SY.

point, and it spread forward to 43.1 mm at the last point. The advancing speed of the water saturation front in sample SY is relatively faster than that in the shale rock sample at each measurement point. Furthermore, the shape of the saturation curve that evolves with time is distinctly different from that of the shale case. The curve of water saturation decreases slowly in tight sandstone, thus increasing the area between the curve and axis and increasing the spreading distance. By contrast, the slope of the curve in the shale rock is steep, thus resulting in the short forward distance of water saturation in the same period. Take the case of the yellow line (time = 12 h). The absolute value of the slope of shale rock is about 1.9; meanwhile, the absolute value of the slope of tight sandstone is approximately 1.5. The shape can be attributed to the strength of capillarity, the discrepancy in permeability, and the heterogeneous nature of the rock sample. The reason why the shale rock sample has high capillary pressure is that it has a small pore throat radius.37−39 Moreover, given the clay-rich region, the shale rock sample exhibits strong heterogeneity. 4.3. Clay Mineral. Compared with conventional reservoirs, a shale reservoir has relatively high clay content (up to 80%).40 To explore the effect of clay content on the water saturation curve in spontaneous imbibition, sample XJH is chosen to

w

m

driving force, increases. Therefore, clay content has a significant effect on the water saturation curve in spontaneous imbibition. 4.4. Salt Concentration. Shale reservoirs have a certain amount of salinity.15,43 In the process of geological conformation movement, the formation is under compaction and water is squeezed out from the origin place.44 Furthermore, a large amount water is consumed in the hydrocarbon generation process.45−48 Therefore, a big difference in salinity exists between pumped fracturing fluids and original water in formation. The fracturing fluid and original water in the formation have low and high salinity, respectively. Shale rock sample LJP2, whose properties are listed in Tables 1 and 2, is used in the experiment to explore the effect of salinity on the spontaneous imbibition process. The permeability, porosity, and clay content of LJP1 and LJP2 are fixed at specific values to eliminate the interference of other factors. According to the designed experimental procedures, LJP1 and LJP2, respectively, adopt deionized water and 10 wt % KCL solutions as imbibition fluid. After data processing, the result of 9101


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is less than that in LJP1 and that the saturation front advancing distance is shorter in LJP3 than in LJP1 during the same period. 4.6. Numerical Simulation. The fluid saturation distribution curves obtained from the experiments can be used to get fitted capillary pressure curves of the shale gas numerical simulation to obtain reliable simulation results. Compared with previous research, this study places great significance in combining the experimental and simulation results. The module IMEX of CMG simulator is adopted, and a horizontal well with a lateral length of 400 m is considered. It is completed with a three-stage hydraulic fracturing treatment. In each single stage, three transverse fractures are created along the horizontal wellbore with a fracture spacing of 40 m, and the fracture half-length is considered 200 m for each fracture. The thickness, length, and width of the shale reservoir are 30, 1000, and 800 m, respectively. The relevant parameters used in the numerical simulation are listed in Table 3.


each measurement point. Meanwhile, the amount of imbibition fluid is also smaller than that in LJP1. According to eq 12, during spontaneous imbibition in shale rock, fluid is driven not only by capillary pressure but also by the difference in the molar fraction of water, that is, osmotic pressure. The water entering LJP1 contains no salinity; thus, xf RT the value of V ln x is larger than that of 10 wt % KCL w

m

solutions. As a result, a more powerful driving force, namely, Δμ/V, stimulates spontaneous imbibition in LJP1. This is the reason why the front forward distance in LJP1 is longer than that in LJP2 at each measurement point. 4.5. Surfactant Solution. The surfactant solution, which provides low surface tension and interfacial tension, can reduce capillary pressure and alter contact angle.49−51 Thus, the surfactant solution is usually used to reduce water retention in the matrix.52 In order to show the effect of surfactant solution, the contact angle on LJP3 is measured by an imaging method (Figure 9). The contact angle is 38.3° and 88.4° before and

Table 3. Main Input Parameters for Production Numerical Simulation Models Parameters

Figure 9. Contact angle on sample LJP3.

after surfactant treatment, respectively. LJP3 is chosen to conduct imbibition experiments with the surfactant solution. The experiment procedures are stated in section 3.2. Figure 10 demonstrates the results of the LJP3 imbibition experiment. The front forward distance in LJP3 is shorter than that in LJP1, which is treated with water, at each measurement point. According to eq 12, pf − pm refers to the capillary pressure during spontaneous imbibition in shale rock. The surfactant solution is able to reduce capillary pressure; thus, the capillary pressure in LJP3 is lower than that in LJP1. This result indicates that Δμ/V, which represents the driving force, in LJP3

Value

Formation depth Initial water saturation Initial reservoir pressure

2000 m

Gas density at standard condition Volume proportion of source rock Source rock density

0.78 kg/m3

0.15 30 MPa

Parameters

Value

Matrix permeability Matrix porosity Hydraulic fracture conductivity Fracture width

0.001 × 10−3 μm2 0.02 2 μm2·cm 0.001 m

0.15

Langmuir’s pressure

3.5 MPa

3.45 × 103 kg/m3

Langmuir’s volume

6 m3/ton

The capillary pressure of rock samples from LJP is measured by the mercury intrusion method. And then, the data that is associated with mercury saturation is converted into a gas− water pattern, as shown in Figure 11 (red line). By matching water saturation distribution curves from numerical simulations and previous spontaneous imbibition experiments, a fitted curve can be obtained (green line in Figure 11). In fact, the CMG cannot take into account osmotic pressure. Thus, actual capillary pressure would be different once osmotic pressure is 9102


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Figure 13. Comparison of cumulative gas production before and after adjusting capillary pressure.

Figure 11. Comparison of capillary pressure between original and fitted curves.

considered. Figure 12 shows the matching result between the experimental work and simulation results in terms of saturation

samples. More experiments should be conducted in future work. From the results, the following conclusions can be drawn. (1) The use of NMR provides a new method for exploring spontaneous imbibition in shale rock because NMR can directly describe the water saturation distribution versus distance. (2) The shale rock sample has a shorter advancing distance of water saturation front than the tight sandstone sample at the same measurement time. Furthermore, the amount of imbibed fluid in the shale rock sample is less than that in the tight sandstone sample. (3) The water saturation front can move forward further under the circumstance of high clay mineral content. Meanwhile, the shale rock samples imbibed with 10 wt % KCL solution and surfactant solution all exhibit shorter water saturation front advancing distance than those imbibed with water. (4) A fitted capillary pressure curve obtained from matching can be used in shale gas numerical simulation to achieve more accurate results.

Figure 12. Match of water saturation distribution.

■

profiles as a function of distance. The capillary pressure curves are fitted until the two curves are closely approaching. The simulated cumulative gas production curves using the original capillary pressure and the fitted one are plotted in Figure 13. The two curves all increase gradually with increasing time. However, disparity still exists between the two curves. The modified cumulative gas production is less than that of the origin at each time point, thus implying that the prediction of cumulative gas production will be overestimated if the original capillary pressure curves are used. Ultimately, the modified cumulative gas production is nearly 10% lower than the original cumulative gas production. Therefore, it is meaningful to adopt the fitted capillary pressure curve in the shale gas numerical simulation model.

AUTHOR INFORMATION

Corresponding Author

*E-mail address: [email protected]. Notes

The authors declare no competing financial interest.

■

ACKNOWLEDGMENTS The authors would like to acknowledge the National Natural Science Foundation (No.51504266), Beijing Natural Science Foundation (No.3154038), and Science Foundation of China University of Petroleum, Beijing (No.2462015YQ0212) for their financial support.

■

5. CONCLUSION Experimental studies to investigate spontaneous imbibition in shale rock with the NMR technique have been carried out. The effects of clay mineral content, salt concentration of fluid, and surfactant on the water saturation distribution curve have been presented in the paper. Nevertheless, it is hard to get such samples so that there is nothing reproduced with additional

REFERENCES

(1) Guo, T.; Zhang, S.; Qu, Z.; et al. Experimental study of hydraulic fracturing for shale by stimulated reservoir volume. Fuel 2014, 128, 373−380. (2) Makhanov, K.; Habibi, A.; Dehghanpour, H.; et al. Liquid uptake of gas shales: A workflow to estimate water loss during shut-in periods after fracturing operations. Journal of Unconventional Oil and Gas Resources 2014, 7, 22−32.

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Experimental Investigation on Imbibition-Front Progression in Shale

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