1. Introduction
According to the “World and China Energy Outlook” (2021 Edition), China’s natural gas demand will maintain rapid growth, which is expected to reach 6000 × 108~6200 × 108 m
3 in 2035 and the task of increasing domestic production of natural gas is urgent [
1]. There are abundant tight sandstone gas reservoirs in China, accounting for about 27.5% of the total natural gas resources, mainly distributed in the Sichuan, Tarim and Ordos basins [
2,
3,
4,
5]. By the end of 2018, a total of 812 gas fields had been developed, and more than 80% of the gas fields had clear formation water bodies, such as edge water and bottom water in varying degrees [
6,
7,
8]. As development time increases, gas wells gradually start to produce water, which is the main issue affecting production stability and recovery in the development of gas fields. In tight reservoirs, matrix permeability might be reduced by more than 70% to 90% due to water blocking damage induced by liquid phase traps as shown in
Figure 1. On the one hand, this will lead to a sharp decline in gas well production, and even off production. on the other hand, water in the formation can block the reservoirs, and a large amount of natural gas reserves cannot be effectively recovered [
9]. Therefore, water blocking damage has emerged as one of the most significant issues limiting the efficient development of tight sandstone gas reserves [
10].
Many methods for removing water blocking damage have been developed, including raising the production pressure difference, introducing dry gas, preheating the formation, injecting miscible solvent and so on. The drawbacks of the procedures described above include a limited effective duration and a high cost of repeated operations [
11,
12,
13,
14]. Injecting chemical agents is another way to remove water blocking damage. It is necessary to formulate or synthesize water blocking removal agents depending on factors, such as surface tension, wettability, and capillary radius [
15]. By changing the capillary force, the liquid recovery in gas flooding could be enhanced, and the water saturation of pores will be reduced, which achieves the goal of reducing water block damage [
16,
17].
The water blocking removing agents are chemicals with low surface tension and wettability alteration ability. Hu et al. [
18] studied the wettability alteration ability of several different surfactants through capillary experiments. The surface tension was lowered to 25.49 mN/m after adding 0.5% XN-OP-2 treatment, and the contact angle reached 74.3°. It converted the glass surface to weak water wetting. Jiang et al. [
19] synthesized a dicationic fluorocarbon surfactant, which can increase the contact angle of strong water-wet surfaces to 100°. Spontaneous imbibition experiments indicate that the surfactant can make the rock surface hydrophobic and oleophobic. Sharifzadeh et al. [
20] investigated polymer surfactants containing fluorine groups, which made the rock surface hydrophobic, and the contact angle increased by 120°. Li et al. [
21] synthesized a water blocking removing agent by emulsion polymerization of acrylic acid and perfluorooctyl ethyl acrylate. The contact angle of the rock surface can be changed to 126°, and the free energy of the rock surface dropped from 73 mN/m to 8.2 mN/m at a concentration of 1.5%. Hoseinpour et al. [
22] proposed a new fluorocarbon-based wettability modifier, which can change the wettability of sandstone rock surface from liquid wettability to preferential gas wettability. After the chemical treatment of the sandstone slice, the contact angles of water and n-decane in the air–liquid-rock system were altered from 0° to 151° and 101°, respectively. Spontaneous imbibition of water and n-decane into the core sample was significantly reduced. The ultimate amounts of liquid imbibition were decreased to 0.03 and 0.16 PV. It demonstrated the sandstone slice was alternated to preferentially gas-wetting. However, fluorocarbon surfactants are difficult to be widely used in the field due to problems, such as environmental protection and high price [
23,
24,
25,
26].
In recent years, nanoemulsions prepared from non-fluorocarbon wetting modifiers by the low energy emulsification method have attracted more and more attention [
27,
28]. Nanoemulsions can reduce the surface tension of the solution and alter the wettability of the solid surface. At the same time, it has a nano-scale droplet size, which can migrate for a long distance in the pores sized less than 1 um. Liang [
29] evaluated the water blocking removing effects of DME with a droplet size of 10 nm, and studied the mechanism combined with spontaneous imbibition and nuclear magnetic resonance (NMR) experiments. It is concluded that the mechanism of removing water blocking is mainly through changing the rock core from water-wetting to gas-wetting. It can also reduce the capillary force by reducing the surface tension. Wang [
11] used CND AD1# with droplet sizes of 100 nm as the water blocking removal agent and explored the water blocking removal effect in rock cores with different permeability. However, the existing studies simply focus on the performance evaluation of the water blocking removal effect with nanoemulsions. There is a lack of mechanistic and structure studies on the water blocking removal of nanoemulsions. Moreover, the relationship between the structure and water removing abilities of the nanoemulsion lock is unclear.
This manuscript firstly synthesizes a series of nanoemulsions with different droplet sizes by a low-energy emulsification method. Then, through the surface tension test, wettability test, adsorption curve measurement and NMR experiments, the surface activity, wetting modification, adsorption characteristics and removal water blocking damage ability of nanoemulsions with different droplet sizes were comprehensively evaluated. Furthermore, the optimized nanoemulsions formula was recommended, and the microscopic mechanism of nanoemulsions removing water blocking damage in tight gas reservoirs was revealed. Based on these studies, nanoemulsions can be used as a promising additive to remove water blocking damage and improve the production in tight gas reservoirs.
2. Experiments
2.1. Experimental Materials
Surfactant ALPE (alkylphenol polyoxyethylene ether, industrial product, purity 80%) was purchased from Beijing Kemax Oilfield Chemical Co., Ltd. Glycerol, sodium chloride (99%, A.R. grade), potassium chloride (99%, A.R. grade), sodium sulfate (99%, A.R. grade), calcium chloride (99%, A.R. grade) and sodium bicarbonate (99%, A.R. grade) were purchased from Sinopharm Group. D-Limonene was purchased from Aladdin Company. All chemicals were of analytical grade without further purification.
The experimental cores were taken from the Changqing Oilfield, and the gas layer depth was 3762.79 m. The specific parameters are shown in
Table 1. The mineral composition obtained by XRD mineral analysis is shown in
Table 2, and the lithology is sandstone. The natural cores were washed with a Soxhlet extractor for further experiments. The types and contents of ions in formation water are shown in
Table 3.
2.2. Nanoemulsion Formulation
Low energy emulsification is an economical and efficient approach to preparing nanoemulsions. In this paper, the microemulsion dilution method is used according to the literature [
30].
Figure 3 illustrates the experimental approach. The first step is pre-emulsification. Water, glycerol, surfactant (ALPE) and oil phase (D-limonene) are mixed uniformly under stirring conditions to obtain a microemulsion, namely a stock solution. The second step is next to dilute the stock solution with water under stirring conditions to obtain nanoemulsions with stable droplet size. The droplet size of nanoemulsion is later found to be related to the oil phase content in the stock solution.
To investigate the influence of nanoemulsions with varying droplet sizes on their ability to remove water blocking damage, five different kinds of stock solutions with varying oil phase content were synthesized. The five stock solutions were numbered 1#–5#. Five stock solutions were diluted to obtain five nanoemulsions of varying droplet sizes. The five nanoemulsions were numbered CND1#–CND5#, as shown in
Table 4. The concentration of nanoemulsion refers to the mass fraction of the stock solution. For example, 0.1 wt.% CND1# is 1# with 99.9 wt.% water.
2.3. Physical Properties Evaluation of Nanoemulsion
2.3.1. Contact Angle Test
The cores were cut into 1 cm slices and then soaked in nanofluid or brine for 6 h. The surface of the rock was dried. The rock slices were placed on the contact angle tester JYB-P (Chengde King and Instrument Manufacturing Co., Ltd., Hebei, China), and a 10 μL formation water drop was injected into the rock surface by a microtubule. The contact angle at the interface was measured with analysis software. The core before and after nanoemulsion soaking were measured, respectively. The experimental temperature is room temperature and the experimental pressure is 0.1 MPa. The schematic diagram of the experimental device is shown in
Figure 4.
2.3.2. Interfacial Tension Test
The instrument used in the experiment is the BZY-2 surface tensiometer (Shanghai Hengping Instrument Factory, Shanghai, China). Firstly, distilled water and alcohol were used to calibrate the interface tension meter. Then, different concentrations of nanoemulsions were prepared, and the surface tension between the solution and air was tested by the du Nouy Ring method. Each concentration was tested five times, and then the arithmetic mean value was taken. The experimental temperature was room temperature and the experimental pressure was 0.1 MPa.
2.3.3. Droplet Size Test
The Zetasizer Nanolaser nanoparticle size analyzer was used to measure its droplet size. The concentration of nanoemulsion was 0.1%. The experimental temperature was room temperature and the experimental pressure was 0.1 MPa. The peak particle size was used in the manuscript.
2.4. Static Adsorption Characteristics of Nanoemulsion on Rock Surface
2.4.1. Measurement of Light Absorption Peak and Preparation Standard Curve
The light absorption intensity curves of five nanoemulsions (0.1 wt.%) were measured by spectrophotometer in the wavelength range 190–340 nm. The curve peaks were selected as the test wavelength. By measuring the absorbance of various concentrations of the nanoemulsions at the test wavelength, the curve of the light absorption intensity of the nanoemulsions versus the concentration was drawn, as shown in
Figure 5. With the increase in the nano-solution concentration, the absorbed light intensity gradually increased and tended to be stable after a certain concentration. This standard curve pattern has also been observed in a similar system [
17].
2.4.2. Chemical Adsorbing Test of Nanoemulsions
We added 10 mL of 0.1 wt.% nanoemulsions or 0.025% ALPE solution to 1.5 g of 70/100 mesh rock powder, and let it stand at room temperature for a period of time. The experimental time was set to 20 min, 40 min, 1 h, 3 h, 6 h and 24 h, respectively. Then, the mixture solutions were centrifuged for 15 min at 4000 RPM, and the supernatant fluids were taken for spectrophotometric measurements. From the change of absorbance over time, the loss of nanoemulsions absorbed by rock surfaces can be quantified.
2.5. Evaluation of Water Blocking Removal Effect
The hydrogen nucleus 1 H in a water molecule has a permanent magnetic moment and hence, produces a remarkable NMR signal. NMR is used to evaluate the distribution of water in pores of different sizes by measuring the relaxation time of hydrogen signals. This paper uses a three-dimensional NMR analyzer named MacroMR12-150 H from Suzhou Newmai Electronic Technology, Suzhou, China. Nuclear magnetic resonance T2 spectrum technology was used to quantitatively analyze the water blocking removal mechanism. The schematic diagram of the experimental device was shown in
Figure 6. The specific experimental steps were as follows:
Step 1: Put the core in a vacuum environment for 4 h, and then saturate it with formation water for 24 h at 20 Mpa.
Step 2: Load the core into the NMR device and inject nitrogen with constant pressure. The displacement pressure was 0.1 MPa and the temperature was 80 °C. The NMR T2 was measured every 5 min, and the water displacement at the outlet was recorded; the total displacement time was 30 min. After 30 min of displacement, the core’s permeability was tested with nitrogen. The core permeability K1 is obtained.
Step 3: Switch the valve and reversely inject the nanoemulsion 3–4 PV. Then the valve was closed and the rock core aged with nanoemulsions for 6 h.
Step 4: Switch the valve and inject 15–20 PV of formation water in the forward direction. Nitrogen was then used to displace the water in the core. The displacement pressure was 0.1 MPa, the temperature was 80 °C, the nuclear magnetic T2 was measured every 5 min, and the drainage volume at the outlet was recorded; the total water displacement time was also 30 min. After 30 min of displacement, the core’s permeability was tested with nitrogen. The core permeability K2 was obtained.
Step 5: the recovery rate of permeability is calculated according to Formula (1).
where V is the permeability recovery rate, %; K
a (in this case it means K
1 or K
2) is the permeability of gas flooding after the formation of water, mD; K
0 is the gas permeability of the dry core, mD.