*2.8. Microscope Test*

The soaked sample was naturally dried for 24 h, and the adsorption state of drilling fluid on the sample surface was observed with SQ500MF high-power integrated video microscope produced by Shanghai victory & Shuangquan tech. (Shanghai, China). The magnification factor is 100, and the distribution state of different drilling fluids on the sample surface was observed by comparing with the sample soaked in water to further analyze the adsorption principle.

#### *2.9. NMR Scanning Test*

The soaked sample was wrapped in PTFE tape to reduce water evaporation. NMR scanning with MacroMR12-150H-I NMR scanner produced by Suzhou Niumag Analytical Instrument Corporation was used to obtain *T*2 spectrum and signal imaging. The *T*2 spectrum was converted into the pore size distribution to compare the pore size distribution of each sample under the saturated state.

According to the basic principle of NMR scanning imaging, the relaxation characteristics of fluid in porous media can be expressed by Equation (4). According to Equation (4), the relaxation time of NMR *T*2 is in direct proportion to the pore size (*D* = 2 *r*). If *C* = 2*Fs*ρ*2*, the Equation (5) can be obtained. The *T*2 spectrum of rock can be converted into pore size distribution curve by Equation (5).

$$\frac{1}{T\_2} \approx \rho\_2 \frac{s}{v} = F\_s \frac{\rho\_2}{r} \tag{4}$$

$$D = \mathbb{C}T\_2\tag{5}$$

where *T2* is NMR transverse relaxation time, ms; ρ*2* is rock transverse surface relaxation strength coe fficient, nm/ms; *S* is total pore surface area of rock, nm2; *V* is pore volume of rock, nm3; *r* is pore radius, nm; *Fs* is geometric shape factor (spherical pores, *Fs* = 3; Cylindrical pores, *Fs* = 2); *D* is pore diameter of the rock, nm; *C* is rock conversion coe fficient, nm/ms.

#### **3. Results and Discussions**

## *3.1. Mineral Analysis*

XRD test results of samples are shown in Figure 1. The results show that the mineral content in the sample is 25% montmorillonite, 20% pyrophyllite, 16% illite, 13% quartz, 12% kaolin, 11% pyrite and 3% anatase. Clay minerals are mainly montmorillonite and illite with content up to 53.

**Figure 1.** The mineral analysis of coal bed methane (CBM) reservoir sample.

#### *3.2. Statistical Analysis of Rheological Properties*

The rheological parameters of the solid-free drilling fluid with di fferent concentrations of TX-10, HSB1618 and penetrant T are shown in Table 2. The apparent viscosity of basic fluid + HSB1618 is the largest, indicating the maximum consistency. When the surfactant concentration is 0.10%, the API filtration of basic fluid + HSB1618 is also the minimum. On the contrary, the apparent viscosity of basic fluid + penetrant T is the smallest, the filtration is the largest, and the performance parameters of basic fluid + TX-10 are in the middle. The funnel viscosity and apparent viscosity of several drilling fluids have the same rule. No matter what kind of surfactant is added, the API filtration is small and the filter cake is thin and tough, which is an ideal drilling fluid parameter and has good wall protection e ffect.


**Table 2.** The rheological properties of solid-free drilling fluid.

The horizontal displacement of CBM reservoir is long, and cuttings are not easy to be carried during drilling, so the rheological property of drilling fluid should be adjusted to make it have good suspension and rock carrying capacity. The yield point of the solid-free drilling fluid with di fferent concentrations of surfactants is shown in Figure 2. As can be seen from the figure, the yield point of basic fluid + penetrant T is very small, while basic fluid + HSB1618 and basic fluid + TX-10 have higher yield point. The difference increases with the concentration of surfactant and is very small when the concentration is 0.05%. As the concentration of surfactant increases, the yield point of basic fluid + HSB1618 and basic fluid + TX-10 increases, while basic fluid + penetrant T has an obvious downward trend. In conclusion, the results show that the basal fluid + HSB1618 has higher yield point, better rock-carrying and hole-cleaning capacity.

**Figure 2.** The yield point of solid-free drilling fluid.

The gel strengths of the solid-free drilling fluid with different concentrations of surfactants is shown in Figure 3. It can be seen from the figure that when the concentration of surfactant is 0.10% and 0.15%, the gel 10 min and the gel 10 sec of basic fluid + TX-10 and basic fluid + HSB1618 have sufficient range, while the gel strengths of basic fluid + penetrant T is very small, and the difference between the gel 10 min and the gel 10 sec is very small. With the increase of surfactant concentration, the gel strengths of basic fluid + TX-10 and basic fluid + HSB1618 increased, while that of basic fluid + penetrant T decreased. At the concentration of 0.05%, the gel strengths of basic fluid + HSB1618 is less than that of basic fluid + TX-10. With the increase of the concentration, the gel strengths of basic fluid + HSB1618 is gradually greater than that of basic fluid + TX-10. The results show that the basic fluid + TX-10 and the basic fluid + HSB1618 have good suspension performance at the surfactant concentration of 0.10% and 0.15%, which can effectively reduce the formation of cuttings bed in the horizontal section of CBM reservoir drilling.

**Figure 3.** The gel strength of solid-free drilling fluid.

The plastic viscosity of the solid-free drilling fluid with different concentrations of surfactants is shown in Figure 4. The plastic viscosity reflects the internal friction between suspended particles and liquid phase as well as continuous liquid phase in the dynamic equilibrium of the destruction and recovery of network structure in drilling fluid under laminar flow. The main factor affecting the plastic viscosity is the content of solid phase, the higher the content of solid phase, the greater the plastic viscosity. In addition, clay dispersion and polymer viscosifier also have an impact on the plastic viscosity, because they can affect the volume fraction or liquid viscosity. In these drilling fluids, basic fluid + TX-10 and basic fluid + HSB1618 have higher plastic viscosities than basic fluid + penetrant T. Surfactants TX-10 and HSB1618 act as viscosifier in drilling fluids, and penetrant T acts as viscosity reducers. With the increase of surfactant concentration, the plastic viscosity of the basic fluid + TX-10 and the basic fluid + HSB1618 increases, and the basic fluid + penetrant T decreases. The change of surfactant and its concentration change the plastic viscosity of drilling fluid by changing the liquid viscosity.

**Figure 4.** The plastic viscosity of solid-free drilling fluid.

#### *3.3. Micro Analysis of Drilling Fluid Suspension Performance*

According to the experimental data of laser particle size analysis, the particle size ranges of basic fluid + TX-10, basic fluid + HSB1618 and basic fluid + penetrant T are 22.664–637.059 μm, 29.703–1118.3 μm and 0.049–2.603 μm, respectively. Basic fluid + HSB1618 suspended rock powder has the largest particle size, followed by basic fluid + TX-10, and basic fluid + penetrant T is the smallest. The particle size of the first 20 differentials is select to draw a graph, and the particle size analysis of the suspended rock powder in the solid-free drilling fluid is shown in Figure 5. With the increase of surfactant concentration, the differentials of rock powder suspended by basic fluid + TX-10 and basic fluid + HSB1618 increases, while the basic fluid + penetrant T does not change much. The maximum differential particle size of basic fluid + 0.15% TX-10, basic fluid + 0.15%HSB1618 and basic fluid + 0.15% penetrant T suspension is 164.744, 309.681 and 0.327 μm, respectively. The maximum differential particle size of basic fluid + 0.05%HSB1618, basic fluid + 0.10%HSB1618 and basic fluid + 0.15%HSB1618 are 150.539, 258.582, 309.681 μm, respectively. Basic fluid + HSB1618 has better suspension capacity, firstly because of its large consistency and gel strengths, and secondly because of the ionization of carboxyl, phenolic hydroxyl group and other functional groups on the rock powder surface, which makes the surface negatively charged. The compression of the double electric layer increases the electrostatic repulsion after HSB1618 is added, which is beneficial to the suspension of rock powder.

**Figure 5.** The particle size of the suspended rock powder in (**a**) basic fluid + TX-10, (**b**) basic fluid + HSB1618 and (**c**) basic fluid + penetrant T.

#### *3.4. Adsorption Mechanism of Drilling Fluid*

Drilling fluid with 0.10% (a) TX-10, (b) HSB1618, (c) penetrant T added to the basic fluid is shown in Figure 6. It can be seen from the figure that, when the concentration of surfactant is 0.10%, basic fluid + TX-10 and basic fluid + HSB1618 are rich in foam, while basic fluid + penetrant T has poor foamability. The foaming volume of the 200 mL of drilling fluid is 250, 240 and 200 mL, respectively. The basic fluid + TX-10 foam is loose while the basic fluid + HSB1618 foam is fine and uniform.

**Figure 6.** The basic fluid is added with 0.10% (**a**) TX-10, (**b**) HSB1618 and (**c**) penetrant T.

CBM reservoirs are highly absorbent which can absorb various liquids and gases. After di fferent drilling fluids (a) water, (b) basic fluid + 0.10%TX-10, (c) basic fluid + 0.10%HSB1618, (d) basic fluid + 0.10%penetrant T, the microscopic diagram of sample surface is shown in Figure 7. According to the figure, there is no significant change on the sample surface after soaking in water, and fracture can be clearly seen on the surface. The basic fluid + 0.10% TX-10 is block or strip on the sample surface with uneven distribution. The basic fluid + 0.10%HSB1618 is evenly spread on the surface of sample, showing a thin layer, while the basic fluid + 0.10%penetrant T has a small adsorption capacity on the sample surface, and is distributed in a granular or strip form with uneven distribution. In the dense adsorption layer of basic fluid + 0.10%HSB1618, the hydrophilic group of HSB1618 points to the aqueous phase, and the sample surface is changed from hydrophobic to hydrophilic.

**Figure 7.** The microscopic photos of sample surface soaked by di fferent drilling fluids: (**a**) water, (**b**) basic fluid + 0.10% TX-10, (**c**) basic fluid + 0.10%HSB1618 and (**d**) basic fluid + 0.10 penetrant T.

Penetrant T is an anionic surfactant with negative charge, while the carboxyl and phenolic hydroxyl group on the CBM reservoir surface ionizes, making the sample surface also negatively charged. The adsorption capacity of anionic surfactant on CBM reservoir surface is minimal due to electrostatic interaction. HSB1618 is a zwitterionic surfactant consisting of anionic and cationic surfactants, in which the cationic part is adsorbed by electrostatic interaction. TX-10 is a nonionic

surfactant that has no charge and cannot be adsorbed on the sample surface by electrostatic interaction. However, the hydrophobic non-polar groups such as aliphatic hydrocarbon and aromatic hydrocarbon on the sample surface make it hydrophobic. The main forces between nonionic surfactant and sample surface are hydrophobic and dispersive forces. In the case of minimal adsorption of penetrant T, basic fluid + penetrant T has better wetting effect, because penetrant T has high permeability, fast and uniform permeability, which can quickly fill pores on the sample surface to play a wetting role.

#### *3.5. Application of NMR Pore Throat Distribution Curve*

The NMR T2 spectrum of each sample obtained by MRI scanning was converted into pore throat distribution, as shown in Figure 8. The pore throats of the samples are concentrated in the interval 0.01~0.1 μm, and the curves presented a bimodal shape, with the right peak being lower, that is, the proportion of large pore throats is small.

**Figure 8.** Pore throat distribution of samples soaked by different drilling fluids.

By comparing the distribution of NMR pore throat of samples soaked by different drilling fluids, it is found that the average pore throat of samples soaked by drilling fluids is greater than that of samples soaked by water. As the surfactant in the drilling fluid is hydrophilic, the pore fluid of samples soaked in the drilling fluid is larger than that soaked in water, resulting in a slightly larger pore throat radius. The pore throat frequency distribution of the sample soaked by basic fluid + TX-10 is the highest, and the 0.026-μm pore throat frequency distribution reaches the highest, 7.7%. The hydrophilicity of different surfactants is different, and the pore throat distribution of the samples soaked by three kinds of drilling fluid is different. This difference is also related to the difference in drilling fluid NMR results and samples.

#### *3.6. Transverse and Longitudinal Section Imaging*

NMR scan imaging of samples soaked by different drilling fluids is shown in Figure 9. In terms of adsorption degree and residual amount, the cross-sectional imaging showed that the more red parts, the more liquid. The adsorption degree and residual amount in the sample ranged from large to small as basic fluid + TX-10, water, basic fluid + penetrant T and basic fluid + HSB1618. During immersion, the samples were placed longitudinally. In terms of saturation changes at different longitudinal positions, the cross-sectional imaging showed that the longitudinal saturation change from large to small was basic fluid + TX-10, basic fluid + penetrant T, basic fluid + HSB1618 and the water.

**Figure 9.** *Cont*. 481

**Figure 9.** NMR imaging of samples soaked by different drilling fluids.

The basic fluid + HSB1618 should be selected based on the comprehensive comparison of adsorption degree, residual amount and saturation changes at different positions in the longitudinal direction. At the same time, because of the strong heterogeneity of samples, the difference of each sample has an impact on the results. In the drilling process of CBM reservoir in Central Hunan, 3%KCl +0.1%Na2CO3 + 0.1%HSB1618 + 0.2%XC + 0.1%PAC can reduce the residual drilling fluid in CBM reservoir and further reduce the damage to the reservoir.

#### *3.7. E*ff*ect of Solid-Free Drilling Fluid Additive on Wettability of CBM Reservoir*

The dynamic and static contact angles of the solid-free drilling fluid to the sample are shown in Figures 10 and 11. It can be seen from the figure that the contact angle of the unsoaked sample is the largest and does not change with time. The contact angle changes very little after water soaking, which indicates that the wettability of water to sample is very weak. The contact angle of sample decreases after soaked in three kinds of solid-free drilling fluids, and the trend of dynamic contact angle decrease significantly, indicating that the three kinds of drilling fluids can greatly increase the moisture of sample. The wetting ability of drilling fluid added with 0.10% surfactant is different to some extent. The wetting ability of drilling fluid added with 0.10% surfactant is as follows: basic fluid + penetrant T, basic fluid + HSB1618 and basic fluid + TX-10.

**Figure 10.** The contact angle variation of solid-free drilling fluid to sample.

**Figure 11.** The contact angle of (**a**) original sample and sample soaked by different drilling fluids (**b**) water, (**c**) basic fluid + 0.10% TX-10, (**d**) basic fluid + 0.10%HSB1618 and (**e**) basic fluid + 0.10 penetrant T.

The curve of contact angle of sample with different concentrations (a) TX-10, (b) HSB1618 and (c) penetrant T added to the basic fluid is shown in Figure 12. According to the figure, with the increase of surfactant concentration, the wettability of the three drilling fluids to sample increases to different degrees, in which the wettability of basic fluid + TX-10 and basic fluid + HSB1618 increases significantly. The wettability of basic fluid + 0.05% TX-10 and basic fluid + 0.05%HSB1618 is similar to that of water, while basic fluid + 0.05% penetrant T can significantly increase the wettability of sample. When the surfactant concentration is 0.15%, the dynamic contact angle of the three drilling fluids fluctuates greatly, which greatly improves the moisture of the sample.

**Figure 12.** The contact angle variation of different concentrations (**a**) TX-10, (**b**) HSB1618 and (**c**) penetrant T added in basic fluid to sample.

#### *3.8. E*ff*ect of Solid-Free Drilling Fluid pH on Wettability of CBM Reservoir*

According to the rheological properties and wetting effect of drilling fluid, HSB1618, the surfactant with the best effect, is selected and the pH of drilling fluid is changed at the optimal concentration of 0.10%. The change of contact angle of drilling fluid pH to sample is shown in Figure 13. It can be seen from the figure that the contact angle increases between pH 8–10, that is, the hydrophilicity of sample decreases. pH 10–12 shows a decreasing trend, that is, the hydrophilicity of sample increase. The contact angle is the smallest at pH 12, and the wetting effect of the drilling fluid on the sample is maximized. The contact angle is the largest at pH = 10, and the hydrophobicity of the drilling fluid to the sample is minimal. The change of hydrophilicity of sample is because the change of drilling fluid pH affects the ionization degree of carboxyl and phenol hydroxyl group on sample surface, further changes the sample surface potential, and finally affects the wettability.

**Figure 13.** The contact angle variation of solid-free drilling fluid pH to sample.
