**1. Introduction**

Water blocking can damage the low permeability of a normally tight gas reservoir due to the increase of water saturation and the reduction of gas phase permeability in the process of drilling, completion, and stimulation. Zhong et al. [1] showed that the permeability damage rate in a gas reservoir could reach 70–90%, and the gas well production could decrease by more than 70% when water-blocking damage occurred. Therefore, it is important to develop an antiwater blocking agent with high efficiency and low cost for the development of a superior lowpermeability gas reservoir.

Besides, it possesses super-strong surface activity, and a very small amount can decrease the surface tension to less than 25 mN/m, while the cost is less than 1/10 of

*Performance Evaluation and Mechanism Study of a Silicone Hydrophobic Polymer…*

adsorption, wettability alteration, and quantum chemistry calculations.

siloxane, hydrophilic groups of sulfonic acid groups, and hydroxyls. The

have the same composition and similar porosity and permeability.

In this study, the influence of OSSF on the aqueous phase trapping damage was evaluated through the measurement of spontaneous imbibition distilled water saturation, water blocking damage rate, permeability recovery, and remaining water saturation. The mechanisms were explained using aggregates blocking, directional

In this study, OSSF and ABSN were used to alleviate the aqueous phase trapping damage to low-permeability sand formation. Both surfactants are water soluble and transparent liquids and were made in our laboratory. The relative molecular mass of an OSSF is 2000–3000. It includes a hydrophobic group of permethylated

polydimethylsilioxane chain enables the surfactant to have water-repelling characteristics and low surface tension. These properties enable its adsorption on the rock via multiple points of attachment and give the surfactant a long-term effectiveness. ABSN is quaternary ammonium salt cationic surfactant, and the hydrophobic tail is dodecyl benzene. **Figure 1(a)** and **(b)** shows the chemical structure of dodecyl benzene sulfonate triethanolamine (ABSN) and oligomeric organosilicon surfactant (OSSF), respectively. The artificial and reservoir cores used in the same experiment

The cores used in this study include artificial cores and reservoir cores. They have same compositions and similar porosity and permeability. The artificial cores (obtained from Haian Petroleum Scientific Research Instrument Co., Ltd. in Nantong, China) are mainly composed of quartz sand, which does not contain any water sensitive substance. Reservoir cores were drilled at the Yingxi exploratory area in the Qinghai oilfields. The physical characteristics of these cores are listed

fluorocarbon surfactants.

*DOI: http://dx.doi.org/10.5772/intechopen.90811*

**2. Experimental approach**

**2.1 Materials**

*2.1.1 Surfactants*

*2.1.2 Cores*

in **Table 1**.

**Figure 1.**

**169**

*Chemical structure of (a) ABSN and (b) OSSF.*

At present, most researchers consider water blocking as caused by capillary thermodynamics and dynamics [2]. The commonly used antiwater blocking agents include lower alcohol content agents (especially methanol), alcohol ethers, silyl ethers, hydrocarbon surfactants [3], and fluorocarbon surfactants, and " … the alcohols react with formation water in the reservoir to form low boiling point azeotrope, which is helpful for gasification and flow back of the injected water" [4]. Nasr et al. indicated that the glycol ether and polyethylene glycol monobutyl ether could remove the water blocking damage and improve the permeability of oil fields in Arab countries [5]. Zhang et al. evaluated the effects of methanol, ethanol, and ethylene glycol on alleviating the water blocking damage of the low-permeability sandstone gas reservoir. The results showed that methanol had the most favorable performance, followed by ethanol and ethylene glycol, respectively [6]. "Bai et al. compared the anti-water blocking effects of methanol and petroleum sulfonate on a low permeability gas reservoir and found methanol to have better performance … " Surfactants can reduce the surface tension and change the reservoir wettability from water wetting to gas or oil wetting [7]. Bang et al. reduced the water blocking damage and increased the fluid flow in the fracture reservoirs with an alcohol solution containing a fluorocarbon surfactant. They also reduced the water blocking damage of the condensate in gas reservoirs by applying the fluorocarbon surfactant. The results showed that the hydrated silanol groups could adsorb water from pore surfaces via covalent bonding with the alkenyl groups of fluorocarbon surfactants. This made fluorine-containing alkyl directionally arranged, changing the reservoir wettability from water wetting to oil wetting and finally increasing the gas phase permeability [8–10]. Li et al. developed an antiwater blocking agent containing perfluoroalkyl side chains by using a stepwise emulsion polymerization method, which showed low surface tension and interfacial tension. The surfactant can adsorb on the surface of the pore via chemical adsorption and modify the surface to preferential gas wetting [11]. Li et al. used two nonionic fluorocarbon surfactant methanol solutions for water phase displacement experiments and found that it could improve the permeability [12]. Liu et al. synthesized a cationic fluoride Gemini surfactant and recorded ultralow surface tension; moreover, its solution could remarkably reduce the damage of water blocking on low-permeability formations [13]. Liu et al. found that a wettability variation from water wetting to gas wetting was achieved by adding 0.1 wt% fluoride. The core flow tests indicated that both the flow back rate and gas relative permeability were significantly improved [14]. Biosurfactants such as *Sophora japonica*, trehalose lipid, rhamnolipid, peptide, and some polymer surfactants also show good prospects in relieving water blocking damage because they can change the wettability by adding a large amount of active groups adsorbed on the rock surface. Moreover, they are natural, environmentally friendly, and easy to produce in the industry. Zhang prepared a biosurfactant referred to as the stearic acid glucose ester methoside maleic acid diester, which can decrease the interfacial tension and overcome the water blocking effect. It has good thermal stability and chemical stability [15].

Due to the high cost and environment concerns of fluorocarbon surfactants, an oligomeric organosilicon surfactant (OSSF) contained functional groups such as the silicon hydroxyl group. The silicon oxygen chain and silicon methyl were prepared by polycondensation reaction [16]. Gas preferential wettability could be achieved by oriented adsorption of silicon methyl via hydrogen bonding or chemical condensation. It could also decrease the dynamic surface tension of fluids owing to faster interfacial adsorption of small molecules during diffusion adsorption.

*Performance Evaluation and Mechanism Study of a Silicone Hydrophobic Polymer… DOI: http://dx.doi.org/10.5772/intechopen.90811*

Besides, it possesses super-strong surface activity, and a very small amount can decrease the surface tension to less than 25 mN/m, while the cost is less than 1/10 of fluorocarbon surfactants.

In this study, the influence of OSSF on the aqueous phase trapping damage was evaluated through the measurement of spontaneous imbibition distilled water saturation, water blocking damage rate, permeability recovery, and remaining water saturation. The mechanisms were explained using aggregates blocking, directional adsorption, wettability alteration, and quantum chemistry calculations.

## **2. Experimental approach**

#### **2.1 Materials**

damage occurred. Therefore, it is important to develop an antiwater blocking agent

At present, most researchers consider water blocking as caused by capillary thermodynamics and dynamics [2]. The commonly used antiwater blocking agents include lower alcohol content agents (especially methanol), alcohol ethers, silyl ethers, hydrocarbon surfactants [3], and fluorocarbon surfactants, and " … the alcohols react with formation water in the reservoir to form low boiling point azeotrope, which is helpful for gasification and flow back of the injected water" [4]. Nasr et al. indicated that the glycol ether and polyethylene glycol monobutyl ether could remove the water blocking damage and improve the permeability of oil fields in Arab countries [5]. Zhang et al. evaluated the effects of methanol, ethanol, and ethylene glycol on alleviating the water blocking damage of the low-permeability sandstone gas reservoir. The results showed that methanol had the most favorable performance, followed by ethanol and ethylene glycol, respectively [6]. "Bai et al. compared the anti-water blocking effects of methanol and petroleum sulfonate on a low permeability gas reservoir and found methanol to have better performance … " Surfactants can reduce the surface tension and change the reservoir wettability from water wetting to gas or oil wetting [7]. Bang et al. reduced the water blocking damage and increased the fluid flow in the fracture reservoirs with an alcohol solution containing a fluorocarbon surfactant. They also reduced the water blocking damage of the condensate in gas reservoirs by applying the fluorocarbon surfactant. The results showed that the hydrated silanol groups could adsorb water from pore surfaces via covalent bonding with the alkenyl groups of fluorocarbon surfactants. This made fluorine-containing alkyl directionally arranged, changing the reservoir wettability from water wetting to oil wetting and finally increasing the gas phase permeability [8–10]. Li et al. developed an antiwater blocking agent containing perfluoroalkyl side chains by using a stepwise emulsion polymerization method, which showed low surface tension and interfacial tension. The surfactant can adsorb on the surface of the pore via chemical adsorption and modify the surface to preferential gas wetting [11]. Li et al. used two nonionic fluorocarbon surfactant methanol solutions for water phase displacement experiments and found that it could improve the permeability [12]. Liu et al. synthesized a cationic fluoride Gemini surfactant and recorded ultralow surface tension; moreover, its solution could remarkably reduce the damage of water blocking on low-permeability formations [13]. Liu et al. found that a wettability variation from water wetting to gas wetting was achieved by adding 0.1 wt% fluoride. The core flow tests indicated that both the flow back rate and gas relative permeability were significantly improved [14]. Biosurfactants such as *Sophora japonica*, trehalose lipid, rhamnolipid, peptide, and some polymer surfactants also show good prospects in relieving water blocking damage because they can change the wettability by adding a large amount of active groups adsorbed on the rock surface. Moreover, they are natural, environmentally friendly, and easy to produce in the industry. Zhang prepared a biosurfactant referred to as the stearic acid glucose ester methoside maleic acid diester, which can decrease the interfacial tension and overcome the water blocking effect. It has

with high efficiency and low cost for the development of a superior low-

permeability gas reservoir.

*21st Century Surface Science - a Handbook*

good thermal stability and chemical stability [15].

**168**

Due to the high cost and environment concerns of fluorocarbon surfactants, an oligomeric organosilicon surfactant (OSSF) contained functional groups such as the silicon hydroxyl group. The silicon oxygen chain and silicon methyl were prepared by polycondensation reaction [16]. Gas preferential wettability could be achieved by oriented adsorption of silicon methyl via hydrogen bonding or chemical condensation. It could also decrease the dynamic surface tension of fluids owing to faster interfacial adsorption of small molecules during diffusion adsorption.

#### *2.1.1 Surfactants*

In this study, OSSF and ABSN were used to alleviate the aqueous phase trapping damage to low-permeability sand formation. Both surfactants are water soluble and transparent liquids and were made in our laboratory. The relative molecular mass of an OSSF is 2000–3000. It includes a hydrophobic group of permethylated siloxane, hydrophilic groups of sulfonic acid groups, and hydroxyls. The polydimethylsilioxane chain enables the surfactant to have water-repelling characteristics and low surface tension. These properties enable its adsorption on the rock via multiple points of attachment and give the surfactant a long-term effectiveness. ABSN is quaternary ammonium salt cationic surfactant, and the hydrophobic tail is dodecyl benzene. **Figure 1(a)** and **(b)** shows the chemical structure of dodecyl benzene sulfonate triethanolamine (ABSN) and oligomeric organosilicon surfactant (OSSF), respectively. The artificial and reservoir cores used in the same experiment have the same composition and similar porosity and permeability.

#### *2.1.2 Cores*

The cores used in this study include artificial cores and reservoir cores. They have same compositions and similar porosity and permeability. The artificial cores (obtained from Haian Petroleum Scientific Research Instrument Co., Ltd. in Nantong, China) are mainly composed of quartz sand, which does not contain any water sensitive substance. Reservoir cores were drilled at the Yingxi exploratory area in the Qinghai oilfields. The physical characteristics of these cores are listed in **Table 1**.

**Figure 1.** *Chemical structure of (a) ABSN and (b) OSSF.*


#### **Table 1.**

*Physical characteristics of cores used in this study.*

#### *2.1.3 Fluids*

Triply distilled water was used in all experiments. About 4% of sodium bentonite mud was added with 0.2% Na2CO3 and then stirred for 2 days. It was used as the basic mud. Sodium bentonite was obtained from Weifang Hua Bentonite Group Co., Ltd. Na2CO3 is a commercially pure reagent.

at different times were defined as the water blocking damage rate. This rate can be

*Schematic of the apparatus used for spontaneous imbibition and reverse displacement.*

*Performance Evaluation and Mechanism Study of a Silicone Hydrophobic Polymer…*

The cores were gas driven and saturated with flow-back spontaneous imbibition. They were used to weigh the core mass at different flow-back stages and to calculate the residual water saturation. The gas permeability recovery was calculated as

water saturation established by the unsteady state gas drive. *KnPV* (10�<sup>3</sup> μm<sup>2</sup>

represent the gas permeability during different flow-back stages.

gas permeability of artificial cores after they were displaced by gas; these cores

This section presents an evaluation of the wettability alteration on both artificial cores and reservoir cores using different surfactants in alkaline solutions. Both the distilled water and ethylene glycol experiments were carried out under high temperatures. As shown in **Table 2** (**Figure 3**), water and ethylene glycol spreading on the artificial cores were treated by 0.2 and 0.4 wt% ABSN; thus, the contact angles were too low to measure. The contact angles of 0.2 wt% OSSF treated cores were 110.12° and 27.54°, respectively. Considering the microscopic anisotropy of the cores and the measurement error, we believe that the real contact angles should not

) is the gas permeability of artificial cores with irreducible

) is the gas permeability of artificial cores at irreducible

) is the gas permeability of artificial cores under

ð1Þ

ð2Þ

) is the

calculated [20]:

**Figure 2.**

different times.

follows [21, 22]:

where *K0* (10�<sup>3</sup> μm<sup>2</sup>

where *K0* (10�<sup>3</sup> μm<sup>2</sup>

**3. Results and discussion**

**3.1 Wettability properties**

**171**

water saturation, and *Ki* (10�<sup>3</sup> μm<sup>2</sup>

*DOI: http://dx.doi.org/10.5772/intechopen.90811*

*2.2.4 Gas driven flow-back experiment*

#### **2.2 Experimental method**

#### *2.2.1 Determination of contact angle, wettability, and surface energy*

Cores were immersed in NaOH solution with a pH of 9 at 150°C for 16 h. Each core was then taken out and dried at 150°C for 4 h. After that, it was cooled down to room temperature. The contact angles among the cores, distilled water, and ethylene glycol were measured with a JC200D3 contact angle analyzer. When the contact angle of water is less than 75°, it is termed "water wetting." When the contact angle of water is greater than 110°, it is considered "oil wetting" [17]. When the contact angle is between 75° and 110°, it is considered "intermediate wetting." This is a condition of gas preferential wetting. The surface energy of cores was calculated using the Owens-Wendt formula [18]. Aging in this paper means rolling under the high temperature of 150°C for 16 h.

#### *2.2.2 Determination of surface tension*

The surface tension measurements of NaOH solution with a pH of 9 and basic mud filtrates before and after aging (rolling in the temperature of 150°C oven for 16 h) were performed with an interfacial tensiometer sigma 701 (KSV, Finland) using the dynamic Wilhelmy plate method.

#### *2.2.3 Spontaneous imbibition experiments*

**Figure 2** shows the experiment's core inside the core holder, and a certain confinement pressure was added. The distilled water was added into the metering tube followed by the OSSF solution. The initial contact volume of the liquid with cores was determined based on the different flow rates. The increased water saturation, defined as spontaneous imbibition volume divided by the core's pore volume, was recorded during the experiment [19]. Core permeability change rates *Performance Evaluation and Mechanism Study of a Silicone Hydrophobic Polymer… DOI: http://dx.doi.org/10.5772/intechopen.90811*

**Figure 2.** *Schematic of the apparatus used for spontaneous imbibition and reverse displacement.*

at different times were defined as the water blocking damage rate. This rate can be calculated [20]:

$$\mathrm{I} = \frac{K\_0 - K\_t}{K\_0} \times 100\% \,\mathrm{o} \tag{1}$$

where *K0* (10�<sup>3</sup> μm<sup>2</sup> ) is the gas permeability of artificial cores with irreducible water saturation, and *Ki* (10�<sup>3</sup> μm<sup>2</sup> ) is the gas permeability of artificial cores under different times.

#### *2.2.4 Gas driven flow-back experiment*

The cores were gas driven and saturated with flow-back spontaneous imbibition. They were used to weigh the core mass at different flow-back stages and to calculate the residual water saturation. The gas permeability recovery was calculated as follows [21, 22]:

$$D = \frac{K\_{\eta pv}}{K\_0} \times 100\% \tag{2}$$

where *K0* (10�<sup>3</sup> μm<sup>2</sup> ) is the gas permeability of artificial cores at irreducible water saturation established by the unsteady state gas drive. *KnPV* (10�<sup>3</sup> μm<sup>2</sup> ) is the gas permeability of artificial cores after they were displaced by gas; these cores represent the gas permeability during different flow-back stages.

### **3. Results and discussion**

#### **3.1 Wettability properties**

This section presents an evaluation of the wettability alteration on both artificial cores and reservoir cores using different surfactants in alkaline solutions. Both the distilled water and ethylene glycol experiments were carried out under high temperatures. As shown in **Table 2** (**Figure 3**), water and ethylene glycol spreading on the artificial cores were treated by 0.2 and 0.4 wt% ABSN; thus, the contact angles were too low to measure. The contact angles of 0.2 wt% OSSF treated cores were 110.12° and 27.54°, respectively. Considering the microscopic anisotropy of the cores and the measurement error, we believe that the real contact angles should not

*2.1.3 Fluids*

**Table 1.**

**2.2 Experimental method**

*Physical characteristics of cores used in this study.*

*21st Century Surface Science - a Handbook*

high temperature of 150°C for 16 h.

*2.2.2 Determination of surface tension*

using the dynamic Wilhelmy plate method.

*2.2.3 Spontaneous imbibition experiments*

**170**

Triply distilled water was used in all experiments. About 4% of sodium bentonite mud was added with 0.2% Na2CO3 and then stirred for 2 days. It was used as the basic mud. Sodium bentonite was obtained from Weifang Hua Bentonite

Cores were immersed in NaOH solution with a pH of 9 at 150°C for 16 h. Each core was then taken out and dried at 150°C for 4 h. After that, it was cooled down to room temperature. The contact angles among the cores, distilled water, and ethylene glycol were measured with a JC200D3 contact angle analyzer. When the contact angle of water is less than 75°, it is termed "water wetting." When the contact angle of water is greater than 110°, it is considered "oil wetting" [17]. When the contact angle is between 75° and 110°, it is considered "intermediate wetting." This is a condition of gas preferential wetting. The surface energy of cores was calculated using the Owens-Wendt formula [18]. Aging in this paper means rolling under the

The surface tension measurements of NaOH solution with a pH of 9 and basic mud filtrates before and after aging (rolling in the temperature of 150°C oven for 16 h) were performed with an interfacial tensiometer sigma 701 (KSV, Finland)

**Figure 2** shows the experiment's core inside the core holder, and a certain confinement pressure was added. The distilled water was added into the metering tube followed by the OSSF solution. The initial contact volume of the liquid with cores was determined based on the different flow rates. The increased water saturation, defined as spontaneous imbibition volume divided by the core's pore volume, was recorded during the experiment [19]. Core permeability change rates

Group Co., Ltd. Na2CO3 is a commercially pure reagent.

*2.2.1 Determination of contact angle, wettability, and surface energy*

**Type L/(mm) D/(mm) m/(g) Ф/(%) K/(10**�**<sup>3</sup> μm<sup>2</sup>**

Artificial cores 50.89 24.77 54.83 14.69 28.59 0.66 0.48 Artificial cores 50.75 24.83 54.12 13.91 27.61 0.54 0.61 Artificial cores 50.92 24.81 53.72 15.27 29.86 0.67 0.52 Reservoir cores 51.02 24.95 62.67 0.67 3.27 0.49 0.57 Artificial cores 50.81 24.83 53.15 14.34 26.91 0.83 0.64 Artificial cores 49.95 24.94 54.27 14.76 28.95 0.70 0.67 Artificial cores 50.24 24.86 53.65 14.08 26.69 0.51 0.59

**) Standard error Ф K**

vary dramatically from one another. The surface energy of the cores decreased to 20–25 mJ/m<sup>2</sup> , which indicated that OSSF could greatly change the wettability from hydrophilic to highly hydrophobic.

spread on the surface. However, the contact angle of water on the OSS-modified cores still reached 110°, and the surface energy decrease was between 26 and

*Performance Evaluation and Mechanism Study of a Silicone Hydrophobic Polymer…*

pore due to the formation of low energy adsorption film treated by OSSF. Since ABSN does not affect wettability alteration, its surface energy is not evaluated here.

. These results indicated that water did not spread on the surface of the

To evaluate the surface activities of OSSF and ABSN in a high-temperature basic environment, the surface tension of solutions and fluid filtrates was measured after aging at 150°C for 16 h. In **Figures 5** and **6**, both 0.2–0.4 wt% ABSN and OSSF could decrease the surface tension under high temperature. Meanwhile, OSSF was better at reducing surface tension, meaning that it could better reduce filtrate adsorption

As shown in **Figure 7**, water saturation of cores gradually increased with time. Obvious spontaneous imbibition and diffusion stages could also be seen. The increase in water saturation was dramatic at the spontaneous imbibition stage, but water

*Contact angle of water on reservoir cores (room temperature). (a) Untreated, (b) treated by 0.20 wt% ABSN,*

*Surface tension of 0.20 wt% solutions before and after aging (cooling down to room temperature, pH free).*

28 mJ/m<sup>2</sup>

**Figure 4.**

**Figure 5.**

**173**

*and (c) treated by 0.20 wt% OSSF.*

**3.2 Interfacial properties**

*DOI: http://dx.doi.org/10.5772/intechopen.90811*

and aqueous phase trapping damage in the rock.

*3.3.1 Spontaneous imbibition property of cores*

**3.3 Evaluation of antiwater blocking properties of OSSF**

As shown in **Table 3** (**Figure 4**), the 0.2 and 0.4 wt% ABSN-treated cores displayed lower water contact angle, and the ethylene glycol droplet completely


#### **Table 2.**

*Contact angle and surface energy of artificial cores after adsorption equilibrium in ABSN and OSSF solutions (T = 150°C, pH = 9).*

#### **Figure 3.**

*Contact angle of water on artificial cores (room temperature). (a) Untreated, (b) treated by 0.20 wt% ABSN, and (c) treated by 0.20 wt% OSSF.*


#### **Table 3.**

*Contact angle and surface energy of reservoir cores after adsorption equilibrium in ABSN and OSSF solutions (T = 150°C, pH = 9).*

*Performance Evaluation and Mechanism Study of a Silicone Hydrophobic Polymer… DOI: http://dx.doi.org/10.5772/intechopen.90811*

spread on the surface. However, the contact angle of water on the OSS-modified cores still reached 110°, and the surface energy decrease was between 26 and 28 mJ/m<sup>2</sup> . These results indicated that water did not spread on the surface of the pore due to the formation of low energy adsorption film treated by OSSF. Since ABSN does not affect wettability alteration, its surface energy is not evaluated here.
