Super-amphiphobic, strong self-cleaning and high-efficiency water-based drilling fluids

Fig. 1. Schematics of synthetic idea for super-amphiphobic agent and superamphiphobic agent modified by polymer grafting (modified from reference [14]).

1.2. Effect of super-amphiphobic agent on the solid surface morphology

The effects of S-A on the surface morphology of core and filter cake were compared through scanning with field emission scanning electron microscope Quanta 200F (Fig. 2). S-A can form mastoid structure on the solid surface, to reduce the number of pores on rock surface and increase the surface roughness, and make the filter cake denser, which is good to reduce the fluid loss and prevent the drilling fluid from infiltrating into the reservoir, to achieve the purpose of protecting the reservoir and stabilizing the well wall.

Fig. 2.

Fig. 2. Effects of S-A on the core and filter cake surface morphology.

1.3. Effect of super-amphiphobic agent on solid surface free energy

The Owens two-liquid method (Equations 1 and 2)^[14] was used to calculate the surface free energy of core, filter cake and metal before and after treated by S-A.

(1)${{\gamma }_{S}}=\gamma _{S,D}^{{}}+\gamma _{S,P}^{{}}$

(2)${{\gamma }_{L}}\left( 1+cos\theta \right)=2{{\left( \gamma _{S,D}^{{}}\gamma _{L,D}^{{}} \right)}^{1/2}}\text{+}2{{\left( \gamma _{S,P}^{{}}\gamma _{L,P}^{{}} \right)}^{1/2}}$

In the experiment, de-ionized water was used as water phase, and hexadecane was used as oil phase. The surface free energy of de-ionized water was 72.8 mN/m, including that of dispersion force of 21.8 mN/m and that of polar force of 51.0 mN/m. The surface free energy of hexadecane was 27.6 mN/m, including that of dispersion force of 27.6 mN/m and that of polar force of 0. So the following equations were obtained.

(3)$72.8(1+cos{{\theta }_{1}})=2{{(21.8\gamma _{S,D}^{{}})}^{1/2}}\text{+}2{{(51.0\gamma _{S,P}^{{}})}^{1/2}}$

(4)$27.6\left( 1+\cos {{\theta }_{2}} \right)=2{{(27.6\gamma _{S,D}^{{}})}^{1/2}}$

The solid surface free energy was calculated by equations (3) and (4). The results show 3% S-A made the surface free energy of the core, filter cake and metal reduce from 62.14, 61.33, 36.79 mN/m to 17.65, 18.42, 18.13 mN/m respectively. Low surface free energy can effectively suppress external liquid or solid from polluting the solid surface, laying an energy base for self-cleaning.

1.4. Effect of super-amphiphobic agent on solid surface wettability

The influence of S-A on the wettability of core, filter cake and metal was investigated by contact angle measuring instrument JC2000D3 (Fig. 3). The results show that the water contact angles of the core, filter cake and metal surface increased from less than 20° before treated to above 150° after treated by S-A with concentration of 3% (Fig. 3a-3f), while the oil contact angles of them increased from 0° before treated to above 150° after treated (Fig. 3g-3l), realizing the transformation of solid surface wettability from hydrophilic/lipophilic to super-amphiphobic.

Fig. 3.

Fig. 3. Effect of S-A on solid surface wettability.

1.5. Effect of super-amphiphobic agent on solid surface self-cleaning

The self-cleaning property of the solid surface reflects the ability of solid surface to repel contaminants (such as sewage and oil). It can be seen from Fig. 4 that the sewage and oil completely spread on the untreated solid surface, but appear as liquid drops and roll off on the solid surface treated by S-A, so S-A can make the solid surface self-cleaning without contaminating it.

Fig. 4.

Fig. 4. Effect of S-A on solid surface self-cleaning property.

2. Evaluation of super-amphiphobic agent performance

2.1. Performance in protecting reservoirs

Capillary pressure, spontaneous imbibition and core permeability recovery experiments were used to evaluate the protective effect of S-A on oil and gas reservoir, and the results were compared with those of reservoir protection agents commonly used at present.

2.1.1. Capillary force experiment

The liquid levels in the capillary treated by different reservoir protection agents were measured, and then the capillary pressure was calculated by equation (5).

(5)${{p}_{c}}=\frac{2\sigma cos\theta }{r}$

It can be seen from the results in Table 1 that the capillary pressure was positive after treated by the commonly used reservoir protectants, and the liquid level in the capillary was above the measured liquid level, while the capillary pressure was negative after treated by S-A, and the liquid level in the capillary was below the measured liquid level, so the capillary force was transformed from driving force to resistance force of fluid flow, preventing the liquid in the wellbore from invading into the rock wall, effectively avoiding the instability of the wellbore and reservoir damage in unconventional oil and gas wells such as tight oil and gas, and shale oil and gas.

Table 1 Effects of different reservoir protection agents on capillary force.

Agent	Contact angle after treated/ (°)	Capillary force after treated/kPa	Liquid level after treated/ mm
No agent added	18.11	799.13	46
Non-filtration protectant	27.19	789.62	35
Film-forming protectant	39.64	768.43	32
S-A	165.72	-833.98	-31

Note: (1) Non-filtration and film-forming agents are all reservoir protection agents commonly used in oilfield; (2) “-” indicates reversal of capillary force direction and liquid level below the measured liquid level

2.1.2. Spontaneous imbibition experiment

The spontaneous imbibition amounts of the core (with permeability of (5.0±0.1)×10^-3μm²) were measured before and after treated by non-filtration, film-forming protectants and S-A (Table 2). It can be seen that the water quantity of spontaneous imbibition of the core reduced from 8.31 g to 0.15 g after treated by S-A, by 98.19%, which was 9.8 and 4.5 times respectively of the non-filtration and film-forming protectants. The oil quality of spontaneous imbibition of the core decreased from 11.33 g to 0.87 g after treated, by 92.3%, which was 6.1 times and 3.0 times that of non-filtration and film-forming protectants, respectively. Therefore, S-A can effectively prevent extraneous fluid from invading into the rock.

Table 2 Effects of different agents on spontaneous imbibition.

Agent	Water imbibition quantity/g	Oil imbibition quantity/g
No agent added	8.31	11.33
Non-filtration protectant	7.48	9.61
Film-forming protectant	6.51	7.88
S-A	0.15	0.87

2.1.3. Core permeability damage experiment

The permeability values of core (with a permeability of (5.0±0.1)×10^-3μm²) polluted by different drilling fluids were measured with JHMD-2 HTHP core dynamic damage evaluation instrument at the temperature of 20 °C and polluting time of 2 h (Table 3). The core was polluted by the drilling fluid for two hours. The No.1 and No.2 drilling fluids were prepared according to the formulas: (1) 3% bentonite + 0.5% filtrate reducer + 1% plugging agent + 1% starch + barite (density of 1.2 g/cm³); (2) formula (1) + 3% reservoir protectant respectively.

Table 3 Effects of different reservoir protectants on recovery of core permeability.

Formula	Agent	Porosity/ %	Initial permeability/ 10^-3μm²	Permeability after polluted by drilling fluid/10^-3μm²	Recovery rate of permeability/%	Pollution depth/cm
1	No agent added	5.47	5.47	3.88	70.93	00.95
2	Non-filtration protectant	5.87	5.33	4.47	83.86	00.60
2	Film-forming protectant	5.96	5.28	4.45	84.28	00.60
2	S-A	5.91	4.96	4.68	94.35	00.45

It can be seen from Table 3 that the core polluted by drilling fluid with 3% S-A had a permeability recovery value of 94.35%, which was 23.42% higher than that of the agent-free system, about over 10% higher than that of non-filtration and film-forming drilling fluid systems.

2.2. Evaluation of inhibition

The linear expansion and rolling recovery methods were used to evaluate the inhibitory effect of S-A on the hydration expansion of bentonite, and the inhibitory effect of S-A was compared with that of the commonly used inhibitors.

The linear expansion values of bentonite (sodium base bentonite consistent with the GB/T 20973—2007^[15]) in solutions of different inhibitor solutions are shown in Fig 5a. It can be seen that the swelling height of bentonite in deionized water was 5.74 mm, and the swelling height in 3% S-A solution was only 1.59 mm, that is a decrease by up to 72%. The recovery rate of every inhibitor is shown in Fig. 5b. It can be seen that the rolling recovery of shale cuttings in 3% S-A solution was 78.79%, which was 4.53 times higher than that (14.26%) in deionized water, and its inhibition was superior to other commonly used inhibitors with the same concentration.

Fig. 5.

Fig. 5. Evaluation of inhibitory property of S-A.

2.3. Drag and viscosity reduction

The lubrication effect of S-A was evaluated with extreme pressure (EP) lubrication factor and four-ball rubbing methods and compared with that of the commonly used lubricants.

2.3.1. Extreme pressure lubrication factor measurement

Extreme pressure (EP) lubricator was used to measure the extreme pressure lubrication factors of base mud with S-A and other lubricants, the results are shown in Tables 4 and 5. At room temperature, the extreme pressure lubrication factor of base mud with 0.5% S-A is 0.10, while that of the blank base mud is 0.54, so the lubrication factor reduces about 81.48%. The extreme pressure lubrication factor further reduces to 0.07 after 120 °C hot rolling for 16 h, 86.54% lower than that of the blank base mud. At the same time, the S-A has much better lubrication effect than other commonly used lubricants.

Table 4 Comparison of lubrication effects of S-A and commonly used lubricants at room temperature.

Sample	Lubrication factor	Reduction rate of lubrication factor/%
4% base mud	0.54
4% base mud +0.5% PF-lube-1	0.35	35.19
4% base mud +0.5% CX-300H	0.18	66.67
4% base mud+0.5% PF-lube-2	0.33	38.89
4% base mud+0.5% Geruidisi	0.24	55.56
4% base mud+0.5%S-A	0.10	81.48

Note: PF-lube-1, CX-300H, PF-lube-2 and Geruidisi are lubricants commonly used in oilfields with good performance.

Table 5 Comparison of lubrication effects of S-A and commonly used lubricants at high temperature.

Sample	Lubrication factor	Reduction rate of lubrication factor/%
4% base mud	0.52
4% base mud+0.5% PF-lube-1	0.34	34.62
4% base mud+0.5% CX-300H	0.17	67.31
4% base mud+0.5% PF-lube-2	0.24	53.84
4% base mud+0.5% Geruidisi	0.15	71.15
4% base mud+0.5%S-A	0.07	86.54

2.3.2. Four-ball friction experiment

Four-ball friction test was used to measure the friction factor of base mud with different lubricants (Fig. 6a). It can be seen that the friction factor of the base mud with S-A is only 0.06 after stabilizing, which is obviously smaller than those of base mud with other lubricants, and reduces about 89.5% than the friction factor (0.57) of the blank base mud. In addition, the surface of the steel ball after the four-ball friction test was observed by scanning electron microscope Quanta 200F. Compared with the steel ball rubbed in blank base mud, the steel ball surface rubbed in base mud with S-A agent has significantly smaller scratch area and shallower scratch depth (Fig. 6b and 6c), proving that S-A can effectively reduce the wear of the metal surface, and has better lubricity to the metal surface.

Fig. 6.

Fig. 6. Four-ball friction experiment results of base mud with different lubricants.

2.4. Enhancement of drilling speed

The effect of S-A on enhancing drilling was evaluated with speed-up evaluation device, and the results are shown in Fig 7. In 3.0% base mud, the average mechanical drilling speed increases with the increase of S-A concentration. When the concentration reaches 3.0%, the mechanical drilling speed reaches 37 cm/min, which is 166% faster than the drilling speed using blank base mud.

Fig. 7.

Fig. 7. Effect of S-A on enhancing drilling speed.

3. Performance evaluation and comparison of super-amphiphobic strong self-cleaning and high-efficiency water-based drilling fluid

Taking the S-A as the core agent, in line with the geological characteristics, some other agents have been added to form super-amphiphobic strong self-cleaning and high-efficiency water-based drilling fluid. And its performance was compared with that of the high efficiency water-based drilling fluid and typical oil-based drilling fluid commonly used in the field.

The formula of super-amphiphobic strong self-cleaning and high-efficiency water-based drilling fluid was: 1% base mud+3% S-A+2.5% fluid loss additive NFA+0.2% viscosity enhancer and extracting agent CX+Barite(density of 1.39 g/cm³); the formula of high-efficiency water-based drilling fluid was: 1% base slurry +0.5% polymer fluid loss additive +4% resin fluid loss additive +2% salt-resistance fluid loss additive +5% organic salt inhibitor +7% inorganic salt inhibitor +3% conventional lubricant +2% high-efficiency lubricant +3% flow pattern adjusting agent +3% rigid plugging agent +0.5% alkaline modifier + barite (density of 1.39 g/cm³); the formula of the typical oil-based drilling fluid was：80% 3# white oil +3% co-emulsifier+1% primary emulsifier +4% wetting agent + 20% calcium chloride solution +1% organic soil+0.5% extracting agent +4% ultrafine calcium(6.5 μm in size, 2 000 mesh)+2.67% plugging fluid loss additive +0.5% viscosity increasing loss control agent +5% lime + barite (density of 1.39 g/cm³).

3.1. Basic performances of the drilling fluid

Table 6 shows the basic performances of super-amphiphobic strong self-cleaning and high-efficiency water-based drilling fluid and high efficiency water-based drilling fluid and typical oil-based drilling fluid used commonly in the field. It can be seen that super-amphiphobic strong self-cleaning and high-efficiency water-based drilling fluid has lower apparent viscosity and plastic viscosity, higher dynamic shear force and better rheology than the other drilling fluids. Its fluid loss under high temperature and high pressure is only 4.6 mL, close to the typical oil-based drilling fluid.

Table 6 Comparison of basic performances of several kinds of drilling fluids.

Formula	Density/ (g•cm^-3)	Filtration/ mL	AV/ (mPa•s)	PV/ (mPa•s)	YP/Pa	(Initial gel-strength/final gel-strength)/Pa	HTHP filtration/mL
Superamphiphobic high-efficacy water-based drilling fluid	1.39	2.0	32	19	13	4.0/8.0	4.6
High-efficiency water-based drilling fluid	1.39	3.0	38	26	11	4.0/10.0	5.0
Typical oil-based drilling fluid	1.39	1.0	30	23	7	2.5/7.0	4.4

Note: Data from the Sulige block of CNPC Chuanqing United Drilling & Exploration Engineering Company, aging at 120 °C for 16 h; the HTHP filtration was tested at 120 °C and 3.5 MPa.

3.2. Inhibition evaluation of the drilling fluid

The rolling recovery and linear expansion method were used to evaluate the inhibitory performance of super-amphiphobic strong self-cleaning and high-efficiency water-based drilling fluid and typical oil-based drilling fluid (Fig. 8). The swelling heights of bentonite in de-ionized water, typical oil-based drilling fluid and super-amphiphobic strong self- cleaning and high-efficiency water-based drilling fluid are 5.99, 1.11, and 1.46mm respectively, which shows the swelling height of bentonite in the super-amphiphobic strong self- cleaning and high efficiency water-based drilling fluid reduces by 75.62% than that in de-ionized water. The rolling recovery rates of shale cuttings in the de-ionized water, typical oil- based drilling fluid and super-amphiphobic strong self-cleaning and high-efficiency water-based drilling fluid are 14.26%, 99.8% and 98.9% respectively. It can be seen that the super- amphiphobic strong self-cleaning and high-efficiency water- based drilling fluid is comparable with the typical oil-based drilling fluid in inhibitory performance, and can meet the high requirements on inhibitory performance in unconventional oil and gas drilling such as tight oil and gas, shale oil and gas.

Fig. 8.

Fig. 8. Evaluation of inhibitory performance of the drilling fluids.

3.3. Evaluation of drilling fluid lubricity

The evaluation results of lubricity show the super-amphiphobic strong self-cleaning and high-efficiency water-based drilling fluid and typical oil-based drilling fluid are comparable in lubricity, with 1 mm thick filter cakes both, and viscosity coefficients of 0.036 9 and 0.025 8, respectively.

3.4. Evaluation of environmental performance of the drilling fluid system

It can be seen from the heavy metal content test of super- amphiphobic strong self-cleaning and high-efficiency water-based drilling fluid (Table 7) that it has heavy metal content much lower than the maximum allowable value and meets the environmental requirements of heavy metal content. The bio-toxicity test of the drilling fluid shows that EC₅₀ ( biological toxicity) of the system is 3.18×10⁴mg/L. The biodegradability test shows that the system has a COD_Cr (chemical oxygen demand) of 1.32×10⁵mg/L, BOD₅ (5 d-biochemical oxygen demand) of 2.54×10⁴mg/L, and BOD₅/COD_Cr(Biodegradation index of sewage) of 0.192, indicating the system is non-toxic and degradable. Therefore, the system is non-toxic, safe and environmentally friendly.

Table 7 Contents of heavy metals in the super-amphiphobic, strong self-cleaning and high-efficiency water-based drilling fluid.

Heavy metal	Content/ (mg•kg^-1)	Maximum allowable value /(mg•kg^-1)
Cadmium	0	20
Mercury	2.41×10^-3	15
Lead	17.2	1 000
Totle Chromium	14.3	1 000
Arsenic	0.62	75

4. Field application

Up to December 2018, the super-amphiphobic, strong self- cleaning and high-efficiency water-based drilling fluid has applied in more than 200 wells in Xinjiang, North China, Sichuan, Jilin, and Changqing oilfields, and worked well in preventing wellbore instability and reservoir damage, enhancing drilling speed and production. Compared with other drilling fluids in the same field, by using this drilling fluid, the average drilling speed increased by more than 32.8%, the drilling fluid comprehensive cost decreased by 39.3%, the average down-hole complexity decreased by 82.9%, and the average production per well increased by more than 1.5 times.

For example, Well HW8003 in the southern slope of the Kewu fault zone in the western uplift of the Junggar Basin in Xinjiang has a vertical depth of kickoff point of 2547 m, vertical depth of horizontal section of 3767 m, and a horizontal section length of 1220 m. The well was drilled to 2356 m depth by using high-efficiency water-based drilling fluid on April 15, 2018, and encountered downhole complexities such as pump pressure build-up, top drive stop, difficulty in lifting and running-in, and serious collapse of the well wall etc. when drilling into the sand shale and tuff and the drilling couldn’t go on, then the well was sidetracked. The sidetracked hole was drilled by using the same kind of high-efficiency water-based drilling fluid too. On May 5, 2018, when drilled to 2365 m, the sidetracked hole had downhole complexities such as sticking, lifting and running-in difficulty, and well wall collapse. The sidetracked hole couldn’t be drilled further and then was filled again. The two times of well filling caused a direct drilling material cost loss of 2.33 million yuan and direct time loss of 25.58 d.

In view of this situation, the super-amphiphobic strong self-cleaning and high-efficiency water-based drilling fluid and the high-efficiency drilling fluid used earlier were compared through lab experiments. Rock cuttings soaking experiment shows the core soaked in super-amphiphobic strong self-cleaning and high-efficiency water-based drilling fluid filtrate remained complete after 16 h, while the core soaked in the high-efficiency drilling fluid filtrate used before dispersed and fell apart rapidly. The rolling recovery rates of cuttings in fresh water, original high-efficiency drilling fluid and super-amphiphobic strong self-cleaning and high-efficiency water-based drilling fluid were 10.0%, 93.4% and 98.8% respectively. The results of field application show that the super-amphiphobic, strong self-cleaning and high-efficiency water-based drilling fluid could effectively prevent swelling of mudstone after contacting with water and wall instability. No complicated underground conditions occurred during the drilling later, and the drilling fluid had stable rheological parameters and good performance at various depths (Table 8). The well was successfully completed on August 2, 2018, which can provide good technical support and reference for “safe and efficient” drilling in Triassic Karamay Formation and Baijiantan Formation reservoirs prone to collapse and leaking in the Baijiantan well area and similar complicated reservoir.

Fig. 9.

Fig. 9. Comparison of cuttings soaked in two kinds of drilling fluids filtrate.

Table 8 Basic performance parameters of drilling fluid used in Well HW8003.

Well depth/m	Density/(g·cm^-3)	AV/(mPa•s)	PV/(mPa•s)	YP/Pa	(Initial gel strength/final gel strength)/Pa	Filtration/mL
2 186	1.38	34.0	28	6.5	1.5/5.0	2.4
2 329	1.38	41.0	33	9.5	2.5/7.5	2.8
2 553	1.38	39.0	29	10.0	5.0/11.5	3.6
2 778	1.39	39.0	27	10.0	4.0/10.0	3.2
2 973	1.39	31.0	23	8.0	3.5/8.0	4.0
3 202	1.39	40.0	32	8.0	4.0/11.5	3.2
3 406	1.39	36.5	28	8.5	3.5/11.0	3.2
3 736	1.39	37.0	30	7.0	3.0/8.0	3.2

5. Conclusions

Based on the surface modification grafting principle of nano-materials, the S-A for water-based drilling fluid has been developed, and its functional mechanism consist of two parts, forming nano-micron multi-stage structures on the solid surface to increase the surface roughness, and reducing the surface free energy to alter the surface wettability from lyophilic to super-amphiphobic. By altering the solid surface wettability, S-A can increase the surface self-cleaning, reduce the capillary force, effectively prevent the liquid from getting into the reservoir, and avoiding hydration expansion of rock and reservoir damage, and increase the permeability recovery. It works better than other reservoir protectants. In addition, it can reduce the friction between solid particles, well wall and drilling tool, avoid bit balling, and increase drilling speed, and has better lubrication than commonly used lubricants. With S-A as the core agent, combined with other agents according to formations drilled, the super-amphiphobic strong self- cleaning and high-efficiency water-based drilling fluid system has been developed, which is close to oil-based drilling fluid in inhibition, lubricity and basic drilling fluid parameters, and is environmentally friendly. Field application shows that this drilling fluid can reduce down-hole complexity or accident and drilling fluid cost greatly, increase drilling speed and single well production. The study provides new theory and technology for the research of high efficiency water-based drilling fluid.

Nomenclature

p_c—capillary force, kPa;

r—capillary radius, the capillary radius is 0.15×10^-2 m in this research;

γ_L—liquid surface free energy, mN/m;

γ_S—solid surface free energy, mN/m;

θ—liquid contact angle on solid surface, (°);

θ₁—water contact angle, (°);

θ₂—oil contact angle, (°);

σ—surface tension of liquid phase in capillary, mN/m.

Subscript:

D—dispersion part;

P—polar part.

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