Research on the main controlling factors and preferred formulations for chemical oil recovery in conglomerate reservoirs based on complex lithology

doi:10.21203/rs.3.rs-3764697/v1

It is found that the mineralogical composition of conglomerate oil reservoirs in the Junggar Basin in northwest China is complex compared to conglomerate oil reservoirs in other regions. Among them, the most active physicochemical properties are zeolite minerals and clay minerals, which have the largest specific surface, the highest zeta potential, and they readily interact with surfactants used in chemical oil recovery. Experiments were conducted according to the actual surfactant/polymer binary composite drive chemical oil recovery model at the production site, and the interfacial tensions of 17 surfactants were measured, and the anionic surfactant KPS petroleum sulfonate, the nonionic surfactant coconut oil fatty acid diethanolamide 6501, and the amphoteric surfactant octadecyl betaine, which achieved ultra-low interfacial tensions, were screened out. Using the core of conglomerate reservoir, the contained minerals and oil and water, three surfactants were tested for adsorption performance, wettability test, emulsification performance evaluation, and finally, after the oil drive validation experiments, it was concluded that the specific surface of the minerals, zeta potential and the amount of adsorption of the chemical agent are positively correlated, and the amount of adsorption affects the recovery rate of chemical drive in conglomerate reservoirs, so that the 6501 was recommended to be the preferred surfactant. The research methodology adopted in the paper can be applied to chemical drive in reservoirs of different types and rock mineral compositions, and is also constructive for the promotion of chemical drive in similar reservoirs.

Conglomerate reservoirs

Surfactants

Minerals

Interfacial tension

Adsorption

Wettability

Emulsification properties

Chemical oil recovery

With the increasing demand for energy and the continuous development of oil and gas prediction and development technology, the study of special reservoirs such as conglomerate reservoirs has received more and more attention. Conglomerate reservoir is a conglomerate, conglomerate sandstone and other coarse clastic reservoirs, China to land-based oil reservoirs, conglomerate reservoirs in general accounted for a small proportion, but in some areas accounted for a high proportion, such as in the Junggar Basin, Xinjiang, conglomerate reservoirs accounted for more than 45% of the number of reservoirs (Zhu et al. 2015), So the contribution of conglomerate reservoirs in the cause of oil and gas development in Junggar Basin cannot be ignored. At present, primary and secondary oil recovery can only collect 30%-40% of the oil in conglomerate reservoirs, and a large amount of crude oil is difficult to be extracted, with the continuous development of oil recovery technology, there is a third oil recovery technology such as chemical drive (Hammond et al. 2011; Murison et al. 2014; Zhao et al. 2014), but there are not many studies related to chemical drive in conglomerate reservoirs.

Chemical drive is an oil recovery method that adds chemical agents to the injected water to change the physicochemical properties of the displacement fluid and the interface properties between the displacement fluid and crude oil and rock minerals, thereby facilitating crude oil production (Herawati et al. 2022; Wang 2001).According to the different chemical agents used, traditional chemical drive generally includes alkali drive, polymer drive, surfactant/polymer binary composite drive and alkali/surfactant/polymer ternary composite drive. With the development of oil displacement theory and the research and development of new oil displacement agents, new chemical drive such as foam drive and nanocomposite drive has also emerged (Muggeridge et al. 2012; Hirasaki et al. 2011; Liao et al. 2017; Moritis 2000; Wang et al. 2012). The polymer-surfactant binary composite drive currently implemented in the field of Xinjiang Oilfield can not only substantially increase the crude oil recovery, but also avoid the problems of formation scaling due to alkali, equipment corrosion, and serious emulsification of the extracted fluid. The injected polymer solution with high viscosity can greatly improve the reservoir wave efficiency, thus playing a role in improving the recovery rate (Liang et al. 1993; Spildo et al. 2009), while the surfactant drive can weaken the tension between the oil-water interface, change the wettability of the rock, so that the water and oil phases in the pores of the rock can be driven out, so as to make the drive efficiency and recovery rate be further improved (Hirasaki et al. 2011; Baek et al. 2022). The selection and use of surfactants determine the recovery efficiency of chemical drive.

For chemical drives in conglomerate reservoirs, surfactants undergo significant adsorption and depletion in the subsurface, with organic molecules adsorbed both on the charged points of clay minerals and on neutral points through polar interactions (Lin and Gao 2005). In binary composite drives, the adsorption of the surfactant is greater than that of the polymer because of its small molecular weight, which results in physical retention as well as depletion due to chemical reactions. In general, comparative studies of anionic, cationic and nonionic surfactants have shown that cationic surfactants are significantly adsorbed to sandstone reservoirs, anionic surfactants are significantly adsorbed to carbonate reservoirs (Lee et al. 2004), and a variety of minerals contained in conglomerate reservoirs can affect surfactants in different ways. Therefore, the study of the interaction between surfactants and rock minerals in conglomerate reservoirs is of theoretical significance and practical guidance for the chemical drive of conglomerate reservoirs to improve the oil recovery efficiency and thus obtain better economic benefits.

2.1 Materials and instruments

2.1.1 Materials

(1) Surfactants for oil displacement:

① Anions: Karamay petroleum sulfonate KPS (a surfactant currently being applied at the production site of Xinjiang conglomerate reservoir), Shengli Oil Field petroleum sulfonate ND, NH, NB-N, heavy alkyl benzene sulfonate sodium; ② Non ionic: 6501 (Coconut oil fatty acid diethanolamide): 6501-1:1LC, 6501-C115, 6501-C120; AEO (Fatty alcohol polyoxyethylene ether): AEO-7, AEO-9; ③ Anionic non-ionic: AES (Fatty alcohol polyoxyethylene ether sodium sulfate); ④ Amphoteric ions: dodecyl dimethyl Betaine, laurylamide propyl hydroxysulfonyl Betaine, dodecyl dimethyl hydroxypropylsulfonyl Betaine, octadecyl dimethyl hydroxypropylsulfonyl Betaine, octadecyl Betaine;

(2)Polymer: Salt resistant polymer, with polyacrylamide (HPAM) as the main component and a relative molecular weight of 15 million;

(3)Mineral and rock materials:

① Minerals: zeolite, montmorillonite, kaolinite, illite, chlorite, sodium feldspar, calcite;② Cores: Xinjiang oilfield conglomerate cores, field outcrop rocks extracted with petroleum ether, dried, crushed and sieved to a particle size of 200 mesh or less; ③ Oil sludge from oil extraction: Xinjiang oilfield poly-surface binary drive extracted end mud outputs extracted by petroleum ether, drying, crushing, sieving, particle size of about 800 mesh;

(4)Experimental water: Formation water in conglomerate reservoirs, NaHCO₃ type, mineralization degree 10000mg/L, and its parameters are shown in Table 1.

Table 1

Parameters of Simulated Formation Water in Xinjiang Oilfield
Water type	Salinity(mg/L)	Chloride ion(mg/L)	PH	divalent cation(mg/L)
NaHCO₃	10000	3850	7ཞ8	72.6

2.1.2 Experimental instruments

Transmission polarization microscope, DFC450C, Leica, Leica, Germany; High resolution field emission scanning electron microscopy, FEIVerios460, FEI, United States; UV visible spectrophotometer, UV-2200, Shanghai Shunyu Hengping; Interface tension meter, TX-500C, Shanghai Zhongchen; Specific Surface Aperture Analyzer, V-Sorb2800P, Beijing Guoyi Precision Measurement Technology Co., Ltd; Zeta potential analyzer, ZetasizerNanoZS, Malvern, UK; X-ray diffraction analyzer, D8Quest, Bruker, Germany; Fully automatic contact angle tester, SDC100S, Guangdong Huashitong; Water bath magnetic stirring pot, Shanghai Keheng.

2.1.3 Material pretreatment

Conglomerate core: drilling, slicing, observation, and oil washing are carried out after full diameter core sampling;

Quartz sand: Soak in 1mol/L hydrochloric acid for 12 hours, then boil multiple times in distilled water and soak until there are no chloride ions in the AgNO₃ test;

Clay minerals: Boil multiple times with distilled water and soak to remove soluble salts until the conductivity no longer changes.

2.2 Methods

2.2.1 Analysis of rock mineral structure, composition, and content

The powder samples were analyzed using high-resolution field emission scanning electron microscopy produced by FEI company in the United States for scanning electron microscopy (SEM) and energy dispersive X-ray (EDX), and the morphology and elemental composition of conglomerate minerals were obtained. Then carry out X-ray diffraction analysis. According to the "SY/T 5162 − 2018 X-ray diffraction analysis method for clay minerals and common non clay minerals in sedimentary rocks" (China Petroleum and Natural Gas Industry Standard, 2018), the quantitative composition of the sample is analyzed.

2.2.2 Determination of specific surface area of rocks and minerals

The specific surface and pore size of the conglomerate samples and the minerals contained in the reservoir were determined by a nitrogen adsorption specific surface and pore size analyzer (V-Sorb2800P), which adopts the BET method and the Langmuir model as the basic working principle. In this paper, block samples were used instead of powder samples, which preserved the fixed structure of the samples as much as possible and closer to the real specific surface of the reservoir.

2.2.3 Zeta potential measurement

The nature of the surface charge of rock minerals and chemical agents was determined by means of a zeta potential meter (ZetasizerNanoZS), which employs Doppler electrophoresis as its basic operating principle.

2.2.4 Surfactant interfacial tension determination

Interfacial tension is the most important performance of surfactant oil displacement, so this paper gives priority to the determination of interfacial tension in the selection of surfactant. Combining theory with practical application in production site, 3000ppm concentration value is selected as the preferred concentration value. According to the oil and natural gas industry standard SYT5370-2018 Surface and Interfacial Tension Measurement Method (China Petroleum and Natural Gas Industry Standard, 2018) of the China, by using the rotary drop method Under the action of gravity and interfacial tension, low-density phase liquids form an elliptical or cylindrical droplet in high-density phase liquids, whose shape is determined by rotational speed and interfacial tension.

The two-phase liquids were surfactants formulated with 3000 ppm concentration of crude oil extracted from the chemical drive site and injected water at the site in Xinjiang oilfield, respectively.The prepared solution was added to the sample tube of a TX500C spin-drop interfacial tensiometer and injected into the corresponding oil phase at a constant temperature of 30°C (to simulate the stratigraphic temperature), and the equilibrium interfacial tension was determined after the interfacial tension was stabilized, with an angular speed of 5000 r∙s ^− 1.

2.2.5 Wettability test

Natural core sand with particle size less than 0.25mm and dehydrated crude oil shall be mixed evenly at a mass ratio of 7:1, and placed in an oven at 30 ℃ (target formation temperature) for thermal aging for more than 48h. The aged oil-bearing core sand shall be adhered to quartz with Double-sided tape to form an oil-bearing natural core sand mold, and different types of surfactant solutions shall be prepared with injected water as the aqueous phase, Measure the contact angle of surfactant solution on the surface of oil bearing natural core sand model using a fully automatic contact angle tester.

2.2.6 Emulsification performance evaluation

(1) Preparation of emulsion, different surfactant solutions were added to the treated crude oil extracted from the conglomerate reservoir in the ratio of 1:1 by volume of oil and water into a stoppered graduated test tube and sealed, and then put into a constant temperature water bath at a temperature of 43 ℃ for 20 min, and then removed, and then left to emulsify for 24h, to obtain the emulsion. Observe the water layer, oil layer and the volume of emulsion layer formed by the emulsion in the test tube, and examine the emulsification performance of the surfactant according to the volume of emulsion layer.

(2) Lotion stability test: according to (1) observe the water separation in the test tube every 20 minutes after the preparation of emulsion, record the volume of water layer and calculate the water separation rate. The calculation formula of water separation rate is as follows:

Q = V_t/V×100%

In the equation:Q - Water evolution rate of emulsion within a certain period of time,%;V_t - Volume of emulsion effluent, mL;V - The total volume of water in the emulsion, mL.

The stability of lotion can be investigated by water evolution rate because the emulsion formed by surfactant and crude oil is a thermodynamic unstable system. After being placed for a period of time, the oil droplets in the solution will coalesce, resulting in oil-water separation and stratification. The water release rate can visually indicate the water release of the emulsion over a period of time, thereby determining the stability of the emulsion (Hou 2016).

2.2.7 Adsorption experiment

(1) Static adsorption experiment

① Prepare the water for preparing the oil displacement agent solution in this experiment according to the composition of injected water in Xinjiang conglomerate reservoir; Prepare the mother liquid of the oil displacement agent and dilute it to a series of concentrations as the initial concentration of the oil displacement agent, denoted as C₀; ② Add the adsorbent and oil displacement agent solution into a ground conical bottle with a stopper in a solid to liquid ratio of 1:9, shake it evenly and cover the bottle stopper, and further seal the conical bottle mouth with a sealing strip; ③ Place the Erlenmeyer flask in a 30℃ thermostatic water bath at 60 rpm for 24 hours; ④ Take out the Erlenmeyer flask, shake up the adsorbed solution, pour it into the centrifuge tube, and centrifuge for 30 minutes at the speed of 4000 rpm; ⑤ Remove the upper layer of clear liquid from the centrifuge tube, shake well, and then measure the concentration of the oil displacement agent in the clear liquid. This concentration is the equilibrium concentration at which adsorption reaches equilibrium, denoted as C_t; ⑥ The static adsorption capacity is calculated according to the following formula (Nurudeen et al. 2019):

Γ = V(C₀-C_t)/G

In the equation, Γ- Static adsorption capacity, expressed in milligrams per gram of mineral adsorbed oil displacement agent, mg/g;V - Volume of oil displacement agent solution, L;C₀- Initial concentration of oil displacement agent in solution, mg/L;Ct-The final concentration of the displacement agent solution after adsorption equilibrium, mg/L;G - Mass of adsorbent, g.

(2) Dynamic adsorption experiment

The binary composite oil repellent formula used for dynamic drive is: 0.3% KPS, 0.18% polymer.

① load the core into the holder, each oil repellent reagent into the intermediate container, turn on the constant temperature drive system, simulate the formation temperature constant temperature for about one hour; ② turn on the injection pump, adjust the injection volume; ③ use the injection of water drive until the injection pressure is stable; ④ inject the binary composite system, the concentration of each component in the effluent end of the constant sampling and testing of the concentration of the components changes until the concentration of each component is equal to or close to the injection of the initial concentration of; ⑤ use the injection of water drive until the concentration of each component of the binary system in the effluent is equal to or close to the initial concentration; ⑤ with Inject water replacement until the concentration of each component of the binary system in the effluent is equal to or close to 0; ⑥ According to the measured concentration of each component in the effluent sample and the volume of the sample, use the principle of material balance to calculate the retention amount of each component in the binary composite system.

(3) Single chemical agent mass concentration detection method

Prepare standard solutions of polymers and surfactants and dilute them to four different concentrations, measure the absorbance of the four diluted solutions by ultraviolet spectrophotometry, establish the standard curve of chemical concentration and absorbance, and the degree of fit reaches more than 0.999, and then the adsorption amount of various surfactants on different rocks and minerals can be measured separately (Zhong et al. 2019; Ni et al. 2018).

2.2.8 Oil displacement verification experiment

Select the natural conglomerate core with medium and high permeability, calculate the pore volume, use the vacuum pump to evacuate the natural core for 4 h, and saturate the natural core with simulated oil under the condition of 30°C for 20 h. Prepare the experimental setup (Fig. 1), simulate the actual condition of the stratum, set the pressure at 12 Mpa and the temperature at 30°C, and prepare the simulated injected water which has the same mineralization as that of the stratum.

Start the advection pump with a flow rate of 0.3 ml/min, start the water drive 2PV, know that the front end contains 98% water, convert to polymer surfactant binary drive, turn off the valve corresponding to the water drive, after injecting a predetermined volume (2PV) of the binary solution, open the valve of the water drive, turn off the valve corresponding to the binary drive, and carry out the subsequent water drive 2PV, until the water content is 98%.

Once the experiment is underway, take readings every half hour including pressure, volume of liquid extracted (volume of water and volume of oil), increase or decrease the reading interval as needed, and always observe the phenomena and the condition of the liquid extracted during the experiment. The response of the pressure gauge is not allowed to exceed the range.

3.1 Rock mineral composition and its influence

As the object and main material of this paper, firstly, we studied the rock mineral composition and its structural characteristics of conglomerate reservoir, and completed the research on the microscopic physicochemical characteristics of conglomerate reservoir reservoir.

3.1.1 Reservoir classification

This article divides conglomerate oil reservoirs into four categories based on pore structure and physical parameters (Tang and Qi 2014) (Table 2). Among them, high permeability reservoirs in categories I and II (Table 3) will be the main targets for chemical flooding, while reservoirs III and IV cannot be completed due to the difficulty of polymer entry, so this article will not discuss them.

Table 2

Reservoir Classification Evaluation Table
Reservoir type		Ⅰ	Ⅱ	Ⅲ	Ⅳ
Pore types		Primary intergranular pores, Intergranular dissolved pores		Internal micropores, and intergranular pores
Pore structure parameters	Coefficient of variation(G)	＞0.3	0.15～0.3	0.16～0.22	＜0.1
	Median pressure(MPa)	＜2.2	2.2～4	4～6	＜4
	Displacement pressure(MPa)	Lower	0.2～0.7	0.5～1.1	＞1
	Pore-throat radius(µm)	＞80	＜80	Small	Very small
	Maximum connected roar radius(µm)	＜15	7.5～1.4	1.4～0.83	0.38
Physical parameters	Porosity(%)	＞20	15～20	10～15	＜10
Physical parameters	Permeability(mD)	＞100	50～100	10～50	＜10
Reservoir evaluation		Good ~ Excellent	Medium	Bad	Very poor

The conglomerate cores were processed, the cores were scanned, drilled, sliced, observed and oil washed, and the porosity and permeability of the conglomerate natural core samples were gas measured using a high temperature overpressure pore penetrometer, of which there were three pieces of Class I cores, three pieces of Class II cores, and one piece of Class III cores, which will be used as the core material for the research of this paper.

Table 3

Parameter Table of Conglomerate Samples
Sample label	Depth/m	Porosity/%	Permeability/mD	Reservoir classification
S09511	1178.09	23.50	118.00	I
S09521	942.28	25.00	675.00	I
S09551	944.88	23.10	168.00	I
S7	945	18.11	53.18	II
S8	945.4	18.00	52.89	II
S11	791	18.77	56.38	II
S20	1132	14.71	36.72	III

3.1.2 Rock composition and structure

The medium and high permeability conglomerate reservoir reservoir rocks were selected for cast thin section fabrication, microscopic observation, and were visible by fabricating oriented slices for observation under incident and reflected light microscopes:

The lithology of Class I reservoir is dominated by coarse sandy fine conglomerate, the particle size is greater than 0.5mm, mainly distributed in 1 ~ 5mm, and the rock fragments are particle-supported with point - line contact. The gravel composition is complex, the particle sorting is medium, and the rounding is dominated by sub-rounded-sub-angular shape. The minerals are mainly quartz and potassium feldspar, followed by plagioclase feldspar; mica flakes are common, mainly intergranular filling and flake or curved flake output on the surface of the grains. The distribution of filler is uneven, including fine sand grade clastic particles, water mica, mud cement and carbonate cement.The porosity of the sample of Class I reservoir is 23%~25%, and the permeability is more than 100×10^− 3µm², which is a medium-high permeability reservoir. The content of intergranular heterogeneous base is high, the particle sorting is poor, the dissolution pore is developed, the distribution of pore throat is not uniform, the filler is clay with poor crystalline shape, etc., and the residual intergranular pore is developed. The pore type is dominated by primary intergranular pores, and the residual intergranular pores are developed (Fig. 2), showing the Combination of intergranular dissolution porosity - intergranular porosity - intragranular dissolution porosity.

The lithology of Class II reservoir is mainly sand-based supporting conglomerate, with moderate grain sorting and mainly sub-angular and sub-rounded. The minerals are mainly quartz and potassium feldspar, followed by plagioclase feldspar. The content of filler is high, including fine sand-grade clastic particles, hydrous mica and mud cement, carbonate cement.The porosity of Class II reservoir is 15%-20%, permeability is 50×10^− 3~100×10^− 3µm², which is a medium-porous and medium-permeable reservoir. The pores are dominated by intergranular pores and secondary dissolution pores (Fig. 3), the type of pore-throat combination is small pore micro-throat type, the distribution of pore throats is single-peak biased fine type, and the mainstream throats are a small number of coarse throats.

The lithology of class III reservoir is mainly sand and gravel mud mixed, with poor particle sorting and high content of filler.The porosity of class III reservoir is less than 15%, and the permeability is 10×10^− 3~50×10^− 3µm², which is a medium-porous and medium-low permeability reservoir (Fig. 4). Minerals are dominated by quartz and feldspar; quartz is fractured and secondary enlarged, feldspar is clay mineralized and severely altered, and sodium feldspar is aggregated in sheets of bicrystals; the content of debris is high, and the particles are not oriented.

3.1.3 Mineral composition and content

The surfaces of the conglomerate sample particles were first scanned by energy spectroscopy (EDS) to analyze the elemental composition of these physicochemically active minerals. The filler material of the conglomerate samples was then analyzed by scanning electron microscopy (SEM) for mineral characterization (after oil washing treatment).

The elemental composition of the conglomerate reservoir rocks can be known by energy spectrum analysis (Fig. 5), in which, in addition to the conventional elements such as C, N, O, S, conglomerate samples contain a large number of Si and Al elements, and it is known that the reservoir backbone minerals are composed of feldspars and quartz, and their chemical structures are Na/K[AlSi₃O₈] and SiO₂, respectively; In addition, clay minerals and zeolite minerals are hydroaluminosilicate mineral products (see Table 4).

Table 4

Chemical formula of hydroaluminosilicate minerals
Minerals	Chemical formula
Kaolinite	Al₄[Si₄O₁₀](OH)₈
Montmorillonite	Ex(H₂O)₄{(Al_2 − x,Mg_x)₂[(Si,Al)₄O₁₀](OH)₂}
Illite	KAl₂[(SiAl)₄O₁₀](OH)₂·nH₂O
Turbidite	Ca[AlSi₂O₆]₂·4H₂O

Then through the scanning electron microscope images, the conglomerate reservoir skeleton mineral surface is indeed complex in composition, with the presence of a large number of clay minerals as well as zeolite-like minerals.The most extensive distribution of kaolinite was observed in the samples, with page-like kaolinite monomers and aggregates seen in almost every sample, as well as illite in the form of bridging pseudohexagonal wafers, acicular and lath-like chlorite growing secondarily on the mineral surfaces, and honeycomb and flamed illite-montmorillonite mixing layers filling the inside of the pore spaces, as well as monocrystalline structural turbidite zeolites and globular grains of galena zeolites, as shown in Fig. 6.

In order to more accurately analyze the mineral composition and ingredients, x-ray diffraction (XRD) analysis was used to characterize the composition of the conglomerate samples filler and to do quantitative analysis, and the results of mineral content analysis are shown in Fig. 7.

Conglomerate reservoir reservoir filler is dominated by feldspar and quartz, with feldspar content of 34.07% and quartz content of 37.53%; colluvium is dominated by sulfate minerals and clay minerals, with contents of 10.8% and 10.45%, and conglomerate reservoir filler does contain zeolite minerals, with contents of about 3.7%, mainly turbidite zeolites and square zeolites. The relative content of clay minerals was also analyzed (Fig. 8).

The result of the analysis tells that the relative content of kaolinite is the highest among the clay minerals, reaching 36.92%, followed by Illite Montmorillonite mixed layer(Later in this article, it is referred to as the Imon mixed layer) with 30.48%,illite with 29.2% and chlorite with the least relative content, 3.38%.

3.1.4 Influence of rock minerals on chemical drive

The rock mineral research finally analyzed the extracted material from Xinjiang conglomerate oil reservoir, the extracted material sample is the treated dirty oil mud, and then more than one week of drying treatment, and finally for the oil-free powdered samples. The analysis results are shown in Fig. 9 and Fig. 10.

Through the quantitative analysis of the samples before and after the chemical drive of the conglomerate reservoir reservoir filler, the mineral species did not change essentially, the proportion of zeolite in the extracted material became higher, the proportion of carbonate minerals became less, and the approximate proportion of the rest of each kind of minerals did not change significantly. The content of clay minerals in the total content did not change much, but the relative content had obvious changes, the content of immonite mixed layer in the post-drive extract was the most, illite and kaolinite content was the second, chlorite was the least, analyzing the reason for this may be related to the ion exchange capacity, lattice substitution occurred. When clay minerals are in contact with water, water can enter between the crystal layers and dissociate the exchangeable cations, and then the surface of the crystal layer establishes a diffuse double electric layer, which produces a negative electronegativity (Su et al. 2002). In clay mineral crystals, some of the cations are replaced by other cations, while the crystal structure remains unchanged, producing an excess charge.

Kaolinite is 1:1 crystal type, the upper and lower adjacent levels, one side is OH surface, the other side is O surface, and O and OH are easy to form hydrogen bonds, interlayer gravity is strong, the interlayer connection is tight, water molecules are not easy to enter the crystal layer, the number of adsorbed cations around is small, and the number of cations that can be exchanged is even smaller. Montmorillonite 2:1 type clay minerals, up and down the adjacent levels are O surface, interlayer gravity to intermolecular force is dominated by interlayer gravity is weaker, water molecules are easy to enter the crystal layer, due to lattice substitution produces more negative charge, around it, it will certainly be adsorbed equal amount of cations, hydration of cations to the clay to bring a thick hydration film, so that the montmorillonite expansion. Montmorillonite exists lattice substitution, the number of cations that can be exchanged is high. Elysite due to lattice substitution of the negative charge generated by the K⁺ to balance, due to ilmenite substitution position mainly in the Si-O tetrahedron, resulting in a negative charge from the surface of the crystalline layer is close to the surface of the crystal layer, so with the K⁺ to produce a very strong electrostatic force, K⁺ is not easy to exchange down the K⁺ size is just embedded in the neighboring crystalline layer of oxygen atoms between the lattice of the formation of the cavities, to play a role in connecting the 12 oxygen around it with the pairing, so, the K⁺ connection is usually very strong, not easy to exchange down. That's why illite is less likely to swell. Chlorite is also due to the presence of hydrogen bonding in its crystalline layers and compensates for the imbalance of the electrovalence resulting from lattice substitution with hydromagnesite instead of exchangeable cations, among other things (Zhao 2010).

Zeolite minerals belong to silica-aluminate minerals, zeolite can be formed in the alkaline environment, Xinjiang conglomerate reservoirs in the diagenetic evolution process of the Permian period have appeared in the alkaline environment (Guo et al. 2002), and clay minerals and zeolite minerals can be transformed into each other, the formation of smaller secondary pore space. Montmorillonite and zeolite both have strong adsorption, ion exchange, but not "a mother and a brother", zeolite is a shelf-structured aluminosilicate, montmorillonite is a layered silica-aluminate mineral, zeolite molecular cage structure has a stronger adsorption, and montmorillonite will be swollen when it comes into contact with water, and its affinity for heavy metal ions is low, poor adsorption capacity. The presence of zeolite minerals also has a great influence on the injection of chemical agents, and previous studies in this area have been largely uninvolved. In this paper, we analyzed and concluded that the ilmenite mixing layer in the stratigraphic output is a mixing layer of illite and montmorillonite minerals, and usually, the mixing layer of minerals is more likely to be swollen and dispersed than a single clay mineral in contact with water (Zhao 2010).

Specific surfaces and pore sizes of block samples from conglomerate reservoirs and minerals contained in conglomerate reservoirs were determined (Table 4). It can be seen that montmorillonite and zeolite have the largest specific surface, while the specific surface of the conglomerate natural core is larger than that of the skeletal minerals quartz and feldspar, indicating that the constituent minerals of the conglomerate reservoir are more complex.

Table 5

Mineral and core specific surfaces of conglomerate reservoirs
Reservoir Mineral Formation	Sample Name	Measurement Methods((m²/g))
Reservoir Mineral Formation	Sample Name	BET Specific Surface	Langmuir specific surface
Skeleton minerals	Quartz sand	0.05	0.12
Skeleton minerals	Feldspar	1.47	2.89
Carbonate minerals	Calcite	3.67	5.71
Carbonate minerals	Dolomite	0.84	1.67
Clay minerals	Kaolinite	15.7	22.67
	Illite	20.62	21.06
	Chlorite	23.76	25.87
	Montmorillonite	40.21	57.54
Aluminosilicate minerals	Zeolite	31.58	43.24
Actual core of conglomerate reservoir	S9551	5.327	6.943
	S7	3.127	4.119
	S8	2.358	3.654
	S20	2.116	3.147
	S4	2.446	3.715
	S9511	4.502	5.379
	S11	2.19	3.186
Stratigraphic extracts	Oil Sludge Extract	3.685	5.492

The high proportion of zeolite and immonium mixed layer in oilfield recovered oil sludge also indicates that these two minerals are easy to hydrate, strong adsorption, and have a large specific surface area, zeolite and immonium mixed layer large amount of adsorption of formation water and chemical agent, along with the migration of the injection agent is taken out of the formation, resulting in the formulation of the chemical drive system in the reservoir has been changed. Therefore, in the face of conglomerate reservoirs with high content of clay minerals and zeolite minerals, it is especially important to choose suitable chemical formulation.

3.2 Formulation optimization

Chemical drive to improve the recovery of conglomerate reservoirs involves three important indicators, namely, formation inhomogeneity, wave coefficient and oil washing efficiency, and these three indicators are interrelated, conglomerate reservoirs of strong inhomogeneity caused by formation inhomogeneity, resulting in polymers and surfactants composed of oil repellents injected after the wave to the limited volume of the formation, and then so that the efficiency of the oil washing is not high, which formed the formation of recovery improvement of the disadvantageous factors, and therefore can be put forward to the direction of the formation of chemical modification and chemical optimization of the direction of the oil reservoir chemical agent.

Zhang et al. (2011) from Xinjiang Oilfield Exploration and Development Research Institute compounded the surfactant with polymers HA and HB in response to the inability to achieve ultra-low interfacial tension (10^− 3 mN/m) between a single Karamay petroleum sulfonate surfactant KPS and crude oil. The experimental formulations KPS/HA, KPS/HB and KPS/HA/HB systems were able to achieve ultra-low interfacial tension and enhanced recovery by more than 20%.

The key to achieve the success of chemical drive for crude oil extraction is the performance of surfactant, analyzed from the performance index of surfactant for oil drive, the amount of adsorption on the rock surface, the ability to reduce interfacial tension, salt and temperature resistance, price and other factors are the key indicators affecting the use of this surfactant (Zhang 2013). The degree of adsorption of the surfactant in the aqueous system depends largely on the nature of the hydrophilic head group of the surfactant monomer (Harendra et al. 2012). On this basis, experimental verification of the actual ability to drive off the oil needs to be carried out both indoors and in the field.

KPS as Xinjiang conglomerate reservoir site is currently the main application of surfactants, its anionic surfactant, synthesis process is simple, economical and practical, for Xinjiang conglomerate reservoir comprehensive performance is also better, the raw material oil for the Xinjiang conglomerate reservoir oil minus two lines or minus three lines of distillate, belong to the local materials, so this paper is still the main surfactant KPS to carry out the formulation of the formulation of the compounding and optimization.

The molecular structure of KPS is schematic:

Secondly, according to the more widely used oil repellent surfactants in the oilfield: nonionic-anionic surfactants and anionic surfactants, amphoteric betaine surfactants and nonionic surfactants are also selected in this paper, and a total of 17 kinds of oil repellent surfactants in the oilfield are selected.Through the interfacial tension measurement, optical contact angle measurement, evaluation of emulsification with crude oil, static adsorption experiments with Xinjiang oilfield water, the final preferred formulation was obtained through a series of evaluation experiments.

Secondly, this paper selects the surfactants that are widely used in oilfields at this stage: nonionic-anionic surfactants, anionic surfactants, amphoteric betaine surfactants and nonionic surfactants, which are 18 surfactants in total. The solution was prepared with formation water, and interfacial tension measurement, video optical contact angle measurement, evaluation of emulsification with crude oil, and adsorption experiments were conducted to arrive at the final preferred formulation through a series of evaluation experiments.

3.2.1 Interface Tension

Surfactant solution is injected into the oil formation to reduce the interfacial tension between oil and water, oil and rock, and change the wettability of the rock so as to improve the recovery rate. The ability to reduce the oil-water interface to ultra-low interfacial tension (10^− 3 mN/m) is one of the main criteria for surfactant systems for tertiary oil recovery. It is widely recognized that only by lowering the oil-water interfacial tension to the ultra-low interfacial tension region, the residual crude oil in the reservoir void can be deformed and flowed (Wang et al. 1995).So in this paper, the interfacial tension was measured as the primary index of surfactant, and the results are shown in Table 6.

Table 6

Data table of interfacial tension between surfactants for oil recovery and crude oil produced from Xinjiang conglomerate reservoirs
Anionic surfactant	Interfacial tension(mN/m)	Nonionic surfactant	Interfacial tension(mN/m)	Amphoteric surfactants	Interfacial tension(mN/m)
Pure KPS	0.06	AES	1.45	18 Alkyl Dimethyl Hydroxypropyl Sulfobetaine	0.002
KPS703	0.008	AEO-7	0.44	12 Alkyl Dimethyl Hydroxypropyl Sulfobetaine	0.18
Sodium dodecylbenzene sulfonate	0.08	AEO-9	0.53	18 alkyl betaine	0.002
Petroleum sulfonate ND	0.37	6501-C120	0.004	12-Alkyl dimethyl betaine	0.29
Petroleum sulfonate NH	0.38	6501-C115	0.006	14-Alkyl dimethyl betaine	0.19
Petroleum sulfonate NB-N	0.13	6501-1: 1LC	0.01	Lauramidopropyl hydroxysulfobetaine	0.35

The results of the interfacial tension measurements of the 18 surfactants at a concentration of 3000 ppm showed that the betaine of octadecyl had the lowest interfacial tension of 10^− 3 mN/m. Although the lowest interfacial tension of octadecyl betaine was found, the longer the carbon chain, the more hydrophobic groups increased, the poorer the solubility, and the lower the CMC was,thus, it can be seen that there is a positive correlation between the hydrophobicity of ionic surfactants and the ultra-low tension at the oil-water interface. In the solubilization of ionic micelles, the solubilization is mainly governed by the hydrocarbon chain length of the solubilizer molecules because the polar substances do not enter the interior of the micelles, but only solubilize on the surface of the micelles (Gong et al. 2019). And 6501 (coconut oil fatty acid diethanolamide) is good water solubility, 6501 series interfacial tension also reached a super low 10^− 3mN/m, and the proportion of diethanolamine the greater its water solubility, so in the 6501 series, 6501-C120 interfacial tension is the lowest. KPS703 is a modified KPS product with lower interfacial tension than pure KPS, it also reaches the 10^− 3 mN/m range.

Han et al. (2012) realized the ultra-low interfacial tension of oil and water in the Shengli Oilfield of PetroChina by using a generalized anionic-cationic surfactant complex with nonionic surfactant, and then understood the regional range of the surfactant concentration ratio for the ultra-low interfacial tension in the corresponding system, and obtained a large window of practical application. In this kind of generalized surfactant compounding dosage form, nonionic surfactant and anionic surfactant are actually two relatively independent factors, the former plays a role in regulating the oil-water equilibrium of the anionic and cationic surfactant compounding system, while the latter is the main factor in reducing the interfacial tension of the system.

The selected 6501 nonionic surfactant in this paper can achieve ultra-low interfacial tension by itself for the crude oil of Xinjiang conglomerate reservoirs, and we further compounded KPS703 and pure KPS with 6501, respectively, and the interfacial tension of the compounded surfactant decreased dramatically (see Fig. 11), which indicates that the nonionic surfactant 6501 and the anionic surfactant KPS are better mated to produce a positive effect.

Because the KPS series has been used for many years in the production site and its comprehensive performance has been affirmed, we initially decided to use KPS703 as the main surfactant, and the octadecyl betaine with ultra-low interfacial tension and 6501-C120 as the co-surfactant based on the results of the laboratory tests.

3.2.2 Surface wettability reversal

The experiment simulated the actual oil reservoir surface sample making, the surface is oily, the contact angle of conglomerate reservoir formation water is more than 100°, 0.3% concentration KPS703 can change the wettability of the rock surface, the contact angle is about 60°, the contact angle of 0.3% concentration betaine is about 31°, and the 0.3% concentration 6501 changes the wettability of the rock surface with a better effect, and the contact angle is about 30% (Fig. 12). And choosing a point on the sample thin section, dropping 6501 first, and then dropping simulated formation water at the same point, it was found that the contact angle was reduced to a very low level (Fig. 13), so that the surface was changed from oleophilic to hydrophilic. The contact angle on the surface of the oil-bearing natural core sand model was reduced, and the wettability was obviously reversed, so that the oil film on the surface of the oil-bearing natural core sand model could be stripped off and the residual oil could be initiated, which is very important for improving the crude oil recovery (Sun et al. 2015).

KPS703 was compounded with 6501 in a 1:1 ratio and the contact angle decreased to 46.8° (Fig. 14).

In addition to alkanes, most crude oils contain small amounts of surface-active polar components, and divalent cations combined with acidic components in the oil can control the wettability of the oil-water-rock system.Frieder Mugele et al. removed divalent ions from the water, and observed that the contact angle between the water and the rock surface was reduced by about 10°, which could improve crude oil recovery by several percentage points (Mugele et al. 2015; Herminghaus 2012). In this paper, the ionic surfactant was replaced with a nonionic surfactant, which again reduces the number of ions in the water that can be exchanged with the rock system, and controls the wettability by controlling the adsorption of ions to the solid-liquid interface, which from the results does change the wettability of the surface.

3.2.3 Emulsification performance with crude oil

The four surfactants were mixed and stirred with the crude oil of seven districts in the ratio of 1:1, and the emulsification effect was observed under the polarized light microscope. KPS and 6501 were oil-in-water (O/W) and hydrophilic with the crude oil, while KPS703 was water-in-oil (W/O) and lipophilic with the betaine (Fig. 15).The type of emulsion formed is due to the hydrophilic-lipophilic balance (HLB) of the surfactant and the disintegration of the emulsion phase also leads to an increase in the oil phase, an observation that implies that the oil is the dispersed phase. With the formation of O/W emulsions, the stability of the emulsions formed is due to the presence of electrical or spatial barriers to agglomeration on the dispersed droplets (Rosen and Kunjappu 2012).

Oil-in-water emulsions can improve oil repulsion in inhomogeneous reservoirs, especially conglomerate reservoirs with large extreme permeability differences. When the surfactant solution entering the oil reservoir is mixed with the crude oil, the oil-in-water emulsion is formed, the crude oil is dispersed phase, and the water is continuous phase, so that the thick oil molecules do not form a continuous mesh structure, and the friction between the water mostly replaces the friction between the oil in the flow, which reduces the viscosity of the crude oil at the leading edge of the displacement. At the same time, the oil-in-water emulsion can reduce the initial pressure gradient of crude oil seepage in the reservoir in the near-well zone, improve the seepage rheology of crude oil, thus increase the driving differential pressure of crude oil seepage, improve the oil recovery rate and increase the crude oil production. Ding et al. (2020) the W/O emulsification mechanism is more robust than the ultra-low interfacial tension and O/ W emulsification mechanisms.

Then from the stability of the emulsion to make a comparison (Fig. 16), it was found that KPS703 and 6501 precipitation rate of water is relatively low, after 2 hours of precipitation rate of about 80%, octadecyl betaine 2 hours of precipitation rate of water up to 100%, the highest relative. So all in all, 6501 has good overall emulsification properties.

3.2.4 Evaluation of adsorption performance

The adsorption of surfactant is mainly: electrical adsorption, ion exchange adsorption, intermolecular gravitational adsorption, formation of hydrogen bond adsorption and other physical and chemical adsorption. In this paper, different types of reservoir conglomerate samples with different types of surfactants were also selected to determine the nature of the surface charge of rock minerals and surfactants, and the results are shown in Tables 7.

Table 7

Table of zeta potential analysis results for the materials used in this paper
Sample name	Zeta(mV)	Mineral name	Zeta(mV)	Chemical agent name	Zeta(mV)
S09511	-28.45	Kaolinite	-8.98	2000ppm concentration KPS703	-37.7
S09521	-30.02	Montmorillonite	-21.03	2000ppm concentration KPS703	-37.7
S09551	-27.61	Montmorillonite	-21.03	5000ppm concentration KPS703	-43.23
S7	-17.32	Illite	-8.18	5000ppm concentration KPS703	-43.23
S8	-18.21	Chlorite group	-17.8	Salt resistant polymer	-3.87
S11	-19.71	Calcite	0.22	Salt resistant polymer	-3.87
S20	-4.033	Albite	-4.75	6501	-3.3
S13	-12.26	Zeolite	-24.47	Octadecyl Betaine	-2.09
Core fragment	-39.63	Zeolite	-24.47	Octadecyl Betaine	-2.09

One of the main uses of zeta potential is to study colloid-electrolyte interactions. Since many colloids are electrically charged, they interact with electrolytes in complex ways. When a solid is in contact with a liquid, the solid-liquid interface carries a charge of opposite sign. Charged ions of opposite polarity to its surface charge (counterions) will be adsorbed to it, while ions of the same charge (co-ions) will be repelled.Zeta potential is the potential at the shear surface, and it is an important indicator of the stability of a colloidal dispersion system.

The DLVO theory (the theory describing colloidal stability) suggests that the stability of a colloidal system is the net structure of the bilayer mutual repulsion and van der Waals mutual attraction between particles when they are in close proximity to each other. It is in the form of a colloidal solution that clay minerals exist in subsurface reservoirs. The energy barrier between particles as they approach each other arises from the repulsive forces, and when the particles have enough energy to overcome this barrier, the mutual attraction will bring the particles closer together and irreversibly stick together (Derjaguin and Landau 1941; Elimelech and O’Melia 1990).

Generally, particles have many negative or positive charges and they repel each other, thus stabilizing the whole system. The particles carry few negative or positive charges, and they will attract each other, thus reaching the instability of the whole system. Zeta potential distribution of conglomerate reservoir ranges from 0 to -40mV, and the potential of underground reservoir spans a wide range, mostly belonging to the unstable system. The larger the specific surface area of clay minerals, such as montmorillonite and zeolite, the higher the potential, and calcite is a carbonate mineral with basically positive charge.

KPS surfactant belongs to anionic surfactant, Zeta potential in -40mV or so, the higher the concentration, the better the stability, but the later need to comprehensive cost considerations, the general field concentration of 3000ppm. 6501 nonionic surfactant charged smaller, amphoteric surfactant betaine is the smallest charged.

The results of static adsorption experiments showed that the polymer adsorption on montmorillonite was the largest, reaching 14 mg/g, on zeolite the amount of adsorption and montmorillonite roughly comparable to the amount of adsorption on the actual conglomerate cores of less than 5 mg/g, and in the loose conglomerate cores of the adsorption amount is greater than that in the dense conglomerate cores of the adsorption amount of the order from the largest to the smallest order is as follows: montmorillonite ≥ zeolite > chlorite > illite > kaolinite > calcite > feldspar > rock cores (Fig. 17).

The adsorption amount of surfactant KPS703 on montmorillonite and zeolite is the largest (Fig. 18), reaching more than 40mg/g, and the adsorption equilibrium concentration is also the highest, and the adsorption equilibrium is 5000 ppm, while the adsorption amount of the backbone minerals, feldspar and calcite, etc., is less than 10 mg/g. In the conglomerate cores, the adsorption amount of KPS703 is around 10 mg/g, and the adsorption equilibrium is around 3,500-4,000ppm. It can be seen that the adsorption amount of surfactant is much larger than that of polymer, especially on clay minerals, the adsorption amount reaches three times as much as that of polymer.

The results of dynamic adsorption experiments show (Tables 8) that the adsorption amount of polymer is much smaller than the adsorption amount of surfactant because its molecular weight is 15 million, which mainly occurs along the large pore channel scurrying as well as blocking the phenomenon of small pore channels, while surfactant is mostly a small molecule solvent, which, in addition to the reduction of the physical retention of the polymer, is more of the loss brought about by the chemical reaction. Therefore, the loss of adsorption and retention of binary composite oil repellent solution mainly occurs on the surfactant (Li et al. 2016).

Table 8

Dynamic adsorption of binary composite oil repellent chemistries on rock cores
Core number	Permeability(mD)	Polymer dynamic adsorption capacity(mg/g)	Surfactant dynamic adsorption(mg/g)
9511	118	0.110	0.216
11	56.38	0.127	0.261
20	26.72	0.139	0.255

Permeability is negatively correlated with dynamic adsorption, i.e., cores with high permeability have low adsorption of oil repellents, and cores with high permeability contain more highly adsorbed minerals. From the X-diffraction whole-rock analysis (Tables 9), The measured 9511 kaolinite content of Class I core is the highest, up to 7%, the content of immonite mixed layer is 6.3%, and the zeolite content is 1.1%. The content of immonite mixed layer of Class II core decreases and becomes 4.2%, but the content of zeolite rises to 7.4%, and the total content of clay minerals is also higher than that of the Class I reservoir, so that the degree of adsorption of the chemical agent in the Class II reservoir is greater than that of the Class I reservoir. Class III cores are too dense, so that large polymers are stuck in the pores, so the polymer retention in class III cores becomes larger, and the dynamic adsorption of surfactant in class III cores is not significantly larger than that in class I and II cores, the reason for the analysis is that Class III core samples contain a large amount of mirabilite, which is a sulfate mineral. The KPS surfactant is a sulfonated product of sulfur trioxide (SO₃), which reacts with water to form sulfuric acid (H₂SO₄). In nature, minerals such as mirabilite, anhydrous mirabilite, and calcium mirabilite can even extract sodium sulfate (Na₂SO₄). mirabilite is generally highly soluble in water and easily weathered, So it is speculated that the solution after dynamic adsorption can detect a large number of absorption peaks of sulfate groups (-SO₃H) or sulfate groups (-SO₄H) under ultraviolet light, allowing the concentration of surfactants to increase instead of decrease.

Table 9

Mineral content analysis of cores from different reservoir types
Core number	Skeleton mineral content (%)		Carbonate mineral content(%)			Sulfate mineral content(%)			Silicon-aluminate mineral content(%)		Clay mineral content(%)				Reservoir type
Core number	feldspar	quartz	calcite	dolomite	limonite	mirabilite	barite	anhydrite	zeolites	corundum	kaolinite	illite	chlorite	Imon mixed layer	Reservoir type
S09511	33.1	36.2	0.5	2.9		10.2	1.6		1.1	1.0	7.0			6.3	I
S11	27.7	42.9				6.7	1.2		7.4		3.2	6.8		4.2	II
S20	16.9	22.9	1.7	1.5	3.2	43.1	0.6		2.0	0.3	1.0	2.7		4.0	III

Considering that the degree of adsorption of surfactant is greater than that of polymer, and the degree of its action is closely related to the minerals contained in the reservoir, therefore, in the later optimization of the formula, the main research direction is to improve the surfactant, and the type and concentration of polymer can remain unchanged.

The role of polymer (HPAM) molecules and clay mineral surface: ① the electrostatic attraction between -COO- of HPAM and the metal active center or Stern layer on the clay surface; ② dispersion force, induced force and hydrogen bonding between the clay mineral surface and HPAM molecules.The level of polymer adsorption depends on three factors. First, the most important of these is the type and nature of the polymer, such as molecular weight, molecular size and charge density or degree of hydrolysis (for HPAM). Secondly, the solvent (only aqueous solutions are considered here) PH, salinity (Na⁺, C1⁻, etc.) and hardness (Ca²⁺, Mg²⁺) are the most important factors. The presence of other substances (e.g., alcohols) in the solution may also affect the solvent quality and thus the level of polymer adsorption.Thirdly, surface area and type of surface (silica, calcium carbonate, clay, etc.) are very important factors. Surface charge is also an important factor in determining polymer adsorption (Yun and Kovscek 2015).

For the surfactant KPS, the -SO³⁻ group, hydrocarbon group and clay mineral surface have strong adsorption, the metal active centers on the clay surface (Al³⁺, Fe³⁺, Fe²⁺, Ca²⁺, Mg²⁺, etc.) will be electrically attracted to the surfactant ions, and there is an electrical attraction between the Sten layer on the negatively charged clay surface and the surfactant -SO³⁻, and there are also dispersion forces, induced forces, hydrogen bonding, and colloidization of surfactants that have already adsorbed on the clay minerals, which ultimately lead to multilayer adsorption.

Sol particles are electrically charged, and the main source of these charges is the selective adsorption of certain ions from the aqueous solution: adsorbed positive ions are positively charged, adsorbed negative ions are negatively charged, but an equal amount of counter-ions should also be present for the whole solution. The ions of the solid particles and the counterions in solution form a double electric layer.

Counterions are acted upon in solution in two opposite directions: ① the gravitational force of the ions adsorbed on the surface of the solid particles, which seeks to pull them toward the interface; and ② the thermal movement of the ions themselves, which causes them to diffuse out of the interface and into the solution.

As a result, the counterions show an equilibrium distribution outside the surface of the solid particles: the concentration of counterions is larger near the interface; as the distance from the interface increases, the counterions go from more to less, forming a diffuse distribution. Here we can lead to the Stern bilayer model, Stern that the solid surface due to electrostatic gravity and van der Waals gravity and attract a layer of counterions, close to the solid surface to form a fixed adsorption layer, this adsorption is known as the characteristic adsorption, this adsorption layer (fixed layer) is called the Stern layer.

Del Hoyo et al. (2008) have found that surfactants adsorb in the spaces between the layers of montmorillonite, while the adsorption of anionic surfactants by kaolinite and illite is not altered x-ray maps, suggesting adsorption on the surfaces or in the structural channels of these minerals.Surfactants interact with hydroaluminosilicates through functional groups of organic compounds,variable cations of clay minerals formed by ion-dipole or hydrogen bonding.On the other hand, rearrangement of the adsorbed surfactant molecules was also observed.So surfactant-mineral interaction produces adsorption and also changes both.

According to the results of the previous experiments, the preferred nonionic surfactant 6501 and the amphoteric surfactant octadecyl betaine, respectively, were static adsorbed with the minerals of conglomerate reservoirs, and it can be seen that the adsorption amount of 6501 was much lower than that of KPS703 and octadecyl betaine (Fig. 19), and the amount of adsorption of octadecyl betaine on the minerals was comparable to that of KPS703 (Fig. 20).

It can be seen that adsorption of anionic surfactants is inevitable in the face of conglomerate reservoirs with complex mineral compositions, and even though the electrical adsorption between negatively charged mineral rocks was reduced, multilayer adsorption still occurs.Therefore, this paper synthesizes all the above results and prefers nonionic surfactant 6501 as the co-surfactant for chemical drive in Xinjiang conglomerate reservoirs, followed by octadecyl betaine, and both of them are compounded with the main surfactant KPS703, and then carry out the dynamic drive validation experiments.

3.3 Analysis of factors affecting the recovery rate

3.3.1 Analysis of oil recovery experiment results

The chemical drive formulations used for dynamic drive are (1) 0.3% KPS703 with 0.18% anti-salt polymer; (2) 0.2% KPS703 + 0.1% 6501 + 0.18% anti-salt polymer; (3) 0.2% KPS703 + 0.1% betaine + 0.18% anti-salt polymer. Two high porosity permeability natural core samples and two medium porosity permeability samples were selected to do parallel comparison experiments with the three formulations, and the results are shown in Table 10.

Table 10

Summary Table of Oil Repellent Validation Experiments
Formulation	Sample	Porosity (%)	permeability (mD)	Degree of water drive recovery	Binary drive recovery degree	Subsequent water drive recovery	Total recovery degree	Price (million yuan/ton)
0.3% KPS703 + 0.18% anti-salt polymer	9551	23.1	168	59.83%	15.67%	14.25%	89.74%	2～2.3
0.3% KPS703 + 0.18% anti-salt polymer	13	11.4	49.13	39.84%	18.59%	13.28%	71.72%	2～2.3
0.2%KPS703 + 0.1%6501 + 0.18%anti-salt polymer	9519	24.7	283	37.24%	27.93%	13.96%	79.13%	0.7～1
0.2%KPS703 + 0.1%6501 + 0.18%anti-salt polymer	11	18.77	56.38	53.05%	26.52%	11.79%	91.36%	0.7～1
0.2% KPS703 + 0.1% betaine + 0.18% antisalt polymer	9519	24.7	283	53.05%	23.58%	17.68%	94.31%	0.9～1.3
0.2% KPS703 + 0.1% betaine + 0.18% antisalt polymer	13	11.4	49.13	39.84%	26.56%	13.28%	79.69%	0.9～1.3

According to the experimental results, the recovery rate of high-porosity and high-permeability reservoirs is greater than that of low-porosity and low-permeability reservoirs, and the total recovery degree of the three formulations is almost the same, reaching 90%, and the recovery rate of the binary system of compounded betaine is slightly higher than that of the other two kinds of systems, and the recovery rate of compounded 6501 is the second one. However, if we only look at the recovery rate of the binary system part, the recovery degree of the binary system of compounded 6501 reaches more than 25%, which is obviously higher than that of the binary system of compounded betaine and single KPS703, and the recovery rate of the subsequent water drive is the highest for betaine. From the results of the recovery rate, 6501 has good relevance and adaptability to the conglomerate reservoirs in the study area.

Since the nonionic surfactant 6501 does not exist in ionic state in solution, it has high stability, is not easily affected by the presence of strong electrolytes, and is not easily affected by acids and alkalis, and it can be mixed with the anionic surfactant KPS703, with good compatibility, good solubility in various solvents, and does not strongly adsorb on solid surfaces. And through the price comparison, it is found that the price per ton of KPS703 is 20,000 to 25,000 RMB yuan, the price per ton of octadecyl betaine is about 9000 to 13,000 RMB yuan, and the price per ton of 6501 is the lowest, only 7000 to 10,000 RMB yuan.

3.3.2 Relationship between microscopic characterization parameters and recovery from binary composite drives

The parameters of the cores used for chemical drive are shown in Table 11, where a relationship can be established between the adsorption of chemicals and the total degree of recovery.

Table 11

Oil-driven natural core adsorption and degree of recovery
Core number	Core dry weight(g)	Zeta potential(mV)	Surfactant adsorption capacity(mg/g)	Polymer adsorption capacity(mg/g)	Total adsorption capacity of surfactants on rock cores(g)	Total adsorption capacity of polymer on rock core(g)	Total recovery rate(%)
9551	28.5	-27.61	0.229046	0.114729	6.527811	3.2697765	89.74
9519	29.8	-30.02	0.225672	0.112078	6.7250256	3.3399244	94.31
13	38.9	-12.26	0.250536	0.131614	9.7458504	5.1197846	71.72
11	46.7	-19.71	0.240106	0.123419	11.2129502	5.7636673	79.13

The amount of chemistries adsorbed was calculated and related to the recovery rate (Fig. 21).

Finally, the correlation between the amount of poly and surface agent adsorption and the recovery rate was obtained to be very good and negatively correlated, indicating that the smaller the adsorption amount is, the higher the recovery rate is.

Recovery versus binary composite drive surfactant adsorption: y = -0.1099x + 0.3284, R² = 0.9894;

Recovery versus binary composite drive polymer adsorption: y = -0.0864x + 0.1928, R² = 0.9894.

Through the comprehensive analysis of the experimental results, the following conclusions are obtained from this study:

(1) Compared with conglomerate reservoirs in eastern China, Xinjiang conglomerate reservoirs have prominent complex-modal pore structure characteristics, with large differences in reservoir pore size, distribution and geometry, average pore-throat ratio, average pore radius, throat, and coordination number, and the anisotropic spreading has obvious directional influences on the formation of the chemical agent; it is difficult to uniformly advance the injectant;

(2) The surface of conglomerate reservoir is active in physicochemical properties, and the mineral composition is complex, containing a large number of clay materials and zeolite minerals with huge specific surface, which are easy to have physicochemical interaction with polymerizing agent, causing polymer retention and adsorption of surface activator, resulting in loss and change of the formulation system in the subsurface, which has a certain impact on the recovery rate;

(3) Although KPS series surfactant is anionic surfactant, it still adsorbs a lot with conglomerate reservoirs because of multilayer adsorption. The nonionic surfactant does not ionize in water and does not contain anions and cations that can be exchanged for ions, and after encountering clay minerals, it forms hydrogen bonds with the polar group on the surface of the mineral crystal layer, and then adsorbs on the surface of the clay particles. Hydrogen bonding is not a chemical bond, it is a special intermolecular force, so the adsorption amount of nonionic surfactant will be smaller than that of ionic surfactant;

(4) Facing the medium temperature, medium mineralization and low formation pressure of medium-high permeability Xinjiang conglomerate reservoirs, nonionic surfactant 6501 can be used as a co-surfactant to improve crude oil recovery, and it also has good economy.

(5) Reservoir microscopic characteristic parameters combined with the study of chemical agent adsorption can be found that the larger the specific surface of the rock mineral Zeta potential is larger, while its adsorption capacity is also stronger, and ultimately the tandem can be obtained from the chemical agent adsorption amount and the recovery rate of the correlation between the graphical plate, reduce the amount of adsorption of the chemical agent can improve the rate of recovery.

(6) This paper provides a complete set of main controlling factors of chemical drive and a methodology for the study of enhanced crude oil recovery. For conglomerate reservoirs, there is an essential and inevitable connection between macroscopic development characteristics and microscopic physicochemical properties. The recovery rate is determined by the interaction between reservoir microscopic properties and fluids. Therefore, an in-depth study of the microscopic physicochemical properties of conglomerate reservoirs and the interaction between chemicals and surface minerals of conglomerate reservoirs can help to solve the problems encountered in the chemical drive of conglomerate reservoirs.Develop and screen out chemical drive products for conglomerate reservoirs, gradually improve the physicochemical indexes of poly-surface compounds for chemical drive, and establish a reasonable chemical drive system, so as to promote the large-scale application of chemical drive for conglomerate reservoirs to improve the recovery rate.

Author contributions XY: Conceptualization, Methodology, Writing-Original Draft, Investigation, Data Curation. YT and YS: Conceptualization, Supervision, Writing-Review and Editing. XW and RL: Resources, Data Curation. HZ and SZ: Investigation, Data analysis, image mapping and revision. BL: Resources, Methodology. All authors reviewed the manuscript.

Acknowledgments The author is grateful for the funding from the National Natural Science Foundation of China [No.51904180] and the Xinjiang Conglomerate Reservoir Laboratory Development Project [2020D04045].

Ethics approval Not applicable.

Competing interests I would like to declare that the authors have no competing interests as defned by Springer, or other interests that might be perceived to infuence the results and/or discussion reported in this paper.

Data Availability The data that support the fndings of this study are available from the corresponding author upon reason- able request.

Consent to publish All the authors have approved the manuscript for submission and publication.

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