Composite synergistic system for old shale gas well and immovable string production increasing process

Abstract

The invention provides a composite synergistic system for a shale gas old well and an immovable string production increasing process. The composite synergistic system mainly comprises the following substances: 10-12% of a wetting improver; 4%-6% of a scale remover; 2%-3% of a scale inhibition dispersant; 5%-10% of a resistance-reducing discharge aiding agent; 15%-20% of a synergistic accelerant; the wetting improver is a mixture of alkyl polyglucoside, an anionic surfactant sodium dodecyl benzene sulfonate and deionized water, the content of the alkyl polyglucoside in the wetting improver is 5%-10%, and the content of the anionic surfactant sodium dodecyl benzene sulfonate is 15%-18%; the descaling agent is a mixture of sodium alpha-olefin sulfonate and nonylphenol polyoxyethylene ether ammonium sulfate, and the mass ratio of the sodium alpha-olefin sulfonate to the nonylphenol polyoxyethylene ether ammonium sulfate in the descaling agent is (2: 1)-(3: 1). According to the composite synergistic system, through combination and reuse of different materials and different doses, the multifunctional composite synergistic system integrating vibration, permeation and dispersion effects is researched and developed, and therefore immovable tubular column yield increase construction of a shale gas old well is achieved.

Description

Technical Field

[0001] The present invention relates to the technical field of oil and natural gas extraction, and in particular to a composite efficiency enhancement system for old shale gas wells and a production enhancement process without moving a tubing string. Background Art

[0002] At present, the exploitation of unconventional oil and gas such as shale oil and gas, deep coal-rock gas, etc. in my country has become the development focus and new growth point of various oilfield companies. However, as the shale gas production time goes by, the formation pressure of shale gas wells gradually decreases, the gas production gradually decreases, the wellbore is seriously filled with liquid and blocked, and the pressure and production drop significantly. The production increase technology of old wells has attracted more and more attention.

[0003] As shale gas well production progresses, formation particle migration, proppant reflux fine sand, soluble bridge plug dissolution residues, inorganic scale, return of drilling and fracturing fluids or materials, and iron oxides caused by bacterial metabolites may clog formation cracks and wellbore channels. Most blockages are the result of accumulation over time, and the blockage goes through a process of initiation-aggravation-blocking. Existing dredging methods mostly use chemical reagents to remove pipeline blockages, but most existing chemical reagents can only target a single type, and it is difficult to achieve multi-effect synergy. In addition, traditional chemical reagents require the tubing to be moved continuously during use in order to optimize the dredging effect and ensure operational safety. However, a series of problems may arise during the movement of the tubing, such as moving the tubing may cause secondary damage to the formation, which may stir and generate sediments at the bottom of the well during the movement of the tubing, causing fine particles to enter the formation gaps, thereby causing a decrease in permeability.

[0004] In view of this, the present invention is proposed. Summary of the Invention

[0005] The first purpose of the present invention is to provide a composite synergistic system for old shale gas wells. The composite synergistic system can simultaneously treat multiple blockages through the compound use of multiple substances, thereby significantly improving the unblocking effect and overcoming the disadvantage of traditional chemical unblocking agents that require frequent movement of the tubing. It is safe, efficient and environmentally friendly.

[0006] The second purpose of the present invention is to provide a shale gas old well fixed tubing production increase construction process, which applies the above-mentioned composite synergistic system. The process eliminates the operation of continuously moving the oil pipe by pumping the composite synergistic system into the fixed tubing, thereby greatly optimizing the effect of the composite synergistic system, so that the composite synergistic system can be immersed in the blocked area for a long time to fully dissolve the blockage.

[0007] In order to achieve the above-mentioned purpose of the present invention, the following technical solutions are adopted: A composite efficiency enhancement system for old shale gas wells, mainly comprising the following substances in percentage by mass: 10%-12% wetting improver; 4%-6% descaling agent; 2%-3% scale inhibitor and dispersant; 5%-10% drag reduction and drainage agent; 15%-20% synergistic promoter; The wettability improving agent is a mixture of alkyl polysaccharide, anionic surfactant sodium dodecylbenzene sulfonate and deionized water, wherein the alkyl polysaccharide in the wettability improving agent is 5%-10%, and the anionic surfactant sodium dodecylbenzene sulfonate is 15%-18%; The descaling agent is a mixture of sodium α-olefin sulfonate and ammonium sulfate of nonylphenol polyoxyethylene ether, and the mass ratio of sodium α-olefin sulfonate to ammonium sulfate of nonylphenol polyoxyethylene ether in the descaling agent is 2:1-3:1.

[0008] Preferably, as a further specific embodiment, 12% wetting improver; 5% descaling agent; 3% scale inhibitor and dispersant; 8% drag reduction and drainage agent; 19% synergistic enhancer; The wettability improving agent contains 8% alkyl polysaccharide and the anionic surfactant sodium dodecylbenzenesulfonate contains 16%; The mass ratio of sodium α-olefin sulfonate to nonylphenol polyoxyethylene ether sulfate ammonium salt in the descaling agent is 2.5:1.

[0009] In the present invention, a supramolecular multifunctional composite composite synergistic system is developed by the combined use of wettability improvers, scale removers, scale reducing dispersants, resistance reducing drainage aids and synergistic promoters. It exhibits significant technical advantages through its unique molecular recognition and dynamic assembly capabilities. Compared with traditional chemical dredging agents, the composite synergistic system provided by the present invention can more efficiently contact a variety of blockages while reducing secondary damage to the formation. At the same time, the composite synergistic system provided by the present invention also has the characteristics of spectral adaptability and selective dissolution. It can achieve efficient unblocking under mild conditions and avoid corrosion of strong acids and alkalis to pipes and formations. At the same time, it has multiple functions such as unblocking, scale removal, water lock release, and drainage assistance.

[0010] In the present invention, the wettability improver is a mixture of alkyl polysaccharide, anionic surfactant sodium dodecylbenzene sulfonate and deionized water, and the alkyl polysaccharide in the wettability improver is 5%-10%, and the anionic surfactant sodium dodecylbenzene sulfonate is 15%-18%. In the present invention, a compound system of alkyl polysaccharide and anionic surfactant sodium dodecylbenzene sulfonate is used as a high-efficiency wettability improver, wherein the compound system of the two can significantly reduce the surface tension of the aqueous solution, enhance the spreading ability of the liquid on the rock surface, thereby improving the wettability, and at the same time, the hydroxyl group in the alkyl polysaccharide and the sulfonic acid group in the anionic surfactant sodium dodecylbenzene sulfonate work together to make the solution It is easier to adsorb on the surface of shale covered with hydrophobic substances such as organic matter or oil film, thereby promoting water phase penetration. At the same time, the hydroxyl groups in alkyl polysaccharide can also be adsorbed on the rock surface through hydrogen bonding, thereby converting oil wettability to water wettability. The strong hydrophilic groups in the anionic surfactant sodium dodecylbenzene sulfonate can further enhance the effect of alkyl polysaccharide on changing the wettability of rocks, thereby improving the flowback efficiency of the composite enhancement system. In addition, alkyl polysaccharide has good solubilizing ability for organic blockages, while the anionic surfactant sodium dodecylbenzene sulfonate has a strong dispersing effect on inorganic scale. The combination of the two can make the prepared composite enhancement system able to treat multiple types of blockages at the same time, and alkyl Polysaccharide can still remain stable in a high temperature and high mineralization environment, thereby compensating for the precipitation problem that may occur in the anionic surfactant sodium dodecylbenzene sulfonate under high salt conditions. Therefore, it can be seen from the above that the present invention reuses the anionic surfactant sodium dodecylbenzene sulfonate and the alkyl polysaccharide as a high-efficiency wettability improver, and for the present invention, the amount of the alkyl polysaccharide and the anionic surfactant sodium dodecylbenzene sulfonate in the wettability improver is limited. When the alkyl polysaccharide is 5%-10% and the anionic surfactant sodium dodecylbenzene sulfonate is 15%-18%, preferably the alkyl polysaccharide is 8% and the anionic surfactant sodium dodecylbenzene sulfonate is 15%. When the amount of sodium benzenesulfonate is 16%, the chemical composite synergistic system prepared has excellent effect. This is because in the system where alkyl polysaccharide and anionic surfactant sodium dodecylbenzenesulfonate are compounded as wettability improvers, the usage ratio of the two significantly affects the wettability improvement effect. A reasonable ratio between the two can better exert a synergistic effect, while an improper ratio between the two will lead to a decrease in the performance of the wettability improver or even an antagonistic effect. If the amount of alkyl polysaccharide is too small and the amount of anionic surfactant sodium dodecylbenzenesulfonate is too large, the prepared composite synergistic system will have poor salt resistance, limited solubilization ability for organic blockages, and insufficient stability at high temperatures.However, if the amount of anionic surfactant sodium dodecylbenzene sulfonate is too high and the amount of alkyl polysaccharide is too low, the dispersion effect on inorganic scale will be poor. In addition, excessive amount of anionic surfactant sodium dodecylbenzene sulfonate will cause the two to compete for adsorption on the rock surface, thereby reducing the effective coverage of alkyl polysaccharide.

[0011] The present invention adopts a mixture of sodium α-olefin sulfonate and nonylphenol polyoxyethylene ether ammonium sulfate as a descaling agent, thereby significantly improving the declogging effect and overcoming the limitations of a single surfactant, wherein sodium α-olefin sulfonate has an excellent ability to reduce surface tension, thereby being able to quickly wet the rock surface and promote the descaling agent to enter the microcracks and pores of old shale gas wells, and the polyoxyethylene chain in nonylphenol polyoxyethylene ether ammonium sulfate can enhance molecular stretchability, and synergize with sodium α-olefin sulfonate to form a more stable micelle structure, further improving the permeability and spreading ability of the descaling agent; at the same time, sodium α-olefin sulfonate has a strong emulsifying ability for light oil and organic scale in old shale gas wells, thereby dispersing them into tiny droplets, and the benzene ring structure of nonylphenol polyoxyethylene ether ammonium sulfate has a specific solubilizing effect on heavy organic matter in old shale gas wells, and the combination of the two can cover a wider range of blockages, and at the same time, sodium α-olefin sulfonate has a strong emulsifying ability for light oil and organic scale in old shale gas wells, thereby dispersing them into tiny droplets, and the benzene ring structure of nonylphenol polyoxyethylene ether ammonium sulfate has a specific solubilizing effect on heavy organic matter in old shale gas wells. Acid can still maintain activity under high mineralization and high temperature, but if it is used alone, it may become ineffective due to the precipitation of calcium and magnesium ions. The EO chain of nonylphenol polyoxyethylene ether ammonium sulfate gives it the ability to resist hard water. At the same time, it can chelate divalent ions to protect nonylphenol polyoxyethylene ether ammonium sulfate from the influence of calcium and magnesium ions. The combination of the two significantly improves tolerance and can also handle organic and inorganic blockages. At the same time, for the present invention, the mass ratio between sodium α-olefin sulfonate and nonylphenol polyoxyethylene ether ammonium sulfate is very important for the composite synergistic system of the present invention. When the mass ratio of sodium α-olefin sulfonate and nonylphenol polyoxyethylene ether ammonium sulfate in the descaling agent is 2:1-3:1, preferably the mass ratio of sodium α-olefin sulfonate and nonylphenol polyoxyethylene ether ammonium sulfate is 2.5:1, the composite synergistic system prepared thereby has excellent effect, because the mass ratio between the two significantly affects the performance of the composite synergistic system. The two can optimize surface activity, emulsification ability and salt resistance stability through synergistic effect, but different ratios will produce different effects. If the amount of sodium α-olefin sulfonate is too much, the prepared composite synergistic system will have weak resistance to hard water and limited solubilization ability for heavy organic matter. If the amount of nonylphenol polyoxyethylene ether ammonium sulfate is too much, the prepared composite synergistic system will have poor biodegradability.

[0012] Preferably, as a further specific embodiment, the scale inhibitor and dispersant is a mixture of hydroxyethylidene diphosphonic acid, sodium hexametaphosphate and deionized water, the mass percentage of the hydroxyethylidene diphosphonic acid is 10%-15%, and the mass percentage of the sodium hexametaphosphate is 2%-5%; Preferably, the mass percentage of the hydroxyethylidene diphosphonic acid is 12%, and the mass percentage of the sodium hexametaphosphate is 3%.

[0013] In the present invention, by using a mixture of hydroxyethylidene diphosphonic acid, sodium hexametaphosphate and deionized water as a scale inhibitor and dispersant, the inhibition and removal effect of inorganic scale can be significantly improved, while taking into account formation compatibility and operation economy. Hydroxyethylidene diphosphonic acid can form stable chelates with many metal ions through chelation, thereby organizing the formation of scale crystal nuclei, and can also be adsorbed on the surface of the crystal to inhibit the growth of scale crystals. At the same time, sodium hexametaphosphate can disperse the formed tiny scale particles through electrostatic repulsion to prevent their aggregation and precipitation, and has outstanding dispersibility for iron oxides and silicon scales. At the same time, hydroxyethylidene diphosphonic acid is more effective in descaling under high temperature and high pH conditions, while sodium hexametaphosphate performs better under medium and low temperature and high salinity conditions. The combination of the two can cover the common composite scales in shale gas wells (such as CaCO3-CaSO4-Fe2O3 mixed scale), and the combination system of the two can penetrate into the scale layer. Hydroxyethylidene diphosphonic acid chelates metal ions in the scale and softens it. Scale body, while sodium hexametaphosphate can decompose the scale layer structure, thereby promoting its disintegration into tiny particles, which is convenient for flowback; wherein, for the present invention, the dosage ratio between the two is also limited, wherein the mass percentage of hydroxyethylidene diphosphonic acid is 10%-15%, and the mass percentage of sodium hexametaphosphate is 2%-5%, preferably the mass percentage of hydroxyethylidene diphosphonic acid is 12%, and the mass percentage of sodium hexametaphosphate is 3%, the prepared composite synergistic system has excellent effect, this is because the dosage ratio between the two directly affects the effect of the scale inhibitor and dispersant, wherein when the dosage of hydroxyethylidene diphosphonic acid is small, the prepared composite synergistic system will have insufficient chelating ability for dense scale such as calcium carbonate, and at the same time, without the assistance of hydroxyethylidene diphosphonic acid, sodium hexametaphosphate will be easily hydrolyzed and ineffective at high temperature; and if the dosage of hydroxyethylidene diphosphonic acid is high, its dispersing effect on suspended particles will be weaker than that of sodium hexametaphosphate, resulting in poor overall dispersion effect of the composite synergistic system.

[0014] Preferably, as a further specific embodiment, the group-reducing agent is a mixture of cocamidopropylamine oxide, dodecyldimethylhydroxysulfobetaine and deionized water; The mass percentage of the cocamidopropylamine oxide is 8%-12%, and the mass percentage of the lauryldimethylhydroxysulfobetaine is 7%-9%; Preferably, the mass percentage of the cocamidopropylamine oxide is 10%, and the mass percentage of the lauryldimethylhydroxysulfobetaine is 8%.

[0015] In the present invention, by adopting a mixture of cocamidopropylamine oxide, dodecyldimethylhydroxysulfobetaine and deionized water as a drag-reducing and drainage agent, the fluid friction resistance can be significantly reduced, the backflow efficiency can be improved and reservoir protection can be taken into account. Among them, cocamidopropylamine oxide is a zwitterionic surfactant, which can form a hydration layer by adsorption on the pipe wall, thereby reducing the friction between the fluid and the pipe string, thereby reducing the friction coefficient, and its unique "slip resistance effect" can promote the transformation of fluid turbulence to laminar flow, and the strong hydrophilic sulfonic acid group of sulfobetaine can enhance the lubricity of the fluid, and can further optimize the flow state in collaboration with cocamidopropylamine oxide. At the same time, it has excellent shear stability. In addition, the composite use of the two can reduce the surface tension, thereby reducing capillary resistance and promoting the backflow of fracturing fluid. In addition, the sulfonic acid group of dodecyldimethylhydroxysulfobetaine and the amide group of cocamidopropylamine oxide synergistically change the rock Wettability, reducing water lock damage, while the mild emulsification effect of the two on the residual oil phase and organic scale can help the blockage move with the backflow flow, and the sulfonic acid group of sulfobetaine and the amine oxide structure of cocamidopropylamine oxide compete for adsorption on the rock surface, reducing agent retention; and for the present invention, the dosage between the two is very important for the performance of the composite synergistic system prepared by the present invention. When the mass percentage of cocamidopropylamine oxide is 8%-12%, the mass percentage of dodecyldimethylhydroxysulfobetaine is 7%-9%, preferably the mass percentage of cocamidopropylamine oxide is 10%, and the mass percentage of dodecyldimethylhydroxysulfobetaine is 8%, the composite synergistic system prepared by it has excellent effect. This is because in the fracturing or dredging operations of old shale gas wells, the dosage ratio of cocamidopropylamine oxide and dodecyldimethylhydroxysulfobetaine will significantly affect the comprehensive performance of the drag reducing and drainage agent. The two can optimize the friction resistance, flowback efficiency and reservoir compatibility of the fluid through synergistic effect, but different ratios will produce differentiated effects. If the amount of cocamidopropylamine oxide is too much, the drainage effect of the prepared composite synergistic system will be weak, and more foam may be generated, which requires the addition of additional defoaming agents. If the amount of cocamidopropylamine oxide is too little, the resistance reduction ability of the prepared composite synergistic system will be weak, and some cocamidopropylamine oxide will be partially ineffective at high temperatures.

[0016] Preferably, as a further specific embodiment, the synergistic promoter is an inorganic salt, nonylphenol polyoxyethylene ether, a polyvalent organic alcohol and deionized water; The mass percentage of the inorganic salt is 1%-2%, the mass percentage of the nonylphenol polyoxyethylene ether is 15%-18%, and the mass percentage of the polyvalent organic alcohol is 4%-6%; Preferably, the mass percentage of the inorganic salt is 1.5%, the mass percentage of the nonylphenol polyoxyethylene ether is 16%, and the mass percentage of the polyvalent organic alcohol is 5%.

[0017] In the present invention, by using a mixture of inorganic salts, nonylphenol polyoxyethylene ether, polyols and deionized water as a synergistic promoter, the permeability, stability and reservoir adaptability of the composite synergistic system can be significantly improved, wherein nonylphenol polyoxyethylene ether can further reduce the surface tension, thereby promoting the composite synergistic system to enter microcracks and pores, and at the same time its hydrophilic-lipophilic balance can adapt to reservoirs with different wettability, and polyols can combine with water molecules through hydrogen bonds, thereby reducing liquid viscosity and improving fluidity. It can also assist nonylphenol polyoxyethylene ether in solubilizing organic blockages, and at the same time, inorganic salts can compress the double layer, reduce clay expansion, and adjust the ionic strength, thereby enhancing the stability of the micelles of nonylphenol polyoxyethylene ether. In addition, nonylphenol polyoxyethylene ether is easy to precipitate under high salt conditions, but polyols can act as "co-solvents" to maintain its solubility. At the same time, inorganic salts can also delay the cloud point phenomenon of nonylphenol polyoxyethylene ether at high temperatures, and polyols buffer pH, thereby avoiding the interaction between inorganic salts and formations. The violent reaction of the mineral, wherein for the present invention, the mass percentage of the inorganic salt is 1%-2%, the mass percentage of nonylphenol polyoxyethylene ether is 15%-18%, and the mass percentage of the polyol is 4%-6%. Preferably, the mass percentage of the inorganic salt is 1.5%, the mass percentage of nonylphenol polyoxyethylene ether is 16%, and the mass percentage of the polyol is 5%. The prepared composite synergistic system has excellent effect. This is because the appropriate dosage ratio can significantly affect the penetrant, stabilizer and reservoir compatibility of the synergistic promoter. If the dosage of nonylphenol polyoxyethylene ether is too high, the nonylphenol polyoxyethylene ether will be easily ineffective in a high-salt environment, thereby increasing the proportion of polyol for buffering. If the dosage of polyol is too high, the viscosity reduction effect will be too strong, thereby reducing the sand carrying capacity. If the dosage of the inorganic salt is too high, the salinity of the overall composite synergistic system will increase, and nonylphenol polyoxyethylene ether may precipitate under high salt conditions and may cause scaling.

[0018] Preferably, as a further specific embodiment, it further comprises 15%-20% chelating dispersant, 3%-5% penetrant, 0.1%-0.2% sterilant and 23.8%-45.9% deionized water; wherein the chelating dispersant is a mixture of polyepoxysuccinic acid, polyphosphate and organic alcohol; The penetrant is one or more of tridecyl alcohol polyoxyethylene ether and dioctyl sulfosuccinate sodium salt; The sterilizing agent is a mixture of 5-chloro-2-methyl-4-isothiazoline-3-one and 2-methyl-4-isothiazoline-3-one.

[0019] In the present invention, the performance of the composite synergistic system is further improved by adding a chelating dispersant, a penetrant and a sterilizing agent, wherein the chelating dispersant is a mixture of polyepoxysuccinic acid, polyphosphate and organic alcohol. The compound system of the three can effectively solve the problems of inorganic scale precipitation, clay expansion and fluidity, while taking into account both environmental protection and economy. Polyepoxysuccinic acid chelates metal ions such as calcium ions and magnesium ions, thereby inhibiting the formation of dense scale such as calcium carbonate, and its unique "threshold effect" is adsorbed on the surface of scale crystals to prevent crystal growth, while polyphosphate can disperse the formed microcrystalline particles through electrostatic repulsion, thereby preventing them from aggregating and depositing, and its dispersing effect on iron scale and silicon scale is significant, and organic alcohol can reduce the viscosity of the liquid, improve the permeability of the agent in the cracks, and act as a "co-solvent" to enhance the The compatibility of acid salts can be improved, thereby preventing precipitation under high salt conditions. In addition, the addition of chelating dispersants can also enable the composite synergistic system to simultaneously treat hardness scale, colloidal scale and organic-inorganic composite scale. At the same time, the present invention can also significantly improve the wetting agent, penetration efficiency and reservoir compatibility of the agent by adding a penetrant, among which tridecanol polyoxyethylene ether can further reduce the surface tension of the solution and significantly reduce the capillary resistance, thereby promoting the agent to enter the nano-pores. The lengths of the hydrophobic and hydrophilic chains are adjustable to adapt to reservoirs with different wettability. The strong hydrophilic sulfonic acid group in the sodium salt of dioctyl sulfosuccinate can make the rock surface change from oil-wet to water-wet, reduce water lock damage, and have high emulsification efficiency for light oil and organic scale. At the same time, the addition of the bactericidal agent can play a role in long-term sterilization and dissolving bacterial metabolites, thereby effectively solving a series of problems caused by microbial activity lock.

[0020] The present invention also provides a shale gas old well production enhancement process without moving the tubing string, which uses the above-mentioned composite efficiency enhancement system for shale gas old wells and includes the following steps: After collecting and analyzing data around old shale gas wells, we designed measures and built a construction environment for the old shale gas wells without moving the pipe string; According to the characteristics of the wellbore structure, gas production wellhead and completion string of the old shale gas well, appropriate injection measures are selected and then the composite enhancement system is injected to perform soaking and then blowout; The injection measures include any one or two of tubing injection, casing injection and oil-casing injection. The tubing injection is used to treat blockage or throttling of tubing; the casing injection is used to treat blockage or throttling of casing annulus in old shale gas wells; the oil-casing injection is used to treat blockage near tubing shoes, horizontal wells or near wells in some old shale gas wells, or water lock in the reservoir caused by pressure channeling from adjacent wells. The formula for calculating the specific dosage of the composite synergistic system is:

[0021] in: Q: Total amount of compound synergistic system (m³) : Crack complexity correction factor (1.2-2.0) : Matrix heterogeneity coefficient (0.8-1.5) :Crack volume (m³) :Fracture porosity (0.3-0.6) : Matrix volume (m³) :Matrix porosity (0.3-0.6) C: Target composite synergistic system concentration (5-10wt%) Gas saturation (0.3-0.7) : Steeping reaction time (h) :Effective action time of compound synergistic system (h) : Target radius of measures to be taken (m) : Effective radius of the composite synergistic system (m) R: The residual coefficient of the composite synergistic system (usually 0.1-0.3).

[0022] Preferably, as a further specific embodiment, during the oil pipe injection process, nitrogen oil pipe is used to push the composite synergistic system, wherein the pushing construction displacement of the nitrogen is 600-800Nm 3 / h, pushing time is 1-2h, and soaking time is 24-48h.

[0023] Preferably, as a further specific embodiment, nitrogen is used to push the composite synergistic system during the casing injection process, wherein the pushing construction displacement of the nitrogen is 600-1200Nm 3 / h, pushing time is 2-4h, and soaking time is 24-72h.

[0024] Preferably, as a further specific embodiment, nitrogen is injected into the oil pipe and casing respectively to push the composite synergistic system, wherein the pushing construction displacement of the nitrogen is 1000-1200Nm 3 / h, pushing time is 6-8h, and soaking time is 48-72h.

[0025] In the present invention, when nitrogen is used to perfuse the composite synergistic system into the tubing string, a variable displacement perturbation method can also be used to perfuse the composite synergistic system, that is, when nitrogen is used to perfuse the tubing string, different construction displacements of nitrogen can be used to push the composite synergistic system throughout the entire time period, so that the composite synergistic system can affect a larger range and achieve better effects. Compared with the perfusion method of using one nitrogen pushing construction displacement throughout the entire time, the variable displacement perturbation perfusion method has a higher production increase multiple.

[0026] In the present invention, a fixed tubing production increase process suitable for old shale gas wells is proposed, and the target well is optimized by comprehensively considering the geological conditions, engineering conditions, dynamic conditions, and economic conditions of the old shale gas wells. A new environmentally friendly supramolecular multifunctional composite synergistic system is used, which has multiple functions such as unblocking, descaling, water lock release, and drainage assistance, thereby realizing the injection, pushing, unblocking and resumption of production of fixed tubing. Compared with the traditional chemical perfusion method, the fixed tubing construction method provided by the present invention does not require lowering the tubing or disassembling the wellhead equipment, which greatly reduces the operation time. The operation method of the movable tubing often requires the wellbore fluid to balance the pressure, which can easily cause reservoir damage. The perfusion of the fixed tubing can maintain the wellbore pressure balance, thereby avoiding secondary damage. The fixed tubing production increase process of the present invention The technology selectively and precisely delivers a composite efficiency-enhancing system to the blocked areas of old shale gas wells. At the same time, the dosage of the efficiency-enhancing system is precisely determined through a formula sought by the inventors through a series of creative work, thereby reducing the damage to the fracture network of old shale gas wells caused by mechanical operations and the excessive use of chemical reagents. At the same time, traditional injection methods are difficult to accurately control the scope of action and are prone to cause the loss of effective agents. The fixed tubing construction method provided by the present invention is more suitable for old shale gas wells with casing deformation and poor wellbore integrity, while the traditional injection process may be unable to be implemented due to wellbore obstacles in old shale gas wells. At the same time, it can also simultaneously integrate multiple functions to achieve multi-effect treatment in "one-trip drilling"; at the same time, the amount of return fluid generated by the fixed tubing process can be reduced by 40%-60%.

[0027] Among them, in the shale gas old well injection process of the present invention, there are three methods: oil pipe injection, casing injection and oil-casing simultaneous injection. Among them, the oil pipe injection of the composite enhancement system has multiple advantages, which can significantly improve the operating efficiency and reservoir protection effect. The oil pipe can directly transport the composite enhancement system to the target layer section to avoid the ineffective diffusion of the composite enhancement system in the casing annulus, thereby greatly improving the utilization rate of the agent. At the same time, the oil pipe insertion is combined with the sealing treatment to realize stratified treatment, and the oil pipe injection can well control the flow and pressure to avoid the composite enhancement system from entering the non-target layer, thereby greatly saving the use of the composite enhancement system.

[0028] Among them, the casing injection composite efficiency enhancement system has unique advantages, and is an efficient solution for dealing with scenarios such as uniform blockage of the entire section and restricted oil pipes in the casing injection type fixed pipe process. Through supporting temporary plugging technology and real-time monitoring, it can give full play to its advantages of large displacement and wide coverage.

[0029] Compared with the prior art, the present invention has the following beneficial effects: (1) The present invention provides a composite synergistic system for old shale gas wells. The composite synergistic system can treat multiple blockages at the same time by compounding multiple substances, thereby significantly improving the blockage removal effect and overcoming the disadvantage of traditional chemical dredging agents that require frequent movement of the pipe column. It is safe, efficient and environmentally friendly.

[0030] (2) The present invention provides a shale gas old well production enhancement process without moving the tubing string. The process applies the above-mentioned composite enhancement system. The process saves the operation of continuously moving the oil pipe by pumping the composite enhancement system into the tubing string without moving the tubing string, thereby greatly optimizing the effect of the composite enhancement system and enabling the composite enhancement system to be immersed in the blocked area for a long time to fully dissolve the blockage. BRIEF DESCRIPTION OF THE DRAWINGS

[0031] Various other advantages and benefits will become apparent to those skilled in the art upon reading the detailed description of the preferred embodiment below. The accompanying drawings are for illustration purposes only and are not to be construed as limiting the present invention. The same reference numerals are used throughout the accompanying drawings to denote the same components.

[0032] Figure 1 Process flow chart for oil pipe injection; Figure 2 The process flow chart for casing injection; Figure 3 This is the process flow chart of oil and casing simultaneous injection; Figure 4 This is the specific data diagram of variable displacement in mode 1; Figure 5 This is the specific data diagram of variable displacement in mode 2; Figure 6 This is a specific data diagram of variable displacement in mode three; Figure 7 This is the specific data diagram of variable displacement in mode four. DETAILED DESCRIPTION

[0033] The technical solutions of the present invention will be described clearly and completely below in conjunction with the accompanying drawings and specific embodiments. However, those skilled in the art will understand that the embodiments described below are only some embodiments of the present invention, not all embodiments, and are only used to illustrate the present invention and should not be regarded as limiting the scope of the present invention. Based on the embodiments of the present invention, all other embodiments obtained by those of ordinary skill in the art without creative work are within the scope of protection of the present invention.

[0034] In order to more clearly illustrate the technical solutions of the present invention, specific embodiments are provided below for illustration.

[0035] Example 1 The specific substances and dosages of the composite synergistic system for old shale gas wells of the present invention are as follows: 10% wetting improver; 4% descaling agent; 2% scale inhibitor and dispersant; 5% drag reduction and drainage agent; 15% synergistic accelerator; 15% chelating dispersant; 3% penetrant; 0.1% sterilant; 45.9 deionized water; The wettability improving agent is 5% alkyl polysaccharide, 15% sodium dodecylbenzene sulfonate and 80% deionized water; The descaling agent is sodium α-olefin sulfonate and nonylphenol polyoxyethylene ether ammonium sulfate in a mass ratio of 2:1; The scale inhibitor and dispersant is 10% hydroxyethylidene diphosphonic acid, 2% sodium hexametaphosphate and 88%g deionized water; The drag-reducing and drainage-aiding agent is a mixture of 8% cocamidopropylamine oxide, 7% dodecyldimethylhydroxysulfobetaine, and 85%g deionized water; The synergistic accelerator is 1% inorganic salt, 15% nonylphenol polyoxyethylene ether, 4% polyol and 80% deionized water; The chelating dispersant is a mixture of 33% polyepoxysuccinic acid, 14% polyphosphate, and 53% organic alcohol; The penetrant is tridecyl alcohol polyoxyethylene ether; The sterilizing agent is a mixture of 50% 5-chloro-2-methyl-4-isothiazolin-3-one and 50% 2-methyl-4-isothiazolin-3-one; The main steps of the shale gas old well unmoved pipe string production increase process of the present invention are: First, data collection and analysis are carried out around old shale gas wells. The specific collection and analysis process is as follows: (1) Analyze and select target wells For old shale gas wells, analysis and evaluation should be conducted from four aspects: geological conditions, engineering conditions, dynamic conditions, and economic conditions. Specifically, they include: Analysis of reservoir geological conditions (trajectory conditions, EUR, test production, cumulative production, etc.), wellbore structure (casing and tubing dimensions, running depth, string structure), wellbore trajectory (depth measurement, well inclination, azimuth, well type, etc.), perforation and bridge plug drilling and grinding depth parameters (perforation location, bridge plug drilling and grinding conditions, wellbore depth, etc.), composition analysis of formation return materials (gas component content, formation water composition, return foreign matter and scale composition), production performance data (production fluctuation, water production, shut-in pressure recovery, dynamic liquid level, etc.), and previous measures (evaluation of the effectiveness of gas lift, foam drainage, plugging removal, etc.) will guide the optimization of chemical formulation, dosage, injection process, production stimulation process, and parameters. 1.1 Formulation of selection principles Based on the analysis and optimization of target wells, a "five-choice and five-non-choice" principle for selecting old shale gas wells for production enhancement measures was formulated to determine the priority of measures and improve their pertinence and effectiveness: 1.2 Optimization of high-pressure injection device To meet the requirements of shale gas old well treatment process construction, the injection pump must be able to withstand sufficiently high pumping pressure. There are two main types of high-pressure injection equipment: mobile vehicle-mounted injection equipment and skid-mounted continuous injection equipment. The following requirements must be met: The high-pressure injection equipment has an adjustable displacement of 1400-2000L / H, which is required to meet the injection requirements of 2-15 cubic meters of drug during on-site construction; High-pressure injection equipment and accessories meet the standardization requirements of natural gas well sites, meet various safety requirements of oil and gas fields, and meet the requirements of nighttime construction; The on-site high-pressure injection equipment and accessories provided must meet the equipment installation requirements of oil and gas fields; The on-site high-pressure injection equipment and accessories provided meet the on-site standardization requirements, meet the various safety requirements of the oil and gas field, and meet the requirements of nighttime construction; The equipment is required to pass the pressure test, and the pipeline pressure test is above 20MPa; (1) Establishing a construction environment for shale gas old wells without moving the tubing string; (2) Select an appropriate perfusion method; The flow chart of oil pipe injection is as follows Figure 1 As shown in the figure, the tubing injection method is selected according to the characteristics of the old shale gas well body structure, gas wellhead and completion string. In order to solve the problem of blocked choke wells in the tubing, the tubing injection process is optimized. First, 2000kg of composite efficiency enhancement system is introduced into the tubing string, and then 600Nm 3 / h of nitrogen will push the agent to the target depth, the pushing time is 1 hour, and the well soaking time is 24 hours.

[0036] Example 2 The composite synergistic system for old shale gas wells of the present invention includes the following specific substances and dosages: 12% lubrication improver; 6% descaling agent; 3% scale inhibitor and dispersant; 10% drag reduction and drainage agent; 20% synergistic promoter; 20% chelating dispersant; 5% penetrant; 0.2% sterilant; 23.8% deionized water; The wettability improver is 10% alkyl polysaccharide, 18% sodium dodecylbenzene sulfonate and 72% deionized water; The descaling agent is sodium α-olefin sulfonate and nonylphenol polyoxyethylene ether ammonium sulfate in a mass ratio of 3:1; The scale inhibitor and dispersant is 15% hydroxyethylidene diphosphonic acid, 5% sodium hexametaphosphate and 80% deionized water; The drag-reducing and drainage-aiding agent is a mixture of 12% cocamidopropylamine oxide, 9% dodecyldimethylhydroxysulfobetaine, and 79% deionized water; The synergistic accelerator is 2% inorganic salt, 18% nonylphenol polyoxyethylene ether, 6% polyol and 74% deionized water. The chelating dispersant is a mixture of 33% polyepoxysuccinic acid, 14% polyphosphate, and 53% organic alcohol; The penetrant is tridecyl alcohol polyoxyethylene ether; The sterilizing agent is a mixture of 50% 5-chloro-2-methyl-4-isothiazolin-3-one and 50% 2-methyl-4-isothiazolin-3-one; The main steps of the shale gas old well unmoved pipe string production increase process of the present invention are: First, data collection and analysis are carried out around old shale gas wells. The specific collection and analysis process is as follows: (1) Analyze and select target wells For old shale gas wells, analysis and evaluation should be conducted from four aspects: geological conditions, engineering conditions, dynamic conditions, and economic conditions. Specifically, they include: Analysis of reservoir geological conditions (trajectory conditions, EUR, test production, cumulative production, etc.), wellbore structure (casing and tubing dimensions, running depth, string structure), wellbore trajectory (depth measurement, well inclination, azimuth, well type, etc.), perforation and bridge plug drilling and grinding depth parameters (perforation location, bridge plug drilling and grinding conditions, wellbore depth, etc.), composition analysis of formation return materials (gas component content, formation water composition, return foreign matter and scale composition), production performance data (production fluctuation, water production, shut-in pressure recovery, dynamic liquid level, etc.), and previous measures (evaluation of the effectiveness of gas lift, foam drainage, plugging removal, etc.) will guide the optimization of chemical formulation, dosage, injection process, production stimulation process, and parameters. 1.1 Formulation of selection principles Based on the analysis and optimization of target wells, a "five-choice and five-non-choice" principle for selecting old shale gas wells for production enhancement measures was formulated to determine the priority of measures and improve their pertinence and effectiveness: 1.2 Optimization of high-pressure injection device To meet the requirements of shale gas old well treatment process construction, the injection pump must be able to withstand sufficiently high pumping pressure. There are two main types of high-pressure injection equipment: mobile vehicle-mounted injection equipment and skid-mounted continuous injection equipment. The following requirements must be met: The high-pressure injection equipment has an adjustable displacement of 1400-2000L / H, which is required to meet the injection requirements of 2-15 cubic meters of drug during on-site construction.

[0037] High-pressure injection equipment and accessories meet the standardization requirements of natural gas well sites, meet various safety requirements of oil and gas fields, and meet the requirements of nighttime construction; The on-site high-pressure injection equipment and accessories provided must meet the equipment installation requirements of oil and gas fields.

[0038] The on-site high-pressure injection equipment and accessories provided meet the on-site standardization requirements, meet all safety requirements of the oil and gas field, and meet the requirements of nighttime construction.

[0039] The equipment is required to pass the pressure test, and the pipeline pressure test is above 20MPa; (1) Establishing a construction environment for shale gas old wells without moving the tubing string; (2) Select an appropriate perfusion method; The flow chart of casing injection is as follows Figure 2 As shown in the figure, the casing injection method is selected according to the characteristics of the old shale gas well body structure, gas wellhead and completion string. In view of the blockage or throttling of the casing annulus of the old shale gas well, 2000kg of composite efficiency enhancement system is first introduced into the string, and then 600Nm 3 / h of nitrogen will push the agent to the target depth, the pushing time is 2h, and the well soaking time is 24h.

[0040] Example 3 The specific substances and dosages of the composite synergistic system for old shale gas wells of the present invention are as follows: 12% wetting improver; 5% descaling agent; 3% scale inhibitor and dispersant; 8% drag reduction and drainage agent; 19% synergistic enhancer; 20% chelating dispersant; 5% penetrant; 0.2% sterilant; 27.8% deionized water; The wettability improver is 8% alkyl polysaccharide, 16% sodium dodecylbenzene sulfonate and 76% deionized water; The descaling agent is sodium α-olefin sulfonate and nonylphenol polyoxyethylene ether ammonium sulfate in a mass ratio of 2.5:1; The scale inhibitor and dispersant is 12% hydroxyethylidene diphosphonic acid, 3% sodium hexametaphosphate and 85% deionized water; The drag-reducing and drainage-aiding agent is a mixture of 10% cocamidopropylamine oxide, 8% dodecyldimethylhydroxysulfobetaine, and 82% deionized water; The synergistic accelerator is 1.5% inorganic salt, 16% nonylphenol polyoxyethylene ether, 5% polyol and 77.5% deionized water; The chelating dispersant is a mixture of 33% polyepoxysuccinic acid, 14% polyphosphate, and 53% organic alcohol; The penetrant is tridecyl alcohol polyoxyethylene ether; The sterilizing agent is a mixture of 50% 5-chloro-2-methyl-4-isothiazolin-3-one and 50% 2-methyl-4-isothiazolin-3-one; The main steps of the shale gas old well unmoved pipe string production increase process of the present invention are: First, data collection and analysis are carried out around old shale gas wells. The specific collection and analysis process is as follows: (1) Analyze and select target wells For old shale gas wells, analysis and evaluation should be conducted from four aspects: geological conditions, engineering conditions, dynamic conditions, and economic conditions. Specifically, they include: Analysis of reservoir geological conditions (trajectory conditions, EUR, test production, cumulative production, etc.), wellbore structure (casing and tubing dimensions, running depth, string structure), wellbore trajectory (depth measurement, well inclination, azimuth, well type, etc.), perforation and bridge plug drilling and grinding depth parameters (perforation location, bridge plug drilling and grinding conditions, wellbore depth, etc.), composition analysis of formation return materials (gas component content, formation water composition, return foreign matter and scale composition), production performance data (production fluctuation, water production, shut-in pressure recovery, dynamic liquid level, etc.), and previous measures (evaluation of the effectiveness of gas lift, foam drainage, plugging removal, etc.) will guide the optimization of chemical formulation, dosage, injection process, production stimulation process, and parameters. 1.1 Formulation of selection principles Based on the analysis and optimization of target wells, a "five-choice and five-non-choice" principle for selecting old shale gas wells for production enhancement measures was formulated to determine the priority of measures and improve their pertinence and effectiveness: 1.2 Optimization of high-pressure injection device To meet the requirements of shale gas old well treatment process construction, the injection pump must be able to withstand sufficiently high pumping pressure. There are two main types of high-pressure injection equipment: mobile vehicle-mounted injection equipment and skid-mounted continuous injection equipment. The following requirements must be met: The high-pressure injection equipment has an adjustable displacement of 1400-2000L / H, which is required to meet the injection requirements of 2-15 cubic meters of drug during on-site construction.

[0041] High-pressure injection equipment and accessories meet the standardization requirements of natural gas well sites, meet various safety requirements of oil and gas fields, and meet the requirements of nighttime construction; The on-site high-pressure injection equipment and accessories provided must meet the equipment installation requirements of oil and gas fields.

[0042] The on-site high-pressure injection equipment and accessories provided meet the on-site standardization requirements, meet all safety requirements of the oil and gas field, and meet the requirements of nighttime construction.

[0043] The equipment is required to pass the pressure test, and the pipeline pressure test is above 20MPa; (1) Establishing a construction environment for shale gas old wells without moving the tubing string; (2) Select an appropriate perfusion method; The injection flow chart of oil-casing injection is as follows: Figure 3 As shown in the figure, the casing insertion method is selected according to the characteristics of the old shale gas well body structure, gas wellhead and completion string. In view of the blockage or throttling of the casing annulus of the old shale gas well, 2000kg of composite efficiency enhancement system is first introduced into the string, and then 1000Nm 3 / h of nitrogen will push the agent to the target depth, the pushing time is 6 hours, and the well soaking time is 48 hours.

[0044] Example 4 The specific implementation process is consistent with Example 3, except that the mass percentage of the alkyl polysaccharide in the wettability improver is 1%, the mass percentage of sodium dodecylbenzenesulfonate remains unchanged, and the mass percentage of deionized water is 83%.

[0045] Example 5 The specific implementation process is consistent with Example 3, except that the mass percentage of the alkyl polysaccharide in the wettability improver is 20%, the mass percentage of sodium dodecylbenzenesulfonate remains unchanged, and the mass percentage of deionized water is 64%.

[0046] Example 6 The specific implementation process is consistent with Example 3, except that the mass percentage of sodium dodecylbenzenesulfonate in the wettability improver is 5%, the mass percentage of alkyl polyglycoside remains unchanged, and the mass percentage of deionized water is 87%.

[0047] Example 7 The specific implementation process is consistent with Example 3, except that the mass percentage of sodium dodecylbenzenesulfonate in the wettability improver is 30%, the mass percentage of alkyl polyglycoside remains unchanged, and the mass percentage of deionized water is 62%.

[0048] Example 8 The specific implementation process is consistent with Example 3, the only difference being that the mass ratio of sodium α-olefin sulfonate and nonylphenol polyoxyethylene ether sulfate ammonium salt in the descaling agent is changed to 0.5:1.

[0049] Example 9 The specific implementation process is consistent with Example 3, the only difference being that the mass ratio of sodium α-olefin sulfonate and nonylphenol polyoxyethylene ether sulfate ammonium salt in the descaling agent is changed to 5:1.

[0050] Example 10 The specific implementation process is consistent with Example 3, with the only difference being that the mass percentage of hydroxyethylidene diphosphonic acid in the scale inhibitor and dispersant is 5%, the mass percentage of sodium hexametaphosphate remains unchanged, and the mass percentage of deionized water is 92%.

[0051] Example 11 The specific implementation process is consistent with Example 3, except that the mass percentage of hydroxyethylidene diphosphonic acid in the scale inhibitor and dispersant is 30%, the mass percentage of sodium hexametaphosphate remains unchanged, and the mass percentage of deionized water is 67%.

[0052] Example 12 The specific implementation process is consistent with Example 3, except that the mass percentage of sodium hexametaphosphate in the scale inhibitor and dispersant is 0.5%, the mass percentage of hydroxyethylidene diphosphonic acid remains unchanged, and the mass percentage of deionized water is 87.5%.

[0053] Example 13 The specific implementation process is consistent with Example 3, except that the mass percentage of sodium hexametaphosphate in the scale inhibitor and dispersant is 10%, the mass percentage of hydroxyethylidene diphosphonic acid remains unchanged, and the mass percentage of deionized water is 78%.

[0054] Example 14 The specific implementation process is consistent with Example 3, except that the mass percentage of cocamidopropylamine oxide in the drag reducing and drainage agent is 1%, the mass percentage of dodecyldimethylhydroxysulfobetaine remains unchanged, and the mass percentage of deionized water is 91%.

[0055] Example 15 The specific implementation process is consistent with Example 3, except that the mass percentage of cocamidopropylamine oxide in the drag reducing and drainage agent is 20%, the mass percentage of dodecyldimethylhydroxysulfobetaine remains unchanged, and the mass percentage of deionized water is 72%.

[0056] Example 16 The specific implementation process is consistent with Example 3, except that the mass percentage of dodecyldimethylhydroxysulfobetaine in the drag reducing and drainage agent is 1%, the mass percentage of cocamidopropylamine oxide remains unchanged, and the mass percentage of deionized water is 89%.

[0057] Example 17 The specific implementation process is consistent with Example 3, except that the mass percentage of dodecyldimethylhydroxysulfobetaine in the drag reducing and drainage agent is 20%, the mass percentage of cocamidopropylamine oxide remains unchanged, and the mass percentage of deionized water is 70%.

[0058] Example 18 The specific implementation process is consistent with Example 3, except that the mass percentage of the inorganic salt in the synergistic accelerator is 0.2%, the mass percentages of nonylphenol polyoxyethylene ether and polyol remain unchanged, and the mass percentage of deionized water is 78.8%.

[0059] Example 19 The specific implementation process is consistent with Example 3, except that the mass percentage of the inorganic salt in the synergistic accelerator is 10%, the mass percentages of nonylphenol polyoxyethylene ether and polyols remain unchanged, and the mass percentage of deionized water is 69%.

[0060] Example 20 The specific implementation process is consistent with Example 3, except that the mass percentage of nonylphenol polyoxyethylene ether in the synergistic accelerator is 5%, the mass percentages of inorganic salts and polyols remain unchanged, and the mass percentage of deionized water is 88.5%.

[0061] Example 21 The specific implementation process is consistent with Example 3, except that the mass percentage of nonylphenol polyoxyethylene ether in the synergistic accelerator is 30%, the mass percentages of inorganic salts and polyols remain unchanged, and the mass percentage of deionized water is 63.5%.

[0062] Example 22 The specific implementation process is consistent with Example 3, except that the mass percentage of the polyol in the synergistic accelerator is 1%, the mass percentages of the inorganic salt and nonylphenol polyoxyethylene ether remain unchanged, and the mass percentage of deionized water is 81.5%.

[0063] Example 23 The specific implementation process is consistent with Example 3, except that the mass percentage of the polyol in the synergistic promoter is 15%, the mass percentages of the inorganic salt and nonylphenol polyoxyethylene ether remain unchanged, and the mass percentage of deionized water is 67.5%.

[0064] Experimental Example 1 Determination of the performance of the composite synergistic system The performance of the composite synergistic system in Examples 1-23 was tested, wherein Examples 1-23 were experimental groups 1-23, and the control group was a common dredging agent used for dredging old well pipes on the market; The specific experimental steps are: 1.1 Blockage collection: Collect blockage samples from the selected target shale gas old wells, weigh them, divide them into 24 groups, and crush them; 1.2 Take the same mass of the composite synergistic system prepared in Examples 1-23 and the unblocking agent of the control group, mix them with the blockage respectively, and place them in a reaction kettle; 1.3 Set the reaction conditions: set the reaction temperature to 120℃, the pressure to 15MPa, and the reaction at constant temperature for 20h; 1.4 After the reaction is complete, filter the remaining solids, dry and weigh them, and calculate the dissolution rate; The specific test results are shown in Table 1 below: Table 1 Dissolution rate results .

[0065] From the above experimental data, it can be seen that by comparing experimental groups 1-5, the performance of the composite synergistic system will also change if the amount of raw materials used in the wettability improver changes. Among them, the alkyl polysaccharide content in experimental group 4 is relatively low, which is far lower than the 5%-10% provided by the present invention, resulting in an imbalance in the prepared surfactant. The low alkyl polysaccharide content makes it difficult for the composite synergistic system to be effectively adsorbed on the hydrophobic surface, resulting in insufficient change in the wettability of the rock on the surface of the old shale gas well, and the dissolution rate dropped to 89.3%. The alkyl polysaccharide in experimental group 5 is as high as 20%, which exceeds the preferred range and competes with sodium dodecylbenzene sulfonate for adsorption, reducing the effective coverage rate. At the same time, the excessive hydroxyl groups lead to increased solution viscosity and decreased permeability, with a dissolution rate of 86.7%. In experimental group 6, the sodium dodecylbenzene sulfonate content is only 5%, less than the preferred value of 15-18%, which seriously affects the dispersibility of inorganic scale. The lack of sulfonic acid groups weakens the electrostatic repulsion and makes it impossible to effectively disperse inorganic particles, with a dissolution rate of 88.1%. In experimental group 7, the sodium dodecylbenzenesulfonate content was as high as 30%, which was prone to precipitation in a high-temperature and high-salt environment. Meanwhile, the excessive amount of anionic surfactants compressed the double layer and promoted particle aggregation, resulting in a dissolution rate of 85.4%. Comparing Experimental Groups 8 and 9, we can see that changes in the raw material dosage in the descaling agent have a certain impact on the performance of the composite synergistic system. In Experimental Group 8, the ratio of sodium α-olefin sulfonate to ammonium nonylphenol polyoxyethylene ether sulfate was 0.5:1, with the former being severely insufficient. This significantly reduced the system's resistance to hard water, with calcium and magnesium ions causing partial descaling failure, resulting in a dissolution rate of 83.6%. In Experimental Group 9, the ratio was 5:1, with the latter being insufficient. The low EO chain content resulted in insufficient solubilization of heavy organic matter and poor biodegradability, resulting in a dissolution rate of 87.2%. Comparison of experimental groups 10-13 shows that changes in the raw material dosage of the scale inhibitor and dispersant affect the performance of the composite synergistic system. When the hydroxyethylidene diphosphonic acid content in experimental group 10 was only 5%, it easily led to a serious lack of chelating sites, failing to effectively inhibit the formation of dense scale such as calcium carbonate, resulting in a reduction in the dissolution rate to 82.9%. When the hydroxyethylidene diphosphonic acid dosage in experimental group 11 was as high as 30%, although its chelating ability was strong, its dispersing effect was not as good as that of sodium hexametaphosphate. Moreover, excessive use may cause excessive chelation of metal ions, which in turn affects the stability of formation minerals, resulting in a reduction in the dissolution rate to 84.5%. At the same time, when the sodium hexametaphosphate dosage in experimental group 12 was only 0.5%, it could not provide sufficient electrostatic repulsion to disperse the formed microcrystalline particles, especially for iron and silica scale, resulting in a reduction in the dissolution rate to 81.7%. When the dosage in experimental group 13 was as high as 10%, it was easily hydrolyzed to form orthophosphate at high temperature, which not only lost its dispersing effect but also may form new precipitates, resulting in a reduction in the dissolution rate to 86.3%. By comparing experimental groups 14-17, it can be seen that when the raw material dosage of the drag-reducing and drainage-aiding agent changes, it has a certain impact on the performance of the composite synergistic system. Among them, the cocamidopropylamine oxide in experimental group 14 is only 1%, which makes it unable to form a complete hydration layer to reduce friction, resulting in poor drag reduction effect of the composite synergistic system and a reduction in the dissolution rate to 80.5%. When the dosage of cocamidopropylamine oxide in experimental group 15 is as high as 20%, although it has a good drag reduction effect, it will produce excessive foam, requiring the addition of an additional defoamer, and may affect the return efficiency. The dosage of dodecyl dimethyl hydroxysulfobetaine in experimental group 16 is only 1%, resulting in insufficient sulfonic acid groups, resulting in reduced lubricity and increased capillary resistance, which reduces the dissolution rate to 83.2%. When the dosage of dodecyl dimethyl hydroxysulfobetaine in experimental group 17 is as high as 20%, the excessive strong hydrophilic groups may lead to excessive rock wettability, resulting in water lock and significantly increased costs, resulting in a reduction in the dissolution rate to 87.6%. By comparing experimental groups 18-23, it can be seen that when the amount of each raw material in the synergistic promoter is changed, the performance of the composite synergistic system will be affected. Among them, when the amount of inorganic salt in experimental group 18 is only 0.2%, it is easy to cause the composite synergistic system to be unable to effectively compress the double layer to control the expansion of the clay, and the ionic strength is insufficiently adjusted, causing the dissolution rate to drop to 88.4%; and when the amount of inorganic salt in experimental group 19 is as high as 10%, the salinity of the system is too high, which may cause the precipitation of nonylphenol polyoxyethylene ether and increase the risk of scaling, thereby causing the dissolution rate to drop to 82.3%; and the amount of nonylphenol polyoxyethylene ether in experimental group 20 is only 5%, which is easy to cause insufficient reduction in surface tension and difficulty in entering the blockage. The nano-scale pores in the experimental group 21 are formed, which leads to a decrease in the dissolution rate to 84.8%. At the same time, when the dosage of nonylphenol polyoxyethylene ether in experimental group 21 is as high as 30%, it is easy to cause the nonylphenol polyoxyethylene ether to fail after exceeding its cloud point temperature, and too many EO chains may be adsorbed on the rock surface and difficult to elute; when the dosage of polyol in experimental group 22 is only 1%, it is easy for the composite enhancement system to fail to effectively reduce the viscosity of the liquid, resulting in insufficient hydrogen bond binding capacity of water molecules, resulting in a decrease in the dissolution rate to 81.5%. When the dosage of polyol in experimental group 23 is as high as 15%, although its viscosity reduction effect is good, it may further lead to insufficient sand carrying capacity of the agent and may affect the stability of the micelles, resulting in a decrease in the dissolution rate to 85.7%.

[0066] Experimental Example 2: Exploration of variable displacement mode in a stationary string The Weiyuan shale gas field, owned by PetroChina Southwest Oil & Gas Field Company, is located in the southern Sichuan Basin and is one of the earliest national shale gas demonstration areas established in China. With mature shale gas wells boasting a maximum production life of over 10 years, over 500 wells are currently in production. The Weiyuan shale gas field produces over 2 billion cubic meters of shale gas annually. Stimulating production from mature wells has become a key technology for maintaining stable shale gas production. The Weiyuan shale gas field has a reservoir depth of 3,000-4,000 meters, a maximum formation temperature of 140°C, a formation pressure coefficient of 1.5-2.0, a Young's modulus of 25-40 GPa, and a Poisson's ratio of 0.18-0.25. Horizontal well staged fracturing is the primary method of development.

[0067] 1.1 Optimization of variable displacement disturbance push mode The modes of changing the construction displacement are as follows: Figure 4-7 As shown, the composite synergistic system used in this experimental example is the composite synergistic system prepared in Example 3. According to the process requirements of the measures for old shale gas wells, the three different injection processes mentioned above, namely tubing injection, casing injection, and oil-casing simultaneous injection, are combined. By optimizing the push mode of nitrogen with different displacement disturbances, the passive random injection is transformed into active slugging disturbance, the range and depth of the agent are expanded, and the production increase effect of the measures for old wells is improved. 1.2 Optimization of drug dosage According to the geological and other parameter characteristics of different wells, the following calculation formula is optimized to optimize the dosage of the agent for the on-site single well production stimulation measures:

[0068] in: Q: Total amount of compound synergistic system (m³) : Crack complexity correction factor (1.2-2.0) : Matrix heterogeneity coefficient (0.8-1.5) :Crack volume (m³) :Fracture porosity (0.3-0.6) : Matrix volume (m³) :Matrix porosity (0.3-0.6) C: Target composite synergistic system concentration (5-10wt%) Gas saturation (0.3-0.7) : Steeping reaction time (h) :Effective action time of compound synergistic system (h) : Target radius of measures to be taken (m) : Effective radius of the composite synergistic system (m) R: Residual coefficient of composite synergistic system (usually 0.1-0.3) The injection amount of the composite enhancement system needs to be comprehensively considered according to the reservoir temperature, gas saturation, fracture volume, fracture and matrix porosity, permeability, well shut-in reaction time, composite enhancement system action radius, composite enhancement system action time of different shale gas wells. In general, the optimization of the well shut-in time of old shale gas wells is 𝑇 𝑟 Effective time of compound synergistic system 𝑇 𝑒 The treatment time is 48h, the average fracture porosity is 3%, the permeability is 1.8mD, the treatment radius of the composite enhancement system is calculated as 30-50m, the margin of the composite enhancement system is considered as 10-15%, and the dosage of the composite enhancement system is calculated to be 2000-8000Kg; For the production increase measure process of old wells in Weiyuan shale gas field, the optimized supramolecular multifunctional composite synergistic system component is the composite synergistic system prepared in Example 3; The dosage of the composite efficiency-enhancing system for the fixed string production enhancement process measures in this block is 2000-5000 kg, the soaking time is optimized to 38-72 hours, the effective period after the measures is 65-87 days, and the production increase multiples of the measures reach 4.7-10.5 times, which has a good effect of increasing and stabilizing production. The specific results are shown in Table 2 below.

[0069] Table 2 Statistics of the effects of production enhancement measures on old shale gas wells in Weiyuan, Southwest Oil and Gas Field, PetroChina .

[0070] As can be seen from the data in Table 2 above, the present invention also provides a method for further improving the production efficiency of old shale gas wells by changing the flux of the composite enhancement system during the entire injection time when nitrogen is used to inject the composite enhancement system.

[0071] It can be seen from the data of the above experimental examples 1-2 that in the present invention, by proposing a composite enhancement system and a fixed tubing production increase process suitable for old shale gas wells, the target wells are optimized by comprehensively considering the geological conditions, engineering conditions, dynamic conditions and economic conditions of the old shale gas wells, and a new environmentally friendly supramolecular multifunctional composite enhancement system is used, which has multiple functions such as unblocking, descaling, water lock release and drainage assistance, thereby realizing the injection, pushing and unblocking of the fixed tubing to resume production. Compared with the traditional chemical perfusion method, the fixed tubing construction method provided by the present invention does not require lowering the tubing or disassembling the wellhead equipment, which greatly reduces the construction cost and operation time, and the operation method of the movable tubing often requires the wellbore fluid to balance the pressure, which can easily cause reservoir damage. The injection of the tubing string can maintain the pressure balance of the wellbore, thereby avoiding secondary damage; and the fixed tubing string process of the present invention selectively and accurately delivers a composite synergistic system to the blockage area of ​​the old shale gas well, thereby reducing the damage of mechanical operations to the fracture network of the old shale gas well. At the same time, the traditional injection method is difficult to accurately control the scope of action, which can easily cause the loss of effective agents. The fixed tubing string construction method provided by the present invention is more suitable for old shale gas wells with casing deformation and poor wellbore integrity, while the traditional injection process may be unable to be implemented due to obstructions in the wellbore of the old shale gas well. At the same time, it can also simultaneously integrate multiple functions to achieve multi-effect treatment of "one-trip drilling"; at the same time, the amount of return fluid generated by the fixed tubing string process can be reduced by 40%-60%.

[0072] Finally, it should be noted that the above embodiments are only used to illustrate the technical solutions of the present invention, rather than to limit it. Although the present invention has been described in detail with reference to the above embodiments, those skilled in the art should understand that they can still modify the technical solutions described in the above embodiments, or replace some or all of the technical features therein with equivalents. However, these modifications or replacements do not cause the essence of the corresponding technical solutions to deviate from the scope of the technical solutions of the embodiments of the present invention.

Claims

1. A composite efficiency enhancement system for old shale gas wells, characterized in that: In terms of mass percentage, it mainly includes the following substances: 10%-12% wetting improver; 4%-6% descaling agent; 2%-3% scale inhibitor and dispersant; 5%-10% drag reduction and drainage aid; 15%-20% synergistic promoter; The wettability improving agent is a mixture of alkyl polysaccharide, anionic surfactant sodium dodecylbenzene sulfonate and deionized water, wherein the alkyl polysaccharide in the wettability improving agent is 5%-10%, and the anionic surfactant sodium dodecylbenzene sulfonate is 15%-18%; The descaling agent is a mixture of sodium α-olefin sulfonate and ammonium sulfate of nonylphenol polyoxyethylene ether, and the mass ratio of sodium α-olefin sulfonate to ammonium sulfate of nonylphenol polyoxyethylene ether in the descaling agent is 2:1-3:

1.

2. The composite efficiency enhancement system for old shale gas wells according to claim 1, characterized in that: 12% wetting improver; 5% descaling agent; 3% scale inhibitor and dispersant; 8% drag reduction and drainage agent; 19% synergistic enhancer; The wettability improving agent contains 8% alkyl polysaccharide and the anionic surfactant sodium dodecylbenzenesulfonate contains 16%; The mass ratio of sodium α-olefin sulfonate to nonylphenol polyoxyethylene ether sulfate ammonium salt in the descaling agent is 2.5:

1.

3. The composite efficiency enhancement system for old shale gas wells according to claim 1, characterized in that: The scale inhibitor and dispersant is a mixture of hydroxyethylidene diphosphonic acid, sodium hexametaphosphate and deionized water, wherein the mass percentage of the hydroxyethylidene diphosphonic acid is 10%-15%, and the mass percentage of the sodium hexametaphosphate is 2%-5%; Preferably, the mass percentage of the hydroxyethylidene diphosphonic acid is 12%, and the mass percentage of the sodium hexametaphosphate is 3%.

4. The composite efficiency enhancement system for old shale gas wells according to claim 1, characterized in that: The group-reducing and drainage-aiding agent is a mixture of cocamidopropylamine oxide, dodecyldimethylhydroxysulfobetaine and deionized water; The mass percentage of the cocamidopropylamine oxide is 8%-12%, and the mass percentage of the lauryldimethylhydroxysulfobetaine is 7%-9%; Preferably, the mass percentage of the cocamidopropylamine oxide is 10%, and the mass percentage of the lauryldimethylhydroxysulfobetaine is 8%.

5. The composite efficiency enhancement system for old shale gas wells according to claim 1, characterized in that: The synergistic promoter is an inorganic salt, nonylphenol polyoxyethylene ether, a polyvalent organic alcohol and deionized water; The mass percentage of the inorganic salt is 1%-2%, the mass percentage of the nonylphenol polyoxyethylene ether is 15%-18%, and the mass percentage of the polyvalent organic alcohol is 4%-6%; Preferably, the mass percentage of the inorganic salt is 1.5%, the mass percentage of the nonylphenol polyoxyethylene ether is 16%, and the mass percentage of the polyvalent organic alcohol is 5%.

6. The composite efficiency enhancement system for old shale gas wells according to claim 1, characterized in that: It also includes 15%-20% chelating dispersant, 3%-5% penetrant, 0.1%-0.2% sterilant, and 23.8%-45.9% deionized water; wherein the chelating dispersant is a mixture of polyepoxysuccinic acid, polyphosphate and organic alcohol; The penetrant is one or more of tridecyl alcohol polyoxyethylene ether and dioctyl sulfosuccinate sodium salt; The sterilizing agent is a mixture of 5-chloro-2-methyl-4-isothiazoline-3-one and 2-methyl-4-isothiazoline-3-one.

7. A process for increasing the production of old shale gas wells without moving the tubing string, using the composite efficiency-enhancing system for old shale gas wells according to any one of claims 1 to 6, characterized in that: The following steps are involved: After collecting and analyzing data around old shale gas wells, we designed measures and built a construction environment for the old shale gas wells without moving the pipe string; According to the characteristics of the wellbore structure, gas wellhead and completion string of the old shale gas well, appropriate injection measures are selected and the specific dosage of the composite enhancement system is calculated, and then the composite enhancement system is injected to perform soaking and post-blowing; The injection measures include any one or two of tubing injection, casing injection and oil-casing injection. The tubing injection is used to treat blockage or throttling of tubing; the casing injection is used to treat blockage or throttling of casing annulus in old shale gas wells; the oil-casing injection is used to treat blockage near tubing shoes, horizontal wells or near wells in some old shale gas wells, or water lock in the reservoir caused by pressure channeling from adjacent wells. The formula for calculating the specific dosage of the composite synergistic system is: in: Q: Total amount of compound synergistic system (m³) : Crack complexity correction factor (1.2-2.0) : Matrix heterogeneity coefficient (0.8-1.5) :Crack volume (m³) :Fracture porosity (0.3-0.6) : Matrix volume (m³) :Matrix porosity (0.3-0.6) C: Target composite synergistic system concentration (5-10wt%) Gas saturation (0.3-0.7) : Steeping reaction time (h) :Effective action time of compound synergistic system (h) : Target radius of measures to be taken (m) : Effective radius of the composite synergistic system (m) R: The residual coefficient of the composite synergistic system (usually 0.1-0.3).

8. The yield increasing process according to claim 7, characterized in that: During the oil pipe injection process, nitrogen oil pipe is used to push the composite synergistic system, wherein the pushing construction displacement of the nitrogen is 600-800Nm 3 / h, pushing time is 1-2h, and soaking time is 24-48h.

9. The yield increasing process according to claim 7, characterized in that: During the casing injection process, nitrogen is used to push the composite synergistic system, wherein the pushing construction displacement of the nitrogen is 600-1200Nm 3 / h, pushing time is 2-4h, and soaking time is 24-72h.

10. The yield increasing process according to claim 7, characterized in that: Nitrogen is used to inject the composite enhancement system into the oil pipe and casing respectively for pushing, wherein the pushing construction displacement of the nitrogen is 1000-1200Nm 3 / h, pushing time is 6-8h, and soaking time is 48-72h.

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