Aqueous entrapment damage control agent for carbonate gas reservoir

Abstract

The invention relates to a water entrapment damage control agent for a carbonate rock gas reservoir, and belongs to the technical field of oil and gas reservoir chemicals. The water-phase trap damage prevention and control agent for the carbonate rock gas reservoir comprises the fatty acid, the alcohol compound and the emulsifier, carboxyl in the fatty acid can be combined with calcium ions on the surface of carbonate rock through chemical bonds, the carboxyl in the fatty acid can be combined with the surface of rock more tightly, hydrophobic alkyl extends out, water wetting of the surface of the rock is changed into neutral wetting, and the water-phase trap damage prevention and control agent is more stable. Therefore, the amount of the fluid self-absorbed into the carbonate rock gas reservoir is reduced, the flowback rate of the entered fluid is increased, and the purpose of preventing and treating the water phase entrapment damage is achieved. Meanwhile, the alcohol compound can assist the fatty acid in changing the surface wettability of the carbonate rock into neutral wettability, and the system flowability is improved. And the emulsifier can form a stable emulsion when the control agent and water are mixed, so that the injection of the water-phase trap damage control agent is facilitated.

Description

Technical Field

[0001] The invention relates to a water phase trap damage prevention agent for carbonate gas reservoirs, belonging to the technical field of oil and gas reservoir chemicals. Background Art

[0002] Water phase trap damage refers to the phenomenon that the water saturation in the near-well zone increases, the gas permeability decreases, and reservoir damage is induced by the invasion of foreign water-based working fluid and the redistribution of initial water content in the gas layer during drilling, completion, production stimulation, and production operations. The main causes of water phase trapping are capillary self-imbibition and liquid phase retention. Tight gas reservoirs are generally divided into tight sandstone gas reservoirs and tight carbonate gas reservoirs. Tight gas reservoirs have the characteristics of fine pore throats, high capillary pressure, poor permeability, and large gas seepage resistance. The capillary effect is very significant. At the same time, due to the ultra-low water saturation in the gas reservoir, the foreign invading fluid is prone to capillary self-imbibition and retention during the drilling and development process to form water phase traps. A large number of studies have shown that water phase trap damage is the most important damage mode for tight gas reservoirs, with a damage rate of up to 70% to 90%. Therefore, the prevention and control of water phase trap damage is particularly important.

[0003] At present, there are many methods to reduce or eliminate the damage of water phase trapping at home and abroad, such as CO injection 2 , using surfactants that reduce interfacial tension, hot gas injection, fracturing, formation heat treatment (FHT), avoiding the use of fluids that are easy to trap, reducing fluid action time and reducing invasion depth, etc., but these treatment methods have problems such as short effective time, high treatment cost, and secondary damage. The wettability of reservoir rocks is the key factor that determines the capillary self-imbibition behavior and has an important impact on liquid phase trap damage. Changing the wettability of rock surface to gas wetting is a new direction for improving seepage capacity and preventing water phase trap damage. This method is mainly aimed at tight reservoirs with small pore throats and significant interface effects. By changing the wettability of rocks, reducing the amount of capillary self-imbibition and promoting the return of invading liquid phase, the purpose of preventing water phase trap damage and increasing gas well production is achieved. The existing water phase trap damage prevention and control agents are only suitable for changing tight sandstone gas reservoirs from water wetting to gas wetting or neutral wetting, but cannot change the wettability of tight carbonate gas reservoirs, and do not have the effect of preventing and controlling water phase trap damage.

[0004] Liu Xuefen et al. used fluorinated surfactant FW-134 (FW-134 is perfluorooctyl quaternary ammonium fluoride, a perfluorocationic surfactant) to transform typical tight sandstone cores in the Ordos Basin from water-wet to gas-wet, and conducted core capillary self-imbibition and flowback experiments simulating formation water before and after the action of FW-134, and measured the water saturation and flowback rate of the liquid phase in the rock samples. The experimental results show that FW-134 can significantly inhibit liquid self-imbibition, the water saturation decreases from 62% to 29.5%, and the liquid flowback rate increases from 56.3% to 83.4%. FW-134 can effectively prevent and control water phase closure damage. Chinese patent document CN104449631A discloses a strong gas wettability nano-silica water-locking agent, a preparation method thereof, and a method for reversing the wetting of rock surfaces. The raw materials of the modified nano-silica water-locking agent are composed of: 0.1%-0.5% of modified nano-silica, 0.5%-1% of emulsifier OP-10, 0.5%-1% of sodium dodecyl sulfate, 25%-50% of ethanol, and the balance is water, wherein the modified nano-silica is obtained by modifying silicon dioxide with a non-ionic fluorocarbon surfactant. The nano-silica water-locking agent of the patent document can reverse the rock surface from liquid wettability to strong gas wettability, reduce the viscous resistance of the fluid flowing on the rock surface, and remove water lock damage. Chinese patent document CN114479808A provides a water-locking chemical agent suitable for sandstone natural gas reservoirs, comprising 5-20% fluorocarbon surfactant, 5-20% biosurfactant, 5-30% synergist, and 30-85% water. The water-locking chemical agent in the patent document can significantly reduce the surface tension of water and adjust the surface of the strongly water-wet matrix to neutral wetting or even hydrophobic. The above documents all adsorb the fluorinated surfactant to the surface of the rock with strong electronegativity through electrostatic attraction, thereby changing the wettability of the rock surface, and the adsorption force is weak, so that the effective period of the chemical agent acting on the rock surface is short.

[0005] Sandstone reservoirs generally have negative charges on their rock surfaces due to their high clay content. The main rock components in carbonate reservoirs are calcite and dolomite, and calcite is an electrically neutral substance that is not charged overall. Dolomite has no charge on its surface when the pH value is 6.0, and when the pH value is less than 6.0 (carbonate gas reservoirs generally contain hydrogen sulfide and are acidic gas reservoirs), the dolomite surface is positively charged. Therefore, the fluorinated surfactants in the above literature cannot be adsorbed on the surface of carbonate reservoirs, and therefore cannot change the wettability of the rock surface. For example, the wetting contact angle of FW-134 fluorinated surfactant after acting on the hydrophilic carbonate reservoir surface is 12.8°, the contact angle of the nano-silica water-locking agent in Chinese patent document CN104449631A after acting on the hydrophilic carbonate reservoir is 12.6°, and the contact angle of the water-locking chemical in Chinese patent document CN114479808A after acting on the hydrophilic carbonate reservoir is 19.6°, and the core still exhibits strong hydrophilicity.

[0006] Therefore, it is urgent to develop a water phase trap damage prevention agent suitable for tight carbonate gas reservoirs. Summary of the invention

[0007] The purpose of the present invention is to provide a water-phase trap damage control agent for carbonate gas reservoirs, which can solve the problem that the current water-phase trap damage control agent cannot reverse the rock surface from liquid wettability to strong gas wettability when used in tight carbonate gas reservoirs.

[0008] In order to achieve the above objectives, the technical solution adopted by the water phase trap damage prevention agent for carbonate gas reservoirs of the present invention is:

[0009] A water phase trap damage prevention agent for carbonate gas reservoirs, mainly composed of fatty acids, alcohol compounds and emulsifiers; the mass ratio of the fatty acids, alcohol compounds and emulsifiers is (5-10): (0.5-3): (0.5-3); the structural formula of the fatty acid is R 1 -R 2 -COOH, where R 1 is hydrogen or carboxyl, R 2 It is a C7-C16 alkylene group.

[0010] The water phase trap damage prevention and control agent for carbonate gas reservoirs of the present invention comprises fatty acids, alcohol compounds and emulsifiers. The carboxyl groups in the fatty acids can be combined with calcium ions on the surface of carbonate rocks to form chemical bonds, and are more tightly combined with the rock surface. The hydrophobic alkyl groups are extended to change the rock surface from water wetting to neutral wetting, thereby reducing the amount of liquid that enters the carbonate gas reservoir through self-absorption of fluids, increasing the return rate of the fluid that has entered, and achieving the purpose of preventing and controlling water phase circle damage. At the same time, the alcohol compounds can assist the fatty acids in changing the surface wettability of carbonate rocks to neutral wetting, and improve the fluidity of the system. The emulsifier can form a stable emulsion when the prevention and control agent and water are mixed, thereby facilitating the injection of the water phase trap damage prevention and control agent. The water phase trap damage prevention and control agent for carbonate gas reservoirs of the present invention can reduce the capillary self-absorption of dense carbonate gas reservoirs through the change of wettability, promote the return of the intruding liquid phase, reduce the water phase trap permeability damage rate, and achieve the purpose of preventing and controlling water phase trap damage and increasing the gas well production.

[0011] In order to further improve the water phase damage prevention effect, preferably, R 2 is a C7-C13 alkylene group. 2 is octylene, heptylene, undecylene, or tridecylene. Further preferably, R 1 is hydrogen, R 2 is C11-C13 alkylene; R 1 is carboxyl, R 2 is a C7-C11 alkylene group. 1 is hydrogen, R 2 is C11-C13 alkylene; R 1 is carboxyl, R 2 For example, the fatty acid is lauric acid, myristic acid, azelaic acid, or sebacic acid.

[0012] Preferably, the alcohol compound is selected from one or any combination of monohydric fatty alcohol, dihydric fatty alcohol, and trihydric fatty alcohol; the carbon atoms of the monohydric fatty alcohol are 1 to 5, the carbon atoms of the dihydric fatty alcohol are 2 to 5, and the carbon atoms of the trihydric fatty alcohol are 3 to 5. Selecting an alcohol compound with no more than 5 carbon atoms can ensure the fluidity of the system and ease of use.

[0013] Preferably, the monohydric fatty alcohol is a saturated monohydric fatty alcohol, the dihydric fatty alcohol is a saturated dihydric fatty alcohol, and the trihydric fatty alcohol is a saturated trihydric fatty alcohol. For example, the monohydric fatty alcohol is ethanol, propanol, butanol; the dihydric fatty alcohol is ethylene glycol, propylene glycol; the trihydric fatty alcohol is glycerol, butanetriol.

[0014] Preferably, the emulsifier is selected from nonionic surfactants and / or anionic surfactants. The selection of nonionic surfactants and / or anionic surfactants can avoid the interaction between cations and fatty acids, and reduce the binding force between fatty acids and calcium ions on the surface of carbonate rocks.

[0015] Preferably, the nonionic surfactant is polyoxyethylene ether and / or alkylphenol polyoxyethylene ether. Preferably, the anionic surfactant is alkylbenzene sulfonate. Preferably, the alkylbenzene sulfonate is alkylbenzene sulfonate alkali metal salt. For example, the emulsifier is dodecylphenol polyoxyethylene ether, sodium dodecylbenzene sulfonate, polyoxyethylene ether.

[0016] Preferably, the water phase trap damage prevention agent for carbonate gas reservoirs also includes water. The water is deionized water or water containing inorganic minerals; preferably, the water containing inorganic minerals is tap water, river water, or carbonate gas reservoir formation water.

[0017] When the control agent also includes water, in order to ensure a better water phase trap damage control effect and to reduce costs, preferably, the mass fraction of the fatty acid in the water phase trap damage control agent for carbonate gas reservoirs is 5-10%. DETAILED DESCRIPTION

[0018] The technical solution of the present invention is further described below in conjunction with specific embodiments.

[0019] The water phase trap damage prevention and control agent for carbonate gas reservoirs of Examples 1-8 is composed of fatty acids, alcohol compounds, emulsifiers and water, the fatty acids are composed of lauric acid, myristic acid, azelaic acid and sebacic acid, the alcohol compounds are composed of ethanol, ethylene glycol and glycerol, and the emulsifier is composed of polyoxyethylene ether, OP-10 and sodium dodecylbenzene sulfonate. The mass fractions of lauric acid, myristic acid, azelaic acid, sebacic acid, ethanol, ethylene glycol, glycerol, polyoxyethylene ether, OP-10 and sodium dodecylbenzene sulfonate in each example are shown in Table 1.

[0020] Table 1 Mass fractions of lauric acid, myristic acid, azelaic acid, sebacic acid, ethanol, ethylene glycol, glycerol, polyoxyethylene ether, OP-10 and sodium dodecylbenzene sulfonate in each example

[0021]

[0022] Comparative Example 1

[0023] The water phase entrapment damage prevention agent of this comparative example is FW-134 fluorine-containing surfactant.

[0024] Comparative Example 2

[0025] The water phase entrapment damage prevention agent of this comparative example is the super hydrophobic nano material water decomposing and locking agent C prepared in Example 3 of the Chinese patent document CN104449631A.

[0026] Comparative Example 3

[0027] The water phase trap damage prevention agent of this comparative example is the water-releasing and locking agent for natural gas reservoirs of Example 8 in Chinese patent document CN114479808A.

[0028] Comparative Example 4

[0029] The water phase entrapment damage control agent of this comparative example is composed of the following components in parts by mass: 2.125 parts of lauric acid, 3.1875 parts of myristic acid, 3.1875 parts of azelaic acid, 1 part of polyoxyethylene ether, 2 parts of sodium dodecylbenzene sulfonate, and 88.5 parts of tap water.

[0030] Comparative Example 5

[0031] The water phase entrapment damage prevention agent of this comparative example is composed of the following components in parts by mass: 8.5 parts of ethanol, 1 part of polyoxyethylene ether, 2 parts of sodium dodecylbenzene sulfonate, and 88.5 parts of tap water.

[0032] Comparative Example 6

[0033] The difference between the water-phase trap damage control agent of this comparative example and the water-phase trap damage control agent for carbonate gas reservoirs of Example 3 is that lauric acid is replaced by decacarboxylic acid in the water-phase trap damage control agent of this comparative example.

[0034] Comparative Example 7

[0035] The difference between the water-phase trap damage control agent of this comparative example and the water-phase trap damage control agent for carbonate gas reservoirs of Example 3 is that lauric acid is replaced by heptadecanoic acid in the water-phase trap damage control agent of this comparative example.

[0036] Comparative Example 8

[0037] The difference between the water-phase trap damage control agent of this comparative example and the water-phase trap damage control agent for carbonate gas reservoirs of Example 3 is that azelaic acid is replaced by suberic acid in the water-phase trap damage control agent of this comparative example.

[0038] Comparative Example 9

[0039] The difference between the water-phase trap damage control agent of this comparative example and the water-phase trap damage control agent for carbonate gas reservoirs of Example 3 is that azelaic acid is replaced by tetradecanedioic acid in the water-phase trap damage control agent of this comparative example.

[0040] Experimental example

[0041] In order to evaluate the prevention and control effects of different water-phase trap damage prevention agents on tight carbonate gas reservoirs, the water-phase trap damage prevention agents of Examples 1-8 and Comparative Examples 1-9 were applied to the core of a tight carbonate gas reservoir (Changxing Formation of Puguang Gas Field), and contact angle measurement, capillary self-imbibition and liquid phase flowback experiments were carried out according to the method in standard SY / T 5153-2017 "Method for Determining Wettability of Reservoir Rocks", and the permeability before and after the action of the water-phase trap damage prevention agent was measured, wherein the change in the self-imbibition amount determined by the capillary self-imbibition experiment is an effect indicator for preventing water-phase trap damage, and the changes in the liquid phase flowback rate and the permeability damage rate are effect indicators for removing and treating water-phase trap damage.

[0042] The specific experimental process is as follows: the experimental core is dried to constant weight, basic parameters such as length, diameter, dry weight, porosity and permeability are measured, formation water is saturated by capillary self-imbibition method, initial water saturation is established, and gas permeability K of the experimental core under initial water saturation is measured. i ; Gradually adjust the height of the beaker until the length of the rock sample immersed in the imbibition liquid (formation water) is 2 to 3 mm, and start collecting data. After the core weight stabilizes, remove the core and weigh it to determine the imbibition amount (final water saturation %). Dehydrate the rock sample using a high-speed centrifuge, centrifuge until the weight stabilizes, and record the weight of the core; Based on the weight of the core before and after centrifugation, calculate the liquid phase return rate C using formula (1) i ; Using nitrogen constant pressure displacement, the gas permeability K of the experimental core under irreducible water saturation conditions was determined ir , using formula (2) to calculate the core water phase trap permeability damage rate R d '. The cores that have completed the formation water capillary self-imbibition experiment are washed with salt and dried. The water phase closure damage prevention agents and formation water are mixed in a mass ratio of 1:99 to obtain the test liquid, and then the test liquid is used to replace the above formation water to repeat the above experiment, and the self-imbibition amount, liquid phase backflow rate and permeability damage rate corresponding to the test liquid are determined. Before using the test liquid for testing, the core containing the test liquid needs to be aged at the reservoir temperature for 24 hours, and then the core is taken out and dried before relevant tests.

[0043]

[0044] In formula 1, △G Di is the cumulative return liquid volume, g; △G i is the total water content of the core after the end of self-imbibition, g.

[0045]

[0046] In formula 2: R d ' is the water phase closure permeability damage rate, %; K i is the gas permeability of the experimental core under the initial water saturation condition, 10-3 μm 2 ; K ir is the gas permeability of the experimental core under irreducible water saturation conditions, 10 -3 μm 2 .

[0047] The experimental process of testing the contact angle is as follows: first cut the core into 1-2cm thick slices, and polish its surface with coarse and fine sandpaper, drip formation water onto the core, and observe and measure the contact angle of formation water on the core. Mix each water phase closure damage prevention agent and formation water in a mass ratio of 1:99 to obtain a test solution, then soak the core in the test solution, place it in an 80℃ water bath and stir for 2h, and place the core containing the test solution in a 120℃ constant temperature oven for 8h, then take out the core slice and test the contact angle of formation water on the core slice. The core samples used for testing the contact angle and the core samples used for testing the self-imbibition, liquid phase backflow rate and permeability damage rate are core samples at the same depth of the formation.

[0048] The corresponding results of testing various water phase entrapment damage control agents are summarized in Table 2.

[0049] Table 2 Test results of contact angle, self-imbibition, liquid phase flowback rate and permeability damage rate of formation water and test fluid on the core of tight carbonate gas reservoir

[0050]

[0051]

[0052] As shown in Table 2, when the control agents of Examples 1-8 are applied to the core of a tight carbonate gas reservoir, the average contact angle of the water\air\carbonate system is 80.1°, which is much higher than the corresponding contact angles of Comparative Examples 1, 2 and 3 (12.8°, 12.6° and 19.6°, respectively); the final water saturation of capillary self-imbibition is 32.1% to 47.5%, which is lower than the capillary self-imbibition water saturation of Comparative Examples 1-3 (59.3%, 51.4% and 62.2%, respectively); the liquid phase flowback rate is 60.7% to 74.1%, which is higher than the liquid phase flowback rate of Comparative Examples 1-3 (45.2%, 50.4% and 52.8%, respectively); the water phase closure permeability damage rate is 51.5% to 60.3%, which is lower than the water phase closure permeability damage rate of Comparative Examples 1-3 (68.5%, 65.2% and 72.6%, respectively). The above data show that the existing water-phase trap damage prevention and control agent (Comparative Examples 1, 2, and 3) cannot change the wettability of tight carbonate gas reservoirs, the capillary self-imbibition is high, the liquid phase return rate is low, and the permeability damage rate is also high, and the water-phase trap damage cannot be effectively prevented and controlled; the water-phase trap damage prevention and control agent of the present invention can effectively change the surface of tight carbonate rock from water wetting to neutral wetting, thereby reducing the self-imbibition amount, preventing the occurrence of water-phase trap damage, increasing the liquid phase return rate, and reducing the permeability damage rate, thereby achieving the purpose of removing water-phase trap damage and increasing gas well production.

[0053] When the azelaic acid in the water-phase trap damage control agent for carbonate gas reservoirs in Example 7 is replaced with undecanedioic acid, dodecanedioic acid or tridecanedioic acid, and the prepared water-phase trap damage control agent is tested according to the above-mentioned test method, the test results are close to the test results of the water-phase trap damage control agent in Example 7.

Claims

1. A water phase trap damage prevention agent for carbonate gas reservoirs, characterized in that: It is mainly composed of fatty acids, alcohol compounds and emulsifiers; the mass ratio of the fatty acids, alcohol compounds and emulsifiers is (5-10):(0.5-3):(0.5-3); the structural formula of the fatty acid is R1-R2-COOH, wherein R1 is hydrogen or carboxyl, and R2 is C7-C16 alkylene.

2. The water phase trap damage prevention agent for carbonate gas reservoirs according to claim 1, characterized in that: R2 is a C7-C13 alkylene group.

3. The water phase trap damage prevention agent for carbonate gas reservoirs according to claim 2, characterized in that: R1 is hydrogen, R2 is C11-C13 alkylene; R1 is carboxyl, R2 is octylene or heptylene.

4. The water phase trap damage prevention agent for carbonate gas reservoirs according to any one of claims 1 to 3, characterized in that: The alcohol compound is selected from one or any combination of monohydric fatty alcohol, dihydric fatty alcohol and trihydric fatty alcohol; the carbon atoms of the monohydric fatty alcohol are 1 to 5, the carbon atoms of the dihydric fatty alcohol are 2 to 5, and the carbon atoms of the trihydric fatty alcohol are 3 to 5.

5. The water phase trap damage prevention agent for carbonate gas reservoirs according to claim 4, characterized in that: The monohydric fatty alcohol is a saturated monohydric fatty alcohol, the dihydric fatty alcohol is a saturated dihydric fatty alcohol, and the trihydric fatty alcohol is a saturated trihydric fatty alcohol.

6. The water phase trap damage prevention agent for carbonate gas reservoirs according to claim 5, characterized in that: The monohydric fatty alcohols are ethanol, propanol and butanol; the dihydric fatty alcohols are ethylene glycol and propylene glycol; the trihydric fatty alcohols are glycerol and butanetriol.

7. The water phase trap damage prevention agent for carbonate gas reservoirs according to any one of claims 1 to 3, characterized in that: The emulsifier is selected from nonionic surfactants and / or anionic surfactants.

8. The water phase trap damage prevention agent for carbonate gas reservoirs according to claim 7, characterized in that: The nonionic surfactant is polyoxyethylene ether and / or alkylphenol polyoxyethylene ether; the anionic surfactant is alkylbenzene sulfonate.

9. The water phase trap damage prevention agent for carbonate gas reservoirs according to any one of claims 1 to 3, characterized in that: The water phase trap damage prevention agent for carbonate gas reservoirs also includes water.

10. The water phase trap damage prevention agent for carbonate gas reservoirs according to claim 9, characterized in that: The mass fraction of the fatty acid in the water phase trap damage prevention agent for carbonate gas reservoirs is 5-10%.

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