A water phase plugging damage prevention agent for carbonate gas reservoirs

Abstract

The present application relates to a kind of water phase trap damage prevention and treatment agent for carbonate gas reservoir, belong to oil and gas reservoir chemical technical field.The water phase trap damage prevention and treatment agent for carbonate gas reservoir of the present application includes fatty acid, alcohol compound and emulsifier, the carboxyl group in fatty acid can be combined with the calcium ion on the surface of carbonate rock by chemical bond, and be combined more closely with rock surface, and the hydrophobic alkyl is stretched out, so that the rock surface is changed from water wetting to neutral wetting, thereby reducing the liquid volume of fluid imbibition into carbonate gas reservoir, increase the flowback rate of fluid that has entered, reach the purpose of water phase trap damage prevention and treatment.Meanwhile, alcohol compound can assist fatty acid to change the wettability of carbonate rock surface to neutral wetting, and improve the fluidity of system.Emulsifier can form stable emulsion when prevention and treatment agent and water are mixed, thereby facilitating the injection of water phase trap damage prevention and treatment agent.

Description

Technical Field

[0001] This invention relates to an agent for preventing damage to aqueous traps in carbonate gas reservoirs, belonging to the field of oil and gas reservoir chemicals technology. Background Technology

[0002] Water-phase trapping damage refers to the phenomenon where, during drilling, completion, production enhancement, and other operations, the intrusion of external water-based working fluids and the redistribution of initial water cut in the gas reservoir lead to increased near-wellbore water saturation, resulting in decreased gas permeability and inducing reservoir damage. The main causes of water-phase trapping are capillary self-absorption and liquid retention. Tight gas reservoirs are generally divided into tight sandstone gas reservoirs and tight carbonate gas reservoirs. Tight gas reservoirs are characterized by fine pore throats, high capillary pressure, poor permeability, and high gas flow resistance, exhibiting a significant capillary effect. Furthermore, due to the presence of extremely low water saturation in some areas of the reservoir, external intruding fluids easily undergo capillary self-absorption and retention during drilling and development, forming water-phase traps. Numerous studies have shown that water-phase trapping damage is the most significant form of damage to tight gas reservoirs, with a damage rate as high as 70%–90%. Therefore, the prevention and control of water-phase trapping damage is of paramount importance.

[0003] Currently, there are various methods both domestically and internationally to mitigate or eliminate water-phase trap damage, such as CO2 injection, the use of surfactants that reduce interfacial tension, hot gas injection, fracturing, formation heat treatment (FHT), avoiding the use of easily trapping fluids, reducing fluid interaction time, and decreasing invasion depth. However, these methods suffer from problems such as short effective time, high processing costs, and the potential for secondary damage. The wettability of reservoir rocks is a key factor determining capillary self-absorption behavior and has a significant impact on liquid-phase trap damage. Changing the surface wettability of the rock to gas wettability is a new direction in improving permeability and preventing water-phase trap damage. This method mainly targets tight reservoirs with small pore throats and significant interfacial effects. By changing the rock wettability, it reduces capillary self-absorption and promotes the flowback of invading liquid phases, thereby achieving the goal of preventing water-phase trap damage and increasing gas well production. Currently available water-phase trap damage prevention agents are only suitable for changing the wettability of tight sandstone gas reservoirs from water-wet to gas-wet or neutral wettability, but cannot change the wettability of tight carbonate gas reservoirs and therefore do not have the effect of preventing water-phase trap damage.

[0004] Liu Xuefen et al. used the fluorinated surfactant FW-134 (FW-134 is a perfluorooctyl quaternary ammonium salt fluoride, a perfluoro cationic surfactant) to change the wetting of typical tight sandstone cores from water to air. They conducted capillary self-absorption and backflow experiments of simulated formation water before and after FW-134 treatment, and measured the water saturation and backflow rate of the liquid phase in the rock samples. The experimental results showed that FW-134 significantly inhibited liquid phase self-absorption, decreasing the water saturation from 62% to 29.5% and increasing the liquid phase backflow rate from 56.3% to 83.4%. FW-134 can effectively prevent water phase trapping damage. Chinese patent document CN104449631A discloses a strong gas-wetting nano-silica water-locking agent, its preparation method, and a method for reversing wetting on rock surfaces. The modified nano-silica water-locking agent comprises: 0.1%-0.5% modified nano-silica, 0.5%-1% emulsifier OP-10, 0.5%-1% sodium dodecyl sulfate, 25%-50% ethanol, and the balance being water. The modified nano-silica is obtained by modifying silica with a nonionic fluorocarbon surfactant. This patent document's nano-silica water-locking agent can reverse the wetting of rock surfaces from liquid to strong gas-wetting, reduce the viscous resistance of fluid flow on the rock surface, and relieve water-locking damage. Chinese patent document CN114479808A discloses a dewatering chemical agent suitable for sandstone natural gas reservoirs, comprising 5-20% fluorocarbon surfactant, 5-20% biosurfactant, 5-30% synergist, and 30-85% water. This dewatering chemical agent can significantly reduce the surface tension of water, regulating a strongly wetted matrix surface to neutral or even hydrophobic. The aforementioned documents all involve the electrostatic attraction of fluorinated surfactants to highly electronegative rock surfaces, thereby altering the wettability of the rock surface. However, this adsorption force is relatively weak, resulting in a short effective period for the chemical agent on the rock surface.

[0005] Sandstone reservoirs, due to their high clay content, generally have negatively charged rock surfaces. Carbonate reservoirs, on the other hand, are primarily composed of calcite and dolomite. Calcite is electrically neutral and carries no charge overall. Dolomite is neutral at pH 6.0, but becomes positively charged at pH values ​​below 6.0 (carbonate gas reservoirs typically contain hydrogen sulfide, making them acidic). Therefore, the fluorinated surfactants mentioned in the literature cannot be adsorbed on the surface of carbonate reservoirs and thus cannot alter their surface wettability. For example, the FW-134 fluorinated surfactant has a wetting contact angle of 12.8° after acting on the surface of a hydrophilic carbonate reservoir. The nano-silica hydrolytic agent in Chinese patent document CN104449631A has a contact angle of 12.6° after acting on a hydrophilic carbonate reservoir. The hydrolytic chemical agent in Chinese patent document CN114479808A has a contact angle of 19.6° after acting on a hydrophilic carbonate reservoir. The core still exhibits strong hydrophilicity.

[0006] Therefore, there is an urgent need to develop an agent suitable for preventing water-phase trap damage in tight carbonate gas reservoirs. Summary of the Invention

[0007] The purpose of this invention is to provide an agent for preventing water phase trap damage in carbonate gas reservoirs, which can solve the problem that current agents for preventing water phase trap damage in tight carbonate gas reservoirs cannot reverse the rock surface from liquid wettability to strong gas wettability.

[0008] To achieve the above objectives, the technical solution adopted by the present invention for the prevention and control of water phase trap damage in carbonate gas reservoirs is as follows:

[0009] An agent for preventing damage to aqueous traps in carbonate gas reservoirs 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 acids is R1-R2-COOH, wherein R1 is hydrogen or carboxyl, and R2 is a C7-C16 alkylene group.

[0010] The present invention relates to an agent for preventing water-phase trap damage in carbonate gas reservoirs, comprising fatty acids, alcohol compounds, and emulsifiers. The carboxyl groups in the fatty acids can form chemical bonds with calcium ions on the carbonate rock surface, resulting in a tighter bond and the extension of hydrophobic alkyl groups. This transforms the rock surface from water-wetted to neutral-wetted, thereby reducing the amount of fluid self-absorbed into the carbonate gas reservoir and increasing the flowback rate of already infiltrated fluids, thus achieving the purpose of preventing and controlling water-phase trap damage. Simultaneously, the alcohol compounds assist the fatty acids in changing the wettability of the carbonate rock surface to neutral wettability and improving the system's fluidity. The emulsifier enables the agent to form a stable emulsion when mixed with water, facilitating the injection of the agent. The agent for preventing water-phase trap damage in carbonate gas reservoirs of the present invention can reduce capillary self-absorption in tight carbonate gas reservoirs by altering wettability, promote the flowback of infiltrated liquid phases, and reduce the water-phase trap permeability damage rate, thereby achieving the purpose of preventing water-phase trap damage and increasing gas well production.

[0011] To further improve the effectiveness of preventing damage to the aqueous phase, preferably, R2 is a C7-C13 alkylene group. For example, R2 is octylene, heptylene, undecylene, or tridecylene. More preferably, R1 is hydrogen and R2 is a C11-C13 alkylene group; or R1 is a carboxyl group and R2 is a C7-C11 alkylene group. For example, R1 is hydrogen and R2 is a C11-C13 alkylene group; or R1 is a carboxyl group and R2 is octylene or heptylene. 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 alcohols, dihydric fatty alcohols, and trihydric fatty alcohols; the monohydric fatty alcohol has 1 to 5 carbon atoms, the dihydric fatty alcohol has 2 to 5 carbon atoms, and the trihydric fatty alcohol has 3 to 5 carbon atoms. Selecting alcohol compounds with no more than 5 carbon atoms ensures the fluidity of the system and makes it easy to 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, or butanol; the dihydric fatty alcohol is ethylene glycol or propylene glycol; and the trihydric fatty alcohol is glycerol or butylene glycol.

[0014] Preferably, the emulsifier is selected from nonionic surfactants and / or anionic surfactants. Using nonionic and / or anionic surfactants can prevent the interaction between cations and fatty acids, reducing the binding force between fatty acids and calcium ions on the carbonate rock surface.

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

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

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

[0018] The technical solution of the present invention will be further described below with reference to specific embodiments.

[0019] The water-phase trap damage prevention agents for carbonate gas reservoirs in Examples 1-8 are 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. The emulsifiers are composed of polyoxyethylene ether, OP-10, and sodium dodecylbenzenesulfonate. The mass fractions of lauric acid, myristic acid, azelaic acid, sebacic acid, ethanol, ethylene glycol, glycerol, polyoxyethylene ether, OP-10, and sodium dodecylbenzenesulfonate in each example are shown in Table 1.

[0020] Table 1 shows the mass fractions of lauric acid, myristic acid, azelaic acid, sebacic acid, ethanol, ethylene glycol, glycerol, polyoxyethylene ether, OP-10, and sodium dodecylbenzenesulfonate in each example.

[0021]

[0022] Comparative Example 1

[0023] The aqueous phase trapping damage prevention agent in this comparative example is FW-134 fluorinated surfactant.

[0024] Comparative Example 2

[0025] The aqueous trapping damage prevention agent in this comparative example is the superhydrophobic nanomaterial hydrolytic lock agent C prepared in Example 3 of Chinese Patent Document CN104449631A.

[0026] Comparative Example 3

[0027] The water-phase trapping damage prevention agent in this comparative example is the water-locking agent for natural gas reservoirs described in Example 8 of Chinese Patent Document CN114479808A.

[0028] Comparative Example 4

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

[0030] Comparative Example 5

[0031] The aqueous trapping damage control agent of this comparative example is composed of the following components in parts by weight: 8.5 parts ethanol, 1 part polyoxyethylene ether, 2 parts sodium dodecylbenzenesulfonate, and 88.5 parts tap water.

[0032] Comparative Example 6

[0033] The only difference between the aqueous trap damage prevention agent of this comparative example and the aqueous trap damage prevention agent for carbonate gas reservoirs in Example 3 is that lauric acid is replaced with decacyanate in the aqueous trap damage prevention agent of this comparative example.

[0034] Comparative Example 7

[0035] The only difference between the aqueous trap damage prevention agent of this comparative example and the aqueous trap damage prevention agent for carbonate gas reservoirs in Example 3 is that lauric acid is replaced with heptadecanic acid in the aqueous trap damage prevention agent of this comparative example.

[0036] Comparative Example 8

[0037] The only difference between the aqueous trap damage prevention agent of this comparative example and the aqueous trap damage prevention agent for carbonate gas reservoirs in Example 3 is that azelaic acid is replaced with octanoic acid in the aqueous trap damage prevention agent of this comparative example.

[0038] Comparative Example 9

[0039] The only difference between the aqueous trap damage prevention agent of this comparative example and the aqueous trap damage prevention agent for carbonate gas reservoirs in Example 3 is that azelaic acid is replaced with tetradecanoic acid in the aqueous trap damage prevention agent of this comparative example.

[0040] Experimental Example

[0041] To evaluate the effectiveness of different aqueous trap damage prevention agents on tight carbonate gas reservoirs, the aqueous trap damage prevention agents of Examples 1-8 and Comparative Examples 1-9 were applied to core samples from tight carbonate gas reservoirs (Changxing Formation, Puguang Gas Field). Contact angle measurements, capillary self-absorption, and liquid phase backflow experiments were conducted according to the methods in standard SY / T 5153-2017 "Methods for Determining the Wettability of Reservoir Rocks". The permeability before and after the application of the aqueous trap damage prevention agents was measured. The change in self-absorption amount measured by the capillary self-absorption experiment is an indicator of the effectiveness in preventing aqueous trap damage, while the changes in liquid phase backflow rate and permeability damage rate are indicators of the effectiveness in relieving and treating aqueous trap damage.

[0042] The specific experimental procedure was as follows: the experimental core was dried to constant weight, and basic parameters such as length, diameter, dry weight, porosity, and permeability were measured. Formation water was saturated using the capillary self-absorption method to establish initial water saturation. The gas phase permeability K of the experimental core under the initial water saturation condition was then determined. i Gradually adjust the height of the beaker until the length of the rock sample immersed in the self-absorbing liquid (formation water) is 2-3 mm, and start collecting data. After the core weight stabilizes, remove the core and weigh it to determine the self-absorption amount (final water saturation %). Dehydrate the rock sample using a high-speed centrifuge until the weight stabilizes, and record the weight of the core. Calculate the liquid backflow rate C using formula (1) based on the weight of the core before and after centrifugation. i Using nitrogen constant-pressure displacement, the gas phase permeability K of the experimental core under bound water saturation conditions was determined. ir The permeability damage rate R of the core water phase trap was calculated using formula (2). d After completing the formation water capillary self-absorption experiment, the core was washed and dried. The various aqueous phase trapping damage prevention agents and formation water were mixed at a mass ratio of 1:99 to obtain the test solution. The test solution was then used to replace the formation water in the experiment, and the self-absorption capacity, liquid phase backflow rate, and permeability damage rate corresponding to the test solution were measured. Before using the test solution, the core containing the test solution needed to be aged at the reservoir temperature for 24 hours, then the core was removed, dried, and then the relevant tests were performed.

[0043]

[0044] In Equation 1, △G Di The cumulative amount of backflowed liquid is expressed in g; ΔG i The total water content of the core after self-absorption is complete, in g.

[0045]

[0046] In Equation 2: R d 'Represents the water phase trap permeability damage rate, %; K' i To measure the gas phase permeability of the experimental core under initial water saturation conditions, 10-3 μm 2 ;K ir To measure the gas phase permeability of the experimental core under bound water saturation conditions, 10 -3 μm 2 .

[0047] The experimental procedure for testing the contact angle is as follows: First, the core is cut into thin slices 1-2 cm thick, and its surface is polished with coarse and fine sandpaper. Formation water is then dripped onto the core, and the contact angle of the formation water on the core is observed and measured. The various water-phase trapping damage prevention agents and formation water are mixed at a mass ratio of 1:99 to obtain the test solution. The core is then immersed in the test solution and stirred in an 80℃ water bath for 2 hours. The core containing the test solution is then placed in a 120℃ constant temperature oven and allowed to stand for 8 hours. The core slices are then removed, and the contact angle of the formation water on the core slices is measured. The core samples used for testing the contact angle are from the same depth in the formation as those used for testing self-absorption, liquid phase backflow rate, and permeability damage rate.

[0048] The results of testing various water-phase trap damage prevention agents are summarized in Table 2.

[0049] Table 2. Test results of contact angle, self-absorption, liquid flowback rate, and permeability damage rate of formation water and test fluid in tight carbonate gas reservoir cores.

[0050]

[0051]

[0052] As shown in Table 2, when the control agents of Examples 1-8 were applied to the core of tight carbonate gas reservoirs, the average contact angle of the water / air / carbonate rock system was 80.1°, which was much higher than the corresponding contact angles of Comparative Examples 1, 2, and 3 (12.8°, 12.6°, and 19.6°, respectively); the final capillary self-absorption water saturation was 32.1%–47.5%, which was lower than the capillary self-absorption water saturation of Comparative Examples 1-3 (59.3%, 51.4%, and 62.2%, respectively); the liquid phase flowback rate was 60.7%–74.1%, which was higher than the liquid phase flowback rate of Comparative Examples 1-3 (45.2%, 50.4%, and 52.8%, respectively); and the water phase trap permeability damage rate was 51.5%–60.3%, which was lower than the water phase trap permeability damage rate of Comparative Examples 1-3 (68.5%, 65.2%, and 72.6%, respectively). The above data shows that existing aqueous trap damage prevention agents (comparative examples 1, 2, and 3) cannot change the wettability of tight carbonate gas reservoirs, have high capillary self-absorption, low liquid flowback rate, and high permeability damage rate, and cannot effectively prevent aqueous trap damage. The aqueous trap damage prevention agent of this invention can effectively change the surface of tight carbonate rocks from water-wet to neutral-wet, thereby reducing self-absorption, preventing the occurrence of aqueous trap damage, increasing the liquid flowback rate, and reducing the permeability damage rate, thus achieving the purpose of relieving aqueous trap damage and increasing gas well production.

[0053] When the azelaic acid in the aqueous phase trap damage prevention agent for carbonate gas reservoirs in Example 7 is replaced with undecanoic acid, dodecanoic acid, or tridecanoic acid, the test results of the prepared aqueous phase trap damage prevention agent when tested according to the above test method are close to the test results of the aqueous phase trap damage prevention agent in Example 7.

Claims

1. An aqueous phase trapping damage prevention agent for carbonate gas reservoirs, characterized by, The prevention agent mainly comprises fatty acid, alcohol compound and emulsifier, the mass ratio of the fatty acid, alcohol compound and emulsifier 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, the emulsifier is selected from non-ionic surfactant and / or anionic surfactant, the emulsifier can form stable emulsion when the prevention agent is mixed with water, the non-ionic surfactant is polyoxyethylene ether and / or alkyl phenol polyoxyethylene ether, the anionic surfactant is alkyl benzene sulfonate, 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 1-5, the carbon atoms of the dihydric fatty alcohol are 2-5, and the carbon atoms of the trihydric fatty alcohol are 3-5.

2. The water phase seal damage prevention agent for carbonate gas reservoirs according to claim 1, characterized by, R2 is C7-C13 alkylene.

3. The water phase seal damage prevention agent for carbonate gas reservoirs according to claim 2, characterized by, R1 is hydrogen, R2 is C11-C13 alkylene, or R1 is carboxyl, and R2 is octylene or heptylene.

4. The water phase seal damage prevention agent for carbonate gas reservoirs according to any one of claims 1 to 3, wherein, The monohydric fatty alcohol is ethanol, propanol or butanol.

5. The water phase seal damage prevention agent for carbonate gas reservoirs of claim 1, wherein, The dihydric fatty alcohol is ethylene glycol or propylene glycol.

6. The water phase seal damage prevention agent for carbonate gas reservoirs according to claim 5, characterized by, The trihydric fatty alcohol is glycerol or butanetriol.

7. The water phase seal damage prevention agent for carbonate gas reservoirs according to any one of claims 1 to 3, wherein The non-ionic surfactant is OP-10.

8. The water phase seal damage prevention agent for carbonate gas reservoirs according to claim 7, characterized by, The anionic surfactant is sodium dodecyl benzene sulfonate.

9. The water phase seal damage prevention agent for carbonate gas reservoirs according to any one of claims 1 to 3, wherein, The water phase trapping damage prevention agent for carbonate gas reservoirs further comprises water.

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

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