Water lock releasing agent for releasing water lock damage of compact reservoir and method for releasing water lock damage of compact reservoir

Abstract

The present application relates to a kind of for relieving dense reservoir water lock damage water lock relieving agent, dense reservoir water lock damage relieving method, belong to oil and gas field development technical field.The water lock relieving agent of the present application is mainly composed of supercritical fluid and entraining agent dispersed in supercritical fluid, the entraining agent includes surfactant, wetting modifier, reservoir drying agent and corrosion inhibitor.The water lock relieving agent of the present application uses supercritical fluid with ultra-low viscosity and strong solubility as main agent, can make the entraining agent dispersed therein more easily be injected into formation, to further improve water lock relieving effect;While the water lock relieving agent injected can greatly improve the fluid flow capacity in reservoir and water lock relieving effect by the mechanism of action such as evaporation formation water, reduce interfacial tension, change reservoir wettability after being injected into reservoir.

Description

Technical Field

[0001] This invention relates to a water-locking agent and a method for relieving water-locking damage in tight reservoirs, belonging to the field of oil and gas field development technology. Background Technology

[0002] Water-locking damage is one of the most significant and impactful problems during the development of tight oil and gas reservoirs. For tight gas reservoirs with widely developed micro- and nano-scale pore-throat systems, water-locking damage is highly likely to occur due to high capillary forces and generally strong hydrophilicity. Once it occurs, it will severely impact fluid flow and normal gas well production. Actual data from a tight gas reservoir in the Ordos Basin shows that over 70% of gas wells are affected by liquid phase damage. Laboratory experiments have also confirmed that the permeability loss in tight cores due to liquid phase damage is generally between 40% and 60%, and in some cases, can reach over 90%.

[0003] To address this issue, oilfields currently commonly employ gas injection or chemical injection to release water locks. However, existing methods are primarily suited for conventional reservoirs, with both advantages and disadvantages being significant, resulting in generally poor performance, especially in tight reservoirs. Gas injection is relatively easy to implement in tight reservoirs, but it only utilizes the expansion capacity of gas to expel stagnant liquid phases, failing to improve their flowability and thus limiting its effectiveness. Chemical injection can effectively improve fluid flowability, but current research and applications of chemical injections are concentrated in medium- to high-permeability reservoirs; injecting chemicals into tight reservoirs is extremely difficult and impractical. Therefore, tight oil and gas reservoirs urgently require a water-lock release agent that can effectively release water locks. Summary of the Invention

[0004] The purpose of this invention is to provide a water-locking agent for relieving water-lock damage in tight reservoirs, thereby solving the problem of the difficulty in injecting chemical agents into tight reservoirs when relieving water-lock damage.

[0005] Another objective of this invention is to provide a method for relieving waterlock damage in tight reservoirs using the aforementioned water-locking agent.

[0006] To achieve the above objectives, the technical solution adopted by the water-locking agent of the present invention for relieving water-locking damage in tight reservoirs is as follows:

[0007] A water-locking agent for relieving water-locking damage in tight reservoirs mainly consists of a supercritical fluid and an entrainer dispersed in the supercritical fluid. The entrainer includes a surfactant, a wetting improver, a reservoir drying agent, and a corrosion inhibitor.

[0008] The water-lock release agent of this invention uses a supercritical fluid with ultra-low viscosity and strong solubility as the main agent, which makes it easier for the entrained agent dispersed therein to be injected into the formation, thereby improving the water-lock release effect. At the same time, the entrained chemical agents in the injected water-lock release agent can significantly improve the fluid flow capacity and water-lock release effect in the reservoir after injection by means of evaporating formation water, reducing interfacial tension, and changing reservoir wettability.

[0009] The water-locking agent of the present invention for relieving water-lock damage in tight reservoirs is obtained by adding different types of entrainers to a supercritical fluid and mixing them thoroughly. Further, the supercritical fluid is supercritical CO2. When the supercritical fluid is supercritical CO2, CO2 is simultaneously pressurized to above 7.5 MPa and heated to above 32°C in a pressurized sealed container. After stabilization, the entrainer is first added and dispersed evenly, then a corrosion inhibitor and a surfactant are added, and finally a reservoir drying agent is added and dispersed evenly.

[0010] Furthermore, the surfactant is a polyethoxykynediol surfactant. Compared to other surfactants, polyethoxykynediol surfactants can better reduce interfacial tension between fluids and have good solubility in supercritical CO2. Even further, the polyethoxykynediol surfactant is Evonik's nonionic surfactant Dynol-604. Furthermore, the concentration of the surfactant in the water-locking agent is 0.01-0.03 mol / L; below this range, the effect of reducing interfacial tension is poor.

[0011] Corrosion inhibitors can mitigate the corrosion of wellbores by supercritical fluids. Further, the corrosion inhibitor is an alcoholic amine corrosion inhibitor. Preferably, the alcoholic amine corrosion inhibitor is methyldiethanolamine. Methyldiethanolamine, used as a corrosion inhibitor in the water-lock deactivating agent of this invention, has the advantage over other corrosion inhibitors in that it exhibits better corrosion inhibition in a supercritical CO2 environment. Further, the concentration of the corrosion inhibitor in the water-lock deactivating agent is (7-10)×10⁻⁶. -4 The corrosion inhibition effect decreases significantly if the concentration of mol / L exceeds this range.

[0012] Furthermore, the wetting improver is an alcohol compound. Alcohol compounds, acting as entrainers, not only enhance the dispersion of other additives in supercritical fluids but also improve reservoir wettability and enhance the water-lock release effect. Ethanol can be selected as the alcohol compound. Furthermore, the concentration of the entrainer in the water-lock release agent is 0.1-0.15 mol / L. Below this range, the wetting improvement effect is poor; above this range, the improvement in wetting improvement is limited, resulting in poor economic efficiency.

[0013] After entering the tight reservoir, the reservoir drying agent reacts chemically with formation water to generate gas and heat, thereby consuming formation water. This significantly reduces reservoir water saturation, relieves water-locking damage in the tight reservoir, and improves permeability. Further, the reservoir drying agent is an ionic carbide. For example, the ionic carbide is aluminum carbide. Preferably, the aluminum carbide is nano-sized aluminum carbide, i.e., aluminum carbide with an average particle size of 10–100 nm, for example, 50 nm. Further, the concentration of the reservoir drying agent in the water-locking agent is (0.8–1.5) × 10⁻⁶. -8 The concentration of mol / L is specified. Below this range, the reservoir drying effect is poor, while above this range, the solubility and carrying capacity of the reservoir drying agent in the supercritical CO2 environment deteriorate.

[0014] The technical solution adopted in the method for relieving water-lock damage in tight reservoirs of the present invention is as follows:

[0015] A method for relieving water-lock damage in tight reservoirs includes the following steps: after draining the liquid from the tubing, injecting a gas corresponding to a supercritical fluid into the tubing until the wellhead pressure is not lower than the critical pressure of the supercritical fluid; then injecting the aforementioned water-locking agent for relieving water-lock damage in tight reservoirs into the tubing; subsequently injecting a gas corresponding to a supercritical fluid into the tubing to push the water-locking agent into the bottom layer, and then shutting the well; after shutting the well, opening the well and inducing a blowout to drain the fluid.

[0016] Compared to traditional gas injection methods for water lock removal, the method for relieving water lock damage in tight reservoirs in this invention injects a variety of chemical additives into the reservoir, significantly improving the fluid flow capacity and water lock removal effect within the reservoir. Furthermore, the ultra-low viscosity and strong solubilizing properties of supercritical fluids make it easier to inject chemical agents into tight reservoirs, thereby enhancing the water lock removal effect.

[0017] The injection volume of the water-locking agent is determined by the expected water-lock radius r, reservoir thickness h, and porosity. The horizontal section length *l* and the coefficient *c* are jointly determined. For a horizontal well, the injection volume calculation formula is... Where c = 0.25~0.35; for vertical wells, the injection volume calculation formula is... Where c = 0.35 to 0.5. Detailed Implementation

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

[0019] Examples 1 to 3 below are examples of water-locking agents for relieving water-locking damage in tight reservoirs, and Example 4 is an example of a method for relieving water-locking damage in tight reservoirs.

[0020] Example 1

[0021] The water-locking agent used in this embodiment to relieve water-locking damage in tight reservoirs consists of a supercritical fluid and an entrainer dispersed in the supercritical fluid. The entrainer is a combination of a surfactant, a wetting improver, a reservoir drying agent, and a corrosion inhibitor. The supercritical fluid used is supercritical CO2, the wetting improver is ethanol, and the concentration of ethanol in the water-locking agent is 0.15 mol / L. The reservoir drying agent used is nano-sized aluminum carbide with an average particle size of 50 nm, and its concentration in the water-locking agent is 1.2 × 10⁻⁶. -8 mol / L; the corrosion inhibitor used was dimethylethanolamine, and its concentration in the water-locking agent was 1×10⁻⁶. -3 The surfactant used was Evonik's nonionic surfactant Dynol-604, with a concentration of 0.02 mol / L in the water-locking agent.

[0022] Example 2

[0023] The water-locking agent used in this embodiment to relieve water-locking damage in tight reservoirs consists of a supercritical fluid and an entrainer dispersed in the supercritical fluid. The entrainer is a combination of a surfactant, a wetting improver, a reservoir drying agent, and a corrosion inhibitor. The supercritical fluid used is supercritical CO2, the wetting improver is ethanol, and the concentration of ethanol in the water-locking agent is 0.1 mol / L. The reservoir drying agent used is nano-sized aluminum carbide with an average particle size of 50 nm, and its concentration in the water-locking agent is 0.8 × 10⁻⁶. -8 mol / L; the corrosion inhibitor used was dimethylethanolamine, and its concentration in the water-locking agent was 7 × 10⁻⁶ mol / L. -4 The surfactant used was Evonik's nonionic surfactant Dynol-604, with a concentration of 0.01 mol / L in the water-locking agent.

[0024] Example 3

[0025] The water-locking agent used in this embodiment to relieve water-locking damage in tight reservoirs consists of a supercritical fluid and an entrainer dispersed in the supercritical fluid. The entrainer is a combination of a surfactant, a wetting improver, a reservoir drying agent, and a corrosion inhibitor. The supercritical fluid used is supercritical CO2, the wetting improver is ethanol, and the concentration of ethanol in the water-locking agent is 0.12 mol / L. The reservoir drying agent used is nano-sized aluminum carbide with an average particle size of 50 nm, and its concentration in the water-locking agent is 1.5 × 10⁻⁶. -8 mol / L; the corrosion inhibitor used was dimethylethanolamine, and its concentration in the water-locking agent was 9 × 10⁻⁶ mol / L. -4 The surfactant used was Evonik's nonionic surfactant Dynol-604, with a concentration of 0.03 mol / L in the water-locking agent.

[0026] In the preparation of the water-locking agents in Examples 1-3 above, CO2 is pressurized to above 7.5 MPa and heated to above 32°C in a pressurized sealed container on the ground to form supercritical CO2. After stabilizing for 5 minutes, ethanol is added first. After being evenly dispersed, methyl diethanolamine, Evonik nonionic surfactant Dynol-604 are added in sequence, and finally nano-aluminum carbide is added. After the composite system is mixed evenly, the system preparation is completed.

[0027] Example 4

[0028] This embodiment uses the X1 gas well in an oilfield in a basin in western China as an example to illustrate the method for removing water lock damage in tight reservoirs. The development layer of the X1 gas well is the He3 layer. Water lock appeared after two years of production. Although the fluid accumulation in the wellbore was not obvious, the gas and fluid production suddenly dropped. Subsequently, water lock removal operations were carried out on the X1 gas well. The specific steps include:

[0029] (1) Preparation of the water-locking agent on the ground: CO2 was pressurized to above 7.5 MPa and heated to above 32°C in a pressurized sealed container. After stabilizing for 5 minutes, ethanol was added first, and after uniform dispersion, methyldiethanolamine, Evonik nonionic surfactant Dynol-604, and finally nano-aluminum carbide were added in sequence. The composite system was mixed evenly to obtain the final product. The prepared water-locking agent used supercritical CO2 as the main agent, and the concentration of nano-aluminum carbide in the water-locking agent was 1.0 × 10⁻⁶. -8 The concentration of ethanol is 0.1 mol / L, and the concentration of methyldiethanolamine is 8 × 10⁻⁶ mol / L. -4 The concentration of Evonik's nonionic surfactant Dynol-604 is 0.02 mol / L.

[0030] (2) Open the well and release the blowout for 15 minutes until no liquid is discharged from the tubing;

[0031] (3) Pressurize the tubing with CO2 until the wellhead pressure reaches 8MPa;

[0032] (4) Since the expected water-lock radius r of well X1 is 3.5m, the reservoir thickness h = 18m, the porosity φ = 13.2%, and well X1 is a vertical well, the coefficient c is taken as 0.5, according to the calculation formula... The calculated injection volume is V = 45.7 m³. 3 45.7m³ of fluid was injected into the oil pipe. 3 The water-locking agent was then used to displace the composite system into the formation, and the well was left to simmer for one day.

[0033] (5) Open the well to induce flow and discharge fluid. Within 12 hours, enlarge the oil nozzle to increase the flow of fluid. After 12 hours, adjust to the normal production process and resume normal production.

[0034] After resuming normal production, the daily gas production of well X1 increased from an average of 3000 m³ before operation. 3 / d increased to 21000m 3 / d, with a stable production period of 150 days, the oil pressure increased from 1.8MPa before operation to 4.2MPa, and the casing pressure increased from 3.5MPa before operation to 9.8MPa, with good water lock removal effect.

[0035] Comparative Example 1

[0036] The water-locking agent in this comparative example for relieving water-lock damage in tight reservoirs differs from the water-locking agent in Example 1 only in that the surfactant in the water-locking agent of this comparative example is sodium secondary alkyl sulfonate.

[0037] Comparative Example 2

[0038] The water-locking agent in this comparative example for relieving water-lock damage in tight reservoirs differs from the water-locking agent in Example 1 only in that the concentration of surfactant in the water-locking agent in this comparative example is 0.004 mol / L.

[0039] Comparative Example 3

[0040] The water-locking agent in this comparative example for relieving water-lock damage in tight reservoirs differs from the water-locking agent in Example 1 only in that the concentration of surfactant in the water-locking agent in this comparative example is 0.6 mol / L.

[0041] Comparative Example 4

[0042] The water-locking agent in this comparative example for relieving water-locking damage in tight reservoirs differs from the water-locking agent in Example 1 only in that the water-locking agent in this comparative example does not contain corrosion inhibitors or surfactants.

[0043] Comparative Example 5

[0044] The water-locking agent in this comparative example for relieving water-locking damage in tight reservoirs differs from the water-locking agent in Example 1 only in that the water-locking agent in this comparative example does not contain a wetting improver (i.e., the wetting improver is omitted from the water-locking agent in Example 1).

[0045] Comparative Example 6

[0046] The water-locking agent in this comparative example for relieving water-locking damage in tight reservoirs differs from the water-locking agent in Example 1 only in that the water-locking agent in this comparative example does not contain a reservoir drying agent (i.e., the reservoir drying agent is omitted from the water-locking agent in Example 1).

[0047] Comparative Example 7

[0048] The water-locking agent in this comparative example for relieving water-locking damage in tight reservoirs differs from the water-locking agent in Example 1 only in that the water-locking agent in this comparative example does not contain an entrainer. In other words, the water-locking agent in this comparative example is pure supercritical CO2.

[0049] Comparative Example 8

[0050] The water-locking agent used in this comparative example to relieve water-lock damage in tight reservoirs is high-purity N2.

[0051] Experimental Example

[0052] The effectiveness of the water-locking agent in the embodiments of the present invention was evaluated and compared through indoor experiments. The experimental equipment used was a high-pressure, high-temperature, multifunctional core displacement testing device.

[0053] Eleven core samples (S1, S2, S3, S4, S5, S6, S7, S8, S9, S10, and S11) were drilled from relatively homogeneous locations in a tight reservoir to ensure that the physical properties of the eleven core samples were basically consistent. After cleaning and drying, the permeability of the eleven core samples was tested and found to be 0.65-0.68 mD.

[0054] Eleven core samples were saturated with water and placed in a holder. They were then displaced with N2 until no water was produced, simulating the state of bound water in the formation. The permeability of samples S1 to S11 (referred to as the first permeability) was measured and is shown in Table 1. The core samples were then removed and vertically immersed in simulated formation water to a depth of 10 mm to simulate a water-locking process. After 2 hours, the core samples were removed and placed back into the holder, with the end immersed in formation water near the outlet of the holder. The permeability of the core samples after water-locking was measured, and the permeability of samples S1 to S11 (referred to as the second permeability) was measured and is shown in Table 1.

[0055] Eleven core samples were simulated for dewatering using the dewatering agents described in Examples 1-3 and Comparative Examples 1-8, respectively. The dewatering agents used for cores S1-S11 are shown in Table 1. The dewatering method was as follows: for cores S1-S10, 0.3 PV of dewatering agent was injected in reverse through the outlet of the clamp; for core S11, 0.3 PV of N2 (gaseous) was injected in reverse through the outlet of the clamp. After injection, the samples were allowed to stand for 1 hour. Then, the outlet was opened, and forward N2 displacement was initiated. The permeability of each core after dewatering (referred to as the third permeability) was measured, and the results are shown in Table 1.

[0056] Table 1. Results of Effect Evaluation

[0057]

[0058] Experimental results show that the water-lock-removing agents of Examples 1-3 of the present invention can significantly improve the water-lock-removing effect compared with the water-lock-removing agents of Comparative Examples 1-8 or other methods.

Claims

1. A water-locking agent for relieving water-lock damage in tight reservoirs, characterized in that: It mainly consists of supercritical CO2 and entrainers dispersed in supercritical CO2, including polyethoxykyne diol surfactants, alcohol compounds, reservoir drying agents and corrosion inhibitors.

2. The water-locking agent for relieving water-lock damage in tight reservoirs according to claim 1, characterized in that: The concentration of the polyethoxyacetylenic diol surfactant in the water-locking agent is 0.01-0.03 mol / L.

3. The water-locking agent for relieving water-lock damage in tight reservoirs according to claim 1, characterized in that: The corrosion inhibitor is an alcohol amine corrosion inhibitor.

4. The water-locking agent for relieving water-lock damage in tight reservoirs according to claim 1 or 3, characterized in that: The concentration of the corrosion inhibitor in the water-locking agent is (7-10)×10. -4 mol / L.

5. The water-locking agent for relieving water-lock damage in tight reservoirs according to claim 1, characterized in that: The concentration of the alcohol compound in the water-locking agent is 0.1-0.15 mol / L.

6. The water-locking agent for relieving water-lock damage in tight reservoirs according to claim 1, characterized in that: The reservoir drying agent is an ionic carbide.

7. The water-locking agent for relieving water-lock damage in tight reservoirs according to claim 1 or 6, characterized in that: The concentration of the reservoir drying agent in the water-locking agent is (0.8-1.5)×10⁻⁶. -8 mol / L.

8. A method for relieving water-lock damage in tight reservoirs, characterized in that: The process includes the following steps: after draining the liquid from the tubing, injecting supercritical CO2-corresponding gas into the tubing until the wellhead pressure is not lower than the supercritical CO2 critical pressure, then injecting the water-locking agent as described in any one of claims 1 to 7 into the tubing to relieve water-lock damage in tight reservoirs, followed by injecting supercritical CO2-corresponding gas into the tubing to push the water-locking agent into the bottom layer, and then shutting the well; after shutting the well, opening the well and inducing a flow to drain the fluid.

Images