Nitrogen foam sand fracturing method

Abstract

The invention belongs to the technical field of fracturing, and discloses a nitrogen foam sand fracturing method which comprises the following steps: establishing a fracturing simulation model, and presetting fracturing parameters to simulate a fracturing crack; injecting a mixture of foam liquid and liquid nitrogen into the annulus according to the fracturing parameters to establish a crack, and enabling the foam liquid to form a foam zone at the front end of the crack; a mixture of foam liquid, liquid nitrogen and a proppant with the first sand concentration is injected into the annulus; injecting a mixture of gel, liquid nitrogen and a proppant with a second sand concentration into the annulus, wherein the second sand concentration is greater than the first sand concentration; injecting a sol solution into the annulus to squeeze the residual propping agent in the annulus into the crack; fracturing is stopped, and pressure monitoring is kept; and testing the flowback fluid. The foam liquid forms a foam belt at the front end of the crack, the fracturing liquid filtration loss is reduced, the fracturing liquid efficiency is improved, the foam belt exists at the front end of the crack, the crack can be guided in the forward direction, traction of a low-pressure area to the crack is weakened, and the possibility of crack deflection is reduced.

Description

Technical Field

[0001] This invention relates to the field of fracturing technology, and in particular to a nitrogen foam fracturing method with sand. Background Technology

[0002] With advancements in fracturing concepts and technologies, tight sandstone gas reservoirs characterized by "low pressure, low permeability, and low abundance" have achieved effective development and yielded significant economic benefits. However, as block development enters its later stages, the large-scale production from older wells created depressurization zones, posing a severe challenge to the development and production of new wells. This includes issues such as disrupting the normal fracture formation in adjacent wells, causing fractures to deflect towards low-pressure areas, thus affecting the production of adjacent wells and even leading to production shutdowns.

[0003] Currently, both domestically and internationally, the main approach for fracturing low-pressure tight sandstone gas reservoirs is passive anti-fracturing measures that control scale and discharge rate. This results in insufficient fracturing stimulation and a certain number of fracturing wells still communicating with adjacent wells, directly impacting production establishment. Therefore, how to reduce or even eliminate the impact of low pressure on fracturing and improve fracturing stimulation effectiveness is a pressing issue that needs to be addressed in the fracturing stimulation of low-pressure tight sandstone gas reservoirs. Summary of the Invention

[0004] The purpose of this invention is to provide a nitrogen foam fracturing method that reduces the impact of low-pressure areas on fracturing and improves fracturing efficiency.

[0005] To achieve this objective, the present invention adopts the following technical solution:

[0006] The nitrogen foam fracturing method includes the following steps:

[0007] S1. Establish a fracturing simulation model, simulate fracturing fractures according to preset fracturing parameters, and correct the fracturing parameters;

[0008] S2, Pre-fracturing stage: According to the fracturing parameters, a mixture of foam liquid and liquid nitrogen is injected into the annulus to establish a fracture, so that the foam liquid forms a foam band at the front end of the fracture;

[0009] S3, First stage of sand-carrying fluid: Injecting a mixture of foam liquid, liquid nitrogen and proppant of the first sand concentration into the annulus, so that the proppant enters the crack;

[0010] S4, Second stage of sand-carrying fluid: Inject a mixture of gel, liquid nitrogen and proppant of the second sand concentration into the annulus, so that the proppant enters the crack, and the second sand concentration is greater than the first sand concentration;

[0011] S5, Displacement stage: Inject sol solution into the annulus to squeeze the remaining proppant in the annulus into the crack;

[0012] S6. Stop fracturing and maintain pressure monitoring;

[0013] S7. Perform backflow test.

[0014] In some embodiments, in S1, the fracturing parameters include at least the pumping procedure parameters, the foam liquid dosage parameters, the liquid nitrogen dosage parameters, the sand addition amount, and the sand ratio; when simulating the fracturing fracture, it is necessary to simulate the fracture length, fracture width, fracture height, and conductivity.

[0015] In some embodiments, the concentration of the first sand is in the range of 240 kg / m³. 3 -440kg / m 3 The second sand concentration range is 460 kg / m³. 3 -520kg / m 3 .

[0016] In some embodiments, the displacement of the foaming liquid is 1.0 cubic meters per minute, the displacement of the foaming liquid is 3.5 cubic meters per minute, and the displacement of the liquid nitrogen is 1.0 cubic meters per minute.

[0017] In some embodiments, the foaming liquid comprises 0.35%-0.40% guar gum, 0.1%-0.3% anti-swelling agent, 0.1% bactericide, 0.3% drainage aid, 0.6%-0.8% foaming agent, 0.1% temperature stabilizer, 0.3%-0.5% pH adjuster, 0.35%-0.45% crosslinking agent, and water;

[0018] The gel comprises 0.40%-0.50% guar gum, 0.1%-0.3% anti-swelling agent, 0.1% bactericide, 0.3% drainage aid, 0.2%-0.3% foaming agent, 0.1% temperature stabilizer, 0.3%-0.5% pH adjuster, 0.35%-0.45% crosslinking agent, and water;

[0019] The sol-gel includes 0.40%-0.50% guar gum, 0.1%-0.3% anti-swelling agent, 0.1% bactericide, 0.3% drainage aid, 0.2%-0.3% foaming agent, 0.1% temperature stabilizer, and water.

[0020] In some embodiments, the monitoring time in S6 is 10 min to 30 min.

[0021] In some embodiments, in step S7, the blowout rate is controlled by adjusting the nozzle according to the different pressures at the wellhead.

[0022] In some embodiments, the pressure at the wellhead is P. When P ≥ 20 MPa, a 4 mm nozzle is used; when 20 MPa > P ≥ 15 MPa, a 4 mm-6 mm nozzle is used; when 15 MPa > P ≥ 10 MPa, a 6 mm-8 mm nozzle is used; when 10 MPa > P ≥ 5 MPa, an 8 mm-10 mm nozzle is used; when 5 MPa > P ≥ 2 MPa, a 10 mm-12 mm nozzle is used; and when P < 2 MPa, the nozzle is not used.

[0023] In some embodiments, the proppant is at least one type of ceramic particle with a mesh size of 20-40, 30-50, or 40-70 mesh.

[0024] In some embodiments, S7 further includes the step of optimizing the fracturing parameters based on the results of the reverse runoff test.

[0025] The beneficial effects of this invention are:

[0026] By creating a foam band at the fracture tip using foamed fluid and liquid nitrogen, fracturing fluid loss can be reduced, fracturing fluid efficiency can be improved, and the presence of the foam band at the fracture tip can positively guide the fracture, reducing the pull of the low-pressure area on the fracture and allowing it to extend towards the reservoir, thus reducing the possibility of fracture deflection. Furthermore, the expansion properties of liquid nitrogen can also increase fracturing efficiency. Attached Figure Description

[0027] Figure 1 This is a flowchart of the nitrogen foam fracturing method of the present invention. Detailed Implementation

[0028] The present invention will now be described in further detail with reference to the accompanying drawings and embodiments. It should be understood that the specific embodiments described herein are merely illustrative of the invention and not intended to limit it. Furthermore, it should be noted that, for ease of description, the accompanying drawings show only the parts relevant to the present invention, and not all of the structures.

[0029] In the description of this invention, unless otherwise explicitly specified and limited, the terms "connected," "linked," and "fixed" should be interpreted broadly. For example, they can refer to a fixed connection, a detachable connection, or an integral part; they can refer to a mechanical connection or an electrical connection; they can refer to a direct connection or an indirect connection through an intermediate medium; they can refer to the internal communication of two components or the interaction between two components. Those skilled in the art can understand the specific meaning of the above terms in this invention based on the specific circumstances.

[0030] In this invention, unless otherwise explicitly specified and limited, "above" or "below" the second feature can include direct contact between the first and second features, or contact between the first and second features through another feature between them. Furthermore, "above," "over," and "on top" of the second feature includes the first feature directly above or diagonally above the second feature, or simply indicates that the first feature is at a higher horizontal level than the second feature. "Below," "below," and "under" the second feature includes the first feature directly below or diagonally below the second feature, or simply indicates that the first feature is at a lower horizontal level than the second feature.

[0031] In the description of this embodiment, the terms "upper," "lower," "right," etc., refer to the orientation or positional relationship shown in the accompanying drawings. They are used only for ease of description and simplification of operation, and do not indicate or imply that the device or element referred to must have a specific orientation, or be constructed and operated in a specific orientation. Therefore, they should not be construed as limitations on the present invention. In addition, the terms "first" and "second" are used only for distinction in description and have no special meaning.

[0032] This application provides a nitrogen foam fracturing method with sand, which includes the following steps:

[0033] S1. Establish a fracturing simulation model, simulate fracturing fractures based on preset fracturing parameters, and correct the fracturing parameters. It is understood that before establishing the fracturing simulation model, data preparation can be carried out, including but not limited to geological data, drilling data, well logging results, and well logging data of the fracturing well. This can also include geological data, fracturing operation data, and production data of adjacent wells in the same area. The fracturing simulation model is constructed using the above data to simulate the fracturing parameters of the fracturing well, thereby simulating the fracturing fracture data. For example, the fracturing simulation model can be constructed using Fracpro pt.

[0034] It should be noted that the preset fracturing parameters mentioned above include at least the pumping procedure parameters, foam liquid dosage parameters, liquid nitrogen dosage parameters, sand addition amount, sand ratio, and other key data parameters. Adjusting these parameters can simulate the fracturing process and simulate the fracture length, width, height, and conductivity of the fracture, providing a theoretical basis for fracturing.

[0035] S2. A mixture of foamed fluid and liquid nitrogen is injected into the annulus to create fractures (pre-fracturing stage) according to fracturing parameters, forming a foam band at the fracture tip. This fracturing process, using both foamed fluid and liquid nitrogen, reduces fracturing fluid loss and improves fracturing fluid efficiency. The presence of the foam band at the fracture tip guides the fracture in a positive direction, reducing the pull of the low-pressure area on the fracture and allowing it to extend towards the reservoir, thus reducing the possibility of fracture deflection. Furthermore, the expansion properties of liquid nitrogen further enhance fracturing efficiency.

[0036] For example, in the current embodiment, the foaming liquid includes 0.35%-0.40% guar gum, 0.1%-0.3% anti-swelling agent, 0.1% bactericide, 0.3% drainage aid, 0.6%-0.8% foaming agent, 0.1% temperature stabilizer, 0.3%-0.5% pH adjuster, 0.35%-0.45% crosslinking agent, and water. Examples of suitable agents include HPG-1 type primary guar gum (modified guar gum), JK05 type anti-swelling agent (organic cationic polymer), JKSJ01 type bactericide (Kasone-based compound), XH-P type drainage aid (organic fluorine surfactant), JK10 type foaming agent (surfactant), JZW01 type temperature stabilizer (thiosulfate solution), JK07 type pH adjuster (organic antioxidant), and JK02 type crosslinking agent (organic titanium-zirconium compound).

[0037] S3. Inject a mixture of foam liquid, liquid nitrogen, and proppant at a first sand concentration into the annulus, allowing the proppant to enter the fracture (first stage of proppant carrying). The mixture of foam liquid, liquid nitrogen, and proppant at a first sand concentration can further enlarge the fracture and also carry a portion of the proppant into the fracture. For example, the first sand concentration is in the range of 240 kg / m³. 3 -440kg / m 3 For example, the proppant can be at least one type of ceramsite with a mesh size of 20-40, 30-50, or 40-70. In the current embodiment, the proppant with the first sand concentration is ceramsite with a mesh size of 40-70.

[0038] S4. Inject a mixture of gel, liquid nitrogen, and proppant of a second sand concentration into the annulus to allow the proppant to enter the crack (second stage of proppant carrying liquid). The second sand concentration is greater than the first sand concentration. In the current embodiment, the proppant of the second sand concentration is selected from 40-70 mesh ceramsite and 20-40 mesh ceramsite. It should be noted that in the section where the first sand concentration and the second sand concentration are connected, the proppant of the second sand concentration is selected from 40-70 mesh ceramsite, and the amount used is 70% of the total amount of proppant of the second sand concentration; the remaining 30% is selected from 20-40 mesh ceramsite.

[0039] The gelatin comprises 0.40%-0.50% guar gum, 0.1%-0.3% anti-swelling agent, 0.1% bactericide, 0.3% drainage aid, 0.2%-0.3% foaming agent, 0.1% temperature stabilizer, 0.3%-0.5% pH adjuster, 0.35%-0.45% crosslinking agent, and water; the concentration of the second sand ranges from 460 kg / m³. 3 -520kg / m 3 The gel has a higher concentration and viscosity than the foam liquid. In steps S2 and S3, a lower viscosity foam liquid is used to form a foam band more quickly. In step S4, a more viscous gel is used, which has a better ability to carry the proppant than the foam liquid, and carries the proppant into the crack more quickly.

[0040] S5. Injecting a sol solution into the annulus to squeeze the remaining proppant in the annulus into the crack (displacement liquid stage); exemplary, the sol solution includes 0.40%-0.50% guar gum, 0.1%-0.3% anti-swelling agent, 0.1% bactericide, 0.3% drainage aid, 0.2%-0.3% foaming agent, 0.1% temperature stabilizer, and water.

[0041] The specific pumping parameter table can be used as follows:

[0042]

[0043]

[0044] S6. After the fracturing operation is completed, pressure monitoring should be maintained. For example, the monitoring time is 10-30 minutes.

[0045] S7. Conduct flowback fluid tests. During this process, adjust the nozzle to control the flowback rate based on the wellhead pressure to prevent proppant backflow. For example, let the wellhead pressure be P. If P ≥ 20 MPa, use a 4mm nozzle; if 20 MPa > P ≥ 15 MPa, use a 4mm-6mm nozzle; if 15 MPa > P ≥ 10 MPa, use a 6mm-8mm nozzle; if 10 MPa > P ≥ 5 MPa, use an 8mm-10mm nozzle; if 5 MPa > P ≥ 2 MPa, use a 10mm-12mm nozzle; if P < 2 MPa, do not use a nozzle. Furthermore, optimize fracturing parameters and the proportions of foam fluid, gel, and sol fluid based on the flowback test results to provide guidance for new well construction.

[0046] Obviously, the above embodiments of the present invention are merely examples for clearly illustrating the present invention, and are not intended to limit the implementation of the present invention. Those skilled in the art will be able to make various obvious changes, readjustments, and substitutions without departing from the scope of protection of the present invention. It is neither necessary nor possible to exhaustively describe all embodiments here. Any modifications, equivalent substitutions, and improvements made within the spirit and principles of the present invention should be included within the scope of protection of the claims of the present invention.

Claims

1. A nitrogen foam fracturing method with added sand, characterized in that, Includes the following steps: S1. Establish a fracturing simulation model, simulate fracturing fractures according to preset fracturing parameters, and correct the fracturing parameters; S2, Pre-fracturing stage: According to the fracturing parameters, a mixture of foam liquid and liquid nitrogen is injected into the annulus to establish a fracture, so that the foam liquid forms a foam band at the front end of the fracture; S3, First stage of sand-carrying fluid: Injecting a mixture of foam liquid, liquid nitrogen and proppant of the first sand concentration into the annulus, so that the proppant enters the crack; S4, Second stage of sand-carrying fluid: Inject a mixture of gel, liquid nitrogen and proppant at a second sand concentration into the annulus, so that the proppant enters the crack, and the second sand concentration is greater than the first sand concentration; S5, Displacement stage: Inject sol solution into the annulus to squeeze the remaining proppant in the annulus into the crack; S6. Stop fracturing and maintain pressure monitoring; S7. Perform backflow test.

2. The nitrogen foam fracturing method according to claim 1, characterized in that, In S1, the fracturing parameters include at least the pumping procedure parameters, the foam liquid dosage parameters, the liquid nitrogen dosage parameters, the sand addition amount, and the sand ratio; when simulating the fracturing fracture, it is necessary to simulate the fracture length, fracture width, fracture height, and conductivity.

3. The nitrogen foam fracturing method according to claim 1, characterized in that, The first sand concentration ranges from 240 kg / m³. 3 -440kg / m 3 The second sand concentration range is 460 kg / m³. 3 -520kg / m 3 .

4. The nitrogen foam fracturing method according to claim 1, characterized in that, The displacement of the foam liquid is 1.0 cubic meters per minute, the displacement of the foam liquid is 3.5 cubic meters per minute, and the displacement of the liquid nitrogen is 1.0 cubic meters per minute.

5. The nitrogen foam fracturing method according to claim 1, characterized in that, The foaming liquid comprises 0.35%-0.40% guar gum, 0.1%-0.3% anti-swelling agent, 0.1% bactericide, 0.3% drainage aid, 0.6%-0.8% foaming agent, 0.1% temperature stabilizer, 0.3%-0.5% pH adjuster, 0.35%-0.45% crosslinking agent, and water; The gel comprises 0.40%-0.50% guar gum, 0.1%-0.3% anti-swelling agent, 0.1% bactericide, 0.3% drainage aid, 0.2%-0.3% foaming agent, 0.1% temperature stabilizer, 0.3%-0.5% pH adjuster, 0.35%-0.45% crosslinking agent, and water; The sol-gel includes 0.40%-0.50% guar gum, 0.1%-0.3% anti-swelling agent, 0.1% bactericide, 0.3% drainage aid, 0.2%-0.3% foaming agent, 0.1% temperature stabilizer, and water.

6. The nitrogen foam fracturing method according to claim 1, characterized in that, The monitoring time in S6 is 10 min to 30 min.

7. The nitrogen foam fracturing method according to claim 1, characterized in that, In S7, the release rate is controlled by adjusting the nozzle according to the different pressures at the wellhead.

8. The nitrogen foam fracturing method according to claim 7, characterized in that, a The wellhead pressure is P. When P ≥ 20 MPa, a 4 mm nozzle is used; when 20 MPa > P ≥ 15 MPa, a 4 mm-6 mm nozzle is used; when 15 MPa > P ≥ 10 MPa, a 6 mm-8 mm nozzle is used; when 10 MPa > P ≥ 5 MPa, an 8 mm-10 mm nozzle is used; when 5 MPa > P ≥ 2 MPa, a 10 mm-12 mm nozzle is used; when P < 2 MPa, the nozzle is not used.

9. The nitrogen foam fracturing method according to claim 1, characterized in that, The proppant is at least one type of ceramic aggregate with a mesh size of 20-40, 30-50, or 40-70.

10. The nitrogen foam fracturing method according to claim 1, characterized in that, S7 also includes the following step: optimizing the fracturing parameters based on the results of the reverse runoff test.

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