Sand prevention method for establishing high flow guide channel of loose sandstone reservoir

Abstract

The invention relates to a sand prevention method for establishing a high diversion channel of a loose sandstone reservoir, and relates to the field of downhole operation technology, and the sand prevention method comprises the following steps: S10, reservoir pretreatment: pretreating an oil well to reduce the skin coefficient of a near wellbore zone; s20, sand prevention design and parameter optimization are carried out, wherein sand prevention design is carried out, and parameters are optimized; and S30, sand prevention well management optimization, wherein optimization management is conducted on the sand prevention well, and a corresponding shaft sand prevention mode is selected. The method has the advantages that the contradiction that the near wellbore area and the wellbore are easily blocked after sand prevention of the oil reservoir is solved, and the long-term high and stable yield of the oil reservoir is achieved.

Description

TECHNICAL FIELD

[0001] The present application relates to the field of downhole operation process technology, in particular to a sand control method for establishing high flow channel of loose sandstone reservoir. BACKGROUND

[0002] The high argillaceous, fine and thin sandstone and other loose sandstone reservoirs are widely distributed in North China Oilfield. The reservoirs mainly have the following characteristics: low rock cementation strength, easy sand production, low formation particle diameter, mainly argillaceous and fine and thin sand, and the argillaceous particles are mainly swelling clay. Therefore, in the development and production and later oil well operation process, the mixing of external fluid can easily cause the hydration and swelling of the clay, block the formation pore channel, and the formation particles can be retained in the near wellbore zone, sand control packing layer and screen pipe, causing serious blockage and reducing the production effect of the oil well.

[0003] For this type of reservoir, the main measure is to use oil well squeeze packing sand control. The squeeze packing steps mainly include: first, squeeze the preflush (pretreatment fluid), then according to the stepwise injection program, gradually increase the sand ratio from low to high, establish a sand barrier in the near wellbore zone to block the migration of formation sand to the wellbore, and protect the screen pipe to reduce the erosion of the formation sand to the screen pipe. However, after the squeeze packing sand control, the liquid production of the oil well often decreases rapidly. It is analyzed that the sand barrier established can block the formation sand, but the argillaceous and fine and thin sand cannot be effectively discharged with the liquid flow, and is retained in the near wellbore zone, the packing layer and the surface of the screen pipe to form blockage, resulting in the decrease of the liquid production of the oil and gas well. SUMMARY

[0004] In order to solve the contradiction that the near wellbore zone and the wellbore are easily blocked after the sand control of this type of reservoir, and realize the long-term high and stable production of this type of reservoir, the present application provides a sand control method for establishing high flow channel of loose sandstone reservoir.

[0005] The sand control method for establishing high flow channel of loose sandstone reservoir provided by the present application adopts the following technical scheme:

[0006] A sand control method for establishing high flow channel of loose sandstone reservoir, comprising the following steps:

[0007] S10: Reservoir pretreatment: pretreating the oil well to reduce the skin factor of the near wellbore zone;

[0008] S20: Sand control design and parameter optimization: sand control design and parameter optimization;

[0009] S30: Optimization of sand control well management: optimization of sand control well management and selection of corresponding wellbore sand control mode.

[0010] Optionally, the S10 comprises:

[0011] S11: Physical jetting plug removal is performed on the formation, and the pump injection displacement is optimized according to the oil layer thickness;

[0012] S12: Reverse circulation pipeline is reversed, and negative pressure flowback is performed.

[0013] Optionally, in the S11, compatibility experiments are performed on the well entry fluid entering the reservoir.

[0014] Optionally, in the S11, if the reservoir has no acid sensitivity, the plug removal fluid is deep plug removal organic retarding acid, and acid etching experiments are carried out on the ground to optimize the acid system, so as to improve the plug removal effect.

[0015] Optionally, the S20 comprises:

[0016] S21: sanding intensity optimization design;

[0017] S22: optimization of construction displacement;

[0018] S23: optimization of filling mode;

[0019] S24: optimization of filling particle size;

[0020] S25: optimization of filling gravel;

[0021] S26: optimization of sand ratio;

[0022] S27: optimization of sand-carrying fluid;

[0023] S28: screen pipe optimization design.

[0024] Optionally, in the S23, a combination of front-end small particle size gravel and tail-end large particle size gravel is adopted, and the volume ratio of the combination is 1:1.

[0025] Optionally, in the S24, if d50≤0.1mm, the optimization calculation formula is:

[0026] D50=(3-4)d50;

[0027] wherein D50 is the filling gravel particle size; d50 is the median value of the reservoir rock particle size;

[0028] If d50≥0.1mm, the optimization calculation formula is: D50=(5-6)d50.

[0029] Optionally, the S27 comprises:

[0030] S271: the viscosity of the sand-carrying fluid satisfies 30-120mPa·s (30℃), the sand suspension capacity (10% sand ratio) is ≥2min, there is no flocculation, no precipitation, and the organic chlorine content is 0%;

[0031] S272: The amount of sand-carrying fluid is designed according to the average sand ratio of 20%-22%;

[0032] S273: When the amount of sand-carrying fluid is more than 120m3, the emulsion type sand-carrying fluid is used; when the amount of sand-carrying fluid is less than 120m3, the guanidium gel type sand-carrying fluid is used.

[0033] Optionally, the S28 comprises the following steps:

[0034] S281: The screen pipe seam width is 2 / 3 of the minimum value of the range of the sand particle size.

[0035] S282: In the 7in casing, the 31 / 2in screen pipe is selected; in the 51 / 2in casing, the 27 / 8in screen pipe is selected; in the 41 / 2in casing, the 23 / 8in screen pipe is selected.

[0036] Optionally, the S30 comprises the following steps:

[0037] S31: The film-coated sand seals the well: the production pressure difference is less than the maximum compression resistance of the film-coated sand.

[0038] S32: The mechanical sand control well: when the production pressure difference is greater than the maximum compression resistance of the film-coated sand, the wellbore circulation filling is performed.

[0039] In summary, the present application comprises at least one of the following beneficial technical effects:

[0040] 1. The method established by the present application can effectively solve the problem of rapid decrease of post-sand control fluid volume and short effective period of sand control for high mud content, fine sandstone reservoirs, such as fracturing and packing sand control, and realize the goal of extending the high-yield and stable-yield period of high-mud-content, fine sandstone and other unconsolidated sandstone reservoirs. BRIEF DESCRIPTION OF DRAWINGS

[0041] Figure 1 FIG. 1 is a whole process schematic diagram of a sand control method for establishing a high-flow channel of a unconsolidated sandstone reservoir in an embodiment of the present application.

[0042] Figure 2 FIG. 2 is a process schematic diagram of reservoir pretreatment of a sand control method for establishing a high-flow channel of a unconsolidated sandstone reservoir in an embodiment of the present application.

[0043] Figure 3 FIG. 3 is a process schematic diagram of sand control design and parameter optimization of a sand control method for establishing a high-flow channel of a unconsolidated sandstone reservoir in an embodiment of the present application.

[0044] Figure 4 FIG. 4 is a process schematic diagram of sand control well management optimization of a sand control method for establishing a high-flow channel of a unconsolidated sandstone reservoir in an embodiment of the present application. DETAILED DESCRIPTION

[0045] In order to enable a more clear understanding of the above-mentioned objects, features and advantages of the present application, the present application will be further described in detail below with reference to the accompanying drawings and specific embodiments. It should be noted that the embodiments of the present application and the features in the embodiments can be combined with each other without conflict.

[0046] In the following description, a large number of specific details are set forth in order to facilitate a thorough understanding of the present application, however, the present application can also be implemented in other manners different from those described herein, and therefore, the protective scope of the present application is not limited to the specific embodiments disclosed below.

[0047] The following will be described in detail with reference to the accompanying drawings Figures 1-4 The present application will be further described in detail.

[0048] The embodiments of the present application disclose a sand control method for establishing a high-flow channel of a loose sandstone reservoir. Referring to Figure 1 , Figure 2 A sand control method for establishing a high-flow channel of a loose sandstone reservoir comprises

[0049] S10: Reservoir pretreatment: pretreatment is performed on the oil well to reduce the skin factor of the near wellbore zone; wherein S10 comprises:

[0050] S11: To restore the permeability of the near wellbore zone, the formation is first subjected to physical jetting to remove blockages, and a jetting to remove blockages and negative pressure flowback integrated tool is used to achieve jetting to remove blockages and negative pressure flowback without moving the pipe string. During construction, the positive circulation connecting pipeline is connected, jetting to remove blockages is performed at a flow rate of 1000 L / min, and the reservoir compatibility of the downhole fluid is ensured. When the construction pressure drops by about 2-3 MPa, the jetting to remove blockages is stopped. If the reservoir has no acid sensitivity, the blocking removal fluid is preferably an organic retarded acid for deep blocking removal, and acid etching experiments are carried out on the ground to optimize the acid system, so as to improve the blocking removal effect.

[0051] S12: Reverse circulation pipeline, negative pressure flowback is performed until the outlet and the inlet are consistent and there are no obvious particles.

[0052] Referring to Figure 1 , Figure 3 S20: Sand control design and parameter optimization: sand control design is performed, and parameters are optimized; wherein S20 comprises:

[0053] S21: Optimization design of sand filling intensity: based on Darcy's seepage theory, the reservoir is set as medium-low permeability, the transformation radius and the yield increase rate are simulated, the simulation results show that when the transformation radius is greater than 3.5 m, the yield increase rate slows down rapidly, the filling radius is optimized to 3-4 m, and the sand filling intensity is optimized to 4 m 3 / m-5 m 3 / m according to the filling radius and the sand filling intensity corresponding curve.

[0054] S22: Optimizing the construction displacement: According to the logging data, the reservoir stress, fracture pressure, Poisson's ratio, and Young's modulus are calculated, and the construction displacement is optimized by simulation software to ensure that the packed sand can enter the formation.

[0055] S23: Preferably filling method: According to the results of physical displacement simulation experiments, a combination of small particle size gravel at the front end and large particle size gravel at the tail end is adopted, with a volume ratio of 1:1. Compared with simply adopting 0.3mm-0.6mm and 0.425mm-0.850mm gravel, the final permeability is increased by more than 25%. According to the field situation, the V small particle size:V large particle size range is (1-1.5).

[0056] S24: Preferably filling particle size: Reservoir particle size median sieve analysis experiments are carried out to determine the reservoir rock particle size median d 50 . According to simulation experiments, if d 50 ≤0.1mm, the packing gravel particle size adopts D 50 =(3-4)d 50 , D 50 =(5-6)d 50 calculated by the Bisocei formula, the final permeability retention rate is increased by 28%, so the optimized calculation formula is D 50 =(3-4)d 50 ; if d 50 ≥0.1mm, D 50 =(5-6)d 50 is preferred to improve the particle passability and reduce the formation of sand mixing.

[0057] According to the simulation results, the fine particle size (0.4mm-0.5mm, 0.5mm-0.6mm) has a final permeability retention rate that is 19% higher than that of the conventional particle size (0.425mm-0.850mm, 0.6mm-1.18mm) in reservoirs with shale and fine sandstone content >10%.

[0058] Therefore, when the shale and fine sandstone content is >10%, the front-end packing gravel particle size is preferably 0.4mm-0.5mm, and the tail-end packing gravel particle size is 0.5mm-0.6mm; when the shale and fine sandstone content is ≤10%, the front-end gravel is preferably 0.425mm-0.850mm, and the tail-end is preferably 0.6mm-0.118mm.

[0059] S25: Preferably packing gravel: To improve the migration of reservoir particles, the membrane-coated sand sealing method is adopted to improve the passability of reservoir particles, so the front-end packing gravel is quartz sand, and the tail-end adopts resin-coated sand sealing. If the oil well is considered for liquid lifting or thermal recovery development in the later stage, the membrane-coated sand can be replaced with inorganic gel particles sand to improve the sand barrier strength and prolong the effective period of sand control.

[0060] S26: sand ratio optimization: to ensure the effect of reservoir reconstruction, a high-strength and high-conductivity channel is established in the near-wellbore zone, and the sand ratio is optimized to 5%-60%.

[0061] S27: preferred sand-carrying fluid: including the following steps:

[0062] S271: preferred sand-carrying fluid, the viscosity of the sand-carrying fluid meets 30-120 mPa·s (30°C), the sand suspension capacity (10% sand ratio) is ≥2 min, there is no flocculation, no precipitation, and the organic chlorine content is 0%.

[0063] S272: the amount of sand-carrying fluid is designed according to the average sand ratio of 20%-22%, and the field loss is considered during design.

[0064] S273: the amount of sand-carrying fluid is more than 120 m 3 , it is recommended to use emulsion type sand-carrying fluid for convenient field control of the amount; less than 120 m 3 , it is recommended to use guanidino gum type sand-carrying fluid to reduce operation cost.

[0065] S28: screen pipe optimization design: including the following steps:

[0066] S281: the preferred screen pipe slot width is 2 / 3 of the minimum value of the filled sand particle size range.

[0067] S282: in a 7in casing, a 31 / 2in size screen pipe is preferred; in a 51 / 2in casing, a 27 / 8in size screen pipe is preferred; in a 41 / 2in casing, a 23 / 8in size screen pipe is preferred.

[0068] Referring to Figure 1 , Figure 4 , S30: sand control well management optimization: optimizing the management of sand control wells and selecting the corresponding wellbore sand control mode. Including the following steps:

[0069] S31: film-coated sand sealed well: according to the specification of the film-coated sand used, the production system is formulated to ensure that the production pressure difference is less than the maximum compression resistance of the film-coated sand.

[0070] S32: mechanical sand control well: when the production pressure difference is greater than the maximum compression resistance of the film-coated sand, wellbore cyclic packing is carried out to achieve the purpose of extending the effective period of sand control.

[0071] In some embodiments: S10: reservoir rock sample screening:

[0072] The well is an old well, and the formation sand in the target layer is flushed out for laser intensity analyzer analysis. The well is d 50 = 0.112, and the shale content is 18.4%.

[0073] Oil well deblocking and flowback pretreatment:

[0074] The unblocking and flowback tubing string was lowered into the oil layer, and the well was subjected to jet unblocking and negative pressure flowback pretreatment. The wellbore has a 7-inch casing, and high-pressure water jet unblocking was performed using a positive circulation method. The oil layer depth is 1586.0m-1596.0m, and the designed surface pump injection rate is 1.5m³ / h. 3 After jetting at a rate of / min for 1 hour, observe the pump injection pressure. Then reverse the circulation line and perform negative pressure unblocking until the outlet and inlet are consistent and there are no obvious particles. Use 5% anti-swelling agent throughout the process.

[0075] S20: Sand Control Design and Parameter Optimization

[0076] (1) Optimize the design of the backfill sand specifications, adopting D... 50 =(5-6)d 50 Based on the formula calculation, 0.425-0.850mm quartz sand and 0.6-1.18mm ceramsite are selected.

[0077] (2) Design of backfill sand usage: Based on the oil layer thickness, the sand concentration is designed to be 5 m3 / m. Considering on-site losses, the total sand usage is 52 m3. This includes 32 m3 of quartz sand and 20 m3 of ceramsite.

[0078] (3) The preferred emulsion-type sand-carrying fluid was selected, and the designed sand-carrying fluid dosage was optimized to 270 m3 based on the designed sand volume. The construction discharge rate was optimized to 3.5 m3 / min based on the formation fracturing.

[0079] S30: Optimization of Sand Control Well Management

[0080] (1) The well is designed to produce 26.2 t / d of liquid per day with a production pressure differential of 7 MPa. Therefore, circulating filling is adopted and mechanical sand control is carried out inside the wellbore.

[0081] (2) The well adopts the cold extraction development method, so the screen pipe adopts the slotted screen pipe to reduce the chance of screen pipe blockage.

[0082] In some other embodiments, S10: Sieving of reservoir rock samples

[0083] This is an old well. Laser intensity analysis was performed on the formation sand ejected from the target formation. This well is a d-well. 50 =0.098mm, clay content 15.2%.

[0084] Oil well unblocking and backflow pretreatment

[0085] The unblocking and flowback tubing string was lowered into the oil layer, and the well was subjected to jet unblocking and negative pressure flowback pretreatment. The wellbore has a 7-inch casing, and high-pressure water jet unblocking was performed using a positive circulation method. The oil layer depth is 1033.0m-1035.2m, and the designed surface pump injection rate is 1.0m³ / h. 3After jetting at a rate of / min for 1 hour, observe the pump injection pressure. Then reverse the circulation line and perform negative pressure unblocking until the outlet and inlet are consistent and there are no obvious particles. Use 5% anti-swelling agent throughout the process.

[0086] S20: Sand Control Design and Parameter Optimization

[0087] (1) Optimize the design of the backfill sand specifications, adopting D... 50 =(3-4)d 50 Based on the formula calculation, 0.4-0.5mm quartz sand and 0.5-0.6mm resin-coated sand are selected.

[0088] (2) Design of backfill sand dosage: Based on the oil layer thickness, the sand concentration is designed to be 5.0m. 3 / m, considering on-site losses, the total sand volume designed is 12m³. 3 .

[0089] (3) Prefer emulsion-type sand-carrying fluid, and optimize the sand-carrying fluid dosage (80m³) according to the designed sand volume. 3 Based on the formation fracturing strategy, the optimized discharge rate is 2.5m³. 3 / min.

[0090] S30: Optimization of Sand Control Well Management

[0091] The well is designed to produce 13.8 tons of fluid per day at a production pressure differential of 4 MPa. It will be put into operation without a mechanical tubing string inside the wellbore, and the production pressure differential will be controlled to remain below 6 MPa during subsequent production.

[0092] In some other embodiments, S10: Sieving of reservoir rock samples

[0093] This is an old well. Laser intensity analysis was performed on the formation sand ejected from the target formation. This well is a d-well. 50 =0.108, clay content 13.9%.

[0094] Oil well unblocking and backflow pretreatment

[0095] The unblocking and flowback tubing string was lowered into the oil layer, and the well was subjected to jet unblocking and negative pressure flowback pretreatment. The wellbore has a 7-inch casing, and high-pressure water jet unblocking was performed using a positive circulation method. The oil layer depth is 1329.1m-1333.4m, and the designed surface pump injection rate is 1.5m³ / h. 3 After jetting at a rate of / min for 1 hour, observe the pump injection pressure. Then reverse the circulation line and perform negative pressure unblocking until the outlet and inlet are consistent and there are no obvious particles. Use 5% anti-swelling agent throughout the process.

[0096] S20: Sand Control Design and Parameter Optimization

[0097] (1) Optimize the design of the backfill sand specifications, adopting D...50 =(5-6)d 50 Based on the formula calculation, 0.425-0.850mm quartz sand and 0.6-1.18mm ceramsite are selected.

[0098] (2) Design of backfill sand dosage: Based on the oil layer thickness, the sand concentration is designed to be 5m. 3 / m, considering on-site losses, the total designed sand volume is 21.5m. 3 The quartz sand is 13m³. 3 8.5m of expanded clay aggregate 3 .

[0099] (3) Guarantee-based sand-carrying fluid is preferred, and the sand-carrying fluid dosage is optimized to 120m³ based on the designed sand volume. 3 Based on the formation fracturing strategy, the optimized discharge rate is 2.5m³. 3 / min.

[0100] Step 4: Optimization of Sand Control Well Management

[0101] (1) The well has a production schedule of 41.8 t / d of liquid per day and a production pressure differential of 7 MPa. Therefore, circulating filling is adopted and mechanical sand control is carried out in the wellbore.

[0102] (2) The well adopts cold production development method, but the daily fluid production is high. Therefore, the screen pipe adopts wire-wound screen pipe to ensure the passage of particles and improve the strength of the screen pipe.

[0103] In this invention, the term "multiple" refers to at least two or more, unless otherwise explicitly defined. The terms "install," "connect," "link," and "fix" should be interpreted broadly. For example, "connect" can be a fixed connection, a detachable connection, or an integral connection; "link" can be a direct connection or an indirect connection through an intermediate medium. Those skilled in the art can understand the specific meaning of the above terms in this invention according to the specific circumstances.

[0104] In the description of this specification, the terms "one embodiment," "some embodiments," "specific embodiment," etc., refer to a specific feature, structure, material, or characteristic described in connection with that embodiment or example, which is included in at least one embodiment or example of the present invention. In this specification, the illustrative expressions of the above terms do not necessarily refer to the same embodiment or example. Furthermore, the specific features, structures, materials, or characteristics described may be combined in any suitable manner in one or more embodiments or examples.

Claims

1. A method for sand control in establishing high conductivity channels in loose sandstone reservoirs, characterized in that: It includes the following steps: S10: Reservoir pretreatment: Pretreatment of oil wells to reduce the skin coefficient in the near-wellbore zone; S20: Sand control design and parameter optimization: Conduct sand control design and optimize parameters; S30: Sand control well management optimization: Optimize the management of sand control wells and select the corresponding sand control method for the wellbore.

2. The sand control method for establishing high conductivity channels in loose sandstone reservoirs according to claim 1, characterized in that: S10 includes: S11: Physical jet unblocking of the formation, and optimization of pump injection rate based on oil layer thickness; S12: Reverse circulation pipeline for negative pressure backflow.

3. The sand control method for establishing high conductivity channels in loose sandstone reservoirs according to claim 2, characterized in that: In step S11, the well fluid entering the reservoir undergoes a compatibility test.

4. The sand control method for establishing high conductivity channels in loose sandstone reservoirs according to claim 2, characterized in that: In S11, if the reservoir is not acid-sensitive, the unblocking solution is a slow-moving organic acid for deep unblocking. Acid etching experiments are carried out on the ground to optimize the acid solution system and improve the unblocking effect.

5. The method for sand control in establishing high conductivity channels in loose sandstone reservoirs according to claim 1, characterized in that: S20 includes: S21: Sand-added strength optimization design; S22: Optimize construction flow rate; S23: Preferred filling method; S24: Preferred filling particle size; S25: Gravel is preferred for filling; S26: Optimize sand ratio; S27: Preferred sand-carrying fluid; S28: Optimized screen tube design.

6. The sand control method for establishing high conductivity channels in loose sandstone reservoirs according to claim 5, characterized in that: In S23, a combination of small-diameter gravel at the front end and large-diameter gravel at the rear end is adopted, with a volume ratio of 1:

1.

7. The method for sand control in establishing high conductivity channels in loose sandstone reservoirs according to claim 5, characterized in that: In S24, if d 50 For thicknesses ≤0.1mm, the optimized calculation formula is as follows: D 50 =(3-4)d 50 ; Where: D 50 For the filling gravel particle size; d 50 This represents the median grain size of the reservoir rock. If d 50 For thicknesses ≥0.1mm, the optimized calculation formula is: D 50 =(5-6)d 50 .

8. The method for sand control in establishing high conductivity channels in loose sandstone reservoirs according to claim 5, characterized in that: S27 includes: S271: The viscosity of the sand-carrying liquid meets the requirements of 30-120 mPa·s (30℃), the sand suspension capacity (10% sand ratio) is ≥2min, there is no flocculation or precipitation, and the organic chlorine content is 0%. S272: The sand-carrying fluid dosage is designed based on an average sand ratio of 20%-22%; S273: Sand-carrying fluid usage exceeds 120m 3 Use emulsion-type sand-carrying fluid; below 120m 3 Guar gum-type sand-carrying fluid is used.

9. The method for sand control in establishing high conductivity channels in loose sandstone reservoirs according to claim 5, characterized in that: S28 includes: S281: The width of the sieve slot is 2 / 3 of the minimum value of the filling sand particle size range; S282: In a 7-inch sleeve, select a 3 1 / 2-inch screen tube; in a 5 1 / 2-inch sleeve, select a 27 / 8-inch screen tube; in a 4 1 / 2-inch sleeve, select a 23 / 8-inch screen tube.

10. The method for sand control in establishing high conductivity channels in loose sandstone reservoirs according to claim 1, characterized in that: S30 includes: S31: Coated sand sealing well: Production pressure differential is less than the maximum compressive strength of the coated sand; S32: Mechanical sand control well: When the production pressure difference exceeds the maximum compressive strength of the coated sand, the wellbore is circulated and filled.

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