A method for reducing water and increasing oil in a fractured oil and gas well by packing a packer with particles

Abstract

The application discloses a method for filling and sealing particles in a fractured oil and gas well to reduce water and increase oil, wherein the oil and gas well comprises one or more production wells and one or more injection wells used in cooperation with the production wells, and the method comprises the following steps: injecting a filling fluid carrying the sealing particles into the wellbore and fractures of the injection well through the wellhead of the injection well until a preset filling amount of the sealing particles is reached; and putting the production well into production or normal production. The application adopts the technical scheme of filling the sealing particles from the injection well to the production well, which has the advantages of low operation cost, direct addition of the sealing particles in the water injection of the injection well, saving of the step of specially arranging a filling pump in the production well, no interference with the normal production of the production well, and further improvement of the production efficiency, and can effectively reduce the water content of the produced liquid and increase the oil production.

Description

Technical Field

[0001] This invention belongs to the field of oil and gas well development technology, and relates to a method for developing oil and gas wells in fractured oil and gas reservoirs, particularly a method for filling packers with particles to reduce water and increase oil production in fractured oil and gas reservoirs. Background Technology

[0002] Fractured oil and gas reservoirs are prevalent, accounting for approximately half of all existing producing reservoirs. These reservoirs are mostly developed using waterflooding methods, including bottom waterflooding, edge waterflooding, and injection waterflooding via injection wells. Due to the presence of fractures, water flow during waterflooding is significant, causing wells to reach water prematurely, resulting in very high water cuts and a substantial decrease in oil production. Actual production processes show that the larger the fracture distribution, the stronger the flow tendency. High-angle fractures are more likely to cause bottom water to flow into production wells. For example, in a horizontal well, despite an oil layer thickness of tens of meters, the presence of fractures resulted in a water cut as high as 50% on the day of production. Long horizontal fractures can easily lead to the flow of edge water and injected water from injection wells into production wells. For example, in one oil reservoir, the distance between an injection well and a production well was 700 meters, and water flowed from the injection well to the production well in just 7 days. The prevalence of fractures in oil and gas reservoirs is due to two main reasons: first, the tearing and shearing movements caused by geostress in the reservoir and surrounding strata result in fractures with large area scales; second, dissolution further increases the width of the fractures. The presence of dissolution fractures and channels ensures that even with overlying formation pressure, fractures possess strong conductivity.

[0003] Practice has shown that fractures in oil and gas wells exhibit various structural patterns: some fractures are fully open at the wellbore (i.e., open fractures) with a large opening; some fractures have partial contact on both sides with a very small opening; some fractures, under formation pressure, have their openings almost completely closed at the wellbore, but these fractures still have the possibility of opening under wellbore pressure (i.e., closed fractures); and some open fractures are blocked by drilling mud or coarse drilling cuttings, resulting in a closed opening.

[0004] One problem caused by fractures in oil and gas extraction is the extremely high water content of the produced fluid. This is due to two main reasons: firstly, fractures possess extremely high conductivity; for example, a 1mm wide fracture has the same conductivity as a 400-meter production section in a well with a 0.2 Darcy matrix permeability. Secondly, the oil in the fractures is quickly replaced by water after production. The high oil-to-water viscosity ratio further exacerbates water production; for example, water viscosity in oil reservoirs is typically less than 0.8 millipascals per second, while oil viscosity is usually tens of millipascals per second, resulting in a viscosity ratio of tens to hundreds. Without technical control measures, the water cut in fractured oil and gas reservoirs can reach over 90%, leading to a significant decrease in oil production. A second problem caused by fractures in oil and gas extraction is the reduced recovery rate of the reservoir matrix. The reason is that due to the presence of fractures, the pressure gradient within the fracture segment is very low, which in turn leads to a very low matrix pressure gradient around the fracture, resulting in a very low oil and gas well recovery rate; this phenomenon exists not only in fractures with openings but also in fractures without openings.

[0005] In summary, during the development of fractured oil and gas reservoirs, special technical measures must be taken to seal the fractures in the production section to control water flow and increase oil production. Existing technologies include gel sealing and chemical reagent sealing. Among these, gel sealing is the most widely used, but in practical applications, it is difficult to determine the appropriate gel strength. If the gel strength is too high, it is difficult to inject into the fractures; conversely, if the strength is too low, the gel is easily recovered during production, leading to sealing failure. Both gel and chemical reagent sealing methods can use thickeners as sealing media, but they are susceptible to degradation and failure due to harsh underground environments such as high temperatures and high salinity, with a lifespan rarely exceeding three months. WO2011 / 069339 discloses a technical solution using packer particles to prevent cross-flow in the production section of oil and gas wells, but this patent does not directly provide technical guidance on applying these packer particles to seal the fractures in the production section of oil and gas wells in fractured oil and gas reservoirs. For these reasons, the water production problem in fractured oil and gas wells remains unresolved. Summary of the Invention

[0006] The purpose of this invention is to overcome the shortcomings of the prior art and provide a method for filling and sealing wells in fractured oil and gas reservoirs with particles to reduce water and increase oil production. This method is simple to operate, has a good fracture sealing effect, a long duration, and a high input-output ratio.

[0007] To achieve the above objectives, the present invention adopts the following technical solution:

[0008] A method for filling packer particles to reduce water and increase oil production in a fractured oil and gas reservoir well includes the following steps: (a1) injecting filling fluid carrying packer particles into the wellbore and fractures through the wellhead until the formation fracture / fracture extension pressure is reached or exceeded, or until the injection volume under unit injection pressure is close to zero, or until the preset packer particle filling volume is reached; (a2) put into production.

[0009] Furthermore, in step (a2), before production begins, the following steps are also included: running flushing tubing to clean out the packer particles inside the wellbore.

[0010] Furthermore, the method for determining the formation fracture / fracture extension pressure includes the following steps: (s1) continuously injecting filling fluid into the wellbore through the wellhead, with the injection rate gradually increasing; (s2) continuously measuring the pressure inside the well until the pressure inside the well experiences a rapid drop; (s3) the highest pressure value before the rapid drop is the formation fracture / fracture extension pressure inside the well.

[0011] Furthermore, the method for determining the preset packer particle filling amount is: V≥ρ·L0; where V is the preset packer particle filling amount, L0 is the total length of the production section wellbore, and ρ is the filling density. When the oil and gas well is a horizontal well, ρ is 0.01-1.0 cubic meters per meter, and when the oil and gas well is a vertical well, ρ is 0.01-5.0 cubic meters per meter.

[0012] Furthermore, the particle size of the sealing particles is 0.05-5 mm.

[0013] Furthermore, the density of the encapsulating particles is 0.7–1.4 g / cm³ (actual density).

[0014] Furthermore, the density of the encapsulating particles is 0.9–1.08 g / cm³ (actual density).

[0015] Furthermore, the sealing particles are made of polyethylene, high-density polyethylene, polypropylene, polyvinyl chloride, or a cross-linked copolymer of styrene and divinylbenzene.

[0016] Furthermore, the sealing particles have a spherical structure.

[0017] Furthermore, the concentration of the packer particles in the filling fluid is 1-20% (by volume).

[0018] To achieve the above objectives, the present invention also employs the following technical solution:

[0019] A method for filling packer particles to reduce water and increase oil production in a fractured oil and gas reservoir well, wherein the wellbore is equipped with a screen pipe, the top of the screen pipe is equipped with a packer, and the packer is equipped with a filling channel for injecting filling fluid; the method includes the following steps: (b1) continuously injecting filling fluid carrying packer particles into the annulus and fractures through the filling channel provided on the packer; until the formation fracture / fracture extension pressure is reached or exceeded, or until the injection volume per unit injection pressure is close to zero, or until a preset packer particle filling volume is reached; (b2) reducing the filling fluid injection rate so that the filling pressure is less than the formation fracture / fracture extension pressure, and continuously injecting filling fluid carrying packer particles until the packer particles fill the annulus, or until the preset packer particle filling volume is reached; (b3) closing the filling channel and starting production.

[0020] Furthermore, the screen tube is a water control screen tube.

[0021] Furthermore, the injection rate of the filling fluid in step (b2) is less than the production fluid rate during the commissioning phase.

[0022] Furthermore, the method for determining the formation fracture / fracture extension pressure includes the following steps: (s1) continuously injecting filling fluid into the wellbore through the wellhead, with the injection rate gradually increasing; (s2) continuously measuring the pressure inside the well until the pressure inside the well experiences a rapid drop; (s3) the highest pressure value before the rapid drop is the formation fracture / fracture extension pressure.

[0023] Furthermore, the method for determining the preset packer particle filling amount is: V≥ρ·L0; where V is the preset packer particle filling amount, L0 is the total length of the production section wellbore, and ρ is the filling density. When the oil and gas well is a horizontal well, ρ is 0.01-1.0 cubic meters per meter, and when the oil and gas well is a vertical well, ρ is 0.01-5.0 cubic meters per meter.

[0024] Furthermore, the method for determining whether the packer particles have filled the annulus is as follows: when injecting the packing fluid at a constant rate, continuously measure the well pressure until the well pressure rises to the set pressure, which indicates that the packer particles have filled the annulus; or when injecting the packing fluid at a constant pressure, continuously measure the flow rate of the packing fluid until the rate drops to the set flow rate, which indicates that the packer particles have filled the annulus.

[0025] Furthermore, the sealing particles have a spherical structure with a particle size of 0.05-5 mm.

[0026] Furthermore, the density of the encapsulating particles is 0.7–1.4 g / cm³ (actual density).

[0027] Furthermore, the density of the encapsulating particles is 0.9–1.08 g / cm³ (actual density).

[0028] Furthermore, the sealing particles are made of polyethylene, high-density polyethylene, polypropylene, polyvinyl chloride, or a cross-linked copolymer of styrene and divinylbenzene.

[0029] Furthermore, the concentration of the packer particles in the filling fluid is 1-20% (by volume).

[0030] To achieve the above objectives, the present invention also employs the following technical solution:

[0031] A method for filling packer particles into oil and gas wells in fractured oil and gas reservoirs to reduce water and increase oil production, wherein the oil and gas wells include one or more production wells and one or more water injection wells used in conjunction with the production wells; the method includes the following steps: (c1) injecting filling fluid carrying packer particles into the wellbore and fractures of the water injection well through the wellhead of the water injection well until the preset packer particle filling amount is reached; (c2) the production well is put into production or in normal production.

[0032] Furthermore, the production well is equipped with a screen pipe or a water control screen pipe.

[0033] Furthermore, the sealing particles have a spherical structure with a particle size of 0.05-5 mm.

[0034] Furthermore, the density of the encapsulating particles is 0.7–1.4 g / cm³ (actual density).

[0035] Furthermore, the density of the encapsulating particles is 0.9–1.08 g / cm³ (actual density).

[0036] Furthermore, the sealing particles are made of polyethylene, high-density polyethylene, polypropylene, polyvinyl chloride, or a cross-linked copolymer of styrene and divinylbenzene.

[0037] Furthermore, the concentration of the packer particles in the filling fluid is 1-10% (by volume).

[0038] To achieve the above objectives, the present invention also employs the following technical solution:

[0039] A method for reducing water level and increasing oil production in a fractured oil and gas reservoir by filling packer particles into the wellbore, comprising the following steps: (d1) injecting packing fluid carrying packer particles into the wellbore and fractures through the wellhead; (d2) commencing production. The injection rate of the packing fluid in step (d1) is less than the production rate after commencing production in step (d2).

[0040] Furthermore, step (d2) includes the following step before production: extracting liquid from the wellbore using a pump installed in the wellbore, wherein the rate at which the liquid is extracted by the pump is greater than the injection rate of the filling fluid.

[0041] Furthermore, the volume of the liquid extracted from the wellbore is greater than the volume of the filling fluid injected.

[0042] Furthermore, step (d2) includes the following step before production: producing liquid in the wellbore using an artificial lift method, wherein the liquid production rate is greater than the filling fluid injection rate.

[0043] Furthermore, the volume of the liquid produced in the wellbore is greater than the volume of the filling fluid injected.

[0044] Furthermore, in step (d1), the volume of the injected packer particles is 1-12 times the volume of the annulus.

[0045] Furthermore, the wellbore is equipped with a screen pipe or a water control screen pipe, and a packer is provided at the top of the screen pipe. The packer is provided with a filling channel for injecting filling fluid. The filling fluid is injected into the annulus and fractures through the filling channel provided on the packer.

[0046] Furthermore, the particle size of the sealing particles is 0.05-5 mm.

[0047] Furthermore, the density of the encapsulating particles is 0.7–1.4 g / cm³ (actual density).

[0048] Furthermore, the density of the encapsulating particles is 0.9–1.08 g / cm³ (actual density).

[0049] Furthermore, the sealing particles are made of polyethylene, high-density polyethylene, polypropylene, polyvinyl chloride, or a cross-linked copolymer of styrene and divinylbenzene.

[0050] Furthermore, the sealing particles have a spherical structure.

[0051] Furthermore, the concentration of the packer particles in the filling fluid is 1-20% (by volume).

[0052] This invention discloses a method for filling packer particles in fractured oil and gas reservoirs to reduce water flow and increase oil production. By using packer particles to directly fill fractures and perform recovery filling, directly filling the annulus and allowing packer particles to flow back from fractures to the annulus for filling, as well as filling from injection wells to production wells, this method effectively solves the problem of cross-flow water production in various types of fractures. In particular, the use of a two-stage pressurized filling method and a recovery filling method allows packer particles to smoothly enter narrow and open fractures, effectively improving the sealing effect of fractures, reducing the conductivity of various fractures, and reducing well water production. Simultaneously, it further increases the pressure gradient during matrix production, enhances the utilization of matrix oil and gas, and improves the recovery rate. Attached Figure Description

[0053] Figure 1This is a schematic diagram of the structure of an oil and gas well in a fractured oil and gas reservoir;

[0054] Figure 2 The method of filling and sealing the gas well with particles to reduce water and increase oil production in fractured oil and gas reservoirs, as described in Example 1, is used to... Figure 1 The diagram shows the structure of an oil well in a fractured oil and gas reservoir after the fractures have been filled.

[0055] Figure 3 The method of filling and sealing the gas well with particles to reduce water and increase oil production in fractured oil and gas reservoirs, as described in Example 2, is used to... Figure 1 The diagram shows the structure of annulus and fractures in a fractured oil and gas reservoir well after filling.

[0056] Figure 4 The method of filling and sealing the gas well with particles to reduce water and increase oil production in fractured oil and gas reservoirs, as described in Example 3, is used to... Figure 1 The diagram shows the structure of annulus and fractures in a fractured oil and gas reservoir well after filling.

[0057] Explanation of reference numerals in the attached diagram: 1 - Christmas tree, 2 - Well casing, 3 - Production section wellbore, 4 - Fracture A, 5 - Fracture B, 6 - Unopened fracture C, 7 - Near-horizontal fracture D, 8 - Surface, 9 - Overlying formation, 10 - Oil area (fractured oil and gas reservoir), 11 - Bottom water, 12 - Packer particles, 13 - Packer, 14 - Annulus, 15 - Screen, 16 - Water control screen. Detailed Implementation

[0058] The following is in conjunction with the appendix Figures 1 to 4 This invention further illustrates specific embodiments of a method for water reduction and oil enhancement in oil and gas wells by filling packers with particles in fractured oil and gas reservoirs. The method for water reduction and oil enhancement in oil and gas wells by filling packers with particles in fractured oil and gas reservoirs is not limited to the descriptions in the following embodiments.

[0059] The terms used in this patent are defined as follows: screen pipe, also known in the industry as downhole filter or sand control pipe; water control screen pipe, also known in the industry as downhole flow control filter, or flow control sand control pipe, flow control screen pipe or water control sand control pipe; water control screen pipe that provides additional flow resistance to water relative to oil is called AICD, and water control screen pipe that does not provide additional flow resistance to water is called ICD. Both AICD and ICD fall under the category of water control screen pipe; annulus refers to the annular space between the screen pipe (or water control screen pipe) and the well wall. In this patent, the ends of the screen pipe (or water control screen pipe) are all closed structures, for example, by using components such as plugs to seal the ends; the filling pressure, well pressure, formation fracture / fracture extension pressure, etc., all refer to the pressure converted to the formation; the density or volume of the packing particles all refer to the actual density or volume, not the bulk density or volume; the filling rate, production rate, and pumping rate of the filling fluid in the wellbore mentioned in the text all refer to the volume of filling fluid flowing through the wellhead per unit time; the continuous packing water control technology refers to the technology of using a water control screen pipe in the wellbore plus a continuous annular packing to control water.

[0060] like Figure 1 As shown, this is a typical fractured oil and gas reservoir well. The oilfield 10 is a fractured oil and gas reservoir with a complex fracture structure. Specifically, fractures A and B are directly connected to the bottom water and the wellbore production section. The opening width of fracture A is smaller than the particle size of the packer, while the opening width of fracture B is larger than the particle size of the packer. Fracture C is an open fracture and is connected to fracture B through a near-horizontal fracture D.

[0061] Example 1:

[0062] This embodiment provides a method for filling packer particles into oil and gas wells in fractured oil and gas reservoirs to reduce water and increase oil production. This method directly fills the wellbore and fractures with packer particles to seal the fractures. Specifically, it includes the following steps: (a1) Injecting filling fluid carrying packer particles into the wellbore and fractures through the wellhead until the formation fracture / fracture extension pressure is reached or exceeded, or until the injection volume at the unit injection pressure is close to zero, or until the preset packer particle filling volume is reached; (a2.1) Running flushing tubing to flush out the packer particles in the wellbore; (a2.2) Production commencement.

[0063] In step (a1) above, there are three criteria for terminating the filling of the filling fluid, which correspond to different structures and different fractures in the production section of the wellbore. In practical applications, filling of the filling fluid can be stopped once any one of the criteria is met. Specifically, in the first scenario, if the filling is carried out at a stable rate (but not limited to a "constant rate," which can vary slowly within a certain range), and if the fracture, i.e., the annulus, is filled with packing material particles and can effectively seal the fracture, the pressure will gradually increase until it reaches or exceeds the formation fracturing / fracture extension pressure, thus reaching the criterion for terminating the filling. In the second scenario, if the filling fluid is continuously injected at a stable pressure, and if the fracture, i.e., the annulus, is filled with packing material particles and can effectively seal or nearly completely seal the fracture, the injection flow rate per unit injection pressure will gradually decrease until it approaches zero or approaches a small value and remains stable (e.g., less than one-fifth or one-tenth of the initial injection pressure), thus reaching the criterion for terminating the filling. In the third scenario, if after completely filling with the preset packing material particles, it is still impossible to reach the formation fracturing / fracture extension pressure, and the injection volume per unit injection pressure is still large or does not decrease significantly, then there are large fractures that cannot be directly sealed. In this case, the fractures can be sealed by the "recovery filling" method described below.

[0064] In step (a1) above, injecting the filling fluid at a stable rate until its final pressure (or termination pressure) equals or exceeds the formation fracturing / fracture extension pressure is the most effective filling method. More preferably, after the filling pressure reaches or exceeds the formation fracturing / fracture extension pressure, filling can continue for a period of time to allow the packing material particles to fully enter the fracture. The reason for this is that the formation fracturing / fracture extension pressure is the expansion pressure of the original fracture. On the one hand, this pressure can further increase the opening of the fracture, thereby injecting more packing material particles into the fracture and achieving a better sealing effect (for example, if the original fracture width is only 0.3 mm, by increasing the filling pressure to slightly expand the fracture, a large number of 0.5 mm packing material particles can enter the fracture). On the other hand, under this pressure, some open fractures will open, allowing packing material particles to enter the fracture, thereby sealing the open fractures.

[0065] Specifically, the determination of the formation fracture / fracture extension pressure needs to be carried out in advance. The determination method includes the following steps: (s1) Connect a pressure gauge and a flow meter at the wellhead, and continuously inject filling fluid (filling fluid without packer particles) into the wellbore through the wellhead. The injection rate is gradually increased, and the pressure in the well continues to increase; (s2) Continuously measure the pressure in the well until the pressure in the well drops rapidly. This drop has a large and obvious cliff-like drop, which is relatively easy to identify. The reason for this drop is that the formation or fracture connected to the wellbore is opened by the pressure, the formation's suction capacity will increase significantly, and the filling fluid in the wellbore will be lost rapidly. In other words, this pressure can cause the formation to fracture and the fracture to break and extend; (s3) The highest pressure value before the rapid drop is the formation fracture / fracture extension pressure.

[0066] In step (a1) above, packer particles with matching particle size can be selected for sealing based on the fracture aperture. However, for some fractures with large apertures, large fracture space volumes, unconnected fractures, near-horizontal fractures, or fractures directly connected to bottom water, the injected packer particles may leak, making it difficult to completely seal them. The well pressure may also be difficult to reach the formation fracture / fracture extension pressure. In this case, "reaching the preset packer particle filling amount" can be used as the sign that the filling is complete.

[0067] After filling is completed, step (a2.1) is performed to completely remove the packing material particles from the wellbore and recover them. At this time, the well pressure decreases, the fracture aperture decreases, and the packing material particles in the fracture will exhibit a "return filling" phenomenon, that is, the packing material particles in the fracture move in the opposite direction to the production section of the wellbore following the fluid flow direction (obviously, the "return filling" phenomenon will be more pronounced after the filling pressure is removed and production is started). However, due to the reduced fracture aperture, some packing material particles will still remain in the fracture, achieving fracture sealing. Figure 2 As shown, after step (a2.1), both cracks A and B have been sealed with sealing particles; more preferably, this method can even seal near-horizontal crack D and open crack C. Figures 2 to 4 (Not shown in the diagram). In the subsequent production step (a2.2), since the cracks have been effectively sealed by the packing particles, the water content of the produced liquid will be significantly reduced, and the production efficiency will be significantly improved.

[0068] In this method, the method for determining the preset packer particle filling amount in step (a1) is: V≥ρ·L0, where V is the preset packer particle filling amount, L0 is the total length of the production section wellbore, and ρ is the filling density, which refers to the packer particle filling volume per unit length of the production section wellbore. When the oil and gas well is a horizontal well, ρ is 0.01-1.0 cubic meters per meter, and when the oil and gas well is a vertical well, ρ is 0.01-5.0 cubic meters per meter. In specific construction, an appropriate packer particle filling amount value can be preset according to the actual size of the fracture and the degree of fracture development under pressure. In one specific implementation, the sealing particles are preferably spherical to ensure good flowability; however, other irregular shapes are also possible, such as pyramidal, square, or dodecahedral shapes, with a particle size (i.e., the maximum size in different directions) of 0.05-5 mm. The sealing particles are made of polyethylene, high-density polyethylene, polypropylene, polyvinyl chloride, or a cross-linked copolymer of styrene and divinylbenzene, with a density of 0.7-1.4 g / cm³, more preferably 0.9-1.08 g / cm³. Sealing particles with smooth surfaces should be selected to improve their flowability. The concentration of sealing particles in the filling fluid is 1-20% (by volume), and the filling fluid should have good lubricity. Using the above-mentioned sealing particles and filling fluid configuration allows the sealing particles to flow more easily into the cracks with the filling fluid.

[0069] Example 2:

[0070] Example 2 is a further optimization of Example 1. According to the technical solution described in Example 1, after the oil and gas well is put into production, as the fluid in the fractures flows from the fractures to the wellbore, the fluid will carry some particles back into the wellbore and produce them. This brings about the following problems: First, after some of the packing particles in the fractures are recovered, the filling degree of the fracture packing decreases, and the ability to control water flow decreases; especially for some wider dissolution fractures, a large number of packing particles that have entered the fractures will be recovered into the wellbore after production, thus failing to maintain the sealing and water control effect of the fractures; Second, the production of packing particles will have a certain impact on the operation of the downhole electric pump, such as the risk of pump jamming; Third, packing particles may enter the fluid delivery pipeline and deposit, posing a risk of affecting fluid delivery.

[0071] To address this issue, Example 2 employs a method of pre-installing sand control tubing in the oil and gas well to solve the aforementioned problem. Specifically, as shown... Figure 3 As shown, the sand control string includes a screen pipe, and a packer is provided at the top of the screen pipe (i.e., the end near the wellhead). The packer has a filling channel for injecting filling fluid; the other end of the screen pipe is sealed with components such as a plug. For more detailed information, please refer to the technical solution disclosed in Chinese Utility Model Patent "Completion Structure for Oil and Gas Wells that Can Improve Water Reduction and Oil Production Capacity (201621200386.1)".

[0072] This embodiment provides a method for reducing water and increasing oil production in a fractured oil and gas reservoir by filling packer particles into the well, comprising the following steps: (b1) opening the filling channel provided on the packer, and continuously injecting filling fluid carrying packer particles into the annulus and fractures through the filling channel until the formation fracture / fracture extension pressure is reached or exceeded, or the preset packer particle filling amount is reached; (b2) reducing the filling fluid injection rate so that the injection rate of the filling fluid is less than the production rate after the production stage, and making the filling pressure less than the formation fracture / fracture extension pressure, and continuously injecting filling fluid carrying packer particles until the packer particles fill the annulus, or until the preset packer particle filling amount is reached; (b3) closing the filling channel and starting production.

[0073] Steps (b1) and (b2) can be defined as the first stage filling and the second stage filling, respectively. The filling pressure of the first stage filling is greater than the formation fracture / fracture extension pressure (i.e., the original fracture extension pressure), and its main purpose is to expand the fracture as much as possible so that the packing material particles can enter the fracture. The filling pressure of the second stage filling is less than the original fracture extension pressure, and its main purpose is to fill the larger fractures and annulus. By filling the annulus with packing material particles in the second stage, not only can the retreat of packing material particles in the fracture during production be suppressed, but it can also have a retreat filling function (when the retreat occurs, the packing material particles in the fracture move in the opposite direction under the influence of the fluid, but they are blocked by the packing material particles in the annulus and cannot enter the annulus. They will gather in the fracture near the annulus, thus producing a better sealing effect), so it can have better water control performance. The reasons for using a two-stage filling method are as follows: First, the filling process requires a relatively large amount of filling material to the fracture, but it cannot be unlimited, otherwise the cost would be too high and the operation time too long; second, the particle size requirements for the sealing particles used in fracture filling and annular filling are different; and third, the material requirements for the sealing particles used in fracture filling and annular filling are different. It should be noted that the "two-stage filling" mentioned above is not narrowly limited to "two fillings," but rather refers to multiple fillings at multiple pressures in each stage. For example, a total of M+N fillings (where M and N are natural numbers) are performed, where the filling pressure of the first M fillings is greater than the formation fracturing / fracture extension pressure, and the filling pressure of the latter N fillings is less than the formation fracturing / fracture extension pressure, which still falls within the scope defined by this method.

[0074] In step (b2), the injection rate of the filling fluid is set to be lower than the production rate after the production phase. The purpose of this is that step (b2) will further fill wider fractures. However, for wider fractures with large volumes that cannot be completely filled, the near-wellbore area will eventually be filled through "recovery filling" to seal and control water. Therefore, if the injection rate of the filling fluid in step (b2) is set too high, the fluid velocity in the fracture will also be too high, and the packing particles will be washed into a more distant location in the fracture. If the fluid velocity in the fracture is too low after production, it may be impossible to recover the distant packing particles to the vicinity of the annulus. Conversely, if the fluid velocity in the fracture is greater than the fluid velocity during filling after production, most or almost all of the packing particles can be recovered to the vicinity of the annulus, thus producing a better "recovery filling" effect.

[0075] In step (b2), the method for determining whether the packer particles have filled the annulus is as follows: When injecting the packing fluid at a constant rate, continuously measure the well pressure until the well pressure rises to a set pressure, indicating that the packer particles have filled the annulus; or when injecting the packing fluid at a constant pressure, continuously measure the flow rate of the packing fluid until the rate drops to a set flow rate, indicating that the packer particles have filled the annulus. The set pressure is preferably 3-5 times the packing pressure, and the set flow rate is preferably one-third to one-fifth of the packing flow rate. Since the packer particles preferentially fill the fractures, there may be larger fractures that cannot be completely filled, thus the annulus cannot be completely filled. Therefore, reaching the preset packer particle filling amount is the termination condition for filling.

[0076] The filling fluid, packer particle parameters, and steps not specifically described in this embodiment are the same as in Example 1.

[0077] The technical solution presented in this embodiment has the following advantages: First, because the annulus is also completely filled, it can effectively prevent the packing material particles in the fracture from flowing back into the annulus, thus preventing the fracture's conductivity from increasing and the water control effect from decreasing. Second, it can avoid the packing material particles affecting the operation of the electric pump. Third, it can prevent the packing material particles from depositing on the ground pipeline, affecting the fluid delivery of the ground pipeline. Fourth, the packing material particles can enter fractures with a fracture width smaller than the particle size, improving the packing material's ability to seal the fracture. Fifth, the technical effect of using backfilling allows for better fracture sealing with fewer packing material particles.

[0078] Example 3:

[0079] Example 3 is a further optimization of Example 2. The technical solution described in Example 2 has the following problems: First, after the fracture is filled with packer particles, although the conductivity is significantly reduced compared to before filling, its permeability is still higher than that of the matrix (several times to hundreds of times), and there is still some water production, so it is necessary to further reduce the water production of the fracture; Second, there are many reasons for water production along the production section of the wellbore, some of which are caused by water production from the locally high-permeability matrix, and controlling water only in the fracture may not be very effective.

[0080] To address this, Example 3 employs a water control screen to further enhance water control capabilities. For example... Figure 4 As shown, the only difference between this embodiment and embodiment 2 is that the screen tube used in this embodiment is a water control screen tube, and the other implementation methods are the same as those in embodiment 2.

[0081] This method achieves dual water control: firstly, water control within the fractures; and secondly, water control within the wellbore (achieved through the combined action of a continuous packer and a water-control screen within the wellbore). The advantages of this dual water control are: firstly, the combined effect of the water-control screen and continuous packer within the wellbore further reduces water seepage from the fractures; secondly, the continuous packer filling the annulus prevents packer particles from being carried away in large quantities by the fluid within the fractures, thus ensuring the sealing effect; and thirdly, during the extraction process, the packer particles carried from the fractures to the annulus increase the compactness of the packer particle accumulation within the annulus, thus achieving a better water control effect with the "technical solution of using annular packer particles plus a water-control screen" in this embodiment. Furthermore, dual water control also has a good water control effect on the high-permeability matrix near the wellbore production section, thus achieving a multi-faceted synergistic effect.

[0082] Example 4:

[0083] This embodiment provides a method for filling packer particles into oil and gas wells in fractured oil and gas reservoirs to reduce water levels and increase oil production. This method is applicable to application scenarios that simultaneously have production wells and water injection wells. The oil and gas wells include one or more production wells and one or more water injection wells used in conjunction with the production wells. The method includes the following steps: (c1) continuously injecting filling fluid carrying packer particles into the wellbore and fractures of the water injection well through the wellhead until the preset packer particle filling volume is reached; (c2) putting the production well into production or normal production.

[0084] The principle behind this method is as follows: For certain fractured oil and gas reservoirs, injecting water into the oil-bearing area through injection wells can significantly increase fluid production. However, in fractured reservoirs, due to the presence of fractures, injected water may directly flow through the fractures to the production wells, failing to effectively displace oil from the matrix. Particularly serious is the possibility that some fracture networks directly connect injection wells and production wells, diverting water directly from the injection wells to the production wells, making it difficult for water to penetrate the matrix. This method, by injecting water into fractured injection wells while simultaneously mixing a certain concentration and quantity of packer particles into the water, can seal the fractures connecting the injection wells, thereby facilitating the penetration of injected water into the matrix and improving oil and gas extraction efficiency.

[0085] Preferably, to prevent the packing material particles injected from the injection well from flowing directly along the fractures into the production well and affecting the pump in the production well, the production section of the production well is equipped with a screen pipe or a water control screen pipe, thereby isolating the packing material within the production well through the screen pipe or water control screen pipe. For production wells equipped with screen pipes or water control screen pipes, if this method can fill the annulus and near-wellbore fractures, the technical effects described in Examples 2 and 3 can also be achieved. Specifically, the packing particles have a spherical structure with a particle size of 0.05-5 mm and a density of 0.7-1.4 g / cm³ (actual density). The material is polyethylene, high-density polyethylene, polypropylene, polyvinyl chloride, or styrene-divinylbenzene cross-linked copolymer. The concentration of the packing particles in water is 1-10% (by volume). The injection amount of the packing particles should meet the requirements of annular volume, fracture volume (or near-wellbore fracture volume), and loss along the way between the production well and the production well. Alternatively, packing particles can be added gradually to the injected water based on the water control effect of the production well (which can be determined by dynamically monitoring the change trend of the water content of the produced fluid).

[0086] The technical solution presented in this embodiment has several advantages: first, it has low operating costs, as packer particles can be added directly to the water injection in the injection well; second, compared to the technical solution of directly filling the production well, it saves the step of setting up a special filling pump in the production well, and will not interfere with the normal production of the production well, thereby further improving production efficiency; and third, it can effectively reduce the water content of the produced fluid and increase the oil production.

[0087] Example 5:

[0088] Existing continuous packer water control technology in wellbore also employs the step of filling the annulus with packer particles. However, this technology can only fill open, interconnected fractures with very small volumes, and cannot effectively fill closed fractures, concealed fractures, and edgeless fractures. Closed and concealed fractures refer to fractures with openings in the wellbore that are too narrow or nonexistent, preventing particles from entering. Edgeless fractures, on the other hand, refer to fractures with wide openings in the wellbore, connecting fractures that are far apart and have large volumes. During filling, the packer particles flow with the filling fluid to locations far from the wellbore, unable to remain near the wellbore, thus failing to fill the near-wellbore area. Filling edgeless fractures is too costly to implement. Edgeless fractures also introduce the problem of incomplete annulus filling. This is because, in the presence of fractures, particles preferentially flow towards the fractures, filling them before attempting to fill the annulus. If the fractures cannot be filled, the annulus cannot be filled either. In this case, if the annulus is not filled, the water control function of the wellbore packer will be completely or partially ineffective. These three types of fractures are also important channels for water channeling, and it is urgent to fill and seal them with packing particles. On the other hand, due to the existence of hidden fractures, water can flow almost unimpeded from a position far from the wellbore to the fracture end near the well through the hidden fractures, and then seep into the wellbore through a short distance of matrix, resulting in a very serious water channeling problem.

[0089] For near-wellbore closed fractures, the technical solutions shown in Examples 1 to 4 can be adopted. Under the condition that the filling pressure reaches or exceeds the formation fracture / fracture extension pressure, a certain volume of packer particles is filled into the wellbore and fractures, or the annulus and fractures, through filling fluid. Preferably, the volume of the filled packer is 1 to 12 times the volume of the annulus.

[0090] This embodiment presents a method for reducing water and increasing oil production in fractured oil and gas reservoirs by filling packer particles into the wellbore with packer particles. This method allows packer particles, which are filled into the fractures and located a certain distance from the wellbore, to be collected and brought back to the production well, achieving recovery and filling. The specific implementation steps are as follows: (d1) Injecting filling fluid carrying packer particles into the wellbore and fractures through the wellhead; (d2) Production commencement. In step (d1), the injection rate of the filling fluid is less than the production rate after production commencement in step (d2). By setting the injection rate of the filling fluid to be less than the production rate, it is possible to prevent the packer particles in the fractures from being carried too far by the filling fluid, thus ensuring that most of the packer particles can be recovered and filled into the annulus and near-wellbore fractures during the recovery and filling process. During the recovery and filling process, hidden fractures and closed fractures can receive packer particles through the interconnected fracture network within the formation, potentially becoming completely or partially filled. Preferably, the volume of the filling spacer is 1 to 12 times the volume of the annulus.

[0091] Preferably, step (d2) further includes the following steps before production: pumping liquid from the wellbore using a pump installed in the wellbore, wherein the rate of liquid pumping is greater than the filling fluid injection rate, and the volume of liquid pumped is greater than the volume of filling fluid injected; or, using an artificial lift method to produce liquid from the wellbore, wherein the production rate is greater than the filling fluid injection rate, and the volume of produced liquid is greater than the volume of filling fluid injected. The purpose of rapidly pumping or producing liquid from the wellbore using pumps or other artificial lift methods is to further increase the recovery velocity of the packer particles in the near-wellbore fractures, increase the recovery rate, and increase the compactness of the recovered particles. For flowing wells, the recovery rate can be greater than the filling rate by increasing the flow rate.

[0092] This method is not only applicable to general oil and gas wells, but also better applicable to oil and gas wells equipped with screen pipes or water control screen pipes. The wellbore is equipped with a screen pipe, which can be a water control screen pipe. The top of the screen pipe is equipped with a packer, and the packer is equipped with a filling channel for injecting filling fluid. The filling fluid is injected into the annulus and fractures through the filling channel provided on the packer.

[0093] The parameters used in this embodiment, such as the filling fluid and the packing particles, are the same as those in Example 1.

[0094] Example 6:

[0095] This embodiment provides a practical application of the technical solution described in Embodiment 1.

[0096] An oil and gas well in a fractured reservoir is located in a hard fractured sandstone formation with a matrix permeability of 0.1 Darcy and an initial fracture extension pressure of 10 MPa. The wellbore has a horizontal section length of 400 meters and a diameter of 8.5 inches. The expected packer particle volume is 15 cubic meters. Upon initial production, the daily oil production is 30 cubic meters, with a water cut of 80%. The fracture filling is performed using the technique described in Example 1. During construction, spherical packer particles with a diameter of 0.1 mm, made of polyethylene with a density of 0.9 g / cm³, are used. The filling volume is 12 cubic meters, and the filling fluid is produced water from the production well with a concentration of 3%. The (maximum) filling pressure is 12 MPa. At the end of filling, the injection flow rate at the same filling pressure decreases to one-fifth of the initial flow rate. After filling, production begins, with a daily oil production of 56 cubic meters and a water cut of 63%.

[0097] Example 7:

[0098] This embodiment provides a practical application of the technical solution described in Embodiment 2.

[0099] An oil and gas well in a fractured oil and gas reservoir is located in a limestone formation with a matrix permeability of 0.2 Darcy. The measured initial fracture extension pressure is 20 MPa. The wellbore has a horizontal section length of 300 meters, a well diameter of 8.5 inches, and a 5.5-inch composite sand control pipe. The annulus volume is 5 cubic meters. Direct production begins, with a daily oil production of 5 cubic meters and a water cut of 89%. The annulus and fractures are filled using the technical scheme described in Example 2. During construction, spherical packer particles with a diameter of 0.3 mm, made of polyvinyl chloride (PVC), and a density of 1.4 g / cm³ are used. The filling fluid is seawater with a concentration of 5%. The first stage (maximum) filling pressure is 25 MPa, and the packer particle volume is 10 cubic meters. The second stage (maximum) filling pressure is 5 MPa, and the filling volume is 4 cubic meters. At the end of filling, the injection volume at the same filling pressure decreases to one-fifth of the initial volume. After filling is completed, the plant will be put into production with a daily oil production of 23 cubic meters and a water content of 50%.

[0100] Example 8:

[0101] This embodiment provides a practical application of the technical solution described in Embodiment 3.

[0102] An oil and gas well in a fractured reservoir is located in a bioherm limestone formation with numerous stress fractures and dissolution fractures, as well as a large number of wide opening fractures. The matrix permeability is 1 Darcy, and the measured original fracture extension pressure is 15 MPa. The wellbore horizontal section is 700 meters long, with a wellbore diameter of 8.5 inches, and a 5.5-inch water control screen is installed. The annulus volume is 9.4 cubic meters. Direct production is initiated, with a daily oil production of 11 cubic meters and a water cut of 95%. The annulus and cracks were filled using the technical solution described in Example 3. During construction, spherical packing particles with a particle size of 0.2 mm were used. The material was a cross-linked copolymer of styrene and divinylbenzene with a density of 1.05 g / cm³. The filling volume was 27 m³. The filling liquid was seawater with a concentration of 2%. The first stage (maximum) filling pressure was 18 MPa, and the filling volume was 5 m³. The second stage (maximum) filling pressure was 10 MPa, which was gradually reduced to 2 MPa, and the filling volume was 22 m³. At this point, the preset filling volume of 27 m³ of packing particles had been reached, but the annulus was still not completely filled, and the filling was terminated. In this embodiment, the preset production rate of the oil well is 110 cubic meters per day. Therefore, the filling rate of the 22 cubic meters of packing material particles in the second stage, carrying the first 2 cubic meters of packing material particles, is above 80 cubic meters per day, while the filling rate of the filling material carrying the last 20 cubic meters of packing material particles is controlled below 80 cubic meters per day (less than the preset production rate of 110 cubic meters per day). This ensures that after production begins, most of the 20 cubic meters of packing material particles injected into the fractures can be recovered and used for backfilling. After filling is completed and production begins, the daily oil production is 100 cubic meters, and the water cut of the produced fluid is 10%.

[0103] Example 9:

[0104] This embodiment provides a practical application of the technical solution described in Embodiment 4.

[0105] A fractured oil and gas reservoir has numerous wide, saturated fractures in its formation. The matrix permeability is 0.2 Darcy, and the measured initial fracture extension pressure is 10 MPa. The wellbore horizontal section is 400 meters long, with a well diameter of 8.5 inches. The expected volume of packer particles is 100 cubic meters. Upon initial production, the well produces 8 cubic meters of oil per day, with a water cut of 87%. The fracture filling is performed using the technique described in Example 1. During construction, spherical packer particles with a diameter of 0.2 mm, made of polypropylene with a density of 0.9 g / cm³, are used. The filling volume is 110 cubic meters, and the filling fluid is the wellhead water with a concentration of 1%. The (maximum) filling pressure is 8 MPa. After filling, production begins, with the well producing 26 cubic meters of oil per day and a water cut of 60%.

[0106] Example 10:

[0107] This embodiment provides a practical application of the technical solution described in Embodiment 5.

[0108] An oil and gas well in a fractured oil and gas reservoir is located in a fractured limestone formation with a matrix permeability of 0.15 Darcy and a measured original fracture extension pressure of 12 MPa. The wellbore has a horizontal section of 500 meters, a well diameter of 8.5 inches, and a 5.5-inch water control screen. The annulus volume is 6.7 cubic meters, and the expected packer particle volume is 42 cubic meters. Direct production is initiated, with a daily oil production of 15 cubic meters and a water cut of 92%. Fracture filling is performed using the technique described in Example 5. During construction, spherical packer particles with a diameter of 0.15 mm, made of polyethylene with a density of 0.9 g / cm³, are used. The filling volume is 42 cubic meters, and the filling fluid is produced water from the production well with a concentration of 3%. The filling flow rate is 150 cubic meters / day. While the annulus is not yet fully filled (42 cubic meters), the expected packer particle volume has been reached, so filling is terminated. After filling is completed and production begins, the liquid production is 375 cubic meters per day, which is greater than the filling flow rate; the daily oil production is 300 cubic meters per day, and the water content of the liquid is 20%.

[0109] The above description, in conjunction with specific preferred embodiments, provides a further detailed explanation of the present invention and should not be construed as limiting the specific implementation of the invention to these descriptions. For example, the technical solutions disclosed in this invention are still applicable to fractured oil and gas reservoirs that primarily produce gas, as well as fractured oil and gas reservoirs that only produce gas, and can achieve the effects of increasing gas production and reducing water content. For those skilled in the art, several simple deductions or substitutions can be made without departing from the concept of the present invention, and all such modifications or substitutions should be considered within the scope of protection of this invention.

Claims

1. A method for filling packing materials with particles to reduce water level and increase oil production in a fractured oil and gas reservoir well, wherein the oil and gas well includes one or more production wells and one or more water injection wells used in conjunction with the production wells. in, The fracture network directly connects the injection well and the production well. The method is characterized by the following steps: (c1) Through the wellhead of the injection well, the filling fluid carrying the packer particles is injected into the wellbore and fractures of the injection well until the preset packer particle filling amount is reached. The production section of the production well is equipped with a screen pipe or a water control screen pipe, which isolates the packer within the production well; the packer particles fill the annulus and near-wellbore fractures. (c2) Production wells are put into production or in normal production.

2. The method for filling packers with particles to reduce water and increase oil production in fractured oil and gas reservoirs according to claim 1, characterized in that: The packing particles have a spherical structure and a particle size of 0.05-5 mm.

3. The method for filling packers with particles to reduce water and increase oil production in fractured oil and gas reservoirs according to claim 2, characterized in that: The actual density of the packing particles is 0.7-1.4 g / cm³.

4. The method for filling packers with particles to reduce water and increase oil production in fractured oil and gas reservoirs according to claim 3, characterized in that: The actual density of the packing particles is 0.9-1.08 g / cm³.

5. The method for filling packers with particles to reduce water and increase oil production in fractured oil and gas reservoirs according to claim 4, characterized in that: The sealing particles are made of polyethylene, high-density polyethylene, polypropylene, polyvinyl chloride, or a cross-linked copolymer of styrene and divinylbenzene.

6. The method for filling packers with particles to reduce water and increase oil production in fractured oil and gas reservoirs according to claim 5, characterized in that: The volume concentration of the packer particles in the filling fluid is 1-10%.

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