A fracturing method for reducing frictional composite weighting

Abstract

The application discloses a fracturing method for reducing frictional composite weighting. The method comprises the following steps: acquiring a construction discharge value in a fracturing process in real time; pumping a first fracturing fluid, a second fracturing fluid, a third fracturing fluid, a fourth fracturing fluid, a fifth fracturing fluid, a sixth fracturing fluid and a seventh fracturing fluid into a wellbore respectively under the conditions that the construction discharge value is within an initial discharge range, after a packer is set, the construction discharge value is less than a first discharge threshold, the first discharge threshold is reached, a second discharge threshold is reached, a third discharge threshold is reached, a fourth discharge threshold is reached and a fifth discharge threshold is reached, wherein each fracturing fluid comprises at least one of a first solution, a second solution or a proppant, and the volume ratio of the first solution, the second solution or the proppant in each fracturing fluid is different. The method can effectively reduce liquid friction and realize the purpose of reducing wellhead pressure while reducing the construction risk under the condition of high construction discharge.

Description

Technical Field

[0001] This invention relates to the field of reservoir stimulation in ultra-deep oil and gas field development, and particularly to a fracturing method for reducing friction and adding weight. Background Technology

[0002] my country possesses abundant deep / ultra-deep oil and gas resources. However, the deeper the target reservoir, the stronger the compaction and the higher the geostress. This leads to limitations in completion tubing, resulting in challenges such as high operating pressure, limited flow rate, and restricted scale of the fracturing process. Existing technologies address this issue by employing highly efficient weighted fracturing fluids. However, in reality, as the operating flow rate increases, the pressure-reducing effect of the weighted fracturing fluid significantly decreases at the wellhead. In other words, the pressure-reducing capacity of the weighted fracturing fluid is inversely correlated with the operating flow rate. Research and analysis have shown that this is because the high fluid friction under high operating flow rates negates the pressure-reducing effect of the weighted fracturing fluid at the wellhead. Therefore, while ensuring operational safety, it is urgent to provide a method to reduce fluid friction under high operating flow rates. Summary of the Invention

[0003] Significant breakthroughs and profitable development of deep / ultra-deep oil and gas have been achieved in areas such as the Tarim Kuqa foreland, the southern edge of the Junggar Basin, and northwestern Sichuan. PetroChina's Tarim Oilfield and Southwest Oil & Gas Field have deployed 10,000-meter exploration wells. In actual development, existing technologies utilize weighted fracturing fluids to reduce wellhead pressure. The fracturing fluids used during fracturing operations are generally based on single soluble inorganic salt solutions. The density of fracturing fluid varies depending on the concentration of the soluble inorganic salt solution; in fact, the density of fracturing fluids using soluble inorganic salt solutions can reach up to 1.7 g / cm³. 3 -2.0g / cm 3 Based on the requirements for the stimulation of ultra-deep wells (i.e., oil and gas wells with a depth exceeding 6500m), the density of the soluble inorganic salt fracturing fluid must not exceed 1.5g / cm³. 3 In actual fracturing operations, the density of soluble inorganic salt solution fracturing fluid is generally around 1.15 g / cm³. 3 -1.35g / cm 3 Theoretically, the density is 1.5 g / cm³. 3 Soluble inorganic salt fracturing fluids can reduce wellhead pressure by 30 MPa, significantly reducing the risks of sand fracturing operations. However, during the stimulation of ultra-deep, high-stress, tight reservoirs, it was found that the pressure-reducing effect of soluble inorganic salt fracturing fluids significantly decreased with increasing fracturing flow rate. This indicates an inverse correlation between the pressure-reducing capacity of soluble inorganic salt fracturing fluids and the fracturing flow rate. Data collection and analysis revealed that increasing the fracturing flow rate to 3.5 m³ / h... 3At flow rates above 3.5 m / min, the pressure reduction effect of inorganic salt fracturing fluid at the wellhead essentially disappears. This is because the friction coefficient of a single-material soluble inorganic salt fracturing fluid is positively correlated with its density; that is, a higher density fracturing fluid has a higher friction coefficient. Existing research shows that the total friction of fluid flow is directly proportional to the friction coefficient and the square of the fracturing fluid flow rate. Therefore, an increase in the friction coefficient of the fracturing fluid and an increase in the flow rate lead to an increase in its total friction. Consequently, at higher flow rates, the pressure reduction effect at the wellhead due to the increased fluid column density cancels out the friction, ultimately resulting in a flow rate exceeding 3.5 m / min. 3 When the pressure drop rate of the inorganic salt solution fracturing fluid reaches a certain value per minute, its pressure-reducing effect on the wellhead essentially disappears.

[0004] In view of the above problems, the present invention is proposed to provide a fracturing method for reducing frictional combined weight to overcome or at least partially solve the above problems.

[0005] In a first aspect, embodiments of the present invention provide a fracturing method for reducing the combined weighting of frictional stress, comprising:

[0006] Real-time acquisition of the fracturing displacement value during the fracturing process;

[0007] When the construction flow rate is within the initial flow rate range, a first fracturing fluid is pumped in. The first fracturing fluid includes a first solution and a second solution in a first preset volume ratio. The first solution is a soluble inorganic salt solution, and the second solution is a solid phase fracturing fluid.

[0008] After the packer is set and the construction flow rate is less than the first flow rate threshold, a second fracturing fluid is pumped in. The second fracturing fluid includes the first solution and the second solution in a second preset volume ratio.

[0009] When the construction flow rate reaches the first flow rate threshold, a third fracturing fluid is pumped in, the third fracturing fluid comprising the first solution and the second solution in a third preset volume ratio;

[0010] When the construction flow rate reaches the second flow rate threshold, a fourth fracturing fluid is pumped in, the fourth fracturing fluid comprising the first solution and the second solution in a fourth preset volume ratio;

[0011] When the construction flow rate reaches the third flow rate threshold, a fifth fracturing fluid is pumped in. The fifth fracturing fluid includes proppant and the first solution and the second solution in a fifth preset volume ratio.

[0012] When the construction flow rate reaches the fourth flow rate threshold, a sixth fracturing fluid is pumped in. The sixth fracturing fluid includes proppant and a first solution and a second solution in a sixth preset volume ratio.

[0013] When the construction flow rate reaches the fifth flow rate threshold, a seventh fracturing fluid is pumped in, the seventh fracturing fluid comprising the second solution and proppant;

[0014] The initial displacement range, the first displacement threshold, the second displacement threshold, the third displacement threshold, the fourth displacement threshold, and the fifth displacement threshold increase sequentially.

[0015] In one embodiment, the volume percentage of the first solution in the first fracturing fluid is higher than that of the second solution.

[0016] In one embodiment, the volume percentage of the first solution in the second fracturing fluid is higher than that of the second solution, and the volume percentage of the first solution in the second fracturing fluid is lower than that in the first fracturing fluid.

[0017] In one embodiment, the volume percentage of the first solution in the third fracturing fluid is higher than that of the second solution, and the volume percentage of the first solution in the third fracturing fluid is lower than that in the second fracturing fluid.

[0018] In one embodiment, the volume percentage of the first solution in the fourth fracturing fluid is lower than that of the second solution.

[0019] In one embodiment, the diameter of the proppant in the fifth fracturing fluid is within a first preset diameter range;

[0020] The volume percentage of the first solution in the fifth fracturing fluid is lower than that of the second solution; and the volume percentage of the first solution in the fifth fracturing fluid is lower than that in the fourth fracturing fluid.

[0021] In one embodiment, the diameter of the proppant in the sixth fracturing fluid is within a second preset diameter range;

[0022] The volume percentage of the first solution in the sixth fracturing fluid is lower than that of the second solution; and the volume percentage of the first solution in the sixth fracturing fluid is lower than that in the fifth fracturing fluid.

[0023] The proppant-to-liquid ratio in the sixth fracturing fluid is higher than that in the fifth fracturing fluid, and the proppant-to-liquid ratio is the volume ratio of proppant to liquid in the fracturing fluid.

[0024] In one embodiment, the seventh fracturing fluid is composed of the second solution and a proppant within a third preset diameter range; the diameter of the proppant in the seventh fracturing fluid is within the third preset diameter range.

[0025] The sand-to-liquid ratio in the seventh fracturing fluid is higher than that in the sixth fracturing fluid.

[0026] In one embodiment, the density of the first solution is 1.5 g / cm³. 3 .

[0027] In one embodiment, the second solution comprises solid spherical particles and gel fracturing fluid.

[0028] The density of the second solution is the same as that of the first solution.

[0029] In one embodiment, the solid spherical particles have a particle size of 200 mesh and are insoluble.

[0030] In one embodiment, the volume ratio of the first solution to the second solution in the first fracturing fluid is nine to one;

[0031] The volume ratio of the first solution to the second solution in the second fracturing fluid is eight to two.

[0032] The volume ratio of the first solution to the second solution in the third fracturing fluid is six to four.

[0033] The volume ratio of the first solution to the second solution in the fourth fracturing fluid is four to six.

[0034] The volume ratio of the first solution to the second solution in the fifth fracturing fluid is 2:8; the sand-to-liquid ratio of the fifth fracturing fluid is 10%.

[0035] The volume ratio of the first solution to the second solution in the sixth fracturing fluid is 1:9; the sand-to-liquid ratio of the sixth fracturing fluid is 15%.

[0036] The seventh fracturing fluid has a sand-to-fluid ratio of 20%.

[0037] In one embodiment, the proppant is ceramsite.

[0038] The beneficial effects of the above-described technical solutions provided in the embodiments of the present invention include at least the following:

[0039] The fracturing method for reducing friction and adding weight provided in this invention obtains the real-time construction displacement value during fracturing. Based on the numerical range of the construction displacement value, fracturing fluid with a corresponding ratio is pumped into the wellbore. Specifically, when the construction displacement value is within the initial displacement range, after packer setting and less than a first displacement threshold, reaching the first displacement threshold, reaching the second displacement threshold, reaching the third displacement threshold, reaching the fourth displacement threshold, and reaching the fifth displacement threshold, first, second, third, fourth, fifth, sixth, and seventh fracturing fluids are pumped into the wellbore, respectively. The first, second, third, fourth, and fifth displacement thresholds are defined as follows: By sequentially increasing the flow threshold, and controlling the composition and proportion of the first solution, second solution, and proppant, fracturing fluids of different compositions are prepared, including the first, second, third, fourth, fifth, sixth, and seventh fracturing fluids. This allows for the selection of fracturing fluids with different component ratios at different drilling rates, enabling different components to leverage their respective advantages and effectively reducing the drilling pressure in ultra-deep, high-stress reservoirs. For ultra-deep, high-stress wells, combined weighted fracturing technology can be implemented according to different drilling rates. As the drilling rate increases, the ratio of soluble inorganic salt fracturing fluid to solid phase fracturing fluid is adjusted so that the drag reduction rate does not decrease regardless of whether the drilling rate is low or high, maintaining the same drilling pressure reduction effect at the wellhead.

[0040] Furthermore, soluble inorganic salt fracturing fluids and solid fracturing fluids have their own frictional characteristics. Soluble inorganic salt fracturing fluids have a high frictional coefficient at high operating rates but low operating risks at low operating rates. Solid fracturing fluids, on the other hand, contain a large number of solid particles, which pose a high risk of solid sedimentation (sand blockage) at low operating rates, easily clogging the wellbore and causing operating accidents. Therefore, at low operating rates, soluble inorganic salt fracturing fluids are used as the main component. As the operating rate increases, the proportion of soluble inorganic salt fracturing fluids is gradually reduced while the proportion of solid fracturing fluids is increased simultaneously. This ensures that the drag reduction rate of the fracturing fluid injected into the wellbore does not decrease, maintaining the same pressure reduction effect at the wellhead under both low and high operating rates.

[0041] Furthermore, the solid phase fracturing fluid uses solid insoluble materials as weighting agents and adopts solid phase weighting material technology. Since the solid phase formed by the dispersion of solid particles in water is insoluble in water, it does not affect the extension of the thickener molecules dissolved in water to form a long chain structure, thus not affecting the overall drag reduction performance of the fracturing fluid.

[0042] Other features and advantages of the invention will be set forth in the description which follows, and will be apparent in part from the description, or may be learned by practicing the invention. The objects and other advantages of the invention may be realized and obtained by means of the structures particularly pointed out in the written description, claims, and drawings.

[0043] The technical solution of the present invention will be further described in detail below with reference to the accompanying drawings and embodiments. Attached Figure Description

[0044] The accompanying drawings are provided to further illustrate the invention and form part of the specification. They are used in conjunction with embodiments of the invention to explain the invention and do not constitute a limitation thereof. In the drawings:

[0045] Figure 1 This is a flowchart of the fracturing method for reducing friction and adding weight in an embodiment of the present invention;

[0046] Figure 2 This is a schematic diagram of the construction curve of the construction well in an embodiment of the present invention. Detailed Implementation

[0047] Exemplary embodiments of the present disclosure will now be described in more detail with reference to the accompanying drawings. While exemplary embodiments of the present disclosure are shown in the drawings, it should be understood that the present disclosure may be implemented in various forms and should not be limited to the embodiments set forth herein. Rather, these embodiments are provided so that this disclosure will be thorough and complete, and will fully convey the scope of the disclosure to those skilled in the art.

[0048] In the description of this invention, it should be noted that the terms "center," "upper," "lower," "left," "right," "vertical," "horizontal," "inner," and "outer," etc., indicate the orientation or positional relationship based on the orientation or positional relationship shown in the accompanying drawings. They are used only for the convenience of describing the invention and for simplifying the description, 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 invention. Furthermore, the terms "first," "second," and "third" are used for descriptive purposes only and should not be construed as indicating or implying relative importance.

[0049] In the description of this invention, it should be noted that, unless otherwise explicitly specified and limited, the terms "installation," "connection," and "linking" should be interpreted broadly. For example, they can refer to a fixed connection, a detachable connection, or an integral connection; 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; and they can refer to the internal connection of two components. Those skilled in the art can understand the specific meaning of the above terms in this invention based on the specific circumstances.

[0050] Example 1

[0051] To address the issue of reduced fracturing fluid friction under high fracturing flow rates in existing technologies, this invention provides a fracturing method that combines friction reduction with weighting, the process of which is described below. Figure 1 As shown, it includes the following steps:

[0052] Step S101: Obtain the construction displacement value in real time during the fracturing process;

[0053] Step S102: When the construction flow rate is within the initial flow rate range, pump in the first fracturing fluid. The first fracturing fluid includes a first solution and a second solution with a first preset volume ratio. The first solution is a soluble inorganic salt solution, and the second solution is a solid phase fracturing fluid.

[0054] Step S103: After the packer is set and the construction flow rate is less than the first flow rate threshold, the second fracturing fluid is pumped in. The second fracturing fluid includes a first solution and a second solution with a second preset volume ratio.

[0055] Step S104: When the construction displacement value reaches the first displacement threshold, the third fracturing fluid is pumped in. The third fracturing fluid includes the first solution and the second solution with a third preset volume ratio.

[0056] Step S105: When the construction displacement value reaches the second displacement threshold, the fourth fracturing fluid is pumped in. The fourth fracturing fluid includes the first solution and the second solution with a fourth preset volume ratio.

[0057] Step S106: When the construction displacement value reaches the third displacement threshold, the fifth fracturing fluid is pumped in. The fifth fracturing fluid includes proppant and a first solution and a second solution with a fifth preset volume ratio.

[0058] Step S107: When the construction displacement value reaches the fourth displacement threshold, the sixth fracturing fluid is pumped in. The sixth fracturing fluid includes proppant and a first solution and a second solution with a sixth preset volume ratio.

[0059] Step S108: When the construction displacement value reaches the fifth displacement threshold, pump in the seventh fracturing fluid, which includes the second solution and proppant;

[0060] The initial displacement range, the first displacement threshold, the second displacement threshold, the third displacement threshold, the fourth displacement threshold, and the fifth displacement threshold increase sequentially.

[0061] By controlling the composition and proportion of the first solution, second solution, and proppant, first, second, third, fourth, fifth, sixth, and seventh fracturing fluids are prepared. Real-time operational flow rates are obtained. The first, second, third, fourth, fifth, sixth, and seventh fracturing fluids are pumped into the wellbore when the operational flow rate is within the initial flow rate range, after packer setting and less than the first flow rate threshold, reaches the first flow rate threshold, reaches the second flow rate threshold, reaches the third flow rate threshold, reaches the fourth flow rate threshold, and reaches the fifth flow rate threshold. This allows fracturing fluids with different compositions or proportions to be pumped into the wellbore according to the operational flow rate. Because different components have different friction coefficients, each component leverages its own advantages, effectively reducing the operational pressure of ultra-deep, high-stress reservoir stimulation.

[0062] The "initial displacement range" refers to a numerical range that indicates the displacement value is in a low displacement state after the fracturing operation begins. The initial displacement range, the first displacement threshold, the second displacement threshold, the third displacement threshold, the fourth displacement threshold, and the fifth displacement threshold can be pre-set empirical values. For example, the initial displacement range could be 0.5m. 3 / min-0.8m 3 / min, the first displacement threshold can be 1.0m 3 / min, the second displacement threshold can be 2.0m 3 / min, the third displacement threshold can be 3.0m 3 / min, the fourth displacement threshold can be 4.0m 3 / min, the fifth displacement threshold can be 5.0m 3 / min, in fact, various thresholds or numerical ranges can be set according to the actual construction situation, and the embodiments of the present invention are not limited here.

[0063] To reduce the friction of fracturing fluid under high flow rates, a thickener (a drag reducer, also known as a non-weighted fracturing fluid) can be added to the fracturing fluid. This is because the thickener expands upon contact with water, forming a linear long-chain structure. This structure extends in water and, in the case of pipe flow, prevents turbulence (a major cause of pipe flow friction), thus reducing friction. The inventors of this invention have discovered that soluble inorganic salt solutions, when dissolved in water, have a high salt ion concentration, which inhibits the thickener's... The dissolution and extension of linear long-chain structures in water, without the constraints of linear long-chain structures, makes the flow of fluid in pipes prone to phenomena, significantly increasing fluid friction. Therefore, fracturing fluids prepared using soluble inorganic salt solutions as weighting agents show a significant decrease in friction coefficient as the density of the fracturing fluid increases. Based on this, the inventors of this invention use soluble inorganic salt solutions (i.e., the first solution) and solid insolubles (the second solution contains solid insolubles) to jointly prepare a weighted fracturing fluid, obtaining a composite weighted fracturing fluid to reduce wellhead pressure.

[0064] In some optional embodiments, the first solution is a soluble inorganic salt solution, such as sodium chloride, potassium chloride, sodium bromide, calcium bromide, potassium bromide, sodium nitrate, potassium formate, or calcium chloride. The density of the fracturing fluid is changed by altering the concentration of the soluble inorganic salt solution. Generally, a low-density weighting solution refers to a solution with a density less than 1.2 g / m³. 3 Soluble inorganic salt solutions; medium- and high-density weighted solutions refer to solutions with a density greater than or equal to 1.2 g / m³. 3 Soluble inorganic salt solutions

[0065] The second solution is a solid-phase fracturing fluid, which can use solid insoluble materials as weighting agents. In this embodiment of the invention, the solid phase selected is high-strength solid particles with a particle size of 200 mesh. These solid particles are insoluble in acid and alkali fracturing fluids. Since the solid phase formed by the dispersion of solid particles in water is also insoluble in water, it does not affect the extension of the thickener molecules dissolved in water to form a linear long-chain structure, thereby reducing the impact on the overall drag reduction performance of the fluid. This ensures that the solid-phase fracturing fluid and the non-weighted fracturing fluid maintain a similar drag reduction rate. The inventors of this invention have found through coiled tubing friction tests that the drag reduction performance of the solid-phase fracturing fluid is close to that of the non-weighted fracturing fluid. Compared with the drag reduction rate of fracturing fluid with soluble inorganic salt solution of the same density, the drag reduction rate of the solid-phase fracturing fluid is increased by 20%-60%.

[0066] In some optional embodiments, a first solution (soluble inorganic salt fracturing fluid) and a second solution (solid-phase fracturing fluid) can be prepared in advance before fracturing operations. The density of the first solution is 1.5 g / cm³. 3 The second solution comprises solid spherical particles and gel fracturing fluid. The solid spherical particles have a particle size of 200 mesh and are insoluble. The density of the second solution is the same as that of the first solution.

[0067] In some optional embodiments, the fracturing displacement value is acquired in real time from the start of the fracturing operation, and the displacement value is within the initial displacement range (0.5m). 3 / min-0.8m 3 When the flow rate is between 0.5 m / min, the first fracturing fluid is pumped into the wellbore to replace the original completion fluid, so that the wellbore is filled with the first fracturing fluid. The volume ratio of the first solution in the first fracturing fluid is higher than that of the second solution.

[0068] After the ball is thrown into the packer and set, that is, after the packer is set, and the construction displacement value is less than the first displacement threshold (1.0m). 3 When the volume ratio of the first solution in the second fracturing fluid is higher than that in the second fracturing fluid, the volume ratio of the first solution in the second fracturing fluid is lower than that in the first fracturing fluid.

[0069] The construction displacement gradually increases, reaching the first displacement threshold (1.0m). 3 At a rate of ( / min), a third fracturing fluid is pumped into the wellbore to replace the second fracturing fluid. The volume percentage of the first solution in the third fracturing fluid is higher than that of the second solution, and the volume percentage of the first solution in the third fracturing fluid is lower than that in the second fracturing fluid.

[0070] The construction displacement continued to gradually increase, reaching the second displacement threshold (2.0m). 3 At a rate of ( / min), a fourth fracturing fluid is pumped into the wellbore to replace the third fracturing fluid. The volume percentage of the first solution in the fourth fracturing fluid is lower than that of the second solution.

[0071] Construction displacement gradually increases, reaching the third displacement threshold (3.0m). 3 In the case of ( / min), the fifth fracturing fluid is pumped into the wellbore to replace the fourth fracturing fluid. The diameter of the proppant in the fifth fracturing fluid is within the range of the first preset diameter. The first preset diameter range can be 30 / 50 mesh. The volume ratio of the first solution in the fifth fracturing fluid is lower than that of the second solution. And the volume ratio of the first solution in the fifth fracturing fluid is lower than that in the fourth fracturing fluid.

[0072] Construction displacement gradually increases, reaching the fourth displacement threshold (4.0m). 3When the volume ratio of the first solution in the sixth fracturing fluid is less than that of the second solution, the volume ratio of the first solution in the sixth fracturing fluid is less than that in the fifth fracturing fluid. The proppant in the sixth fracturing fluid is within the range of the second preset diameter. The second preset diameter range can be 40 / 70 mesh. The volume ratio of the first solution in the sixth fracturing fluid is lower than that in the fifth fracturing fluid. The sand-to-liquid ratio in the sixth fracturing fluid is higher than that in the fifth fracturing fluid. The sand-to-liquid ratio is the volume ratio of proppant to liquid in the fracturing fluid.

[0073] Construction displacement gradually increases, reaching the fifth displacement threshold (5.0m). 3 At a rate of ( / min), the seventh fracturing fluid is pumped into the wellbore to replace the sixth fracturing fluid. The seventh fracturing fluid consists of the second solution and a proppant within a third preset diameter range. The diameter of the proppant in the seventh fracturing fluid is within the third preset diameter range. The third preset diameter range can be 70 / 140 mesh. The sand-to-liquid ratio in the seventh fracturing fluid is higher than that in the sixth fracturing fluid.

[0074] In some optional embodiments, the proppant is ceramsite, and the volume ratio of the first solution to the second solution in the first fracturing fluid is nine to one, that is, 90 v% of the first solution and 10 v% of the second solution are mixed to obtain the first fracturing fluid.

[0075] The volume ratio of the first solution to the second solution in the second fracturing fluid is 8:2, that is, 80v% of the first solution and 20v% of the second solution are mixed to obtain the second fracturing fluid.

[0076] The volume ratio of the first solution to the second solution in the third fracturing fluid is 6:4, that is, 60v% of the first solution and 40v% of the second solution are mixed to obtain the third fracturing fluid.

[0077] The volume ratio of the first solution to the second solution in the fourth fracturing fluid is four to six, that is, 40 v% of the first solution and 60 v% of the second solution are mixed to obtain the fourth fracturing fluid.

[0078] The volume ratio of the first solution to the second solution in the fifth fracturing fluid is 2:8; the sand-to-liquid ratio of the fifth fracturing fluid is 10%, that is, 20v% of the first solution and 80v% of the second solution are mixed, and 30 / 50 mesh high-strength ceramic particles are added as proppant to obtain the fifth fracturing fluid.

[0079] The volume ratio of the first solution to the second solution in the sixth fracturing fluid is 1:9; the sand-to-liquid ratio of the sixth fracturing fluid is 15%, that is, 10v% of the first solution and 90v% of the second solution are mixed, and 40 / 70 mesh high-strength ceramic particles are added as proppant to obtain the sixth fracturing fluid.

[0080] The seventh fracturing fluid has a sand-to-liquid ratio of 20%, which is 100% v% of the second solution mixed together, and 70 / 140 mesh high-strength ceramic particles are added as proppant to obtain the seventh fracturing fluid.

[0081] The following specific example illustrates the fracturing method of reducing friction and adding weight:

[0082] Step 1: Taking the KS-11 well, an ultra-deep well in western China, as an example, the specific implementation of this invention will be described. This well is a vertical well with a vertical depth of 7700m in the stimulated section. Pre-fracturing reservoir assessment indicates a high geostress gradient, predicting high construction pressure and significant challenges in high-flow-rate fracturing. To increase the production of the single well after stimulation, large-scale proppant fracturing is required. Simultaneously, to ensure construction safety, 2000m³ of high-density (1.5g / cm³) weighted fracturing fluid is designed, with a designed proppant addition rate of 320m³. 3. According to the technical method of the present invention, firstly, 400 m³ of weighted fracturing fluid A with a density of 1.5 g / cm³ is prepared using soluble inorganic salts (bromine salts). Then, the components for preparing 1600 m³ of weighted fracturing fluid B with a density of 1.5 g / cm³ are prepared. Since the proportion of liquid B is relatively high in the high-displacement stage, the types of B in the prepared fracturing fluid account for about 74%, achieving the goal of maximizing the proportion of low-friction liquid under high displacement, which is more conducive to reducing construction friction at high displacement. B includes 1000 m³ of gel fracturing fluid base, 10 tons of crosslinking agent, and 500 m³ of high-strength spherical solid particles with a particle size of 200 mesh. Fracturing fluid B consists of gel fracturing fluid base + 5% (weakly crosslinked) - 10% (crosslinked gel) crosslinking agent + 60 m% 200 mesh spherical solid particles. After the start of construction, it is mixed in the mixing tank of the sand mixing truck and then directly pumped in. After preparing the above liquid, pump 50 m3 (the tubing string volume from the wellhead to the modified section) of a mixture of 90 v% fracturing fluid A and 10 v% fracturing fluid B through the tubing at a discharge rate of 0.5 m3 / min. In this stage, pump 0.5% crosslinking agent into the mixture to keep it in a weak crosslinking state and ensure that the 200 mesh spherical solid particles do not settle.

[0083] Step 2: Pump the packing ball at a flow rate of 0.5 m³ / min. The liquid type is 90 v% inorganic salt weighted fracturing fluid A + 10 v% solid phase weighted fracturing fluid B. After pumping 20 m³, replace it with 80 v% inorganic salt weighted fracturing fluid A + 20 v% solid phase weighted fracturing fluid B. Pump about 20 m³ of the packing ball until it reaches the packer ball seat position. After setting, increase the flow rate to 1.0 m³ / min. The liquid in the wellbore will gradually become 80 v% inorganic salt weighted fracturing fluid A + 20 v% solid phase weighted fracturing fluid B. The crosslinking agent pumped in this stage is all at a dosage of 1.0% to ensure that the wellbore is in a gel state. The total liquid pumped in this stage is about 60 m³.

[0084] Step 3, as described above, after increasing the pumping rate to 1.0 m³ / min, adjust the pumped fluid to 60v% inorganic salt weighted fracturing fluid A + 40v% solid-phase weighted fracturing fluid B, with a corresponding crosslinking agent dosage of 1%. After pumping a total of 50 m³ of fluid, the fluid in the wellbore will be entirely composed of 60v% inorganic salt weighted fracturing fluid A + 40v% solid-phase weighted fracturing fluid B. Then, increase the pumping rate to 2.0 m³ / min and continue pumping for 50 m³. During this stage, the crosslinking agent dosage is 1% of the pumped fluid. The total fluid used in this step is approximately 100 m³.

[0085] Step four: After completing step three, increase the pumping rate to 3.0 m³ / min. Simultaneously, replace the fluid with 40% inorganic salt-weighted fracturing fluid A + 60% solid-phase-weighted fracturing fluid B, with a crosslinking agent pumping ratio of 1%. After pumping for 20 minutes, the pumped fluid volume is approximately 60 m³, ensuring all fluid in the wellbore is the same as before. Then, at a pumping rate of 3.0 m³ / min, begin adding proppant at a proppant-to-fluid ratio of 10%. Continue this process for 50 minutes at this pumping rate and proppant-to-fluid ratio, with a total fluid volume of 150 minutes and 15 m³ of proppant added. The total fluid volume for this step is 210 m³, and the proppant volume is 15 m³.

[0086] Step 5: After completing Step 4, increase the pumping rate to 4.0 m³ / min and replace the pumped fluid with 20 v% inorganic salt weighted fracturing fluid A + 80 v% solid phase weighted fracturing fluid B. The crosslinking agent pumping ratio remains at 1%, and the entire fluid is in a crosslinked gel state. The sand-to-fluid ratio is increased to 15%. The total pumped fluid volume in this stage is 600 m³, and the sand addition volume is 90 m³.

[0087] Step Six: After completing Step Five, the pumping rate is increased to 5.0 m³ / min. The pumped fluid is replaced with 10 v% inorganic salt weighted fracturing fluid A + 90 v% solid phase weighted fracturing fluid B. The crosslinking agent pumping ratio remains at 1%. The entire fluid is in a crosslinked gel state. The sand-to-fluid ratio is increased to 20%. The total pumped fluid volume in this stage is 800 m³, and the sand addition volume is 160 m³.

[0088] Step 7: After completing Step 6, the pumping rate is increased to 6.0 m³ / min. The pumped fluid is replaced with 100% solid-phase weighted fracturing fluid B. The crosslinking agent injection ratio remains at 1%. The entire fluid is in a crosslinked gel state, and the sand-to-fluid ratio is increased to 25%. The total pumped fluid volume in this stage is 200 m³, and the sand volume is 50 m³. In this step, the pumping rate is adjusted according to the construction pressure. For ultra-deep wells using a 140 MPa wellhead, the pumping rate can be increased as much as possible under a pressure limit of 120 MPa. However, the total fluid volume and total sand volume in this step are controlled within the design range. This completes the well construction. The total fluid volume is approximately 2000 m³, the sand volume reaches 315 m³, the average sand-to-fluid ratio reaches 15.75%, and the total volume of fluid A used is 400 m³, while fluid B used is 1600 m³.

[0089] This invention utilizes different weighting fluids at high and low operating rates to leverage their respective advantages: at low operating rates, soluble salt weighting fluids are used to open the reservoir while reducing the risk of sand blockage (solid phase weighting). Because the absolute total frictional resistance of the fluid is low at low operating rates, it does not significantly increase the wellhead operating pressure. As the operating rate is increased, the proportion of solid phase weighting fluid is gradually increased to maintain a relatively high net pressure in the wellbore. At the same time, frictional resistance does not increase significantly at high operating rates because the absolute frictional resistance along the fluid path increased by the weighting fluid does not exceed the net pressure of the fluid column increased by the weighting fluid, thus leveraging the effect of reducing operating pressure through weighting.

[0090] refer to Figure 2 As shown, Figure 2 This represents the data corresponding to each step in the above process, from steps one to seven. The blue line represents the construction displacement value for each step, and the black line represents the sand-liquid ratio value for each step. Figure 2 As can be seen, no ceramic aggregate was added in steps one through three, therefore the sand-to-liquid ratio was 0. The red line represents the real-time wellhead pressure data. Figure 2 As can be seen from the data, during steps one through three, the wellhead pressure increases significantly with the increase in the discharge rate, and decreases significantly after step seven is completed.

[0091] Unless otherwise specifically stated, terms such as processing, calculation, operation, determination, display, etc., may refer to the actions and / or processes of one or more processing or computing systems or similar devices that represent the manipulation and conversion of data representing physical (e.g., electronic) quantities within the registers or memory of the processing system into other data similarly representing physical quantities within the memory, registers, or other such information storage, transmission, or display devices of the processing system. Information and signals can be represented using any of a variety of different techniques and methods. For example, data, instructions, commands, information, signals, bits, symbols, and chips mentioned throughout the above description can be represented by voltage, current, electromagnetic waves, magnetic fields or particles, light fields or particles, or any combination thereof.

[0092] It should be understood that the specific order or hierarchy of steps in the disclosed process is an example of an exemplary method. Based on design preferences, it should be understood that the specific order or hierarchy of steps in the process may be rearranged without departing from the scope of this disclosure. The appended method claims provide elements of various steps in an exemplary order and are not intended to limit the scope to the specific order or hierarchy described.

[0093] In the detailed description above, various features are combined together in a single embodiment to simplify this disclosure. This approach to disclosure should not be construed as reflecting an intention that embodiments of the claimed subject matter require more features than are explicitly stated in each claim. Rather, as reflected in the appended claims, the invention is presented with fewer features than all of the features in a single disclosed embodiment. Therefore, the appended claims are hereby explicitly incorporated into the detailed description, with each claim representing a separate preferred embodiment of the invention.

[0094] The foregoing description includes examples of one or more embodiments. It is certainly impossible to describe all possible combinations of components or methods in order to describe the above embodiments, but those skilled in the art will recognize that further combinations and arrangements of the various embodiments are possible. Therefore, the embodiments described herein are intended to cover all such changes, modifications, and variations that fall within the scope of the appended claims. Furthermore, the term "comprising" as used in the specification or claims is interpreted in a manner similar to the term "including," as interpreted when used as a conjunction in the claims. Additionally, the use of any term "or" in the specification of the claims is intended to mean "non-exclusive or."

Claims

1. A fracturing method for reducing friction and adding weight, characterized in that, include: Real-time acquisition of the fracturing displacement value during the fracturing process; When the construction flow rate is within the initial flow rate range, a first fracturing fluid is pumped in. The first fracturing fluid includes a first solution and a second solution with a first preset volume ratio. The first solution is a soluble inorganic salt solution, and the second solution is a solid phase fracturing fluid. After the packer is set and the construction flow rate is less than the first flow rate threshold, a second fracturing fluid is pumped in. The second fracturing fluid includes the first solution and the second solution in a second preset volume ratio. When the construction flow rate reaches the first flow rate threshold, a third fracturing fluid is pumped in, the third fracturing fluid comprising the first solution and the second solution in a third preset volume ratio; When the construction flow rate reaches the second flow rate threshold, a fourth fracturing fluid is pumped in, the fourth fracturing fluid comprising the first solution and the second solution in a fourth preset volume ratio; When the construction flow rate reaches the third flow rate threshold, a fifth fracturing fluid is pumped in. The fifth fracturing fluid includes proppant and the first solution and the second solution in a fifth preset volume ratio. When the construction flow rate reaches the fourth flow rate threshold, a sixth fracturing fluid is pumped in. The sixth fracturing fluid includes proppant and a first solution and a second solution in a sixth preset volume ratio. When the construction flow rate reaches the fifth flow rate threshold, a seventh fracturing fluid is pumped in, the seventh fracturing fluid comprising the second solution and proppant; The initial displacement range, the first displacement threshold, the second displacement threshold, the third displacement threshold, the fourth displacement threshold, and the fifth displacement threshold increase sequentially; In the first fracturing fluid, the second fracturing fluid, the third fracturing fluid, the fourth fracturing fluid, the fifth fracturing fluid, and the sixth fracturing fluid, the volume percentage of the first solution decreases sequentially; and in the first fracturing fluid, the second fracturing fluid, and the third fracturing fluid, the volume percentage of the first solution is greater than the volume percentage of the second solution, while in the fourth fracturing fluid, the fifth fracturing fluid, and the sixth fracturing fluid, the volume percentage of the first solution is less than the volume percentage of the second solution. The diameter of the proppant in the fifth fracturing fluid is within the range of the first preset diameter; The diameter of the proppant in the sixth fracturing fluid is within the range of the second preset diameter; The diameter of the proppant in the seventh fracturing fluid is within the range of the third preset diameter; The proppant-to-liquid ratio in the fifth, sixth, and seventh fracturing fluids increases sequentially, and the proppant-to-liquid ratio is the volume ratio of proppant to liquid in the fracturing fluid.

2. The method as described in claim 1, characterized in that, The density of the first solution is 1.5 g / cm³. 3 .

3. The method as described in claim 1, characterized in that, The second solution comprises solid spherical particles and gel fracturing fluid; The density of the second solution is the same as that of the first solution.

4. The method as described in claim 3, characterized in that, The solid spherical particles have a particle size of 200 mesh and are insoluble.

5. The method as described in claim 1, characterized in that, The volume ratio of the first solution to the second solution in the first fracturing fluid is nine to one; The volume ratio of the first solution to the second solution in the second fracturing fluid is eight to two. The volume ratio of the first solution to the second solution in the third fracturing fluid is six to four. The volume ratio of the first solution to the second solution in the fourth fracturing fluid is four to six. The volume ratio of the first solution to the second solution in the fifth fracturing fluid is 2:8; the sand-to-liquid ratio of the fifth fracturing fluid is 10%. The volume ratio of the first solution to the second solution in the sixth fracturing fluid is 1:9; the sand-to-liquid ratio of the sixth fracturing fluid is 15%. The sand-to-liquid ratio of the seventh fracturing fluid is 20%.

6. The method as described in claim 1, characterized in that, The proppant is ceramsite.

Images