Source Analysis and Countermeasure Research of Sand Production after Hydraulic Fracturing in Tight Sandstone Gas Reservoir

Hydraulic fracturing technology is the most effective stimulation method for enhancing hydrocarbon production, especially in the tight gas, shale gas, and other unconventional oil and gas resources. It improves the permeability of formation by breaking down rocks and forming a large number of fractures through the injection of fluids at sufficiently high pressure. The induced fractures are then kept open via proppant placement, which is pumped in the form of slurries [1–5]. Proppant is the hard solid particles at a certain size, typically between 8 and 140 mesh, such as sand or ceramic particles, which is mixed with fracturing fluid in order to keep fractures open after hydraulic fracturing treatment [6–8]. The results of proppant applications in oilfield clearly demonstrate the necessity of achieving and maintaining near-wellbore conductivity. The performance of the proppant is of utmost importance and is affected by many factors. This includes the properties of the proppant itself, the properties of the formation, and the transportation system.

Sand production or proppant flowback is the most common problem after hydraulic fracturing treatment [9–11]. This problem is particular prominent in sandstone reservoirs, which are common to observe in a majority of the oil and gas reservoir fields. Typical substances of the sandstone reservoir are quartz, mica, rock fragments, and different type of mineral grains with silica, cements, or clay [12]. In weakly consolidated sandstone reservoirs, sand particles will start to erode from weak sandstone formations for different reasons, such as shear and tensile failures, erosion and transportation of fine particles, strength, permeability, and pressure distribution. And sand production may cause many undesirable problems including filling and blocking of wellbores, wellbore collapse, plugging of perforations or flowlines, erosion failure of downhole and surface facilities, and additional cost of remedial and cleanup operations [13, 14]. Many reasons account for proppant flowback, such as high drag forces of the fluid with high velocity, low fracture closure stress, mechanical properties of the treated formation, high viscous of the produced fluid, and improper size or density of proppant. Proppant flowback has a lot of adverse effects, such as narrowing down the width of the fracture, reducing the conductivity of the fracture, and decreasing the effectiveness of the treatment. Moreover, the proppant flowback will erode downhole equipment, as well as surface pipelines and equipment, shortening their service lives. In some cases, well potential must be suppressed to reduce sand production within the facilities limits, and some wells may even be abandoned due to lower economic production rates. In addition, if proppant backflow is too much, downhole remedial operations are needed for wells, such as sand cleanout and disposal operations, which increases the overall cost to operators and leads to increased nonproductive time, environmental impact mainly from solids disposal, and significant production decline as the fracture conductivity diminishes over time [15, 16].

Sand production or proppant flowback has always been a challenge in hydraulic fracturing. For decades, the problem of sand production or proppant flowback has been approached with the use of sand avoidance techniques, called sand control methods [17]. These methods involve mechanical sand control, chemical sand control, and physical sand control. Mechanical sand control is by lowering the screen or slotted liner into the sand control section of the well and then carrying the gravel with the preferred appropriate particle size with the fluid and filling it between the screen and the formation or casing. It is a sand control method to form a gravel layer with a certain thickness and use it to prevent formation sand from flowing into the well. The particle size of packed gravel shall be matched according to the particle size of reservoir sand. The sand particles in the formation are blocked outside the gravel layer and accumulate outside the gravel layer through natural selection to form a coarse to fine sand arch, which not only has good flow capacity but also can effectively prevent sand production in the formation [18–20]. But mechanical sand control is not applicable to prevent sand production in fine silty sand formation and downhole tools from lefting in the well after construction. Overhaul and removal are often required in operations such as hydraulic fracturing treatment. Chemical sand control is a method to reconsolidate the formation and prevent sand from flowing with resin or other chemical agents, such as epoxy resin, phenolic resin, furfural resin, and furfuralcohol resin, to coat the propants, which pointed out that choosing the appropriate resin for different conditions can prepare effective resin-coated proppant (RCP) to prevent proppant flowback. The coating can either be precured (fully cured during manufacturing) or curable (cured in the formation fractures). The curable resin-coated proppants are typically used in formations, whereby there is a tendency of proppant flowback during production operations. This is prevented by the formation of a consolidated pack as the curable coatings bonded each grain on their surface, resisting the flowback [21, 22]. Since silica sand is the most commonly used proppant, development efforts were mainly focused on this surface. Use amino-containing polymer as coating material can achieve good binding to the sand surface. This on-the-fly chemical additive will pour liquid resin with untreated proppants into the fracturing fluid. During stirring, on-the-fly chemical additive is absorbed onto the sand. The on-the-fly chemical additive cures under formation conditions, and proppants pack with high compressive strength is formed [23]. In general, the chemical sand control usually perform well in proppant flowback control, but usually cause significant reduction in the permeability of the proppant pack. Physical sand control is a method which uses special functional materials to achieve sand control effect, such as fiber and unconventionally shaped proppant. Injecting fibers with the proppants into the fracturing fluid is another effective method in proppant flowback control [24]. Unlike chemical reactions of resin-coated proppants, fibers provide framework and bond the proppants together only by physical bondage effect. So there is no obvious impact to the permeability of the proppant pack. However, fibers are easy to break into smaller fragments and cause blockage in the injection or lead to a weakened framework in the fracture [25, 26]. Proppants have been engineered into rod or X-shaped forms to provide physical proppant flowback solutions. The unique geometries are believed to enhance proppant flowback control due to the interlocking tendencies of the particles. Since these designed ceramics are likely relatively costly to make, and their performance in proppant flowback control is largely unproven, they have not yet been widely used [27, 28].

In this study, based on the analysis of sand production source, it is clear that the sand production mainly is 70/140 mesh sand flowback after in hydraulic fracturing treatment. In order to control this proppant flowback, a series of laboratory evaluations are designed to quantify the effectiveness of fibers on proppant flowback control, so as to explore the mechanisms behind for optimizing their properties for a chosen reservoir. The key fiber properties include dispersion performance, microstructure, the influence on proppant transport in fracture, fracture conductivity, and critical flowrate. The field test is carried out through the fiber type and dosage optimized by indoor experiment. A systematic indoor evaluation and field test shows that fiber plays a significant role in proppant flowback control.

The channel sand of Shaximiao formation, a tight sandstone in Jinqiu gas field, Sichuan Basin, is widely distributed, which has the geological conditions for large-scale oil and gas accumulation. The area is vertically superimposed with 23 river courses, which is generally a lithologic gas reservoir of “one river and one reservoir” or “one river and multiple reservoirs,” the plane distribution of tight gas channel sand formation of Shaximiao formation in Sichuan Basin is shown in Figure 1. High quality hydrocarbon sources, high quality river sand bodies, and multilevel fault system jointly control the accumulation of oil and gas reservoirs. The reservoirs depth is 1500-2800 m, the cumulative thickness of the reservoir is 20-70 m, the reservoir rock type is mainly medium fine-grained arkose, followed by lithic arkose, the intergranular pore filler is mainly clay, the cement is mainly calcareous, the reservoir porosity is mainly 8-15%, the permeability is mainly 0.01-1.00 mD, and the geothermal gradient is 1.9°C-2.5°C/100 m. The pressure coefficient is 0.85-1.05, belonging to normal temperature and pressure tight gas reservoir [29–33].

The integrated practice of exploration and development in Jinqiu gas field has achieved remarkable results. Through three process tests, large displacement pump is used to inject variable viscosity slickwater, and the combination of 70/140 mesh sand and 40/70 mesh resin coated sand is used to create a high-strength and low damage multifracture fracturing technology for horizontal wells. The relevant hydraulic fracturing treatment engineering parameters are shown in Table 1.

In order to improve the flowback speed and flowback rate of fracturing fluid, shorten the contact time between fracturing fluid and formation to reduce reservoir damage, the well is often opened in time after fracturing, and the large nozzle is used to drain the fluid and the forced drainage measures with large driving force such as liquid nitrogen mixing and injection, gas lift, and suction are adopted to make the proppant return or formation sand return to the wellhead with the fracturing fluid or gas flow. The sand production of Jinqiu gas field, Sichuan Basin is shown in Figure 2.

It can be seen from Figure 2 that the average sand production is 103 tons, and the sand production rate is 2.36% through statistics of 12 wells. The sand production after fracturing will seriously damage the wellhead nozzle, needle valve, gate, elbow, and other ground facilities, as shown in Figure 3. Because of the sand plug of downhole tools and the closure of proppant fracture, the conductivity of proppant fracture is reduced, and the oil and gas well stimulation effect after fracturing is affected. In addition, after the proppant returns to the wellbore, it is also a life-threaten to the on-site construction workers, which is very harmful.

Sand production after hydraulic fracturing treatment may come from proppant used in fracturing operation or sand production in weakly consolidated sandstone reservoirs. As the foundation of sand control design, sand production source analysis is extremely important work to clarify the sand production mechanism and law, which can offer strong support for sand control optimization. Enhance the stability of fracturing sand in propped fractures, prevent or reduce the massive migration of sand particles in fractures, effectively control the backflow of proppant into the wellbore, reduce various adverse effects caused by sand production, and ensure the safe and efficient production of oil and gas fields.

Based on the sand production after hydraulic fracturing treatment, fracturing sand, and downhole core of Jinqiu gas field in Sichuan Basin, the relevant experimental evaluation and analysis such as appearance, scanning electron microscope, apparent density, mineral composition, and sieve analysis are carried out to clarify the source of sand production after hydraulic fracturing treatment in tight sandstone. The appearance and scanning electron microscope are shown in Figures 4 and 5, and the experimental results of apparent density, mineral composition, and sieve analysis are shown in Table 2.

It can be seen from Figure 4, Figure 5, and Table 2 that the appearance color of the sand production sample after hydraulic fracturing treatment is different from that of the downhole core sample. The apparent density of the sand production sample after hydraulic fracturing treatment (2.66-2.67 g/cm³) is higher than that of the downhole core sample (2.25-2.45 g/cm³), the quartz content of the sand production sample after hydraulic fracturing treatment (99-100%) is much higher than that of the downhole rock core sand sample (20-53%), and the particle size distribution of the sand production sample after hydraulic fracturing treatment (106-212 μm) is larger than the particle size distribution of downhole core sample. Therefore, it can be judged that the sand produced after hydraulic fracturing treatment is not the same as the downhole core sample. At the same time, the appearance, apparent density, quartz content, particle size distribution, and microstructure of the sand produced after hydraulic fracturing treatment are close to the parameters after the pressure crushing test of 70/140 mesh sand, but significantly different from the appearance color and particle size distribution of 40/70 mesh resin-coated sand, and noncoated sand is found on the sand produced after hydraulic fracturing treatment. Therefore, comparative analysis shows that the main source of sand production after fracturing is 70/140 mesh fracturing sand flowback.

The sand production source analysis in Jinqiu gas field, Sichuan Basin is clarified that the sand is fracturing sand flowback. So proppant flowback control design is needed to enhance the stability of fracturing sand in proppant fractures, prevent or reduce the massive migration of sand particles in fractures, and effectively control the backflow of proppant into the wellbore. The oil and gas industry developed several methods to control proppant flowback following hydraulic fracturing.

40/70 mesh resin-coated sand and combined particle size sand have been used in Jinqiu gas field in Sichuan basin in order to further control proppant flowback. A cooperation to resin-coated sand is the fiber-network proppant flowback control technique. Fibers have also been used to stabilize proppant packs. When fibers are mixed with proppant and then pumped downhole, the fibers form a net-like structure that reinforces the pack and holds the proppant in place, allowing oil and gas to flow as shown in Figure 6.

Fibers are white silky fibrous material. As a result of the manufacturing process, most of the fibers are assembled in bundles. The fibers are easily separated and diverged from these bundles when mixed with a fluid. The polymer used to make the fibers is chemically inert and has very high stability at elevated temperatures in hydrocarbons, water, acid, and alkali solutions. Fibers with average length of about 3 mm, 6 mm, 9 mm, and 12 mm are selected to proppant flowback control experimental study.

The experiment uses fibers length is 3 mm, 6 mm, 9 mm, and 12 mm, and slickwater, 70/140 mesh sand, and 40/70 mesh coated sand for fracturing in Jinqiu gas field. The appearance of fibers with different lengths is shown in Figure 7. The properties of slickwater and proppant are shown in Tables 3 and 4.

To evaluate the fiber dispersion, first weigh fibers of different concentrations (0.2%, 0.4%, and 0.6%) and lengths (3 mm, 6 mm, 9 mm, and 12 mm) into a beaker, measure 100 mL of slickwater and introduce it into the beaker containing fiber, stir the fiber with a glass rod, and stand for 5 min to observe the dispersion in water. The dispersion performance of fiber can be judged by the state of fiber in slickwater.

The scanning electron microscope equipment used in microstructure experiments is mainly composed of electron microscope, electron gun filament, vacuum system, automatic sample, and image acquisition and processing system. The maximum magnification is 150000 times, and the resolution is better than 10 nm, so it can quickly obtain high-quality images with rich surface details, which can be used to measure submicron or nanoscale samples.

In the microstructure experiments, after mixing different lengths fibers with 70/140 mesh sand, observe the microstructure of entangled fibers and sand.

The proppant transport visualization experimental equipment used in evaluation proppant transport performance in hydraulic fractures is shown in Figure 8. It is mainly composed of liquid supply and pumping system, sand mixing system, visual fracture system, liquid recovery system, and data acquisition and control system. The fracture width is 0.1-1 cm, the fracture height is 60 cm, the fracture length is 400 cm, the maximum displacement is 200 L/min, the maximum liquid viscosity is 100 mPa·s, the volume of liquid storage tank is 300 L, the maximum temperature is 90°C, the maximum pressure resistance is 1.2 MPa, and the applicable proppant type is various proppant particles of 20-140 mesh. Through the transparent plexiglass of the visible fracture system, the flow state of fracturing fluid or sand carrying fluid in the fracture and the transport and placement of proppant can be clearly observed.

In the proppant transport performance, the experimental displacement is 80 L/min, and the sand concentration is 300 kg/m³. Evaluated the effects of different fiber lengths (3 mm, 6 mm, 9 mm, and 12 mm) and different fiber concentrations (0.2%, 0.4%, and 0.6%) on the transport and placement of 70/140 mesh sand and 40/70 mesh resin-coated sand.

The propped fracture conductivity device is shown in Figure 9. It is mainly composed of hydraulic press, advection pump, intermediate container, flowmeter, pressure sensor, vacuum pump, back pressure valve, electronic balance, diversion chamber, displacement sensor, and heating rod, etc. The equipment parameters are as follows: the maximum closing pressure is 100 MPa; the temperature is normal temperature to 90°C; the displacement is 0-10 mL/min; the area of diversion chamber is 64.5 cm²; the differential pressure sensor is 0-10 kPa.

In the propped fracture conductivity experiment, the laying concentration of 70/140 mesh sand and 40/70 mesh coated sand is 5 kg/m², and the closing pressure is 30 MPa. The laying concentration is converted from the sand concentration during on-site fracturing construction, and the closing pressure is obtained by subtracting the formation fluid pressure (20 MPa) from the minimum principal stress of the formation (50 MPa). Evaluated the effects of different fiber lengths (3 mm, 6 mm, 9 mm, and 12 mm) and different fiber concentrations (0, 0.2%, 0.4%, and 0.6%) on the conductivity of 70/140 mesh sand and 40/70 mesh resin-coated sand.

In the critical flowrate experiment, different fiber concentrations (0, 0.2%, 0.4%, and 0.6%) are added to 70/140 mesh sand and 40/70 mesh coated sand. Under the closing pressure of 30 MPa, the sand production under different displacement (45-125 mL/min) is collected to evaluate the influence of fiber with different length and concentration on proppant flowback.

After the fracturing fiber is mixed with proppant in the sand mixer, it enters the hydraulic fracture through the fracturing pump truck, surface pipeline, wellbore, and perforation. Initially, fiber is in bundle or cluster shape. If fiber is not evenly dispersed in slickwater, agglomeration may occur, resulting in blockage of flow channel and hydraulic fracturing treatment failure. Therefore, it is required that the fiber should have good dispersion in slickwater.

The dispersion evaluation results of fibers with different lengths and concentrations in slickwater are shown in Table 5. It can be seen from the table that the dispersion of fibers with different lengths and concentrations in slickwater is good.

The fiber in the fracture through a variety of mechanisms stabilizes the sand-filling beds. Each fiber contacts with several proppant particles to form a spatial network structure through the interaction of contact pressure and friction, so as to provide additional bonding force between sand and fracture, so as to stabilize the proppant in the original position, and the fluid can pass freely, so as to improve the stability and critical flowback flowrate of sand-filling beds.

The experimental results of microstructure of different length fibers with sand are shown in Figure 10. It can be seen from Figure 10 that fibers with different lengths have the potential to improve the filling layer of sand.

Master the performance of proppant settlement and transport in the fracture, and understand the law of proppant placement, roll up, and proppant dune distribution in the hydraulic fracturing treatment, so as to optimize the stimulation treatment materials and optimize the hydraulic fracturing parameters. The experimental results of proppant transport distance of 70/140 mesh sand and 40/70 mesh resin-coated sand under different fiber lengths (3 mm, 6 mm, 9 mm, and 12 mm) and different fiber concentrations (0.2%, 0.4%, 0.6%) are shown in Figure 11.

For 70/140 mesh sand, under the same fiber length, the sand transport distance increases by 3.5-18.0% with the increase of fiber concentration, and the increase is relatively uniform. At the same fiber concentration, the transport distance increases with the increase of fiber length, and the increase of migration distance is greater with the increase of fiber length. When the concentration of 12 mm fiber is 0.6%, the transport distance increases by 18.0%.

For 40/70 mesh resin-coated sand, under the same fiber length, the transport distance increases by 3.0-14.2% with the increase of fiber concentration, and the increase is relatively uniform. At the same fiber concentration, the transport distance increases with the increase of fiber length, and the increase of migration distance is greater with the increase of fiber length. When the concentration of 12 mm fiber is 0.6%, the migration distance increases by 14.2%.

At the same time, it is found that when the length and concentration of fiber are the same, the influence to migration distance of fiber to 70/140 mesh sand is 0.5-3.8% larger than that of 40/70 mesh coated sand.

Due to the interaction between fiber and sand, as shown in Figure 12, the settlement rate of sand is reduced, and the settlement rate of sand is inconsistent, which is conducive to the transport of sand further into the fracture. The farther away most sand is from the perforation tunnel during hydraulic fracturing treatment, the more difficult it is to migrate to the perforation tunnel after treatment. Therefore, fiber helps to inhibit the flowback of sand.

Researchers at home and abroad have conducted a lot of research on fiber sand control. The results show that after mixing fiber in proppant, because it partially fills the pore between proppant particles and occupies part of the fluid flow space, although it greatly reduces the proppant flowback rate, it also reduces the conductivity of hydraulic fractures. Therefore, it is necessary to explore the damage of fiber parameters to the conductivity.

The experimental results of propped fracture conductivity of 70/140 mesh sand and 40/70 mesh resin-coated sand under different fiber lengths (3 mm, 6 mm, 9 mm, and 12 mm) and different fiber concentrations (0.2%, 0.4%, and 0.6%) are shown in Figure 13. Some experimental results are shown in Figure 14.

For 70/140 mesh sand, under the same fiber length, the propped fracture conductivity decreases by 6.9-71.9% with the increase of fiber concentration; when the fiber concentration is greater than 0.4%, the propped fracture conductivity decreases significantly. At the same fiber concentration, the propped $t$ fracture conductivity decreases with the increase of fiber length. When the fiber length is more than 6 mm, the decrease of propped fracture conductivity is more than 20%. When the concentration of 9 mm fiber is 0.2%, the propped fracture conductivity decreases by 25.5%.

For 40/70 mesh resin-coated sand, under the same fiber length, the propped fracture conductivity decreases by 14.7-59.4% with the increase of fiber concentration, when the fiber concentration is greater than 0.4%, the propped fracture conductivity decrease significantly. At the same fiber concentration, the propped fracture conductivity decreases of fiber length. When the fiber length is more than 6 mm, the decrease of propped fracture conductivity is more than 20%. When the concentration of 9 mm fiber is 0.2%, the propped fracture conductivity decreases by 26.4%.

At the same time, fibers with a length of less than 6 mm have a greater reduction in the propped fracture conductivity of 40/70 mesh resin-coated sand, and fibers with a length of more than 6 mm have a greater reduction in the propped fracture conductivity of 70/140 mesh sand.

The stability of proppant filling beds was investigated by measuring the critical sand production velocity. Add proppant and fiber into the fracture conductivity chamber, and test the change of critical sand production velocity of sand filling beds with and without fiber under the conditions of different viscosity fluid and different fiber concentration, so as to obtain the influence of fiber on the stability of sand filling beds, which can also be used as the basis for the selection of flowback flowrate after fiber fracturing.

The experimental results of critical flowrate of 70/140 mesh sand and 40/70 mesh resin-coated sand under different fiber lengths (3 mm, 6 mm, 9 mm, and 12 mm) and different fiber concentrations (0.2%, 0.4%, and 0.6%) are shown in Figure 15.

For 70/140 mesh sand, under the same fiber length, the critical flowrate increases by 4.0-44.0% with the increase of fiber concentration; when the fiber concentration is greater than 0.4%, the critical flowrate increase is little. At the same fiber concentration, the critical flowrate increases with the increase of fiber length, and the increase is relatively uniform.

For 40/70 mesh resin-coated sand, under the same fiber length, the critical flowrate increases by 2.0-20.0% with the increase of fiber concentration; when the fiber concentration is greater than 0.4%, the critical flowrate increase is little. At the same fiber concentration, the critical flowrate increases with the increase of fiber length, and the increase is relatively uniform.

At the same time, the increase of critical flowrate of 70/140 mesh sand by fiber is higher than that of 40/70 mesh resin-coated sand.

In summary, through fiber dispersion evaluation and microstructure evaluation, different fiber lengths (3 mm, 6 mm, 9 mm, and 12 mm) and different fiber concentrations (0.2%, 0.4%, and 0.6%) can uniform dispersion in slickwater, and have the potential to improve the filling layer of sand. However, when the fiber concentration exceeds 0.4%, the critical flow rate is not greatly improved, and the conductivity of 9 mm and 12 mm fibers is significantly reduced. Therefore, 3 mm and 6 mm fibers are selected with the dosage of 0.4% to carry out the field test.

Combined with the analysis of sand production source and the experimental research of proppant flowback control, the field tests of 3 mm fiber and 6 mm fiber are carried out. Taking well jq-511-6-H1 of Jinqiu gas field in Sichuan Basin as an example, this well is designed to fracturing in 21 stages, using low-temperature all metal dissolvable bridge plug as segmentation tool, and the liquid is variable viscosity slickwater. The design injection volume is 31000 m³, the design construction displacement is 18 m³/min, the proppant is 40/70 mesh coated sand+70/140 mesh sand, and the stepped sand adding mode is adopted, with the design maximum sand concentration is 480 kg/m³. The amount of sand added is 8200 t, and fiber added is 6300 kg, including 40/70 mesh coated sand mixed with 0.4% fiber (6 mm) and 70/140 mesh sand mixed with 0.4% fiber (3 mm). The fiber injection device and the sand fracturing construction curve of number 13 stages are shown in Figures 16 and 17. After fracturing treatment, the well blowout and drainage for 13 days, the natural gas test output is 834300 m³/day, the sand production is 19 tons, and the sand production rate is only 0.2%. The sand production is significantly lower than that in the early stage, indicating that the fiber has good proppant flowback effect.

• (1)

  Sand production is the most common problem after hydraulic fracturing treatment. This problem is particular prominent in sandstone gas reservoirs. In Jinqiu gas reservoir of Sichuan Basin, the sand production after fracturing is 45-180 tons, and the sand production rate is 0.97-5.09%. The sand production will seriously damage the downhole equipment and other ground facilities. Choose the sand production after fracturing, fracturing sand, and downhole core; the appearance, scanning electron microscope, apparent density, mineral composition, and sieve analysis are carried out to clarify the source; the results show that the main source of sand production after fracturing is 70/140 mesh fracturing sand flowback

• (2)

  In order to control proppant flowback in Jinqiu gas reservoir of Sichuan Basin, fibers with average length of about 3 mm, 6 mm, 9 mm, and 12 mm are selected to proppant flowback control experimental study. A series of laboratory evaluations are designed to quantify the effectiveness of fibers on proppant flowback control. The key fiber properties include dispersion performance, microstructure, the influence on proppant transport in fracture, fracture conductivity, and critical flowrate. The dispersion of fibers with different lengths and concentrations in slickwater is good, and the fibers can form a net-like structure that reinforces the pack, and for 70/140 mesh sand and 40/70 mesh resin-coated sand, with the increase of fiber length and concentration, the sand transport distance and critical flowrate increase, but fracture conductivity decreases

• (3)

  The field test is carried out through the fiber type and dosage optimized by indoor experiment. After fracturing treatment, the sand production is 19 tons, and the sand production rate is only 0.2%. The sand production is significantly lower than that in the early stage, indicating that the fiber plays a significant role in proppant flowback control. The findings of this study can help for a better understanding of the source analysis and countermeasure research of sand production after hydraulic fracturing in tight sandstone gas reservoir

The experimental data used to support the findings of this study are included within the article.

The authors declare that they have no conflicts of interest.

This work is funded by the Scientific Research and Technology Development Project of Southwest Oil and Gas Field Company, petrochina, Project no: 20210302-05.