A fracturing water control and gas production method for low-permeability high-water-saturation gas reservoirs

Abstract

This invention provides a method for fracturing and controlling water production in low-permeability, high-water-saturation gas reservoirs. The method includes: identifying the target well and target layer and perforating in the upper and middle sections; sequentially injecting fracturing fluid pre-flush fluid, fracturing fluid carrying sand, and fracturing fluid displacement fluid containing a fracturing thickener, a breaker, and water through the perforation holes to fracture the target well and target layer; shutting in the well after fracturing until the fracturing fluid breaks down, then opening the well for fracturing fluid flowback and subsequent production; wherein the water-controlling material can trigger coalescence at temperatures of 70-120℃ and formation water salinity of 10000-80000 mg / L, with a coalescence time of 30-60 minutes; the median particle size after coalescence is more than 10 times that before coalescence, while the median particle size before coalescence is 1 / 6 to 1 / 3 of the median pore diameter of the target well and target layer.

Description

Technical Field

[0001] This invention relates to the field of low-permeability, high-water-cut gas fracturing and extraction, specifically to a construction method for controlled water extraction of gas from high-water-cut gas reservoirs. Background Technology

[0002] As natural gas plays an increasingly important role in industrial energy, natural gas extraction has gradually become a focal point of energy development. The exploration and development of unconventional natural gas wells is challenging, and the development of water-bearing and high-water-cut gas reservoirs has gradually become a key project in the current exploration and development research field.

[0003] For some low-permeability, high-water-saturation gas wells, conventional fracturing operations improve both the flow properties of the gas and the flow properties of formation water in the porous medium, ultimately leading to water production and a high water-to-gas ratio. Developing low-permeability, high-water-saturation gas reservoirs is a highly significant undertaking. If certain technologies can be employed to directly address the high water-to-gas ratio problem in later production stages during fracturing in high-water-cut gas reservoirs, it can not only reduce processing costs and increase economic benefits but also avoid the problem of handling large amounts of produced water in drainage processes, mitigating environmental pollution, formation sand production, pipeline corrosion, and scaling. This research is particularly necessary for wells producing water where drainage production technology is costly or where on-site conditions do not allow for such technology.

[0004] Currently, a series of technologies have been gradually studied for the development of low-permeability, high-water-saturation gas reservoirs. Among these, for reservoirs with different gas and water layers, the following technologies are employed: ① Using casing sliding sleeves and mechanical isolation, diagnostic techniques are used to identify gas-producing and water-producing layers, and isolation technology is used to isolate the water-producing layer, effectively reducing the water-to-gas ratio during gas well production and ensuring normal gas well production; ② For low-permeability reservoirs with bottom water, during reservoir stimulation, high-strength artificial baffles are installed between the bottom water layer and the upper gas layer to seal the bottom water layer and achieve water shut-off and gas production. For low-permeability, high-water-saturation gas reservoirs, the following technologies are employed: ① Adding hydrophobic proppant to the fracturing fractures. The hydrophobic proppant artificially supports the fractures, forming capillary force to prevent water from entering the fractures and wellbore, thereby achieving water-controlled gas production. For example, invention application 201810272901.4 provides a fracturing method for water-bearing gas wells. During the fracturing process, a gas-water two-phase support material is laid within the artificial fractures to form gas-water two-phase channels. Relying on gravity and the support of the fractures, the underground gas and water phases are separated and extracted, improving the recovery rate of inefficient water-bearing gas wells. However, because the hydrophobic proppant in this process only exists within the artificial fractures formed by fracturing, its effective range is small and its effect is weak. ② A general gas well water shut-off fracturing process. For example, invention application 201510226350.4 discloses a construction method for water control in gas reservoirs, using an atomized gel plugging agent; invention application 201910124436.4 discloses a selective water control method in tight gas, using a gel formed by polyacrylamide and the additive cadmium acetate; invention application 202010187658.3 discloses a gel prepared using chemical materials such as nanoparticles, polyacrylamide, and crosslinking agents, suitable for water control in high-water-cut, low-permeability gas reservoirs and high-sulfur natural gas wells. However, the selectivity of gel chemical plugging agents is poor, resulting in high risks and low success rates for water plugging in gas wells. For example, invention application 201910124436.4 discloses a method for improving the recovery rate of bottom-water gas reservoirs by controlling water with carbon dioxide in horizontal wells. This method uses carbon dioxide gas to suppress the conical advance rate of bottom water, which can increase the waterless gas production period of gas wells. However, for gas wells that have already been flooded, there is no effective water control and plugging technology for gas production. ③ For high water-cut gas reservoirs, large-scale volumetric fracturing is employed to create numerous high-conductivity fractures, coupled with surface drainage equipment, to achieve both drainage and gas production—a intensive drainage and extraction approach. However, this approach presents the challenge of handling large amounts of highly salinized produced water. Furthermore, the intensive drainage and extraction process drastically reduces formation energy, ultimately lowering the reservoir's recovery rate.

[0005] The main reasons for the poor water control and plugging effect of traditional gas wells are: (1) the chemical plugging agent system for gas wells has poor selectivity. Since high water content gas wells generally exhibit two-phase flow of water and gas, it is easy to cause both water and gas to be plugged; (2) the gas reservoir pressure coefficient is low and the reservoir permeability is low, making it easy to be contaminated by external liquids, resulting in a sharp decline in production capacity after the measures are taken; (3) the water plugging technology for gas wells is difficult and the supporting process has poor adaptability.

[0006] In summary, due to the significant risks associated with water-controlled fracturing in gas wells, there are currently no effective development methods for gas reservoirs with high water saturation and co-existing gas and water layers. Therefore, there is an urgent need to establish fracturing and water-controlled gas production technologies for low-permeability gas reservoirs with high water saturation. Summary of the Invention

[0007] The purpose of this invention is to provide a fracturing water control and gas production technology solution suitable for low-permeability, high-water-saturation gas reservoirs, which can effectively block the large pore channels of water production without affecting the flow guidance capacity of the non-water-producing gas flow channels.

[0008] To address the aforementioned problems, this invention provides a method for hydraulic fracturing and water-controlled gas production in low-permeability, high-water-saturation gas reservoirs, wherein the method includes:

[0009] 1) Determine the target layer of the target well and perform perforation in the upper section of the target layer; wherein, the sand layer thickness of the target layer is greater than 4m, the water saturation is 45%-80%, the average permeability is 0.05-10mD, the reservoir temperature is 70℃-120℃, and the formation water salinity is 10000-80000mg / L; the upper section of the target layer refers to the position between the top surface of the target layer and 1 / 2 of its thickness;

[0010] 2) Perform fracturing operations on the target well and target formation, including:

[0011] By injecting pre-fracturing fluid carrying water control agent into the target layer of the target well through the perforation holes in the upper section of the target layer, fracturing fluid carrying sand and fracturing fluid displacement fluid are injected in sequence to fracture the target layer of the target well.

[0012] Among them, the water control agent is a trigger-type nano water control material. The trigger-type nano water control material can trigger aggregation under the conditions of temperature 70-120℃ and formation water salinity 10000-80000 mg / L, and the aggregation time is 30-60 min. The median particle size after aggregation is more than 10 times the median particle size before aggregation. The median particle size before aggregation is 1 / 6-1 / 3 of the median pore diameter of the target well and the target layer.

[0013] 3) After the fracturing operation is completed, shut in the well until the fracturing fluid breaks down, then open the well to flow back the fracturing fluid and start production.

[0014] This invention provides a fracturing and water-controlled gas production method for low-permeability, high-water-saturation gas reservoirs. For specific well sections, the method utilizes the combined action of fracturing fluid pre-flush fluid carrying sand and fracturing fluid, and fracturing fluid displacement fluid to pre-place the trigger-type nano-water-controlling material in the reservoir matrix pores at the fracture front. In high-water-cut channels, when formation water comes into contact with the pre-placed trigger-type nano-water-controlling material in the matrix, the material agglomerates and expands under the influence of temperature and high-salinity formation water, forming large-sized solid particles that block the high-permeability water flow channels. In waterless channels, the water-controlling material does not agglomerate, thus not blocking the gas-producing pore channels. This achieves effective blocking of large-pore water-producing channels without affecting the flow capacity of non-water-producing gas channels, thereby achieving the goal of fracturing and water-controlled gas production in low-permeability, high-water-saturated gas reservoirs.

[0015] In this invention, a low-permeability, high-water-saturation gas reservoir refers to a gas reservoir with a permeability of 0.01-10 mD and a water saturation of >30%.

[0016] According to a preferred embodiment of the fracturing water control and gas production method for low-permeability, high-water-saturation gas reservoirs, the trigger-type nano-water control material is preferably a colloidal solution of nanoparticles surface-modified with a silane coupling agent; wherein the nanoparticles are a mixture of at least one of TiO2, CaCO3, and fullerene with SiO2; and the mass content of SiO2 is 60-80% based on the total mass of the nanoparticles as 100%.

[0017] More preferably, the shape of the nanoparticles may be, but is not limited to, at least one of spherical, near-spherical, rod-shaped, and sheet-like;

[0018] More preferably, the silane coupling agent is selected from at least one of 3-aminopropyltrimethoxysilane, 3-aminopropyltriethoxysilane, and N-2-aminoethyl-3-aminopropyltrimethoxysilane.

[0019] More preferably, the triggered nano-water-controlling material is prepared by the following method:

[0020] A silane coupling agent is mixed with an alcohol solvent and water to prepare a silane coupling agent dispersion; more preferably, based on the total mass of the silane coupling agent dispersion as 100%, the mass content of the silane coupling agent is 10-15%, and the mass content of the alcohol solvent is 70-80%; more preferably, the alcohol solvent is ethanol.

[0021] Nanoparticles are mixed with an alcohol solvent and water to prepare a nanoparticle dispersion; more preferably, based on the total mass of the nanoparticle dispersion as 100%, the mass content of nanoparticles is 10-20%, and the mass content of alcohol solvent is 3-8%; more preferably, ethanol is selected as the alcohol solvent.

[0022] A silane coupling agent dispersion and a nanoparticle dispersion are mixed, and the pH of the mixture is adjusted to 4-5. The reaction is carried out at 48-52°C under a protective atmosphere to obtain a trigger-type nano-water-controlling material. More preferably, the amount of silane coupling agent dispersion is 2-5% based on the total mass of the silane coupling agent dispersion and the nanoparticle dispersion being 100%. More preferably, formic acid is used to adjust the pH of the mixture. More preferably, nitrogen atmosphere is used as the protective atmosphere. More preferably, the reaction time is not less than 3 hours.

[0023] According to a preferred embodiment of the fracturing water control and gas production method for low-permeability, high-water-saturation gas reservoirs, preferably, the particle size (particle size before aggregation) of the trigger-type nano water control material is distributed in the range of 50-300nm (inclusive of 50nm and 300nm).

[0024] According to the preferred embodiment of the fracturing water control and gas production method for low-permeability, high-water-saturation gas reservoirs, preferably, the particle size of the trigger-type nano water control material before agglomeration is within 1 / 6 to 1 / 3 of the median radius of the pore channel of the target layer in the target well (including 1 / 6 and 1 / 3).

[0025] According to the preferred embodiment of the fracturing water control and gas production method for low-permeability, high-water-saturation gas reservoirs, preferably, the viscosity of the fracturing fluid carrying the proppant is greater than the viscosity of the fracturing fluid pre-flush fluid and the viscosity of the fracturing fluid displacement fluid.

[0026] According to the preferred embodiment of the fracturing water control and gas production method for low-permeability, high-water-saturation gas reservoirs, the apparent viscosity of the fracturing fluid pre-flush fluid is preferably 20-40 mPa·s under the conditions of 100 r / min, 25℃, and 0.1 MPa.

[0027] According to the preferred embodiment of the fracturing water control and gas production method for low-permeability, high-water-saturation gas reservoirs, the apparent viscosity of the fracturing fluid carrying the proppant is preferably 90-120 mPa·s under the conditions of 100 r / min, 25℃, and 0.1 MPa.

[0028] According to the preferred embodiment of the fracturing water control and gas production method for low-permeability, high-water-saturation gas reservoirs, the apparent viscosity of the fracturing fluid displacement fluid is preferably 3-15 mPa·s under the conditions of 100 r / min, 25℃, and 0.1 MPa.

[0029] According to the preferred embodiment of the fracturing water control and gas production method for low-permeability, high-water-saturation gas reservoirs, preferably, the mass content of the trigger-type nano water control material is 1-2% based on the total mass of the fracturing fluid pre-flush fluid (including the trigger-type nano water control material) as 100%.

[0030] According to the preferred embodiment of the fracturing water control and gas production method for low-permeability, high-water-saturation gas reservoirs, preferably, the fracturing fluid carrying the proppant, the fracturing fluid pre-fracturing fluid, and the fracturing fluid displacement fluid all contain a fracturing thickener, a breaker, and water.

[0031] According to the preferred embodiment of the fracturing water control and gas production method for low-permeability, high-water-saturation gas reservoirs, preferably, the breaker agent can achieve a viscosity of less than 3 mPa·s after the fracturing fluid is broken.

[0032] According to the preferred embodiment of the fracturing water control and gas production method for low-permeability, high-water-saturation gas reservoirs, preferably, the thickener used for fracturing is at least one of polymer thickener for fracturing and plant gum thickener for fracturing.

[0033] More preferably, the thickener for fracturing is selected from one or more of anionic polyacrylamide, hydroxypropyl guar gum, and carboxymethyl guar gum;

[0034] The broken fluid obtained after fracturing fluid breaks up contains residual polymer thickener molecules and water-insoluble residues of plant glue thickener used for fracturing. These residues act as a linker for nano-water-controlling materials that are triggered to aggregate when they encounter formation water, further increasing the volume of the aggregates to the millimeter level and improving the water-blocking effect.

[0035] More preferably, ammonium persulfate is selected as the degreasing agent.

[0036] According to the preferred embodiment of the fracturing water control and gas production method for low-permeability, high-water-saturation gas reservoirs, preferably, the fracturing fluid pre-flush fluid contains 0.3-0.5% fracturing thickener, based on the total mass of the fracturing fluid pre-flush fluid as 100%.

[0037] According to the preferred embodiment of the fracturing water control and gas production method for low-permeability, high-water-saturation gas reservoirs, preferably, the fracturing fluid pre-flush fluid contains 0.015-0.025% breaker, based on 100% of the total mass of the fracturing fluid pre-flush fluid.

[0038] According to the preferred embodiment of the fracturing water control and gas production method for low-permeability, high-water-saturation gas reservoirs, preferably, the fracturing fluid carrying sand contains 0.8-1.2% fracturing thickener, based on the total mass of the fracturing fluid carrying sand as 100%.

[0039] According to the preferred embodiment of the fracturing water control and gas production method for low-permeability, high-water-saturation gas reservoirs, preferably, the fracturing fluid carrying sand contains 0.025-0.035% breaker, based on the total mass of the fracturing fluid carrying sand as 100%.

[0040] According to a preferred embodiment of the fracturing water control and gas production method for low-permeability, high-water-saturation gas reservoirs, preferably, the fracturing fluid displacement fluid contains 0.1-0.2% fracturing thickener, based on 100% of the total mass of the fracturing fluid displacement fluid.

[0041] According to the preferred embodiment of the fracturing water control and gas production method for low-permeability, high-water-saturation gas reservoirs, preferably, the fracturing fluid displacement fluid contains 0.005-0.015% breaker, based on 100% of the total mass of the fracturing fluid displacement fluid.

[0042] According to the preferred embodiment of the fracturing and water-controlled gas production method for low-permeability, high-water-saturation gas reservoirs, the preferred sand addition intensity is 2-4m. 3 / m sand body thickness.

[0043] According to the preferred embodiment of the fracturing and water-controlled gas production method for low-permeability, high-water-saturation gas reservoirs, preferably, the sand-carrying concentration of the sand-carrying fluid is 120 kg / m³, based on the volume of the sand-carrying fluid. 3 -520kg / m 3 .

[0044] According to the preferred embodiment of the fracturing water control and gas production method for low-permeability, high-water-saturation gas reservoirs, the shut-in time after the fracturing operation is preferably 2-3 hours.

[0045] According to the preferred embodiment of the fracturing and water-controlled gas production method for low-permeability, high-water-saturation gas reservoirs, the injection velocity of the fracturing fluid carrying proppant is preferably 6-12 m / s. 3 / min.

[0046] According to the preferred embodiment of the fracturing and water-controlled gas production method for low-permeability, high-water-saturation gas reservoirs, the injection rate of the fracturing fluid pre-flush fluid is preferably 6-12 m / s. 3 / min.

[0047] According to the preferred embodiment of the fracturing and water-controlled gas production method for low-permeability, high-water-saturation gas reservoirs, the injection rate of the fracturing fluid displacement fluid is preferably 6-12 m / s. 3 / min.

[0048] According to the preferred embodiment of the fracturing and water-controlled gas production method for low-permeability, high-water-saturation gas reservoirs, the target well and target layer are preferably determined as follows:

[0049] Obtain logging data and formation water salinity of the well to be fractured and the formation water to be fractured.

[0050] Based on the logging data of the fractured layer in the well to be fractured, determine the sand layer thickness, reservoir temperature, water saturation, and average permeability of the fractured layer in the well to be fractured;

[0051] If the sand layer thickness of the well to be fractured is greater than 4m, the water saturation is 45%-80%, the average permeability is 0.05-10mD, the reservoir temperature is 70℃-120℃, and the formation water salinity is 10000-80000mg / L, then the layer to be fractured in the well to be fractured will be taken as the target layer of the target well.

[0052] According to a preferred embodiment of the fracturing and water-controlled gas production method for low-permeability, high-water-saturation gas reservoirs, the method preferably includes:

[0053] The pore channel characteristics of the target layer in the target well are analyzed to determine the median pore channel radius of the target layer in the target well. Based on the median pore channel radius of the target layer in the target well, the particle size of the trigger-type nano water control material is determined.

[0054] According to a preferred embodiment of the fracturing and water-controlled gas production method for low-permeability, high-water-saturation gas reservoirs, the method preferably includes:

[0055] Obtain logging data of the target layer in the target well;

[0056] Based on the logging data of the target well and the target layer, the thickness of the water-bearing gas layer, reservoir temperature, peak total hydrocarbon content, and water saturation parameters of the target well and the target layer are determined. Then, the scale of fracturing stimulation of the target well and the target layer is determined, and the amount of fracturing fluid pre-flush fluid, fracturing fluid carrying sand fluid, and fracturing fluid displacement fluid is determined.

[0057] According to a preferred embodiment of the fracturing and water-controlled gas production method for low-permeability, high-water-saturation gas reservoirs, the method preferably includes:

[0058] Ion analysis was performed on the formation water in the target well and target layer to determine the formation water salinity.

[0059] Based on the formation water salinity and reservoir temperature of the target well and target layer, a trigger-type nano-water control material is selected; the trigger-type nano-water control material can trigger aggregation under conditions of 70-120℃ and formation water salinity of 10000-80000 mg / L, and the aggregation time is 30-60 min;

[0060] In one specific embodiment, a "formation water salinity-temperature-coalescence time" chart was constructed for different trigger-type nano-water control materials. Based on the formation water salinity and reservoir temperature of the target well and the "formation water salinity-temperature-coalescence time" chart of different trigger-type nano-water control materials, the appropriate trigger-type nano-water control material for the target well and target layer was selected.

[0061] According to a preferred embodiment of the fracturing and water-controlled gas production method for low-permeability, high-water-saturation gas reservoirs, the method preferably includes:

[0062] During the fracturing fluid flowback process in step 3), pressure changes are monitored, and the concentration and particle size of the trigger-type nano-water control material in the flowback fluid are detected as a function of the flowback time.

[0063] According to a preferred embodiment of the fracturing and water-controlled gas production method for low-permeability, high-water-saturation gas reservoirs, the method preferably includes:

[0064] In step 3), during the production process, the daily gas production and water production are obtained and the effect is evaluated.

[0065] The technical solution provided by this invention targets specific types of well sections. Under the combined action of fracturing fluid pre-flush fluid carrying sand and fracturing fluid, and fracturing fluid displacement fluid carrying trigger-type nano-water control material, the trigger-type nano-water control material is pre-placed in the reservoir matrix pores at the fracture front. When formation water in the formation comes into contact with the pre-placed trigger-type nano-water control material in the matrix, the material agglomerates and expands under the influence of temperature and high-salinity formation water, forming large-sized solid particles that block high-water-content, high-permeability water flow channels. In waterless channels, the water control material does not agglomerate and does not block gas-producing pore channels. This achieves effective blocking of large-pore water-producing channels without affecting the flow capacity of non-water-producing gas flow channels, thus enabling fracturing and water-controlled gas production in low-permeability, high-water-saturated gas reservoirs. Compared with conventional fracturing methods (without adding trigger-type nano-water-saturated materials) for fracturing and water-controlled gas production in low-permeability, high-water-saturation gas reservoirs, the technical solution provided by this invention reduces the permeability of the water phase by an average of more than 65% (67.68% in one specific embodiment) and the permeability of the gas phase by an average of about 7% (7.62% in one specific embodiment), achieving a good water-controlled gas production effect. Attached Figure Description

[0066] Figure 1 This is a schematic diagram of a fracturing and water-controlled gas production method for low-permeability, high-water-saturation gas reservoirs. Detailed Implementation

[0067] In order to provide a clearer understanding of the technical features, objectives and beneficial effects of the present invention, the technical solution of the present invention will now be described in detail below, but it should not be construed as limiting the scope of implementation of the present invention.

[0068] Example 1

[0069] This embodiment provides a method for hydraulic fracturing and water-controlled gas production in a low-permeability, high-water-saturation gas reservoir, the method comprising:

[0070] 1. Identify the target well and target layer, and perform perforation in the upper section of the target well and target layer, specifically including:

[0071] Obtain logging data of the fractured zone in the well to be fractured, and determine the sand layer thickness, water-bearing gas layer thickness (effective thickness), reservoir temperature, peak total hydrocarbons, water saturation, and average permeability based on the logging data of the fractured zone. Perform ion analysis on the formation water in the fractured zone to determine the formation water salinity. Perform pore channel characteristic analysis on the fractured zone to determine the median pore channel radius.

[0072] The reservoir sand body of the well to be fractured has a thickness of 17m, an effective thickness of 3m, an average porosity of 7.28%, an average permeability of 3.39mD, a median pore channel radius of 0.753μm, a water saturation of 71.3%, a total hydrocarbon peak value of >50%, a reservoir temperature of 103℃, and a formation water salinity of 24571mg / L. The well type to be fractured is a vertical well.

[0073] If the thickness of the fractured layer in a well to be fractured is greater than 4m, the water saturation is 45%-80%, the average permeability is 0.05-10mD, the reservoir temperature is 70℃-120℃, and the formation water salinity is 10000-80000mg / L, then the fractured layer in the well to be fractured can be used as the target layer of the target well.

[0074] Perforation was carried out in the upper section of the target layer in the target well. The perforation interval in the fracturing layer was 3586-3587m, and in the sand body section it was 3577-3594m.

[0075] 2. Determine the fracturing fluid system, specifically including:

[0076] The median particle size of the trigger-type nano-water control material was determined based on the median radius of the pore cannon in the target layer of the target well. Specifically, the median particle size of the trigger-type nano-water control material before aggregation was 1 / 6 to 1 / 3 of the median radius of the pore cannon in the target layer of the target well. In this embodiment, the median radius of the pore cannon in the target layer of the target well was 0.753 μm, and the determined median particle size of the trigger-type nano-water control material before aggregation was 220 nm, with a particle size ranging from 251 to 150 nm.

[0077] Based on the formation water salinity and reservoir temperature of the target well and target layer, a trigger-type nano-water control material was selected. The selected trigger-type nano-water control material can trigger aggregation under the conditions of 103℃ temperature and 24571mg / L formation water salinity, with an aggregation time of 40min and a median particle size of 3440nm after aggregation.

[0078] Based on the effective thickness of the target layer, reservoir temperature, peak total hydrocarbon content, and water saturation parameters of the target well, the scale of fracturing stimulation of the target layer in the target well is determined, and then the amount of fracturing fluid pre-flush fluid, fracturing fluid carrying sand fluid, and fracturing fluid displacement fluid is determined.

[0079] In this embodiment, taking the total mass of the fracturing fluid pre-flush as 100%, the fracturing fluid pre-flush consists of 0.3% anionic polyacrylamide for fracturing, 1.0% trigger-type nano-water control material, 0.01% ammonium persulfate as a breaker, and the remainder being water. The designed dosage of the fracturing fluid pre-flush is 192 cubic meters, and the apparent viscosity of the fracturing fluid pre-flush at 100 r / min, 25°C, and 0.1 MPa is 10-30 mPa·s.

[0080] Based on the total mass of the fracturing fluid carrying proppant as 100%, the fracturing fluid carrying proppant consists of 1.0% anionic polyacrylamide (a fracturing thickener), 0.02% ammonium persulfate (a breaker), and the remainder water. The designed dosage of the fracturing fluid carrying proppant is 288 cubic meters. Under conditions of 100 r / min, 25℃, and 0.1 MPa, the apparent viscosity of the fracturing fluid carrying proppant is in the range of 70-130 mPa·s. Based on the mass of the fracturing fluid carrying proppant, the proppant content carried is 20%, and the specific proppant loading intensity is 3 m. 3 / m sand body thickness.

[0081] Based on the total mass of the fracturing fluid displacement fluid as 100%, the fracturing fluid displacement fluid consists of 0.1% anionic polyacrylamide as a fracturing thickener, 0.01% ammonium persulfate as a breaker, and the balance being water. The designed dosage of the fracturing fluid displacement fluid is one wellbore volume. The apparent viscosity of the fracturing fluid displacement fluid is in the range of 20-40 mPa·s under the conditions of 100 r / min, 25℃, and 0.1 MPa.

[0082] Among them, the breaker can make the viscosity of the breaker fluid obtained after fracturing fluid is less than 3 mPa·s.

[0083] The compatibility of fracturing thickeners, breaker agents, and trigger-type nano-water control materials was evaluated. The fracturing thickeners and breaker agents did not affect the coalescence and expansion properties of the trigger-type nano-water control materials under the influence of formation temperature and formation water salinity. At the same time, the trigger-type nano-water control materials also improved the thickening properties, temperature resistance, and shear resistance of the fracturing thickeners.

[0084] The triggered nano-water-controlling material was prepared by the following method:

[0085] Based on the analysis of the target well, a trigger-type nanomaterial for water control is preferably developed. The spherical nanoparticles are selected from 70% SiO2, 10% TiO2, and 20% CaCO3.

[0086] More preferably, the silane coupling agent is selected from at least one of 3-aminopropyltrimethoxysilane, 3-aminopropyltriethoxysilane, and N-2-aminoethyl-3-aminopropyltrimethoxysilane.

[0087] Triggered nanomaterials for water control were prepared using the following methods:

[0088] Step 1: Under room temperature and high-speed stirring conditions, 3-aminopropyltrimethoxysilane, ethanol, and water were mixed to prepare a silane coupling agent dispersion; based on the total mass of the silane coupling agent dispersion as 100%, the amount of 3-aminopropyltrimethoxysilane was 12%, the amount of ethanol was 75%, and the amount of water was 13%.

[0089] Step 2: Under room temperature and high-speed stirring conditions, the nanoparticles are dispersed in a mixed solution of ethanol and water for 60 minutes to obtain a nanoparticle dispersion. The total mass of the nanoparticle dispersion is 100%, with nanoparticles accounting for 15%, ethanol accounting for 5%, and water accounting for 80%. The nanoparticles are a mixture of SiO2 and TiO2 in a mass ratio of 7:3.

[0090] Step 3: The silane coupling agent dispersion is uniformly added to the nanoparticle dispersion, the pH of the system is adjusted to 4.5 with formic acid, the temperature is raised to 50°C, nitrogen gas is purged for protection, and the reaction is carried out for 3 hours to obtain the trigger-type nano-water control material; wherein, based on the total mass of the silane coupling agent dispersion and the nanoparticle dispersion being 100%, the amount of silane coupling agent dispersion is 3%.

[0091] 3. Perform fracturing operations on the target well and target formation, including:

[0092] Through the perforations in the upper section of the target layer of the target well, fracturing fluid pre-fracturing fluid, fracturing fluid carrying sand, and fracturing fluid displacement fluid carrying trigger-type nano water control material are sequentially injected into the target layer of the target well to fracture the target layer of the target well.

[0093] Among them, 3m 3 The fracturing fluid pre-fluid was pumped at a rate of 192 cubic meters per minute, carrying the trigger-type nano-water control material into the reservoir, where it entered the matrix pores.

[0094] With 3m 3 The pumped fracturing fluid, carrying proppant, is injected at a rate of 288 cubic meters per minute, carrying proppant into the fracture and pushing the triggered nano-water-controlling material into the matrix pores at the distal end of the fracture. Figure 1 As shown;

[0095] With 3m 3 Injecting fracturing fluid at a rate of / min displaces the fracturing fluid and sand-carrying fluid in the wellbore into the fracture, while simultaneously pushing the trigger-type nano-water control material further into the matrix pores at the far end of the fracture.

[0096] 4. After the fracturing operation is completed, shut in the well for about 2-3 hours. The fracturing fluid will break up (the viscosity of the broken fluid after fracturing fluid breaking up is less than 3 mPa·s). Then, open the well to flow back the fracturing fluid and start production.

[0097] During the fracturing fluid flowback process, pressure changes are monitored, and the concentration and particle size of the trigger-type nano-water control material in the flowback fluid are detected as a function of the flowback time to evaluate the effect.

[0098] During the production process, the daily gas and water production are recorded for performance evaluation.

[0099] Comparative Example 1

[0100] For comparison, fracturing and gas production were performed on the adjacent wells of the wells used in this embodiment. The only difference between the specific method and the fracturing and water-controlled gas production method for low-permeability, high-water-saturation gas reservoirs used in this embodiment is that no trigger-type nano-water-controlled material was added.

[0101] Compared with the scheme provided in Comparative Example 1 (without adding trigger-type nano-water control materials), the water permeability of fracturing and water-controlled gas production in low-permeability, high-water-saturation gas reservoirs using the scheme provided in Example 1 was reduced by approximately 67.68%, and the gas permeability was reduced by an average of approximately 7.62%. This demonstrates that the scheme provided in Example 1 achieved good water control and gas production results.

[0102] The above description is only a preferred embodiment of the present invention and is not intended to limit the present invention. Any modifications, equivalent substitutions, improvements, etc., made within the spirit and principles of the present invention should be included within the protection scope of the present invention.

Claims

1. A method for fracturing and water control in gas production in low permeability high water saturation gas reservoirs, wherein, The method includes: 1) Determine the target well and target layer, and perform perforation in the upper section of the target well and target layer; wherein, the sand layer thickness of the target well and target layer is greater than 4m, the water saturation is 45%-80%, the average permeability is 0.05-10mD, the reservoir temperature is 70℃-120℃, and the formation water salinity is 10000-80000mg / L; 2) Through the perforations in the upper section of the target layer of the target well, the fracturing fluid pre-fracturing fluid, the fracturing fluid carrying sand, and the fracturing fluid displacement fluid carrying water control agent are injected sequentially into the target layer of the target well to fracture the target layer of the target well. Among them, the water control agent is a trigger-type nano water control material. The trigger-type nano water control material can trigger aggregation under the conditions of temperature 70-120℃ and formation water salinity 10000-80000 mg / L, and the aggregation time is 30-60 min. The median particle size after aggregation is more than 10 times the median particle size before aggregation. The median particle size before aggregation is 1 / 6-1 / 3 of the median pore diameter of the target well and the target layer. 3) After the fracturing operation is completed, shut in the well until the fracturing fluid breaks down, then open the well to flow back the fracturing fluid and start production.

2. The method of claim 1, wherein, Based on the total mass of the fracturing fluid pre-flush fluid being 100%, the mass content of the trigger-type nano-water control material is 1-2%.

3. The method of claim 1 or 2, wherein, The triggered nano-water control material is a solution of nanoparticles with surface modified by a silane coupling agent; The nanoparticles are selected from at least one of TiO2, CaCO3, and fullerene, and are a mixture of SiO2; the mass content of SiO2 is 60-80% based on the total mass of the nanoparticles as 100%. Preferably, the silane coupling agent is selected from at least one of 3-aminopropyltrimethoxysilane, 3-aminopropyltriethoxysilane, and N-2-aminoethyl-3-aminopropyltrimethoxysilane.

4. The method according to claim 3, wherein, The triggered nano-water control material was prepared by a coefficient preparation method: A silane coupling agent dispersion was prepared by mixing a silane coupling agent with an alcohol solvent and water. A nanoparticle dispersion was prepared by mixing silane coupling agent dispersion nanoparticles with alcohol solvent and water. The silane coupling agent dispersion and the nanoparticle dispersion were mixed, and the pH of the mixture was adjusted to 4-5. The mixture was reacted at 48-52℃ under a protective atmosphere for at least 3 hours to obtain a trigger-type nano-water control material.

5. The method according to claim 4, wherein, Based on a total mass of 100% for the silane coupling agent dispersion, the silane coupling agent content is 10-15% by mass, and the alcohol solvent content is 70-80% by mass; and / or Based on a total mass of 100% for the nanoparticle dispersion, the nanoparticle content is 10-20%, and the alcohol solvent content is 3-8%; and / or Based on the total mass of the silane coupling agent dispersion and the nanoparticle dispersion being 100%, the amount of silane coupling agent dispersion used is 2-5%.

6. The method according to claim 1, wherein, The particle size distribution of the triggered nano-water control material is in the range of 50-300 nm; and / or The particle size of the triggered nano-water control material before agglomeration is within 1 / 6 to 1 / 3 of the median radius of the pore channel in the target layer of the target well.

7. The method according to claim 1, wherein, The viscosity of the fracturing fluid carrying the proppant is greater than the viscosity of the fracturing fluid pre-flush fluid and the viscosity of the fracturing fluid displacement fluid. The apparent viscosity of the fracturing fluid pre-fluid at 100 r / min, 25℃, and 0.1 MPa is 20-40 mPa·s. The apparent viscosity of the fracturing fluid carrying the proppant is 90-120 mPa·s at 100 r / min, 25℃, and 0.1 MPa. The apparent viscosity of the fracturing fluid displacement fluid at 100 r / min, 25℃, and 0.1 MPa is 3-15 mPa·s.

8. The method according to claim 1, wherein, Fracturing fluid carrying proppant, fracturing fluid pre-fracturing fluid, and fracturing fluid displacement fluid all contain fracturing thickener, breaker and water; Among them, the breaker can make the viscosity of the breaker fluid obtained after fracturing fluid is less than 3 mPa·s.

9. The method according to claim 8, wherein, The thickener used for fracturing is at least one of polymer thickeners for fracturing and plant-based gum thickeners for fracturing; Preferably, the thickener used for fracturing is selected from one or a combination of two or more of anionic polyacrylamide, hydroxypropyl guar gum, and carboxymethyl guar gum; More preferably, ammonium persulfate is selected as the de-gluing agent.

10. The method according to claim 9, wherein, Based on the total mass of the fracturing fluid pre-flush fluid as 100%, the fracturing fluid pre-flush fluid contains: 0.3-0.5% fracturing thickener; Based on the total mass of the fracturing fluid carrying proppant as 100%, the fracturing fluid carrying proppant contains: 0.8-1.2% fracturing thickener; Based on the total mass of the fracturing fluid displacement fluid as 100%, the fracturing fluid displacement fluid contains: 0.1-0.2% fracturing thickener.

11. The method according to claim 9, wherein, Based on the total mass of the fracturing fluid pre-flush fluid as 100%, the fracturing fluid pre-flush fluid contains: 0.015-0.025% breaker; Based on the total mass of the fracturing fluid carrying the proppant as 100%, the fracturing fluid carrying the proppant contains: 0.025-0.035% breaker; Based on the total mass of the fracturing fluid displacement fluid as 100%, the fracturing fluid displacement fluid contains: 0.005-0.015% breaker.

12. The method according to claim 1, wherein, The injection rate of the fracturing fluid carrying sand is 6-12 m 3 / min; The injection rate of the fracturing fluid preflush is 6-12 m 3 / min; The injection rate of the fracturing fluid displacement fluid is 6-12 m 3 / min.

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