Gas well potential tapping and yield increasing composite technology

Abstract

The invention discloses a gas well potential tapping and yield increasing composite technology, and relates to the technical field of petroleum and natural gas development, the gas well potential tapping and yield increasing composite technology comprises the following three steps: S1, plugging removal liquid (18-22% of composite chelating acid, 0.6-1.0% of a nanometer surfactant, 0.4-0.7% of a biological enzyme preparation and the balance of formation water, and the chelating acid is prepared from glycolic acid, EDTA disodium and ammonium fluoride according to the ratio of 18-22: 6-8: 4-7); s2, performing 3-5 stages of fracturing circulation, and injecting prepad fluid, sand-carrying fluid and a temporary plugging agent at each stage; and S3, supercritical gas is injected step by step, the initial pressure is 0.65-0.75 times of formation pressure, the final pressure is 1.3-1.45 times of formation pressure, and the pressure is increased by 0.02-0.03 MPa / min. According to the invention, pre-blocking removal and multi-stage temporary blocking fracturing are cooperated, a complex fracture net is made by means of a compound agent, pulse blocking removal and improvement of liquid spreading, and a bi-component temporary blocking agent and modified ceramsite; a desorption activation program is combined with controllable gradient supercritical gas injection, mixed gas activates adsorption gas, supercritical gas channeling prevention is controlled, real-time monitoring is carried out, traditional pain spots are broken, the recovery rate of residual gas is increased, and the stable production period of a gas well is prolonged.

Description

TECHNICAL FIELD

[0001] The present application relates to the technical field of oil and gas development, in particular to a gas well potential tapping and production increasing composite process. BACKGROUND

[0002] In the current oil and gas development field, tapping and production increasing of middle and low permeability reservoirs and gas wells in the middle and late development stage have become the key direction to guarantee the recovery ratio of gas reservoirs, but the existing technology always faces three core bottlenecks, which is difficult to meet the field demand.

[0003] Firstly, the effect of formation plugging removal is limited. Traditional plugging removal schemes mostly use single acid or single enzyme preparation, the acid is easy to react with formation minerals to generate secondary precipitation, the enzyme preparation has the problems of insufficient high temperature resistance and incomplete removal of organic plugging, part of the schemes adds surfactant, but the surfactant is mostly conventional type, the liquid has poor spreading property in formation pores, the plugging removal range is limited, and it is impossible to build effective seepage channels for subsequent production increasing.

[0004] Secondly, the fracture control and conductivity of fracturing are insufficient. Conventional fracturing is mostly single or two-stage construction, the temporary plugging agent is mostly single material (such as pure resin or pure microspheres), which has low steering efficiency (the fracture cannot be forced to extend to the untransformed area) or poor stability under formation conditions; at the same time, the proppant is mostly ordinary ceramic particles, which has smooth surface and insufficient compressive strength, and is easy to be embedded or broken in long-term production, which leads to rapid decay of fracture conductivity and makes it difficult to realize long-term stable production.

[0005] Thirdly, the remaining gas displacement efficiency is low. The existing gas injection displacement technology mostly uses constant pressure injection, which either causes gas channeling (damages the original seepage field of the reservoir) due to too high initial pressure, or makes it difficult to maintain the supercritical state (the high-efficiency displacement ability of supercritical gas cannot be played) due to too fast pressure increase; and there is lack of targeted desorption activation measures before gas injection, the adsorbed natural gas in the formation is difficult to be effectively desorbed, the remaining gas in the low gas saturation area cannot be fully produced, and finally the recovery ratio of the gas well is improved limitedly.

[0006] Therefore, it is urgent to develop a composite process which can solve the problems of incomplete plugging removal, fracture control and low displacement efficiency, so as to adapt to the complex conditions of middle and low permeability and middle and late gas wells, realize the dual improvement of gas reservoir potential tapping and production increasing effect and long-term stability. SUMMARY

[0007] The purpose of the present application is to make up for the deficiencies of the prior art, and provide a gas well potential tapping and production increasing composite process. The present application cooperates pre-plugging removal and multi-stage temporary plugging fracturing, improves the liquid spreading by compounding agents + pulse plugging removal, and forms a complex fracture network by two-component temporary plugging agent + modified ceramic particles; combines desorption activation program and controllable gradient supercritical gas injection, activates the adsorbed gas by mixed gas, prevents gas channeling by controlling supercritical state, and realizes real-time monitoring, breaks the traditional pain points, improves the recovery ratio of remaining gas, and prolongs the stable production period of the gas well.

[0008] The present application provides the following technical solutions to solve the above technical problems: A gas well potential tapping and production increasing composite process, the process comprising the following steps:

[0009] S1. Pre-deblocking excitation: injecting a deblocking liquid composition into the target layer, the deblocking liquid composition comprising, by mass percentage:

[0010] Composite chelating acid 18-22%;

[0011] Nano surfactant 0.6-1.0%;

[0012] Biological enzyme preparation 0.4-0.7%;

[0013] The balance is formation water;

[0014] S2. Multi-stage temporary plugging and diverting fracturing: sequentially performing three to five stages of fracturing cycles, each stage of cycle comprising:

[0015] Injecting a preflush to form an initial fracture, injecting a sand-carrying liquid to fill proppants, and injecting a temporary plugging and diverting agent to block the current fracture;

[0016] S3. Controllable gradient gas injection displacement: injecting supercritical displacement gas into the formation in steps through a pressure boosting device, meeting:

[0017] The initial gas injection pressure is 0.65 to 0.75 times the formation pressure;

[0018] The final gas injection pressure is 1.3 to 1.45 times the formation pressure;

[0019] The pressure increase rate is 0.02 to 0.03 MPa per minute;

[0020] The composite chelating acid is composed of hydroxyacetic acid, ethylenediaminetetraacetic acid disodium, and ammonium fluoride in a mass ratio of 18-22:6-8:4-7.

[0021] Further, the nano surfactant in the S1 step is modified mesoporous silica, which is specifically:

[0022] The pore size distribution is 3 to 8 nanometers;

[0023] The specific surface area is greater than or equal to 280 square meters per gram;

[0024] The surface grafting rate is 12 to 18 millimoles per gram;

[0025] The bio-enzyme preparation comprises thermostable cellulase and lipase, wherein the activity of the thermostable cellulase is 9,000 units per gram to 11,000 units per gram, and the activity of the lipase is 5,500 units per gram to 7,000 units per gram, and the mass ratio of the two is 2.2-2.8:1.

[0026] Furthermore, the injection process parameters for step S1 are controlled as follows:

[0027] The injection rate is 0.6 cubic meters to 1.0 cubic meters per minute;

[0028] The total injection volume is 2.0 to 2.3 times the annulus volume of the wellbore;

[0029] The parameters for applying the pulsed pressure wave are:

[0030] Frequency 6 Hz to 8 Hz;

[0031] Amplitude: 0.7 MPa to 1.0 MPa;

[0032] The treatment cycle is 15 to 20 minutes each time.

[0033] Furthermore, the temporary deflector in step S2 comprises a two-component response system:

[0034] Temperature-responsive microspheres:

[0035] The material is a copolymer of acrylamide and N-vinylcaprolactam;

[0036] The phase transition temperature is 63 degrees Celsius ± 2 degrees Celsius;

[0037] The particle size distribution is from 120 mesh to 250 mesh;

[0038] Oil-soluble resin particles:

[0039] The mass ratio of the components is C9 petroleum resin: hydrogenated rosin ester = 6.8-7.2:3;

[0040] The dissolution rate is greater than or equal to 0.9 grams per square centimeter per hour;

[0041] The mass ratio of component (Ⅰ) to component (Ⅱ) is 1.8-2.2:1.

[0042] Furthermore, the S2 step fracturing operation specifically includes:

[0043] S201 injects pre-fluid at a rate of 3.0 to 3.8 cubic meters per minute, with a single-stage volume of 25 to 28 cubic meters;

[0044] S202 is injected with sand-carrying fluid at a rate of 3.5 to 4.5 cubic meters per minute, with a sand-to-fluid ratio of 10% to 14%.

[0045] S203 is injected to temporarily plug the diverter slug, with a volume of 0.18 to 0.22 times the volume of the pre-fluid.

[0046] S204 was shut in and pressurized to 1.35 to 1.55 times the formation fracturing pressure;

[0047] S205 repeats steps S201 to S204 three to four times.

[0048] Furthermore, the sand-carrying fluid system in step S202 includes:

[0049] The thickener is 0.38% to 0.42% by weight of hydrophobic associating polyacrylamide;

[0050] The crosslinking agent is an organozirconium and organotitanium composite, with a zirconium-titanium molar ratio of 1:0.2-0.3;

[0051] The de-gelling agent is ammonium persulfate in double-layer microcapsules, with ethyl cellulose as the inner wall material and polylactic acid as the outer wall material;

[0052] The proppant is nano-alumina modified ceramic particles with a surface roughness Ra of 3.5 micrometers to 4.2 micrometers.

[0053] Furthermore, a desorption-activation transition procedure is performed before step S3:

[0054] S301 injects a mixture of carbon dioxide and nitrogen until the pressure reaches 0.90 to 0.94 times the formation pressure, with a volume ratio of 1:1.

[0055] S302 voltage stabilization for 12 hours;

[0056] S303 was depressurized to the original formation pressure;

[0057] S304 repeats steps S301 to S302 twice, with each injection amount being 0.35% to 0.45% of the formation pore volume.

[0058] Furthermore, the conditions for maintaining the supercritical state in step S3 are as follows:

[0059] Wellbore temperature control: not lower than the critical temperature of carbon dioxide plus 5 degrees Celsius, where the critical temperature of carbon dioxide is 31.1 degrees Celsius;

[0060] Bottom hole pressure control: not lower than the critical carbon dioxide pressure plus 1.0 MPa, where the critical carbon dioxide pressure is 7.38 MPa;

[0061] Real-time monitoring: The gas leading edge propulsion velocity is monitored through a distributed acoustic wave sensing system.

[0062] Furthermore, the applicable conditions are limited to:

[0063] Reservoir permeability range: 0.02 millidarcy to 8.5 millidarcy;

[0064] Formation temperature range: 75 degrees Celsius to 115 degrees Celsius;

[0065] Gas saturation greater than or equal to 48%;

[0066] Gas well production status: Cumulative production has reached 65% to 80% of the initial recoverable reserves.

[0067] Compared with existing technologies, this combined process for tapping the potential and increasing production of gas wells has the following advantages:

[0068] I. This invention effectively addresses the problems of incomplete deblocking, single fracture type, and rapid decline in conductivity in traditional production enhancement technologies by synergistically combining pre-treatment deblocking activation with multi-stage temporary plugging and diversion fracturing. It utilizes a compound of chelated acid, bio-enzyme preparations, and nano-surfactants, along with pulsed pressure wave-assisted injection, to efficiently remove formation scale and organic blockages while improving fluid spreadability through the interfacial activity of nano-surfactants. In multi-stage fracturing, a two-component responsive temporary plugging and diversion agent, combined with a specific sand-to-fluid ratio and nano-alumina-modified ceramic proppant, forces fractures to divert, forming a complex fracture network. This significantly expands the effective seepage range and enhances the long-term conductivity of fractures, creating a stable channel for subsequent gas injection and displacement.

[0069] II. This invention achieves a significant improvement in the development efficiency of gas reservoirs by combining a desorption activation transition process with a controllable gradient supercritical gas injection displacement process. The desorption activation transition process, through the cyclic injection, stabilization, and depressurization of a mixture of carbon dioxide and nitrogen, can efficiently activate the adsorbed natural gas in the formation and reduce gas flow resistance. The controllable gradient gas injection mode, combined with precise control of the supercritical state, can avoid the risk of gas channeling. In addition, the real-time monitoring of the distributed acoustic sensing system ensures the uniform advancement of the displacement gas, significantly improving the recovery rate of residual gas in areas with low gas saturation and extending the stable production period of gas wells.

[0070] Other advantages, objectives and features of the invention will be set forth in part in the description which follows, and in part will be apparent to those skilled in the art from the following examination or study, or may be learned from the practice of the invention. Attached Figure Description

[0071] To more clearly illustrate the technical solutions in the embodiments of the present invention or the prior art, the drawings used in the description of the embodiments or the prior art will be briefly introduced below. Obviously, the drawings described below are only some embodiments of the present invention. For those skilled in the art, other drawings can be obtained based on these drawings without creative effort.

[0072] Figure 1 A flowchart for a combined process of tapping the potential and increasing production of gas wells;

[0073] Figure 2 This is a multi-stage temporary plugging and diversion fracturing process for a combined technology of tapping the potential and increasing production of gas wells. Detailed Implementation

[0074] To further illustrate the technical means and effects of the present invention in achieving its intended purpose, the following detailed description of the specific implementation methods, structures, features, and effects of the present invention, in conjunction with the accompanying drawings and preferred embodiments, is provided below.

[0075] Example 1

[0076] This embodiment focuses on Well A in a gas field. The well has a reservoir permeability of 1.2 millidarcy, a formation temperature of 95°C, a gas saturation of 52%, and has already produced 72% of its initial recoverable reserves, thus meeting the applicable conditions of this invention. The specific implementation steps are as follows:

[0077] S1: Pre-blockage removal activation

[0078] Preparation of the unblocking solution: By mass percentage, the solution consists of 20% composite chelating acid, 0.8% nano-surfactant, 0.55% bio-enzyme preparation, and the remainder is formation water. Formation water is injected into a vacuum stirred tank, and stirring is started at a speed of 300 rpm. The composite chelating acid and nano-surfactant are added sequentially, and stirring is continued for 20 minutes. Then, the bio-enzyme preparation is added, and stirring is continued for another 15 minutes to obtain a homogeneous unblocking solution with a pH value controlled at 3.2.

[0079] Injection process: A high-pressure plunger pump was used to inject unblocking fluid into the target formation at a rate of 0.8 m³ / min, with a total injection volume of 2.15 times the wellbore annulus volume. The well's annulus volume is 18 m³, corresponding to an actual injection volume of 38.7 m³. During injection, a pulsed pressure wave was applied simultaneously, with parameters set to a frequency of 7 Hz and an amplitude of 0.85 MPa. The wave was paused for 5 minutes every 18 minutes until the unblocking fluid injection was complete.

[0080] Shutdown reaction: After injection, the well is shut in for 24 hours to allow the unblocking fluid to fully react with reservoir contaminants, dissolving mineral blockages such as calcium carbonate and iron oxides. It also degrades organic contaminants such as cellulose and colloids. Furthermore, the oscillating action of pulsed pressure waves removes blockage particles adhering to the well wall.

[0081] S2: Multi-stage temporary styling fracturing

[0082] Pre-flush fluid injection: Hydroxypropyl guar gum was selected as the base fluid, and 0.3% anti-swelling agent and 0.2% demulsifier were added to prepare the pre-flush fluid. The pre-flush fluid was injected at a rate of 3.4 m³ / min using a high-pressure plunger pump, with a single-stage injection volume of 26.5 m³. The purpose was to create fractures and cool the formation, thereby reducing the filtration loss of subsequent sand-carrying fluid.

[0083] Sand-carrying fluid injection: In the sand-carrying fluid system, the thickener (hydrophobic associating polyacrylamide) is 0.4% by mass, the crosslinking agent (organo-zirconium-organo-titanium composite, zirconium-titanium molar ratio 1:0.25) is added at 15% by mass of the thickener, the debriding agent (double-layer microcapsule ammonium persulfate) is added at 0.08%, and the proppant (nano-alumina modified ceramsite) is added at a sand-to-fluid ratio of 12%. The sand-carrying fluid is injected at a rate of 4.0 m³ / min, with a single-stage injection volume of 42 m³, to deliver the proppant into the crack and form effective support.

[0084] Temporary plugging and diverting agent injection: The temporary plugging and diverting agent is a mixture of temperature-responsive microspheres and oil-soluble resin particles at a mass ratio of 2:1. The injection volume is 0.2 times the volume of the pre-filled liquid, corresponding to an injection volume of 5.3 m³, and an injection rate of 2.5 m³ / min. After injection, the wellhead valve is closed.

[0085] Shutdown pressurization: The pressure is slowly increased through the surface pressurization system until the bottom hole pressure reaches 1.45 times the formation fracturing pressure. In this well, the formation fracturing pressure is 32 MPa, corresponding to a pressurization to 46.4 MPa. The pressure is maintained for 30 minutes, forcing the fracture to change direction and forming a new branch fracture.

[0086] Multi-stage circulation: Repeat steps S201-S204 above 4 times, injecting a total of 106m³ of pre-flush fluid, 168m³ of sand-carrying fluid, and 21.2m³ of temporary plugging and diverting agent to form a complex fracture network system of "main fracture + multi-branch fractures". The fracture network sweep volume is increased by more than 60% compared with conventional fracturing.

[0087] S3: Desorption and activation transition procedure (pre-step procedure for S3)

[0088] Mixed gas injection: A mixture of carbon dioxide and nitrogen in a 1:1 volume ratio was prepared and injected into the formation via a pressurization device, raising the injection pressure to 0.92 times the formation pressure. The original formation pressure of this well was 28 MPa, corresponding to an injection pressure of 25.76 MPa, and the injection volume was 0.4% of the formation pore volume. The formation pore volume of this well was 8500 m³, corresponding to an injection volume of 34 m³.

[0089] Pressure stabilization and depressurization: After injection, stabilize the pressure for 12 hours to allow the mixed gas to fully diffuse into the reservoir pores, and then slowly depressurize to the original formation pressure (28MPa). The depressurization rate is controlled at 0.5MPa / h to avoid secondary damage to the reservoir.

[0090] Cyclic execution: Repeat steps S301-S302 twice, injecting a total of 68m³ of mixed gas. Through the adsorption-desorption cycle of the mixed gas, the adsorbed natural gas in the reservoir is activated, improving the subsequent displacement efficiency.

[0091] S4: Controlled gradient gas injection displacement

[0092] Supercritical state control: Before construction, the wellbore temperature is raised to above the critical temperature of carbon dioxide (31.1℃) plus 5℃ using a wellbore heating device, and is actually controlled at 40℃; the bottom pressure is controlled to above the critical pressure of carbon dioxide (7.38MPa) plus 1.0MPa using a booster unit, and is initially controlled at 10MPa to ensure that the injected carbon dioxide is in a supercritical state.

[0093] Gradient gas injection: The initial gas injection pressure is set to 0.7 times the formation pressure, 28MPa×0.7=19.6MPa. The gas injection pressure is gradually increased at a rate of 0.025MPa per minute, eventually reaching 1.38 times the formation pressure, 28MPa×1.38=38.64MPa. The injection rate is maintained at 1.2m³ / min throughout the process.

[0094] Real-time monitoring: The gas leading edge propagation speed is monitored in real time through a distributed acoustic wave sensing system. When the propagation speed in a certain area is detected to slow down, the gas injection pressure gradient is adjusted appropriately to maintain the gas injection pressure gradient within the range of 0.02-0.03 MPa / min, ensuring that the gas uniformly spreads throughout the target layer.

[0095] Gas injection ends: When the total gas injection volume reaches 15% of the formation pore volume (8500m³ × 15% = 1275m³), gas injection is stopped, the well is shut in and pressure is stabilized for 48 hours, and then production is resumed.

[0096] Example 2

[0097] This example focuses on Well B in a gas field, with a reservoir permeability of 0.05 millidarcy, a formation temperature of 78°C, a gas saturation of 48%, and a cumulative production reaching 65% of the initial recoverable reserves. The lower limit parameters are used for implementation.

[0098] S1: Pre-blockage removal activation

[0099] Unblocking fluid formulation: 18% compound chelating acid, 0.6% nano-surfactant, 0.4% bio-enzyme preparation, and 76.9% formation water. In the compound chelating acid, the ratio of glycolic acid to EDTA-2Na to ammonium fluoride is 18:6:4; in the bio-enzyme preparation, the ratio of cellulase to lipase is 2.2:1, with cellulase activity of 9000 U / g and lipase activity of 5500 U / g. The injection rate is 0.6 m³ / min, and the total injection volume is 2.0 times the annular volume. The annular volume of this well is 15 m³, corresponding to an injection volume of 30 m³. Pulse pressure wave parameters: frequency 6 Hz, amplitude 0.7 MPa, and an action cycle of 15 minutes / cycle. The well is shut in for 20 hours.

[0100] S2: Multi-stage temporary styling fracturing

[0101] The injection rate of the pre-flush fluid was 3.0 m³ / min, with a single-stage volume of 25 m³. The injection rate of the proppant-carrying fluid was 3.5 m³ / min, with a proppant-to-liquid ratio of 10%, a thickener mass fraction of 0.38%, a zirconium-to-titanium molar ratio of 1:0.2 for the crosslinking agent, a breaker dosage of 0.06%, and a proppant Ra=3.5μm. The temporary plugging and redirecting agent was a mixture of temperature-responsive microspheres (phase transition temperature 61℃) and oil-soluble resin particles (mass ratio 6.8:3) at a ratio of 1.8:1, injected in a volume 0.18 times that of the pre-flush fluid. The well was shut in and pressurized to 1.35 times the formation fracturing pressure, repeated three times.

[0102] S3: Desorption Activation Transition Procedure

[0103] A mixture of carbon dioxide and nitrogen (volume ratio 1:1) was injected to 0.90 times the formation pressure, with the injection volume being 0.35% of the formation pore volume. After stabilizing the pressure for 12 hours, the pressure was released, and the cycle was repeated twice.

[0104] S4: Controlled gradient gas injection displacement

[0105] The wellbore temperature was controlled at 36.1℃, which is 5℃ above the critical temperature of carbon dioxide (31.1℃). The bottom hole pressure was 8.38 MPa, which is ≥ the critical pressure of carbon dioxide (7.38 MPa) plus 1.0 MPa. The initial injection pressure was 0.65 times the formation pressure, and the final pressure was 1.3 times the formation pressure, with a pressure rise rate of 0.02 MPa / min. The gas front was monitored using the DAS system. After the total injected gas volume reached 12% of the formation pore volume, the well was shut in and the pressure stabilized for 48 hours.

[0106] Example 3

[0107] This example focuses on Well C in a gas field, with a reservoir permeability of 8.2 millidarcy, a formation temperature of 112°C, a gas saturation of 60%, and a cumulative production reaching 78% of the initial recoverable reserves. The upper limit parameters are used for implementation.

[0108] S1: Pre-blockage removal activation

[0109] Unblocking fluid formulation: 22% compound chelating acid, 1.0% nano-surfactant, 0.7% biological enzyme preparation, and 76.3% formation water. In the compound chelating acid, the ratio of glycolic acid to EDTA-2Na to ammonium fluoride is 22:8:7; in the biological enzyme preparation, the ratio of cellulase to lipase is 2.8:1, with cellulase activity of 11000 U / g and lipase activity of 7000 U / g. The injection rate is 1.0 m³ / min, and the total injection volume is 2.3 times the annular volume. The annular volume of this well is 20 m³, corresponding to an injection volume of 46 m³. Pulse pressure wave parameters: frequency 8 Hz, amplitude 1.0 MPa, and an action cycle of 20 minutes / cycle. The well is shut in for 28 hours.

[0110] S2: Multi-stage temporary styling fracturing

[0111] The injection rate of the pre-flush fluid was 3.8 m³ / min, with a single-stage volume of 28 m³. The injection rate of the proppant-carrying fluid was 4.5 m³ / min, with a proppant-to-liquid ratio of 14%, a thickener mass fraction of 0.42%, a zirconium-to-titanium molar ratio of 1:0.3 for the crosslinking agent, a breaker dosage of 0.10%, and a proppant Ra=4.2 μm. The temporary plugging and redirecting agent was a mixture of temperature-responsive microspheres (phase transition temperature 65℃) and oil-soluble resin particles (mass ratio 7.2:3) at a ratio of 2.2:1, injected in a volume 0.22 times that of the pre-flush fluid. The well was shut in and pressurized to 1.55 times the formation fracturing pressure, repeated four times.

[0112] S3: Desorption Activation Transition Procedure

[0113] A mixture of carbon dioxide and nitrogen (volume ratio 1:1) was injected to 0.94 times the formation pressure, with the injection volume being 0.45% of the formation pore volume. After stabilizing the pressure for 12 hours, the pressure was released, and the cycle was repeated twice.

[0114] S4: Controlled gradient gas injection displacement

[0115] The wellbore temperature was controlled at 40℃, and the bottom hole pressure was ≥10MPa. The initial injection pressure was 0.75 times the formation pressure, and the final pressure was 1.45 times the formation pressure, with a pressure rise rate of 0.03MPa / min. The gas front was monitored using the DAS system, and the well was shut in and pressure stabilized for 48 hours after the total injected gas volume reached 18% of the formation pore volume.

[0116] II. Scale Settings

[0117] To verify the superiority of the technical solution of the present invention, five comparative examples were set up, all based on the A well conditions of Example 1, with only a single variable changed or existing technical solutions adopted:

[0118] Comparative Example 1: Lack of pre-congestion removal and activation steps

[0119] The steps S2-S4 of Example 1 are executed directly, skipping the S1 pre-unblocking and activation step, and the remaining parameters are completely consistent with those of Example 1.

[0120] Comparative Example 2: Temporary blocking diverter is a single component

[0121] The temporary blocking diverting agent uses only temperature-responsive microspheres, and the other parameters are the same as in Example 1.

[0122] Comparative Example 3: Gas injection displacement in constant pressure mode

[0123] Step S3 cancels the desorption activation transition procedure, and the gas injection displacement adopts a constant pressure mode, fixing the pressure at 1.38 times the formation pressure, without gradient pressurization, and the remaining parameters are the same as in Example 1.

[0124] Comparative Example 4: Core parameters exceed the scope of the claims

[0125] The composite chelating acid mass percentage is 15%, which is below the range of 18-22%; the surface grafting rate of the nano surfactant is 10 mmol / g, which is below the range of 12-18 mmol / g; the gas injection pressure increase rate is 0.04 MPa / min, which is above the range of 0.02-0.03 MPa / min; and the other parameters are consistent with those in Example 1.

[0126] Comparative Example 5: Conventional fracturing + single unblocking

[0127] Conventional hydraulic fracturing (without temporary plugging and diversion, single-stage fracturing) was adopted, along with single soil acid unblocking (15% hydrochloric acid + 5% hydrofluoric acid). After the unblocking fluid was injected, there was no pulse pressure wave assistance, and no gas displacement was performed after fracturing. The remaining construction parameters were matched with those in Example 1.

[0128] III. Test Results and Data Comparison

[0129] Test index Example 1 Example 2 Example 3 Comparative Example 1 Comparative Example 2 Comparative Example 3 Comparative Example 4 Comparative Example 5 Daily average gas production before construction (104m3) 1.85 1.22 3.58 1.85 1.85 1.85 1.85 1.85 Daily average gas production after construction (104m3) 4.72 2.98 8.25 3.15 3.68 3.86 3.02 2.63 Daily gas production improvement multiple 2.55 2.44 2.30 1.70 2.00 2.09 1.63 1.42 6-month cumulative production increase (104m3) 856.8 518.4 1728.6 475.2 604.8 648.0 448.8 349.2 Production increase effective period (months) 28 24 32 16 20 22 15 12 Plugging removal rate (%) 89.6 82.3 93.5 45.2 88.9 89.2 42.8 58.7 Fracture complexity coefficient 2.85 2.52 3.12 2.78 1.86 2.82 2.75 1.35 Gas drive sweep efficiency (%) 78.3 72.5 83.6 65.8 77.8 68.4 63.5 - Reservoir permeability after construction (mD) 2.32 0.091 15.85 1.81 2.29 2.30 1.74 1.10

[0130] In summary, this invention achieves efficient potential tapping and production enhancement for medium-low permeability, medium-high temperature, and mid-to-late stage gas wells through a three-stage composite process of pre-plugging activation, multi-stage temporary plugging and diversion fracturing, and controllable gradient gas injection displacement. This process thoroughly removes reservoir blockage through the synergistic effect of the composite plugging system; constructs a complex fracture network through two-component temporary plugging and diversion and multi-stage fracturing; and improves natural gas desorption efficiency and displacement range through desorption activation and gradient gas injection.

[0131] The above description is merely a preferred embodiment of the present invention and is not intended to limit the present invention in any way. Although the present invention has been disclosed above with reference to preferred embodiments, it is not intended to limit the present invention. Any person skilled in the art can make some modifications or alterations to the above-disclosed technical content to create equivalent embodiments without departing from the scope of the present invention. Any simple modifications, equivalent changes and alterations made to the above embodiments based on the technical essence of the present invention without departing from the scope of the present invention shall still fall within the scope of the present invention.

Claims

1. A combined process for tapping the potential and increasing production of gas wells, characterized in that, The process includes the following steps: S1. Pre-treatment unblocking activation: Injecting an unblocking fluid composition into the target layer, wherein the unblocking fluid composition comprises, by mass percentage: Complex chelated acids 18-22%; Nano-surfactants 0.6-1.0%; Biological enzyme preparations: 0.4-0.7%; The remainder is formation water; S2. Multi-stage temporary plugging and redirection fracturing: Execute three to five stages of fracturing cycles sequentially. Each stage includes: Injecting pre-flush fluid to form an initial crack, injecting sand-carrying fluid to fill the proppant, and injecting temporary plugging and diverting agent to seal the current crack; S3. Controlled gradient gas injection displacement: Supercritical displacement gas is injected into the formation in a stepped manner using a pressurization device to meet the following requirements: The initial gas injection pressure is 0.65 to 0.75 times the formation pressure; The final gas injection pressure is 1.3 to 1.45 times the formation pressure; The pressure rise rate is 0.02 MPa to 0.03 MPa per minute; The composite chelating acid is composed of glycolic acid, disodium ethylenediaminetetraacetate, and ammonium fluoride in a mass ratio of 18-22:6-8:4-7.

2. The combined process for tapping the potential and increasing production of gas wells according to claim 1, characterized in that, The nano-surfactant mentioned in step S1 is modified mesoporous silica, specifically: The pore size distribution ranges from 3 nanometers to 8 nanometers; Specific surface area greater than or equal to 280 square meters per gram; The surface grafting rate is 12 mmol / g to 18 mmol / g; The bio-enzyme preparation comprises thermostable cellulase and lipase, wherein the activity of the thermostable cellulase is 9,000 units per gram to 11,000 units per gram, and the activity of the lipase is 5,500 units per gram to 7,000 units per gram, and the mass ratio of the two is 2.2-2.8:

1.

3. The combined process for tapping the potential and increasing production of gas wells according to claim 1, characterized in that, The injection process parameters for step S1 are controlled as follows: The injection rate is 0.6 cubic meters to 1.0 cubic meters per minute; The total injection volume is 2.0 to 2.3 times the annulus volume of the wellbore; The parameters for applying the pulsed pressure wave are: Frequency 6 Hz to 8 Hz; Amplitude: 0.7 MPa to 1.0 MPa; The treatment cycle is 15 to 20 minutes each time.

4. The combined process for tapping the potential and increasing production of gas wells according to claim 1, characterized in that, The temporary blocking diverting agent in step S2 comprises a two-component response system: Temperature-responsive microspheres: The material is a copolymer of acrylamide and N-vinylcaprolactam; The phase transition temperature is 63 degrees Celsius ± 2 degrees Celsius; The particle size distribution is from 120 mesh to 250 mesh; Oil-soluble resin particles: The mass ratio of the components is C9 petroleum resin: hydrogenated rosin ester = 6.8-7.2:3; The dissolution rate is greater than or equal to 0.9 grams per square centimeter per hour; The mass ratio of temperature-responsive microspheres to oil-soluble resin particles is 1.8-2.2:

1.

5. The combined process for tapping the potential and increasing production of gas wells according to claim 1, characterized in that, The S2 step fracturing operation specifically includes: S201 injects pre-fluid at a rate of 3.0 to 3.8 cubic meters per minute, with a single-stage volume of 25 to 28 cubic meters; S202 is injected with sand-carrying fluid at a rate of 3.5 to 4.5 cubic meters per minute, with a sand-to-fluid ratio of 10% to 14%. S203 is injected to temporarily plug the diverter slug, with a volume of 0.18 to 0.22 times the volume of the pre-fluid. S204 was shut in and pressurized to 1.35 to 1.55 times the formation fracturing pressure; S205 repeats steps S201 to S204 three to four times.

6. The combined process for tapping the potential and increasing production of gas wells according to claim 5, characterized in that, The sand-carrying fluid system in step S202 includes: The thickener is 0.38% to 0.42% by weight of hydrophobic associating polyacrylamide; The crosslinking agent is an organozirconium and organotitanium composite, with a zirconium-titanium molar ratio of 1:0.2-0.3; The de-gelling agent is ammonium persulfate in double-layer microcapsules, with ethyl cellulose as the inner wall material and polylactic acid as the outer wall material; The proppant is nano-alumina modified ceramic particles with a surface roughness Ra of 3.5 micrometers to 4.2 micrometers.

7. The combined process for tapping the potential and increasing production of gas wells according to claim 1, characterized in that, Perform a desorption-activation transition procedure before step S3: S301 injects a mixture of carbon dioxide and nitrogen until the pressure reaches 0.90 to 0.94 times the formation pressure, with a volume ratio of 1:

1. S302 voltage stabilization for 12 hours; S303 was depressurized to the original formation pressure; S304 repeats steps S301 to S302 twice, with each injection amount being 0.35% to 0.45% of the formation pore volume.

8. The combined process for tapping the potential and increasing production of gas wells according to claim 1, characterized in that, Conditions for maintaining the supercritical state in step S3: Wellbore temperature control: not lower than the critical temperature of carbon dioxide plus 5 degrees Celsius, where the critical temperature of carbon dioxide is 31.1 degrees Celsius; Bottom hole pressure control: not lower than the critical carbon dioxide pressure plus 1.0 MPa, where the critical carbon dioxide pressure is 7.38 MPa; Real-time monitoring: The gas leading edge propulsion velocity is monitored through a distributed acoustic wave sensing system.

9. The combined process for tapping the potential and increasing production of gas wells according to claim 1, characterized in that, The applicable conditions are limited to: Reservoir permeability range: 0.02 millidarcy to 8.5 millidarcy; Formation temperature range: 75 degrees Celsius to 115 degrees Celsius; Gas saturation level is greater than or equal to 48%; Gas well production status: Cumulative production has reached 65% to 80% of the initial recoverable reserves.

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