High temperature and high pressure pressure-dissolved gas recovery system and method

Abstract

The present application relates to the technical field of oil and gas exploitation, and particularly relates to a high-temperature and high-pressure pressure-dissolution gas recovery system and method; the system comprises at least one gas well arranged in a gas reservoir, the bottom of the gas well is deep into a water layer; the gas well comprises a production pipe and a casing pipe, the production pipe contains a water recovery device, and a plurality of electrically-controlled sliding sleeves are arranged on the production pipe at intervals; the system further comprises a pressure sensor arranged outside the bottom of the production pipe; the system further comprises the water recovery device; the system further comprises a ground control device, which is used for receiving a pressure signal of the downhole pressure sensor, judging a depth of a bottom hole fluid accumulation, and controlling opening or closing of one or more intelligent sliding sleeves and a displacement of the water recovery device based on the fluid accumulation, so that the high-temperature and high-pressure pressure-dissolution gas can be continuously and efficiently recovered.

Description

Technical Field

[0001] This invention relates to the field of oil and gas extraction technology, and in particular to a high-temperature and high-pressure dissolved gas extraction system and a gas extraction method based on the system. Background Technology

[0002] With the continued growth of global energy demand, the development of conventional oil and gas reservoirs has gradually entered the later stages, with problems such as decreasing resource volume, increased extraction difficulty, and rising costs becoming increasingly prominent. Conventional reservoirs are mainly concentrated in shallow and medium-deep layers. After long-term development, their resource potential is nearing depletion, and the remaining resources are mostly distributed in areas with complex geological conditions and high development difficulty. This situation has prompted the energy industry to turn its attention to unconventional reservoirs such as shale gas, natural gas hydrates, and pressure-dissolved gas. There are many types of proven natural gas accumulations. The most common natural gas occurrence states include free gas and water-dissolved gas. The former is the commonly understood accumulated free gas, i.e., conventional gas layers, while the latter is natural gas dissolved in water. However, gas-water coexistence phenomena are observed in high-temperature and high-pressure reservoirs, such as pressure-dissolved gas zones. These zones contain a certain amount of dispersed free gas and saturated dissolved gas. The natural gas contained in the gas-water zone and water-dissolved gas within these high-pressure reservoirs is called pressure-dissolved gas.

[0003] In the development of solution gas reservoirs, water production in gas wells is an unavoidable phenomenon as development progresses. Existing technologies typically employ the following methods to control bottom water coning in water-bearing gas reservoirs: production parameter optimization and control, active drainage technology, physicochemical water control, and monitoring and early warning systems. Production parameter optimization and control includes determining reasonable production allocation through numerical simulation, maintaining critical production control by keeping the production pressure differential below a critical value (typically 0.5-1.0 MPa), employing an intermittent production system with an "on-off" cycle to delay water coning, and implementing stratified water control and multi-layered combined production optimization for vertically heterogeneous reservoirs. Active drainage technology includes gas lift drainage technology with designed reasonable injection depths (1000-2500 m) and injection volumes (5-15 × 10^4 m³ / d), and foam drainage technology that improves gas-liquid flow efficiency by injecting foaming agents (concentration 0.3%-0.8%). Physicochemical water control includes intelligent well completion technology that uses ICD / AICD water control screens to regulate flow distribution in different formations; gel plugging technology that injects polymer gel systems (gelation time 12-48h) to seal high-permeability water channels; and nano-plugging agents that selectively reduce aqueous permeability using novel materials (particle size 50-200nm). The monitoring and early warning system includes establishing a joint wellbore-formation monitoring system that integrates production profile testing, microseismic monitoring, and tracer detection technologies. Based on the monitoring results, the numerical simulation model is revised to predict the advance velocity of the water front.

[0004] However, the aforementioned methods in the existing technology have drawbacks such as bottom water rise, high abandoned pressure of gas reservoirs, and a huge amount of pressure-dissolved gas and water-dissolved gas remaining in the structure, making it difficult to maximize the economic benefits of pressure-dissolved gas reservoir development. Based on this, this application proposes a high-temperature and high-pressure pressure-dissolved gas production system and method to achieve intelligent and precise water control technology and maximize the exploitation of pressure-dissolved gas reservoirs. Summary of the Invention

[0005] One object of the present invention is to provide a high-temperature and high-pressure dissolved gas extraction system, and a gas extraction method based on the system.

[0006] In a first aspect, the present invention provides a high-temperature and high-pressure pressure-dissolved gas production system, comprising at least one gas well located in a gas reservoir, the gas well comprising casing and production tubing, casing completion, casing perforation below the gas layer and above the water layer, characterized in that: the bottom of at least one gas well extends into the water layer;

[0007] The production tubing is used to provide a gas extraction channel and space to accommodate the water extraction tubing string. A packer is installed in the annulus above the top of the gas layer.

[0008] It also includes several electrically controlled sliding sleeves spaced apart on the production tubing, used to open the gas supply channel or close the isolation annulus and tubing;

[0009] It also includes a pressure sensor, which is installed on the outside of the bottom of the production tubing to monitor the pressure information at the bottom of the production tubing string;

[0010] It also includes a water collection device, which is used to extract the accumulated liquid from the water layer that enters the production oil pipeline;

[0011] It also includes a ground control device, which receives pressure signals from downhole pressure sensors, determines the depth of liquid accumulation at the bottom of the well, and controls the opening or closing of one or more intelligent sliding sleeves and the discharge rate of the water extraction device based on the liquid accumulation, so as to achieve continuous and efficient extraction of dissolved gas under high temperature and high pressure.

[0012] Several electrically controlled sliding sleeves are evenly distributed on the production tubing in the gas top layer and the pressure-dissolved gas zone. The spacing between the electrically controlled sliding sleeves is 10m, 20m or 30m. For high-permeability gas reservoirs, the spacing between the electrically controlled sliding sleeves is set to 10m, and for low-permeability gas reservoirs, the spacing between the electrically controlled sliding sleeves is set to 30m.

[0013] Preferably, the electrically controlled sliding sleeve is arranged on the production oil pipe in the gas top layer region. Preferably, the electrically controlled sliding sleeve can also be arranged on the production oil pipe in the pressure dissolved gas zone and / or water dissolved gas zone region.

[0014] Preferably, the electrically controlled sliding sleeves are unevenly spaced, with the interval dH decreasing from bottom to top. For example, dH from bottom to top is 20m, 18m, 16m...4m, 2m. This concentrates more electrically controlled sliding sleeves on the top gas layer, which helps to accelerate the extraction of natural gas from the top gas layer, delay the extraction of natural gas from the water-soluble gas zone, and slow down the water cone advance, so as to extract more natural gas.

[0015] It also includes cables, including communication cables, power supply cables and control cables, used to transmit pressure signals from pressure sensors to ground control devices, supply power to several electrically controlled sliding sleeves and control the opening and closing of several electrically controlled sliding sleeves.

[0016] The water sampling device includes an electric submersible pump and a water sampling pipe. The electric submersible pump is lowered to the bottom of the production oil pipe to extract the accumulated liquid that has entered the production oil pipe.

[0017] The system also includes a downhole electrically controlled packer valve, which is used to control the opening and closing of the bottom of the production tubing and is controlled by a surface control device. It is used to provide a gas production channel in the early stages of gas well production and to prevent liquid from entering the production tubing from the bottom when closed.

[0018] The system consists of two wells: a water well and a gas well. The bottom of the water well extends deep into the water layer, while the bottom of the gas well is located in the gas layer or pressure-dissolved gas layer above the water layer.

[0019] The bottom depth of the water well is deeper than that of the gas well, which meets the requirements.

[0020] ;

[0021] Where Hw is the bottom depth of the water well, in meters; and Hg is the bottom depth of the gas well, in meters. denoted as the elevation difference between the wellheads of the water well and the gas well, in meters (m), and h as the effective thickness of the gas reservoir, in meters (m).

[0022] The distance between the water extraction well and the gas extraction well must meet the following requirements:

[0023] ;

[0024] Where Dwell is the distance between water well 4 and gas well 5, in meters; c This is the well group layout coefficient for pressure-dissolved gas reservoirs, typically ranging from 2 to 5.

[0025] The bottom of the production tubing in a water production well does not include a downhole electrically controlled packer valve, while the bottom of the production tubing in a gas production well does include a downhole electrically controlled packer valve. When the control device detects that the liquid accumulation at the bottom of the water production well has reached a certain level, a water production device is lowered in to extract the accumulated liquid.

[0026] Preferably, the gas well is a dual-branch well, comprising a gas production branch at the upper end and a water production branch at the lower end. Both the gas production branch and the water production branch have production tubing equipped with several electrically controlled sliding sleeves and pressure sensors. The gas production branch is located in the gas layer, or in the gas layer and the pressure-dissolved gas layer, and at least a portion of the well section of the water production branch is located in a water layer.

[0027] It also includes a Y-joint, where the gas production line and the water production line of the production line meet. A water production device is installed in the water production line, which includes an electric submersible pump and a water production pipe. The electric submersible pump is located in the water production line near the pressure sensor.

[0028] The cable is also used to power the electric submersible pump and control its displacement, or to power the downhole electrically controlled packer valve and control its opening and closing.

[0029] On the other hand, the present invention provides a method for gas production from high-temperature and high-pressure dissolved gas reservoirs, characterized by employing the gas production system described above, and the following steps:

[0030] Step 1. Assemble the gas production system production string. Conduct system commissioning on the surface control unit. After commissioning, lower the production string into the well and record the initial bottom hole pressure P. wf0 ;

[0031] Step 2. The surface control device continuously monitors the bottom hole pressure and records the bottom hole pressure P. wf Calculate the depth of liquid accumulation at the bottom of the well. If there is no liquid accumulation, control the opening of the downhole electrically controlled packer valve, close all electrically controlled sliding sleeves, and the downhole electrically controlled packer valve provides the gas production channel.

[0032] Step 3. The ground control device calculates and finds that there is a small amount of liquid at the bottom of the well. It closes the downhole electrically controlled packer valve and opens one or more electrically controlled sliding sleeves at the top of the production tubing. The electrically controlled sliding sleeves provide a gas production channel.

[0033] Step 4. If the ground control device calculates and finds that there is a large amount of liquid at the bottom of the well and the natural gas production at the wellhead has decreased significantly, then close all electrically controlled sliding sleeves, open the downhole electrically controlled packer valve, lower the electric submersible pump and water production pipe, control the discharge rate of the electric submersible pump, and start water production. During the water production process, open one or more electrically controlled sliding sleeves at the top of the production tubing to extract natural gas.

[0034] Step 5. Repeat steps 3-4. The ground control device continuously calculates the depth of liquid accumulation at the bottom of the well. Based on the depth of liquid accumulation at the bottom of the well, it adjusts the opening and closing of several electrically controlled sliding sleeves and downhole electrically controlled packing valves, adjusts the water production discharge of the electric submersible pump, and continues to produce gas.

[0035] Preferably, the assembly of the gas production system production tubing in step 1 specifically involves determining the number and spacing dH of electrically controlled sliding sleeves in the production tubing based on gas reservoir geological exploration data, and assembling the production tubing containing cables, electrically controlled sliding sleeves, downhole electrically controlled packer valves, and sensors.

[0036] Preferably, the ground control device described in step 1 carries out system debugging, specifically during the assembly process, the control device checks whether the communication with the pressure sensor is normal and whether it can control the electric sliding sleeve and the downhole electric packer valve to open and close normally.

[0037] Preferably, in step 2, controlling the opening degree of the downhole electrically controlled packer valve means controlling the downhole electrically controlled packer valve to open to a certain extent so that the wellhead gas production does not exceed the predetermined production q. r The planned output can be calculated using the following formula:

[0038] ;

[0039] Where, q r To meet the projected production target, 10 4 m³ / d; kh is the horizontal permeability, mD; h is the effective thickness of the gas layer, m; Δρ is the water-gas density difference, kg / m³ 3 β is the vertical permeability correction factor, typically taken as 0.5~1; γ is the gas well production stage correction factor, determined by... calculate, The ratio of the water layer's ascent depth to the effective thickness of the gas layer; μ g为 Gas viscosity, mPa·s, B g The gas volume coefficient is dimensionless and typically ranges from 0.005 to 0.01; r e r is the discharge radius, in meters (m); w Let be the radius of the wellbore, in meters (m).

[0040] Preferably, The ratio of the water layer's rise depth to the effective thickness of the gas layer is calculated using the following formula:

[0041] ;

[0042] Among them, h l The depth of fluid accumulation at the bottom of the gas well above the bottom pressure sensor, in meters (m); h c The distance, in meters, is the distance from the bottom pressure sensor of the gas well to the original gas-water boundary.

[0043] Preferably, in step 3, there is a small amount of accumulated fluid at the bottom of the well, which is... When <0.2.

[0044] Preferably, in step 3, one or more electrically controlled sliding sleeves are opened above the depth of the accumulated liquid surface, and the number of electrically controlled sliding sleeves opened is determined by q.r The decision is made so that, after several electrically controlled sliding sleeves are opened, the wellhead production at the moment q is closest to the current level of fluid accumulation. r .

[0045] Preferably, in steps 2-4, during the gas production process, the control module continuously monitors the bottom hole pressure and calculates the bottom hole fluid accumulation depth h. l Based on the depth of fluid accumulation at the bottom of the well, h l Calculate the predetermined output q r By pre-determining production volume q r Determine the number of electrically controlled sliding sleeves to be opened, and then open the multiple electrically controlled sliding sleeves.

[0046] Preferably, in step 4, the control device controls the discharge rate of the electric submersible pump based on the depth of the liquid accumulation at the bottom of the well to ensure that the depth of the liquid accumulation at the bottom of the well does not increase. When the discharge rate of the electric submersible pump reaches its maximum value, if the depth of the liquid accumulation at the bottom of the well still increases, the number of electrically controlled sliding sleeves that are opened is gradually reduced until the depth of the liquid accumulation at the bottom of the well no longer increases, or the rate of increase tends to stabilize.

[0047] On the other hand, the present invention provides a method for gas production from high-temperature and high-pressure dissolved gas reservoirs, employing a dual-well gas production system, with the following steps:

[0048] Step 1. Assemble the production tubing for the water production well and gas production well separately. Conduct system commissioning on the surface control device. After commissioning, lower the production tubing into the well and record the initial bottom hole pressure P of both wells. wf0 ;

[0049] Step 2. The ground control device continuously monitors the bottom hole pressure and records the bottom hole pressure P of the water production well. wfw and the bottom pressure P of the gas well wfg Calculate the depth of liquid accumulation at the bottom of the well. If there is no liquid accumulation, close all electrically controlled sliding sleeves. The water production well is supplied with a gas production channel by the production tubing. The gas production well controls the opening of the downhole electrically controlled packer valve, which provides the gas production channel for the gas production well.

[0050] Step 3. If the ground control device calculates and finds that there is a small amount of liquid at the bottom of the water well, it will open one or more electrically controlled sliding sleeves above the liquid level. The electrically controlled sliding sleeves provide a channel for extracting natural gas from the water well.

[0051] Step 4. If the ground control device calculates and finds that there is a large amount of liquid at the bottom of the water well and the natural gas production at the wellhead has decreased significantly, then all electrically controlled sliding sleeves are shut down, the electric submersible pump and water pipe are lowered down, and water extraction begins. During the water extraction process, one or more electrically controlled sliding sleeves at the top of the production oil pipe are opened to extract natural gas from the water well.

[0052] Step 5. Repeat steps 2-4. The ground control device continuously calculates the depth of liquid accumulation at the bottom of the water well. Based on the depth of liquid accumulation at the bottom of the well, it adjusts the opening and closing of several electrically controlled sliding sleeves and downhole electrically controlled packing valves of the water well and gas well, adjusts the discharge rate of the electric submersible pump, and continuously extracts natural gas from the water well and gas well.

[0053] In step 2, the control device controls the opening degree of the downhole electrically controlled packer valve of the gas production well to open the valve to a certain extent, so that the gas production at the wellhead does not exceed the predetermined production rate q. r The planned output can be calculated using the following formula:

[0054] ;

[0055] Where, q r To meet the projected production target, 10 4 m³ / d; kh is the horizontal permeability, mD; h is the effective thickness of the gas layer, m; Δρ is the water-gas density difference, kg / m³ 3 β is the vertical permeability correction factor, typically taken as 0.5~1; γ is the gas well production stage correction factor, determined by... calculate, The ratio of the water layer's ascent depth to the effective thickness of the gas layer; μ g为 Gas viscosity, mPa·s, B g The gas volume coefficient is dimensionless and typically ranges from 0.005 to 0.01; r e r is the discharge radius, in meters (m); w Let be the radius of the wellbore, in meters (m).

[0056] In steps 3-4, when liquid accumulation is found at the bottom of water well 4, control device 15 determines whether there is liquid accumulation at the bottom of gas well 5. If there is no liquid accumulation, the production system of the gas well is not changed; if there is a small amount of liquid accumulation, the downhole electrically controlled packer valve 12 is closed, and one or more electrically controlled sliding sleeves 10 above the liquid level are opened to ensure that the gas production at the wellhead does not exceed 0.8 times the predetermined production q. r If there is a large amount of accumulated fluid in gas well 5, open the downhole electrically controlled packer valve 12, close all electrically controlled sliding sleeves 10, and shut in the well. As the accumulated fluid at the bottom of water well 4 is extracted, and the depth of the accumulated fluid at the bottom of gas well 5 decreases to a certain level, the control device 15 controls one or more electrically controlled sliding sleeves 10 at the top of the production tubing 7 to open, so that the gas production at the wellhead does not exceed 0.8 times the predetermined production q at the current time of accumulated fluid. r .

[0057] The depth of the liquid accumulation at the bottom of gas production well 5 has decreased to a certain extent, which refers to h l <1 / 3Hs, where Hs refers to the distance from the uppermost electrically controlled sliding sleeve to the lowermost electrically controlled sliding sleeve in the production tubing of the gas well.

[0058] Compared with the prior art, the advantages of the present invention are:

[0059] This application establishes an intelligent and precise gas production system by using a control device, pressure sensor, several electrically controlled sliding sleeves, downhole electrically controlled packer valves, and water production device. The control device monitors downhole pressure signals to determine whether there is liquid accumulation and calculates the depth of downhole liquid accumulation. It then controls the opening and closing of one or more electrically controlled sliding sleeves and downhole electrically controlled packer valves to dynamically control production, extend the extraction of natural gas during the waterless period as much as possible, and maximize the extraction of pressure dissolved gas.

[0060] This application uses a control device to calculate the level of downhole liquid accumulation and control the intelligent water production of the water production device. By controlling the discharge rate of the water production device and adjusting the number of openings of the electrically controlled sliding sleeve, the two can effectively reduce the liquid accumulation at the bottom of the well or keep the water layer at a certain level, thereby maximizing the life cycle of the gas well and maximizing the extraction of pressure dissolved gas.

[0061] The control device in this application is based on the predetermined production rate q of the gas well at each production period. r Determine the number of electrically controlled sliding sleeves to open or the opening degree of the downhole electrically controlled packer valve to slow down the rise of the water layer to the greatest extent possible.

[0062] This application designs three different gas production systems: single-well, dual-well, and dual-branch well, each adapted to different pressure-dissolution conditions. Attached Figure Description

[0063] Figure 1 This is a schematic diagram of the gas extraction system in the initial stage of the gas extraction process according to Embodiment 1 of this application;

[0064] Figure 2 This is a schematic diagram of the gas extraction system after a certain stage of extraction, as shown in Embodiment 1 of this application.

[0065] Figure 3 This is a schematic diagram of the gas extraction system in the initial stage of extraction according to Embodiment 2 of this application;

[0066] Figure 4 This is a schematic diagram of the gas extraction system in Embodiment 2 of this application after a certain stage of extraction;

[0067] Figure 5 This is a schematic diagram of the gas extraction system in the initial stage of extraction according to Embodiment 3 of this application;

[0068] Figure 6 This is a schematic diagram of the gas extraction system after a certain stage of extraction, as shown in Embodiment 3 of this application.

[0069] Numbers in the diagram

[0070] Overlying strata 1, gas-bearing layer 2, gas-bearing layer 2-1, pressure-dissolved gas layer 2-2, water-dissolved gas layer 2-3, water layer 3, water production well 4, gas production well 5, casing 6, production tubing 7, cable 8, packer 9, main packer 9-1, branch well 1 packer 9-2, branch well 2 packer 9-3, electrically controlled sliding sleeve 10, pressure sensor 11, downhole electrically controlled packer valve 12, water production pipe 13, electric submersible pump 14, control device 15, Y-joint 16, branch well 17, branch well 2 18. Detailed Implementation

[0071] To make the objectives, technical solutions, and advantages of the embodiments of the present invention clearer, the technical solutions of the embodiments of the present invention will be clearly and completely described below with reference to the accompanying drawings. Obviously, the described embodiments are only some, not all, of the embodiments of the present invention. The components of the embodiments of the present invention described and shown in the accompanying drawings can generally be arranged and designed in various different configurations.

[0072] The specific embodiments of the present invention will now be described in detail with reference to the accompanying drawings.

[0073] Example 1

[0074] like Figure 1 and Figure 2 As shown, the vertical structure of a conventional high-pressure natural gas reservoir can generally be divided into a gas layer, a pressure-dissolved gas zone, and a water layer. The main forms of natural gas occurrence are, in order, continuous free gas, dispersed free gas, saturated dissolved gas, and unsaturated dissolved gas, with the gas abundance per unit volume of formation decreasing in that order. Figure 1 The diagram illustrates a typical geological structural trap for pressure-dissolved gas, which refers to natural gas contained in the gas-water zone and water-dissolved gas zone within a high-pressure reservoir. Figure 1 As shown, during the hydrocarbon accumulation process, due to the combined effects of gravity differentiation and capillary forces, the trap structure generally consists of, from bottom to top, a water layer 3, a water-dissolved gas zone 2-3, a pressure-dissolved gas zone 2-2, and a gas-top layer 2-1. The fluid in water layer 3 is water, which is the pure water zone, and the gas saturation Sg in the formation pore media can be considered 0. Above water layer 3 is the water-dissolved gas zone 2-3, which contains dissolved gas, existing in the pore media in an unsaturated to saturated dissolved gas state. Above water-dissolved gas zone 2-3 is the pressure-dissolved gas zone 2-2, which mainly consists of dispersed free gas and continuous free gas. The gas-top layer 2-1 only produces gas, corresponding to a pure gas zone (containing only bound water) with a water saturation lower than the bound water saturation and a reservoir zone with a water saturation between the bound water saturation and the critical water saturation (containing some free water).

[0075] In conventional gas reservoir development systems, as gas wells are developed, the wellbore pressure gradually decreases, causing water to converge towards the bottom of the well. This leads to water coning or tongueing, resulting in water flooding of the gas well and a sharp decrease in gas production. A large amount of dissolved gas in the reservoir cannot be extracted. Based on this, this application proposes a high-temperature, high-pressure dissolved gas reservoir production system.

[0076] The bottom of the gas well extends a certain distance into the water layer 3. The gas well includes casing 6 and production tubing 7. The gas well is completed using casing to the gas top layer 2-1 and below, and the casing is perforated above the water layer 3.

[0077] The production tubing 7 is used to provide a gas production channel and space to accommodate the water production tubing string. A packer 9 is installed in the annulus above the top of the gas top layer 2-1.

[0078] Several electrically controlled sliding sleeves 10 are installed on the production tubing 7. The several electrically controlled sliding sleeves 10 are evenly spaced, with each electrically controlled sliding sleeve spaced dH apart. The electrically controlled sliding sleeves 10 are controlled by a cable 8 extending from the wellhead to the bottom of the production tubing, and are used to selectively allow natural gas in the well to enter the production tubing from the annulus.

[0079] Preferably, the spacing dH of the electrically controlled sliding sleeve is 10m, 20m, or 30m, depending on the gas reservoir properties.

[0080] Preferably, the electrically controlled sliding sleeve is arranged on the production oil pipe 7 in the gas top layer 2-1 region. Preferably, the electrically controlled sliding sleeve can also be arranged on the production oil pipe 7 in the pressure dissolved gas zone 2-2 and / or water dissolved gas zone 2-3 region.

[0081] Preferably, the electrically controlled sliding sleeves are unevenly spaced, with the interval dH decreasing from bottom to top. For example, dH from bottom to top is 20m, 18m, 16m...4m, 2m. This concentrates more electrically controlled sliding sleeves in the gas top layer, which helps to accelerate the extraction of natural gas in the gas top layer 2-1, delay the extraction of natural gas in the water-soluble gas zone 2-3, and delay the water cone advance, thus extracting more natural gas.

[0082] A pressure sensor 11 is installed on the outer side of the bottom of the production tubing 7. The pressure sensor 11 monitors the pressure at the bottom of the production tubing string and transmits the pressure information to the ground via cable 8 to determine the depth of the liquid accumulation at the bottom of the gas well.

[0083] The gas extraction system also includes an electric submersible pump 14 and a water extraction pipe 13. The electric submersible pump 14 is lowered to the bottom of the production oil pipe 7 to extract the accumulated liquid entering the production oil pipe 7.

[0084] The gas production system also includes a ground control device 15, which receives pressure signals from the downhole pressure sensor 11 via wired or wireless means, determines the liquid accumulation at the bottom of the well, and controls the opening or closing of several intelligent sliding sleeves 10.

[0085] The gas production system also includes a downhole electrically controlled packer valve 12, which is used to control the opening and closing of the bottom of the production tubing 7 and is controlled by the surface control device 15.

[0086] Cable 8 includes a communication cable, a power supply cable, and a control cable, used to transmit pressure signals from pressure sensor 11 to ground control device 15, supply power to and control the opening and closing of several electrically controlled sliding sleeves 10, supply power to and control the discharge rate of electric submersible pump, and supply power to and control the opening and closing of downhole electrically controlled packer valve 12.

[0087] Preferably, a surface pressure sensor is also installed at the wellhead to measure the natural gas pressure at the wellhead. The control system determines the depth of fluid accumulation at the bottom of the well based on the signals from the downhole pressure sensor 11 and the wellhead pressure sensor. The calculation method is a conventional existing technology and will not be described in detail here.

[0088] The gas extraction method using the gas extraction system described in Example 1 includes the following steps:

[0089] Step 1. Assemble the gas production system production string. The surface control device 15 conducts system commissioning. After commissioning, the production string is lowered into the well, and the initial bottom hole pressure P is recorded. wf0 .

[0090] Step 2. The surface control device 15 continuously monitors the bottom hole pressure and records the bottom hole pressure P. wf Calculate the depth of fluid accumulation at the bottom of the well. If there is no fluid accumulation downhole, control the opening of the downhole electrically controlled packer valve 12, close all electrically controlled sliding sleeves 10, and the downhole electrically controlled packer valve 12 provides a channel for natural gas extraction.

[0091] Step 3. If the ground control device 15 calculates and finds that there is a small amount of liquid at the bottom of the well, close the downhole electrically controlled packer valve 12, open one or more electrically controlled sliding sleeves 10 at the top of the production tubing 7, and the electrically controlled sliding sleeves 10 provide a channel for the extraction of natural gas.

[0092] Step 4. If the ground control device 15 calculates and finds that there is a large amount of liquid at the bottom of the well and the natural gas production at the wellhead is greatly reduced, then close all the electrically controlled sliding sleeves, open the downhole electrically controlled packer valve 12, lower the electric submersible pump 14 and the water production pipe 13, and start water production. During the water production process, open one or more electrically controlled sliding sleeves 10 at the top of the production tubing 7 to extract natural gas.

[0093] Step 5. Repeat steps 3-4. The ground control device 15 continuously calculates the depth of the liquid accumulation at the bottom of the well. Based on the depth of the liquid accumulation at the bottom of the well, it adjusts the opening and closing of several electrically controlled sliding sleeves 10 and downhole electrically controlled packing valves 12, adjusts the water production discharge of the electric submersible pump, controls the gas-water interface, and continuously produces gas.

[0094] Specifically, the assembly of the gas production system production tubing in step 1 involves determining the number and spacing dH of electrically controlled sliding sleeves 10 in the production tubing 7 based on gas reservoir geological exploration data, and assembling the production tubing 7 with cables 8, electrically controlled sliding sleeves 10, downhole electrically controlled packer valves 12, and sensors 11.

[0095] The ground control device 15 described in step 1 undergoes system debugging. Specifically, during the assembly process, the control device 15 checks whether the communication with the pressure sensor 11 is normal and whether it can control the electric sliding sleeve 10 and the downhole electric packer valve 12 to open and close normally. Debugging the gas production system before lowering it into the well allows for early detection and rectification of system problems, ensuring system stability and avoiding the hassle of troubleshooting problems discovered downhole.

[0096] In step 2, controlling the opening degree of the downhole electrically controlled packer valve 12 is to control the downhole electrically controlled packer valve 12 to open to a certain extent, so that the wellhead gas production does not exceed the predetermined production q. r Expected production q r It can be calculated using the following formula:

[0097] ;

[0098] Where, q r To meet the projected production target, 10 4 m³ / d; k h ρ is the horizontal permeability, mD; h is the effective thickness of the gas layer, m; Δρ is the water-gas density difference, kg / m³. 3 β is the vertical permeability correction factor, typically taken as 0.5~1; γ is the gas well production stage correction factor, determined by... Calculation; μ g为 Gas viscosity, mPa·s, B g The gas volume coefficient is dimensionless and typically ranges from 0.005 to 0.01; r e r is the discharge radius, in meters (m); w Let be the radius of the wellbore, in meters (m).

[0099] This invention innovatively introduces a correction coefficient γ for the gas well production stage, which can dynamically adjust the predetermined wellhead production rate q according to the degree of water intrusion in the gas well. r This prevented the gas well from being further eroded by water.

[0100] By controlling the opening degree of the downhole electrically controlled packer valve 12, the wellhead gas production is controlled to not exceed the predetermined production rate q. r This will maximize the duration of waterless extraction and increase the recovery rate of natural gas.

[0101] The ratio of the water depth at the bottom of the wellbore to the effective thickness of the gas layer is calculated using the following formula:

[0102] ;

[0103] Among them, h l The depth of fluid accumulation at the bottom of the well, in meters (m); h c The distance, in meters, is the distance from the location of the bottom pressure sensor 11 in the gas well to the original gas-water boundary.

[0104] In step 3, a small amount of liquid is present at the bottom of the well, which is... When <0.25.

[0105] In step 3, one or more electrically controlled sliding sleeves 10 at the top of the production oil pipe 7 are opened, and the number of electrically controlled sliding sleeves 10 opened is determined by q. r The decision is made to ensure that, after several electrically controlled sliding sleeves 10 are opened, the wellhead production is closest to the level of fluid accumulation at time q. r .

[0106] In steps 2-4, during the gas production process, the control module 15 continuously monitors the bottom hole pressure and calculates the bottom hole fluid accumulation depth h. l Based on the depth of fluid accumulation at the bottom of the well, h l Calculate the predetermined output q r By pre-determining production volume q r Determine the number of times multiple electrically controlled sliding sleeves 10 are opened, and then open multiple electrically controlled sliding sleeves 10.

[0107] In step 4, the depth of the electric submersible pump is equal to or lower than the location of the bottom pressure sensor 11.

[0108] In step 4, the control device 15 controls the discharge rate of the electric submersible pump 14 according to the depth of the liquid accumulation at the bottom of the well to ensure that the depth of the liquid accumulation at the bottom of the well does not increase. When the discharge rate of the electric submersible pump 14 reaches its maximum value and the depth of the liquid accumulation at the bottom of the well still increases, the number of electrically controlled sliding sleeves 10 that are opened is gradually reduced until the depth of the liquid accumulation at the bottom of the well no longer increases.

[0109] This embodiment achieves continuous development of pressure-dissolved gas through a single well. By continuously monitoring the depth of the liquid accumulation at the bottom of the well, the number of openings of the electrically controlled sliding sleeve and the opening and closing of the downhole electrically controlled packer valve are dynamically adjusted. Combined with the extraction of the downhole liquid using the water production tubing, natural gas is continuously extracted, maximizing the recovery of natural gas from the pressure-dissolved gas reservoir.

[0110] Example 2

[0111] like Figure 3 and Figure 4 As shown, based on Embodiment 1, an additional water well 4 is added for water extraction when the aquifer is flooded. It also includes a gas well 5 with the same structure as in Embodiment 1, such as... Figure 3 As shown, both water well 4 and gas well 5 are located in the same high-temperature and high-pressure dissolved gas reservoir.

[0112] Preferably, according to geological data, the bottom of the water well 4 extends into the water layer 3, and the bottom of the gas well 5 is located in the gas layer 2-1 or the pressure-dissolved gas layer 2-2 above the water layer 3.

[0113] Preferably, the bottom depth of the water well 4 is deeper than the bottom depth of the gas well 5, specifically:

[0114] ;

[0115] Where Hw is the bottom depth of water well 4, in meters; and Hg is the bottom depth of gas well 5, in meters. The elevation difference between the wellheads of water well 4 and gas well 5 is denoted as m. This configuration ensures that the bottom water of the gas reservoir contacts water well 4 first, without affecting gas well 5, thus maximizing the water-free gas production from gas well 5.

[0116] Preferably, the spacing between the water well 4 and the gas well 5 is calculated as follows:

[0117] ;

[0118] Where Dwell is the distance between water well 4 and gas well 5, in meters; c This is the well group layout coefficient for pressure-dissolved gas reservoirs, which is usually taken as 2-5 based on field practice.

[0119] Based on the development practice of pressure-dissolved gas reservoirs, the above-mentioned distance setting takes into account both the discharge radius of the gas well and the gas reservoir parameters, so that the two are not too close to avoid inter-well interference, nor too far apart to achieve the protection of the gas well by the water production well.

[0120] In the water production well 4, the gas well includes casing 6, production tubing 7, casing completion, and casing perforation completion below the gas layer 2-1 and above the water layer 3. Production tubing 7 provides a gas production channel and space to accommodate the water production tubing string. A packer 9 is installed near the bottom of the casing in the production tubing. Several electrically controlled sliding sleeves 10 are installed on the production tubing 7, evenly spaced with a spacing of dH between each sleeve. The electrically controlled sliding sleeves 10 are controlled by a cable 8 extending from the wellhead to the bottom of the production tubing, selectively allowing natural gas from the annulus into the production tubing. Preferably, the spacing dH between the electrically controlled sliding sleeves is 10m, 20m, or 30m, determined according to the gas reservoir properties. A pressure sensor 11 is installed at the bottom of the production tubing 7. The pressure sensor 11 tests the pressure at the bottom of the production tubing string and transmits the pressure information to the surface via the cable 8 to determine whether the gas well bottom is flooded and the depth of the bottom fluid accumulation. The wellhead of the water intake well 4 is connected to the control device 15 via a cable. The cable 8 includes a communication cable, a power supply cable, and a control cable, used to transmit the pressure signal from the pressure sensor 11 to the ground control device 15, to supply power to and control the opening and closing of several electrically controlled sliding sleeves 10, to supply power to the electric submersible pump, and to control the pump's discharge rate.

[0121] Based on the above structure of the water production well 4, the gas production well 5 is also equipped with a downhole electrically controlled packer valve 12 at the bottom of the production tubing 7. The downhole electrically controlled packer valve 12 is controlled to open and close by the control device 15 via a cable.

[0122] The water well 4 also includes an electric submersible pump 14 and a water production pipe 13. The electric submersible pump 14 is lowered to the position below the lowest electrically controlled sliding sleeve 10 to extract the accumulated liquid that enters the production oil pipe 7.

[0123] The control device 15 receives the pressure signals from the downhole pressure sensor 11 of the water well 4 and the downhole pressure sensor 11 of the gas well 5, calculates the liquid accumulation at the bottom of the water well 4 and the gas well 5, and controls the opening and closing of each electrically controlled sliding sleeve 10 of the water well, as well as the opening and closing of each electrically controlled sliding sleeve 10 and the downhole electrically controlled packer valve 12 of the gas well 5 based on the liquid accumulation at the bottom of the water well 4 and the gas well 5.

[0124] The gas extraction method using the gas extraction system described in Example 2 includes the following steps:

[0125] Step 1. Assemble the production tubing for the water production well 4 and the gas production well 5 respectively. Conduct system commissioning on the surface control device 15. After commissioning, lower the production tubing into the wells and record the initial bottom hole pressure P of both wells. wf0 .

[0126] Step 2. The ground control device 15 continuously monitors the bottom hole pressure and records the bottom hole pressure P of the water production well. wfw and the bottom pressure P of the gas well wfgCalculate the depth of fluid accumulation at the bottom of the well. If there is no fluid accumulation, close all electrically controlled sliding sleeves 10. The water production well 4 is provided with a gas production channel by the production tubing. The gas production well 5 controls the opening of the downhole electrically controlled packer valve 12, which provides a gas production channel for the gas production well 5.

[0127] Step 3. If the ground control device 15 calculates and finds that there is a small amount of liquid at the bottom of the water well 4, then open one or more electrically controlled sliding sleeves 10 at the top of the production oil pipe 7. The electrically controlled sliding sleeves 10 provide a channel to extract natural gas from the water well 4.

[0128] Step 4. The ground control device 15 calculates and finds that there is a large amount of liquid at the bottom of the water well 4 and the natural gas production at the wellhead has decreased significantly. Then, all the electrically controlled sliding sleeves are shut down, the electric submersible pump 14 and the water production pipe 13 are lowered down, and water production begins. During the water production process, one or more electrically controlled sliding sleeves 10 at the top of the production oil pipe 7 are opened to extract natural gas from the water well 4.

[0129] Step 5. Repeat steps 2-4. The ground control device 15 continuously calculates the depth of the liquid accumulation at the bottom of the water well 4. Based on the depth of the liquid accumulation at the bottom of the well, it adjusts the opening and closing of several electrically controlled sliding sleeves 10 and downhole electrically controlled packing valves 12 of the water well 4 and the gas well 5, adjusts the discharge rate of the electric submersible pump, and continuously extracts natural gas from the water well 4 and the gas well 5.

[0130] In step 2, the gas production well 5 controls the opening of the downhole electrically controlled packer valve 12. This is achieved by the control device 15 controlling the downhole electrically controlled packer valve 12 of the gas production well 5 to open to a certain extent, so that the gas production at the wellhead does not exceed the predetermined production q. r This is to prevent water from being encountered in gas well 5.

[0131] In steps 3-4, when liquid accumulation is found at the bottom of water well 4, control device 15 determines whether there is liquid accumulation at the bottom of gas well 5. If there is no liquid accumulation, the production system of gas well 5 is not changed; if there is a small amount of liquid accumulation, the downhole electrically controlled packer valve 12 is closed, and one or more electrically controlled sliding sleeves 10 at the top of the production tubing are opened to ensure that the gas production at the wellhead does not exceed 0.8 times the predetermined production q. r If there is a large amount of accumulated fluid in gas well 5, open the downhole electrically controlled packer valve 12, close all electrically controlled sliding sleeves 10, and shut in the well. As the accumulated fluid at the bottom of water well 4 is extracted, and the depth of the accumulated fluid at the bottom of gas well 5 decreases to a certain level, the control device 15 controls one or more electrically controlled sliding sleeves 10 at the top of the production tubing 7 to open, so that the gas production at the wellhead does not exceed 0.8 times the predetermined production q. r .

[0132] This is because the presence of a small amount of liquid in water well 4 indicates that water layer 3 in the gas reservoir has entered the production area of ​​water well 4. If a small amount of liquid is also present in gas well 5, it indicates water channeling, requiring a reduction in production to prevent further water intrusion in gas well 5. The wellhead gas production rate is set at 0.8 times the predetermined production rate q. rBased on experience in the early development of solution-exposed gas reservoirs, it was found that when signs of fluid accumulation appeared in the gas well, the wellhead production was appropriately reduced to 0.8 times the predetermined production rate q. r This can effectively extend the production period of gas wells and obtain maximum economic benefits, exceeding 0.8 times the predetermined production rate q. r The waterless gas production period will decline rapidly; if there is a large amount of liquid accumulation in gas production well 5, it indicates severe water intrusion. At this time, the well needs to be temporarily shut down. Gas production can only continue after the liquid accumulation at the bottom of the well is extracted by water production well 5.

[0133] The depth of the liquid accumulation at the bottom of gas production well 5 has decreased to a certain extent, which refers to h l <1 / 3Hs, where Hs refers to the distance from the uppermost electrically controlled sliding sleeve 10 to the lowermost electrically controlled sliding sleeve 10 in the production tubing 7 of gas well 5.

[0134] Example 3

[0135] like Figure 5 and Figure 6 As shown, based on Example 1, the gas production well is improved by setting it as a dual-branch horizontal well, forming branch well 17 and branch well 18, as follows. Figure 5 As shown, both branch well 17 and branch well 28 are located in the same high-temperature and high-pressure solution gas reservoir. At least part of branch well 28 is located in water layer 3, while branch well 17 is located in the gas layer 2-1, or in the gas layer 2-1 and the solution gas layer 2-2. The lower casing of branch well 17 and branch well 28 were perforated for completion.

[0136] The system also includes Y-joint 16, branch well 1 tubing and branch well 2 tubing, which converge at Y-joint 16.

[0137] The first and second branch well tubing strings are suspended on the well wall of the branch well via packer 9-2 and packer 9-3, respectively.

[0138] Both the first and second branch well tubing strings include a production tubing 7. Several electrically controlled sliding sleeves 10 are installed on the production tubing 7. The several electrically controlled sliding sleeves 10 are evenly spaced, with each electrically controlled sliding sleeve spaced dH apart. The electrically controlled sliding sleeves 10 are controlled by a cable 8 extending from the wellhead to the bottom of the production tubing. The electrically controlled sliding sleeves 10 are used to selectively allow natural gas in the well to enter the production tubing from the annulus.

[0139] Pressure sensors 11 are installed at the bottom of the production tubing 7 of both the first and second branch wells. The pressure sensors 11 test the pressure at the bottom of the production tubing and transmit the pressure information to the ground via cable 8 to determine whether the bottom of the gas well is flooded and the depth of the liquid accumulation at the bottom of the well.

[0140] The wellhead of the gas production well is connected to the control device 15 via a cable. The control device 15 receives pressure signals from the downhole pressure sensors 11 of branch well 17 and branch well 2 via the cable, calculates the liquid accumulation at the bottom of branch well 17 and branch well 2, and controls the opening and closing of each electrically controlled sliding sleeve 10 of the water production well based on the liquid accumulation at the bottom of branch well 17 and branch well 2, as well as the opening and closing of the electrically controlled sliding sleeve 10 and the downhole electrically controlled packer valve 12 of branch well 17.

[0141] A water production device is installed in branch well 2-18, which includes an electric submersible pump and a water production pipe. The electric submersible pump is located near the pressure sensor in the production tubing of branch well 2-18.

[0142] The above settings enable priority water intake for branch well 218, thus protecting the gas production branch from the water production branch.

[0143] The above description is merely a preferred embodiment of the present invention and is not intended to limit the invention. For those skilled in the art, the features in the above embodiments can be combined with each other without conflict, and the present invention can also have various modifications and variations. Any modifications, equivalent substitutions, improvements, etc., made within the spirit and principles of the present invention should be included within the scope of protection of the present invention. Furthermore, the embodiments should be considered exemplary and non-limiting; the scope of the present invention is defined by the appended claims rather than the foregoing description. Therefore, it is intended that all variations falling within the meaning and scope of equivalent elements of the claims be included within the present invention. No reference numerals in the claims should be construed as limiting the scope of the claims.

Claims

1. A high-temperature and high-pressure pressure-dissolved gas recovery system, characterized in that: the system comprises two wells, a water recovery well and a gas recovery well, the bottom of the water recovery well is deep into the water layer, and the bottom of the gas recovery well is located in the gas cap layer or the pressure-dissolved gas layer above the water layer; the gas recovery well comprises a casing and a production tubing, the gas recovery well is completed with the casing to below the gas cap layer, the casing is perforated above the water layer, the production tubing is used to provide a gas recovery channel and accommodate a water recovery string, and a packer is arranged at a position of the production tubing close to the bottom of the casing; a plurality of electrically controlled sliding sleeves are further arranged on the production tubing at intervals, which are used to open the gas recovery channel or close the annulus and the tubing; a pressure sensor is further arranged outside the bottom of the production tubing, which is used to monitor the pressure below the production string; a water recovery device is further arranged, which is used to recover the accumulated liquid in the water layer into the production tubing; and a surface control device is further arranged, which is used to receive the pressure signal of the downhole pressure sensor, judge the depth of the accumulated liquid at the bottom of the well, and control the opening or closing of at least one intelligent sliding sleeve based on the accumulated liquid condition; the bottom of the production tubing of the water recovery well does not comprise a downhole electrically controlled packer, the bottom of the production tubing of the gas recovery well comprises a downhole electrically controlled packer, and the downhole electrically controlled packer is used to control the opening and closing of the bottom of the production tubing and is controlled by the surface control device. The water recovery device comprises an electric submersible pump and a water recovery pipe, the electric submersible pump is lowered to the bottom of the production tubing, and is used to recover the accumulated liquid into the production tubing. The plurality of electrically controlled sliding sleeves are uniformly distributed on the production tubing in the gas cap layer and the pressure-dissolved gas zone. The interval of the electrically controlled sliding sleeves is 10 m, 20 m or 30 m. The electrically controlled sliding sleeves are arranged on the production tubing in the gas cap layer. The electrically controlled sliding sleeves are unevenly distributed, and the interval dH decreases from bottom to top. The system further comprises a cable, which comprises a communication cable, a power supply cable and a control cable, and is used to transmit the pressure signal of the pressure sensor to the surface control device, supply power to the plurality of electrically controlled sliding sleeves and control the opening and closing of the plurality of electrically controlled sliding sleeves. The gas recovery system of claim 2 is used, and the steps are as follows:

2. The high-temperature and high-pressure solution gas driving system according to claim 1, characterized in that: Step 3. The surface control device calculates that there is a small amount of accumulated liquid at the bottom of the water recovery well, and then opens one or more electrically controlled sliding sleeves at the top of the production tubing, the electrically controlled sliding sleeves provide a channel, and the natural gas in the water recovery well is recovered; 3. The high-temperature and high-pressure solution gas driving system according to claim 1, characterized in that: Step 4. The surface control device calculates that there is a large amount of accumulated liquid at the bottom of the water recovery well, and the natural gas production at the wellhead is greatly reduced, then all the electrically controlled sliding sleeves are closed, the electric submersible pump and the water recovery pipe are lowered, and the water recovery process is started, during which one or more electrically controlled sliding sleeves at the top of the production tubing are opened, and the natural gas in the water recovery well is recovered; 4. The high-temperature and high-pressure solution gas driving system according to claim 3, characterized in that: Step 5. The steps 2-4 are cycled, the surface control device continuously calculates the depth of the accumulated liquid at the bottom of the water recovery well, adjusts the opening and closing of the plurality of electrically controlled sliding sleeves and the downhole electrically controlled packer of the water recovery well and the gas recovery well according to the depth of the accumulated liquid at the bottom of the well, adjusts the displacement of the electric submersible pump, and continuously recovers the natural gas in the water recovery well and the gas recovery well.

5. The high-temperature and high-pressure solution gas driving system according to claim 1, characterized in that: ​ 6. The high-temperature and high-pressure solution gas driving system according to claim 1, characterized in that: ​ 7. The high-temperature and high-pressure solution gas driving system according to claim 1, characterized in that: ​ 8. A high-temperature and high-pressure pressure-dissolved gas recovery method, characterized by: ​ Step 1. Assemble the water well and gas well gas production string respectively, and carry out system debugging with the ground control device. After the debugging is completed, lower the production string into the well, and record the initial moment well bottom pressure P of the two wells wf0 ; Step 2. The surface control device continuously monitors the bottom hole pressure, records the bottom hole pressure P of the water injection well wfw and the bottom hole pressure P of the gas production well wfg , calculates the bottom hole fluid accumulation depth, if there is no fluid accumulation, closes all electrically controlled sliding sleeves, and the water injection well provides a gas production channel by the production tubing, and the gas production well controls the opening of the downhole electrically controlled packer valve to provide a gas production channel for the gas production well by the downhole electrically controlled packer valve; ​ ​ ​

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