Shale condensate gas reservoir well completion pipe string and method

Abstract

The present application provides a kind of shale condensate gas reservoir same well circulation injection production completion pipe column and completion method, belong to oil and gas field development field.The completion pipe column includes gas injection pipe column and gas production pipe column;The end of the gas injection pipe column is provided with gas injection port, and gas can flow out from the gas injection port;The end of the gas production pipe column is provided with horn mouth, and gas can flow into from the horn mouth.The present application realizes circulating gas injection in the single well of condensate shale gas reservoir, keeps the formation pressure above dew point pressure, and then inhibits the reverse condensation;The condensate oil and gas recovery degree is improved by using the pressure maintaining, displacement and miscible effect of injected gas, the shortcomings of the existing pressure maintaining development method are overcome, and the condensate oil production and recovery of shale condensate gas reservoir are improved.

Description

Technical Field

[0001] This invention belongs to the field of oil and gas field development, specifically relating to a shale condensate gas reservoir with a same-well cycle injection and production completion string and completion method. Background Technology

[0002] Shale condensate gas reservoirs are a special type of shale gas reservoir. Unlike highly mature shale gas reservoirs, shale condensate gas reservoirs have a relatively low degree of thermal evolution. The hydrocarbon fluids are in the gas phase in the original state of the reservoir. However, during depressurization production, when the bottom hole pressure is lower than the dew point pressure, reverse condensation occurs. The condensate oil precipitated from the condensate gas causes "oil lock," which seriously affects the reservoir's gas phase permeability. The condensate oil remains in the reservoir and is difficult to extract, resulting in a loss of condensate oil and gas production and ultimately a decrease in condensate oil recovery rate.

[0003] To delay oil lock-in and improve condensate oil recovery, pressure-maintaining development methods are commonly used to exploit condensate gas reservoirs. Currently, common pressure-maintaining development methods in sandstone condensate gas reservoirs include circulating gas injection and single-well gas injection huff and puff, with dry gas typically injected as the fluid. Circulating gas injection requires the simultaneous installation of injection and production wells. Dry gas is injected through the injection well, causing reverse evaporation, gravity overlap, and gas-phase displacement in the formation, thereby increasing condensate oil production and recovery in the production well. Circulating gas injection requires the condensate gas reservoir to meet requirements such as good connectivity, high condensate oil content, and low reverse condensation contamination. Single-well gas injection huff and puff involves multiple rounds of injection-well shut-off-production operations within the same production well, utilizing reverse evaporation to increase condensate oil production and recovery. Single-well gas injection huff and puff is suitable for low-permeability condensate gas reservoirs with poor reservoir connectivity and severe reverse condensation contamination.

[0004] Chinese patent publication CN206957669U discloses a tubing string device and its injection system for condensate gas extraction. The disclosed tubing string device enables simultaneous pressurization of both the upper and lower condensate gas layers within a single injection well. The disclosed injection system includes well casing, an injection valve assembly, and the tubing string device for condensate gas extraction, which can shorten the injection pressurization time and improve condensate gas development efficiency. The condensate gas extraction tubing string device and injection system are suitable for individually injecting gas into different condensate gas layers within a single injection well.

[0005] Chinese patent publication CN107605443B discloses a CO2-driven gas injection process tubing structure. During operation, the tubing is connected and lowered sequentially. Reverse circulation fills the annulus with conventional oil-based annulus protection fluid. A fast-dissolving soluble ball is then added for pressure setting, allowing for normal gas injection. When retrieving the tubing, the presence of a check valve allows for direct venting of the tubing, achieving pressure relief. The tubing string is then pulled up and the insertion tube removed, allowing the tubing string to be retrieved. If tubing pressure relief fails, reverse circulation injection of kill fluid can be used to retrieving the well before pulling up the tubing string again. After completing the string inspection, the tubing is connected and lowered sequentially, and the insertion tube is inserted into the packer to seal the well. This CO2-driven gas injection process tubing is used to inject CO2 into the injection well for oil recovery.

[0006] The publicly available Chinese literature, "Evaluation of the Effect of Dry Gas Huff and Puff on Gas Wells in Low-Permeability Condensate Gas Reservoirs Rich in Condensate Oil" (Petroleum Exploration and Development, June 2010), discloses a method for establishing single-well models based on phase fitting of gas wells that have undergone actual single-well huff and puff operations. This involves fitting the gas injection history and correcting for single-well reserves, then studying the effect of single-well huff and puff based on the bottomhole pressure after well shutdown, and optimizing the huff and puff method. The study shows that the injection rate, well shut-in time, and gas production rate after well shut-in have little impact on oil and gas recovery. Simulation predictions of closed gas wells indicate that with increasing injected gas volume, the increase in condensate oil recovery is small, while the increase in natural gas recovery remains almost unchanged. The main purpose of gas injection is unblocking, and the well pressure does not rise significantly. Field single-well huff and puff tests can unblock anti-condensate contaminated gas wells, significantly improve natural gas recovery, and reduce reservoir abandonment pressure, but contribute little to improving condensate oil recovery. The study primarily focuses on the simulation analysis and effect evaluation of single-well huff and puff methods for unblocking anti-condensate.

[0007] The publicly available Chinese document, "Concentric Tubing Layered Gas Injection Technology for the Yaha High-Pressure Condensate Gas Field" (Natural Gas Industry, April 2016), addresses the significant reservoir property differences between the two main gas layers and within the same gas layer. Indiscriminate gas injection not only leads to uneven utilization of gas reserves but also exacerbates the exploitation conflict between high- and low-permeability layers. Based on the current wellbore structure, surface facilities, and layered gas injection requirements, a concentric tubing layered gas injection string structure was designed, along with a layered gas injection wellhead device. This enabled the completion and commissioning of the layered gas injection well, meeting the production needs of the layered gas injection process. Simultaneously, two tubing combination methods were designed for the concentric tubing scheme, and the wellbore temperature field, pressure field, and string safety of the two tubing combinations were theoretically analyzed and evaluated according to different operating conditions. The concentric tubing layered gas injection technology for condensate gas fields is used to achieve layered gas injection in injection wells.

[0008] However, the tubing setups and pressure-maintaining development methods described in the aforementioned patents or papers cannot be applied to shale condensate gas reservoirs. In shale condensate gas reservoirs, due to the extremely low permeability of the shale matrix and poor inter-well connectivity, circulating gas injection cannot be used for development. Furthermore, most shale condensate gas reservoirs are currently in the early stages of development, with low levels of anti-condensation contamination, making single-well gas injection and huff-and-puff unsuitable.

[0009] In summary, there is currently a lack of an effective gas injection and pressure-maintaining development method applicable to shale condensate gas reservoirs. Therefore, it is urgent to study a cyclic injection and production completion string and completion method for shale condensate gas reservoirs, so as to achieve cyclic gas injection in a single well, overcome the shortcomings of existing pressure-maintaining development methods, and improve the condensate oil production and recovery rate of shale condensate gas reservoirs. Summary of the Invention

[0010] The purpose of this invention is to solve the problems existing in the prior art and provide a shale condensate gas reservoir with a same-well cycle injection and production completion string and completion method, which suppresses reverse condensation, improves the fluid flow characteristics of shale reservoirs, and increases the recovery rate of shale condensate gas reservoirs.

[0011] This invention is achieved through the following technical solution:

[0012] In a first aspect, the present invention provides a shale condensate gas reservoir co-loop injection and production completion string, wherein the completion string includes an injection string and a production string;

[0013] The gas injection tube is provided with a gas injection port at the end, from which gas can flow out;

[0014] The gas sampling tubing is equipped with a bell-shaped opening at the end, through which gas can flow in.

[0015] Preferably, the gas injection string includes, in sequence, the following components connected to the gas injection tubing: a first telescopic connector, a kill sleeve, a second telescopic connector, a first gas injection packer, a first setting ball seat, a second gas injection packer, a second setting ball seat, and a gas injection port.

[0016] Preferably, the gas production tubing includes a safety valve, a production sleeve, a telescopic connector, a double-tube packer, a setting ball seat, and a bell mouth, which are connected in sequence to the gas production tubing.

[0017] The dual-tube packer is simultaneously connected to the gas injection tubing and is located between the first telescopic connector and the kill sleeve.

[0018] In a second aspect, the present invention provides a shale condensate gas reservoir co-loop injection and production completion method. The method employs an upturned double-step horizontal well and runs the aforementioned completion tubing. Then, the timing of gas injection, the injection volume, and the wellhead injection pressure are determined to suppress reverse condensation.

[0019] A further improvement of the present invention is that the method includes:

[0020] Step 1: Collect reservoir parameters, wellbore parameters, and fluid parameters for shale condensate gas reservoirs;

[0021] Step 2: Determine the vertical depth of the upward-curving step and drill an upward-curving double-step horizontal well;

[0022] Step 3: Determine the perforation location and perform fracturing;

[0023] Step 4: Determine the diameter of the gas sampling tubing;

[0024] Step 5: Run the completion string;

[0025] Step Six: Determine the timing for gas injection;

[0026] Step 7: Determine the gas injection volume;

[0027] Step 8: Determine the wellhead gas injection pressure.

[0028] Preferably, the reservoir parameters in step one include: the vertical depth H of the reservoir top. top Vertical depth H at the bottom of the reservoir down Horizontal well length L, formation inflow dynamic curve, dew point pressure P d Maximum condensate pressure P cmax ;

[0029] The wellbore parameters include: well inclination angle θ d Bottom hole pressure P, bottom hole temperature T;

[0030] The fluid parameters include: gas-liquid surface tension σ, liquid phase density ρ l Gas phase density ρ g Gas phase deviation coefficient Z.

[0031] Preferably, the operation of determining the vertical depth of the upturned step in step two includes:

[0032] The vertical depth H of the upturned step is determined using the following formula. s :

[0033] H s =H top +(0.25~0.3)(H down -H top )

[0034] In the formula, H s This refers to the vertical depth of the upturned steps.

[0035] Preferably, the operation of drilling the upward-curving double-step horizontal well in step two includes:

[0036] Drill an upward-curving double-step horizontal well based on the reservoir parameters and the vertical depth of the upward-curving step.

[0037] A technical casing is installed in the vertical well, and a production casing is installed in the horizontal well; the upper end of the production casing is connected to the lower end of the technical casing.

[0038] Preferably, step three includes the following operations:

[0039] In a horizontal well, the L / 3 section near the heel is the gas production section, the L / 3 section in the middle of the horizontal well is the ejection avoidance section, and the L / 3 section near the toe is the gas injection section.

[0040] The depth of the gas injection section is the vertical depth of the upturned step, which is located above the gas extraction section.

[0041] Perforation and fracturing were performed in the gas production section and the gas injection section, respectively.

[0042] Preferably, step four includes the following operations:

[0043] The diameter of the gas sampling tubing is determined using the following formula:

[0044]

[0045]

[0046] Among them, u c ρ is the critical liquid-carrying velocity; σ is the gas-liquid surface tension; l ρ is the density of the liquid phase; g θ is the gas phase density; d The well inclination angle; Q g D is the gas production rate; P is the diameter of the gas production tubing; Z is the bottom hole pressure; T is the gas phase deviation coefficient; and T is the bottom hole temperature.

[0047] The diameter of the gas injection tubing is equal to the diameter of the gas extraction tubing.

[0048] Preferably, step five includes the following operations:

[0049] Run the completion tubing string and position the bell mouth of the gas production tubing string above the heel of the horizontal well, position the gas injection port of the gas injection tubing string within the gas injection section, position the first and second gas injection packers of the gas injection tubing string at the ends of the anti-jet section, and position the double-tube packers within the technical casing.

[0050] The first gas-injected packer, the second gas-injected packer, and the double-tube packer are respectively set.

[0051] Preferably, step six includes the following operation: when the bottom hole pressure, dew point pressure, and maximum reverse condensation pressure satisfy the following formula, it is the timing for starting gas injection:

[0052] Pcmax <P<P d

[0053] Among them, P cmax P is the maximum condensate pressure; d This refers to the dew point pressure.

[0054] Preferably, step seven includes the following operations:

[0055] The injection volume is determined using the following formula:

[0056] Q inj =Q g

[0057] Among them, Q inj This refers to the gas injection volume.

[0058] Preferably, step eight includes the following operations:

[0059] The wellhead gas injection pressure is determined using the following formula:

[0060] P inj =P d +ΔP

[0061] Among them, P inj ΔP is the wellhead injection pressure; ΔP is the pressure drop of the injection tubing.

[0062] Compared with the prior art, the beneficial effects of the present invention are:

[0063] This invention achieves circulating gas injection in a single well of a condensate shale gas reservoir, maintaining the formation pressure above the dew point pressure, thereby suppressing reverse condensation; by utilizing the pressure-maintaining, displacement, and miscibility effects of the injected gas, the recovery rate of condensate oil and gas is improved, overcoming the shortcomings of existing pressure-maintaining development methods, and increasing the condensate oil production and recovery rate of shale condensate gas reservoirs. Attached Figure Description

[0064] Figure 1 Schematic diagram of the well completion string for the same-well cycle injection and production of shale condensate gas reservoir;

[0065] Figure 2 This is a schematic diagram of a shale condensate gas reservoir with a single-well cycle injection and production completion method.

[0066] 1. Gas injection tubing; 2. Gas production tubing; 3. Technical casing; 4. Production casing; 5. Gas production section; 6. Avoidance section; 7. Gas injection section; 8. Segmented perforation fracturing; 101. Gas injection tubing; 102. First telescopic joint; 103. Kill sleeve; 104. Second telescopic joint; 105. First gas injection packer; 106. First setting ball seat; 107. Second gas injection packer; 108. Second setting ball seat; 109. Gas injection port; 201. Gas production tubing; 202. Safety valve; 203. Production sleeve; 204. Telescopic joint; 205. Dual-tube packer; 206. Setting ball seat; 207. Bell mouth. Detailed Implementation

[0067] The present invention will now be described in further detail with reference to the accompanying drawings:

[0068] This invention designs an upward-curving double-step horizontal well drilling and completion method, runs in a same-well cyclic injection and production completion string, and determines the timing, volume, and pressure of gas injection. This forms a same-well cyclic injection and production completion string and completion method for shale condensate gas reservoirs, suppresses reverse condensation, improves the fluid flow characteristics of shale reservoirs, and increases the recovery rate of shale condensate gas reservoirs.

[0069] like Figure 1 As shown, the shale condensate gas reservoir co-circulation injection and production completion string provided by the present invention includes: injection string 1 and production string 2.

[0070] In this embodiment, the gas injection string 1 includes, in sequence: gas injection tubing 101, a first telescopic joint 102, a kill sleeve 103, a second telescopic joint 104, a first gas injection packer 105, a first setting ball seat 106, a second gas injection packer 107, a second setting ball seat 108, and a gas injection port 109 (these devices are all existing products, and the detailed structure of each device will not be described in detail). The first telescopic joint 102, the kill sleeve 103, the second telescopic joint 104, the first gas injection packer 105, the first setting ball seat 106, the second gas injection packer 107, the second setting ball seat 108, and the gas injection port 109 are connected in series on the gas injection tubing 101 (i.e., the gas injection tubing is divided into multiple segments, and adjacent segments are connected by the aforementioned devices). The connection method is threaded connection, and the thread type is airtight thread.

[0071] In this embodiment, the gas production tubing string 2 includes: a gas production tubing 201, a safety valve 202, a production sleeve 203, a telescopic connector 204, a double-tube packer 205, a setting ball seat 206, and a bell mouth 207 (these devices are all existing products, and the detailed structure of each device will not be described in detail). The safety valve 202, production sleeve 203, telescopic connector 204, double-tube packer 205, setting ball seat 206, and bell mouth 207 are connected in series on the gas production tubing 201 (i.e., the gas production tubing is divided into multiple segments, and adjacent segments are connected by the above-mentioned devices). The connection method is threaded connection, and the thread type is airtight thread. The double-tube packer 205 is also connected to the gas injection tubing 101 and is located between the first telescopic connector 102 and the kill sleeve 103.

[0072] The gas injection string and gas production string of this invention are composed of a series of existing devices. The gas injection string and gas production string are combined with the upward-curving double-step horizontal wellbore, which has the following advantages and innovations: ① It realizes the same-well and same-layer cyclic injection and production of shale condensate gas wells, which improves the recovery rate; ② It realizes high injection and low production, which improves the displacement efficiency of injected gas; ③ It proposes for the first time a cyclic injection and production completion method for shale condensate gas reservoirs, which makes full use of the anti-radiation section as the gas injection flow section and avoids gas channeling in the gas production section.

[0073] When running the same injection and production completion string into the shale condensate gas reservoir, a technical casing 3 is installed in the vertical well section and a production casing 4 is installed in the horizontal well section. The upper end of the production casing 4 is connected to the lower end of the technical casing 3. First, connect the gas injection port 109, the second setting ball seat 108, the second gas injection packer 107, the first setting ball seat 106, the first gas injection packer 105, the second telescopic short connector 104, and the kill sleeve 103 of the gas injection string 1 in series on the gas injection tubing 101 and lower them into the production casing 4 (the production casing 4 extends from the lower end of the technical casing 3 to the end of the gas injection section 7. During use, perforations must first be made in the gas production section 5 and the gas injection section 7 of the production casing 4). Position the gas injection port 109 in the gas injection section 7, the second gas injection packer 107 between the gas injection section 7 and the anti-perforation section 6, and the first gas injection packer 105 between the gas production section 5 and the anti-perforation section 6. Then, connect the bell mouth 207 of the gas production string 2... The set-in ball seat 206 is connected in series with the gas production tubing 201 and lowered into the production casing 4 (the entire gas production tubing string is located inside the technical casing 3) at a predetermined position, so that the bell mouth 207 is located near the heel end of the horizontal section; then the double-tube packer 205 is lowered in, and the double-tube packer 205 is connected to both the gas production tubing 201 and the gas injection tubing 101 (that is, the upper part of the gas production tubing 201 and the upper part of the gas injection tubing 101 are both divided into two sections, and the two sections are connected by the double-tube packer 205); then the gas injection tubing 101 and the gas production tubing 201 are lowered in at the same time until the wellhead, the first telescopic short connector 102 is connected to the gas injection tubing 101, and the telescopic short connector 204, the production sleeve 203 and the safety valve 202 are connected in series with the gas production tubing 201.

[0074] After the well completion tubing for the same-well cycle injection and production of shale condensate gas reservoirs is in place, a ball is dropped into the injection tubing 101, allowing it to pass through the first setting ball seat 106 and fall into the second setting ball seat 108, pressurizing and setting the second injection packer 107. Subsequently, another ball is dropped into the injection tubing 101, allowing it to fall into the first setting ball seat 106, pressurizing and setting the first injection packer 105. Finally, a ball is dropped into the production tubing 201, allowing it to fall into the setting ball seat 206, pressurizing and setting the double-tube packer 205. The balls in both the injection and production tubing 101 are made of a soluble material; dissolving the balls ensures unobstructed flow within both tubings.

[0075] After the sphere is dissolved, it enters the circulating injection and production process. During this process, gas is injected into the injection tubing 1. The injected gas flows out from the injection port 109 and enters the injection section 7, increasing the shale formation pressure, inhibiting reverse condensation, and displacing the formation fluids. Finally, the injected gas and formation fluids are produced together from the production section 5 and flow into the production tubing 2 to reach the wellhead, achieving circulating injection and production within the same well. Specifically, the injected gas flows along the injection tubing 1, flows out from the injection port 109 at the end of the injection tubing 1, enters the formation through the perforations and fracturing fractures in the injection section 7, flows through the fracturing fractures and perforations in the production section 5, flows into the production casing 4, and enters the production tubing 2 through the bell-shaped opening 207 at the lower end of the production tubing 2.

[0076] Injection section 7 and production section 5 are two horizontal sections of a single horizontal well. Injection section 7 is located above production section 5, with a height difference between them, forming two "steps." Therefore, injection section 7 is called the "upward-curving stage" (a specialized term in this field, also known as "upward-curving horizontal well," "stepped horizontal well," or "double-step horizontal well"). Such a horizontal well is called an upward-curving double-step horizontal well. This type of upward-curving double-step horizontal well achieves high injection and low production, improving the displacement efficiency of the injected gas. The flow avoidance section 6 forms a buffer zone between injection section 7 and production section 5, allowing the injected gas to have a wider sweep range in the formation and preventing gas channeling in production section 5. The injected gas is primarily dry methane, but non-hydrocarbon gases such as nitrogen and carbon dioxide can also be selected.

[0077] This invention also provides a method for completing a shale condensate gas reservoir using a simultaneous injection and production cycle, such as... Figure 2 As shown, the method specifically includes the following steps:

[0078] Step 1: Collect reservoir parameters, wellbore parameters, and fluid parameters for shale condensate gas reservoirs:

[0079] The reservoir parameters include: vertical depth H at the top of the reservoir. top Vertical depth H at the bottom of the reservoir down Horizontal well length L, formation inflow dynamic curve, dew point pressure P d Maximum condensate pressure P cmax .

[0080] The wellbore parameters include: well inclination angle θ d Bottom hole pressure P, bottom hole temperature T.

[0081] The fluid parameters include: gas-liquid surface tension σ, liquid phase density ρ l Gas phase density ρ g Gas phase deviation coefficient Z.

[0082] The above parameters were all obtained using existing technologies, and will not be elaborated further here.

[0083] Step 2: Determine the vertical depth of the upturned step based on the reservoir depth, and drill an upturned double-step horizontal well.

[0084] The vertical depth H of the upturned step is determined by the following formula. s :

[0085] H s =H top +(0.25~0.3)(H down -H top (1)

[0086] In the formula, H s H represents the vertical depth of the upturned steps, in meters (m). top H represents the vertical depth of the top of the reservoir, in meters. down denoted as the vertical depth of the bottom of the reservoir, in meters (m).

[0087] After drilling an upward-curving double-step horizontal well, a technical casing is installed in the vertical well, and a production casing is installed in the horizontal well. The upper end of the production casing is connected to the lower end of the technical casing.

[0088] Step 3: Determine the perforation location and fracturing based on the horizontal well length L obtained in Step 1. Perforate and fracture the L / 3 portion near the toe and L / 3 portion near the heel of the horizontal well. The middle L / 3 portion of the horizontal well is the perforation avoidance section 6, the L / 3 portion near the toe is the platform stage (i.e., the gas injection section 7), and the L / 3 portion near the heel is the gas production section 5. Here, L represents the horizontal well length. Figure 1 Segments 5, 6, and 7 are illustrative labels. Segments 5, 6, and 7 are connected sequentially, each occupying 1 / 3 of the total area. The segments are connected by a spacer.

[0089] Step 4: Determine the gas production tubing diameter based on formation productivity and critical fluid-carrying velocity. Determine the gas production rate Q based on the formation inflow dynamic curve and bottom hole pressure. g (Obtained using conventional techniques, which will not be elaborated here.) Then, determine the diameter of the gas extraction tubing 2 according to the following formula:

[0090]

[0091]

[0092] In the formula, u c σ is the critical liquid-carrying velocity, m / s; σ is the gas-liquid surface tension, N / m; ρl is the liquid density, kg / m³. 3 ;ρ g The density is in the gas phase, kg / m³ 3 ;θ d Q is the well inclination angle, in degrees; gFor gas production, m 3 / d; D is the diameter of the gas production tubing, m; P is the bottom hole pressure, MPa; Z is the gas phase deviation coefficient, dimensionless; T is the bottom hole temperature, K.

[0093] The diameter of the gas injection tubing can be equal to the diameter of the gas extraction tubing.

[0094] Step 5: Run the above-mentioned dual-tube completion tubing for injection and production in the same well, and position the bell mouth 207 of the production tubing 2 above the heel of the horizontal well, position the injection port 109 of the injection tubing 1 in the injection section 7 near the toe of the horizontal well, position the first gas injection packer 105 and the second gas injection packer 107 on the injection tubing 1 at the two ends of the anti-jet section 6 respectively, and position the dual-tube packer inside the technical casing 3; and set the first gas injection packer 105, the second gas injection packer 107 and the dual-tube packer 205 respectively.

[0095] Step Six: Determine the timing of gas injection based on the dew point pressure and the maximum reverse condensation pressure. The timing for starting gas injection is when the bottom hole pressure, dew point pressure, and maximum reverse condensation pressure satisfy the following relationship:

[0096] P cmax <P<P d (4)

[0097] In the formula, P cmax The maximum condensate pressure is MPa; P d The dew point pressure is expressed in MPa.

[0098] Step 7: Determine the gas injection rate based on formation productivity. The gas production rate Q is determined based on the formation inflow dynamic curve and bottom hole pressure. g The injection volume is determined according to the following formula:

[0099] Q inj =Q g (5)

[0100] In the formula, Q inj The gas injection volume is m. 3 / d.

[0101] Step 8: Determine the wellhead injection pressure based on the dew point pressure and the pressure drop of the injection tubing. The pressure drop of the injection tubing can be calculated using a two-phase flow pressure drop model, and then the wellhead injection pressure is determined according to the following formula:

[0102] P inj =P d +ΔP (6)

[0103] In the formula, P inj ΔP is the wellhead gas injection pressure, MPa; ΔP is the pressure drop of the gas injection tubing, MPa.

[0104] Shale condensate gas reservoirs are a special type of shale gas reservoir. When the bottomhole pressure falls below the dew point pressure, reverse condensation occurs, and the precipitated oil phase partially accumulates in the near-wellbore zone, causing "oil lock-in," leading to a loss of condensate oil production and ultimately a decrease in recovery rate. This invention provides a cyclic injection and production completion string and completion method for shale condensate gas reservoirs. It achieves cyclic gas injection in a single well of a condensate shale gas reservoir, maintaining the formation pressure above the dew point pressure, suppressing reverse condensation, and utilizing the pressure-maintaining, displacement, and miscibility effects of the injected gas to improve the recovery rate of condensate oil and gas. This overcomes the shortcomings of existing pressure-maintaining development methods, increases condensate oil production and recovery rate in shale condensate gas reservoirs, and has broad application prospects.

[0105] In the description of this invention, unless otherwise stated, the terms "upper," "lower," "left," "right," "inner," "outer," etc., indicate the orientation or positional relationship based on the orientation or positional relationship shown in the accompanying drawings. They are used only for the convenience of describing this invention and simplifying the description, and do not indicate or imply that the device or element referred to must have a specific orientation, or be constructed and operated in a specific orientation. Therefore, they should not be construed as limitations on this invention.

[0106] Finally, it should be noted that the above technical solution is only one embodiment of the present invention. For those skilled in the art, based on the application methods and principles disclosed in the present invention, it is easy to make various types of improvements or modifications, and not limited to the methods described in the above specific embodiments of the present invention. Therefore, the methods described above are only preferred and have no limiting significance.

Claims

1. A well completion method for simultaneous injection and production in a shale condensate gas reservoir, characterized in that: The method employs an upturned double-step horizontal well and runs a completion string, then determines the timing, volume, and pressure of gas injection at the wellhead, thereby suppressing reverse condensation. The well completion string includes an injection string and a production string; the end of the injection string is provided with an injection port from which gas can flow out; the end of the production string is provided with a bell mouth from which gas can flow in. The method includes: Step 1: collecting reservoir parameters, wellbore parameters, and fluid parameters of shale condensate gas reservoirs; Step 2: determining the vertical depth of the upturned bench and drilling an upturned double-bench horizontal well; Step 3: determining the perforation location and fracturing; Step 4: determining the diameter of the gas production tubing; Step 5: running the completion tubing; Step 6: determining the timing of gas injection; Step 7: determining the gas injection volume; Step 8: determining the wellhead injection pressure. The operation in step three includes: near the heel end of the horizontal well. Part of it is the gas production section, in the middle of the horizontal well. Part of it is the section for avoiding firing, in the horizontal well near the toe. Part of it is the gas injection section; It is the length of the horizontal well; the depth of the injection section is the vertical depth of the upturned step, which is located above the production section; perforations and fracturing are performed in the production section and the injection section respectively; Step five includes: running the completion tubing string and positioning the bell-shaped opening of the production tubing string above the heel of the horizontal well; positioning the injection port of the injection tubing string within the injection section; positioning the first and second injection packers of the injection tubing string at the ends of the anti-jet section; positioning the double-tube packer within the technical casing; and setting the first injection packer, the second injection packer, and the double-tube packer respectively.

2. The shale condensate gas reservoir same-well injection and production completion method according to claim 1, characterized in that: The gas injection string includes, in sequence, the following components connected to the gas injection tubing: a first telescopic connector, a kill sleeve, a second telescopic connector, a first gas injection packer, a first setting ball seat, a second gas injection packer, a second setting ball seat, and a gas injection port.

3. The shale condensate gas reservoir same-well cycle injection and production completion method according to claim 2, characterized in that: The gas production tubing string includes a safety valve, a production sleeve, a telescopic joint, a double-tube packer, a setting ball seat, and a bell mouth, which are connected in sequence to the gas production tubing. The dual-tube packer is simultaneously connected to the gas injection tubing and is located between the first telescopic connector and the kill sleeve.

4. The shale condensate gas reservoir same-well cycle injection and production completion method according to claim 1, characterized in that: The reservoir parameters in step one include: vertical depth of the reservoir top. Vertical depth at the bottom of the reservoir Horizontal well length Formation inflow dynamic curve, dew point pressure Maximum condensate pressure ; The wellbore parameters include: well inclination angle. Bottom hole pressure Bottom hole temperature ; The fluid parameters include: gas-liquid surface tension. Liquid phase density gas phase density Gas phase deviation coefficient .

5. The shale condensate gas reservoir same-well cycle injection and production completion method according to claim 4, characterized in that: The operation of determining the vertical depth of the upturned step in step two includes: The vertical depth of the upturned step can be determined using the following formula. : In the formula, This refers to the vertical depth of the upturned steps.

6. The shale condensate gas reservoir same-well injection and production completion method according to claim 5, characterized in that: The operation of drilling the upward-curving double-step horizontal well in step two includes: Drill an upward-curving double-step horizontal well based on the reservoir parameters and the vertical depth of the upward-curving step. A technical casing is installed in the vertical well, and a production casing is installed in the horizontal well; the upper end of the production casing is connected to the lower end of the technical casing.

7. The shale condensate gas reservoir same-well injection and production completion method according to claim 6, characterized in that: The operations in step four include: The diameter of the gas sampling tubing is determined using the following formula: in, The critical liquid-carrying flow rate; The surface tension of the gas and liquid; The density of the liquid phase; This refers to the gas phase density. The well inclination angle; This refers to the amount of gas produced. This refers to the diameter of the gas extraction tubing. This refers to the bottom hole pressure. This is the gas phase deviation coefficient; This refers to the bottom hole temperature. The diameter of the gas injection tubing is equal to the diameter of the gas extraction tubing.

8. The shale condensate gas reservoir same-well injection and production completion method according to claim 7, characterized in that: Step six involves the following operation: when the bottom hole pressure, dew point pressure, and maximum reverse condensation pressure satisfy the following formula, it is the opportune time to start gas injection: in, This is the maximum anti-condensation pressure; For dew point pressure.

9. The shale condensate gas reservoir same-well injection and production completion method according to claim 8, characterized in that: The operations in step seven include: The injection volume is determined using the following formula: in, This refers to the gas injection volume.

10. The shale condensate gas reservoir same-well injection and production completion method according to claim 9, characterized in that: The operations in step eight include: The wellhead gas injection pressure is determined using the following formula: in, The wellhead gas injection pressure; This refers to the pressure drop of the gas injection tubing.

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