Dense sandstone gas reservoir encryption adjustment well deployment method

Abstract

The invention discloses a dense sandstone gas reservoir encryption adjustment well deployment method which comprises the following specific steps: S100, selecting a gas reservoir with encryption adjustment potential in a gas field, and determining the reserve utilization degree and formation pressure of the gas reservoir in the current state; s200, calculating the remaining reserves according to the formation pressure, and calculating the controlled reserves and the cumulative gas production of the to-be-deployed encryption adjustment well control area; and S300, through economic evaluation, calculating the productivity construction investment when the internal yield reaches 8% under the condition of cumulative gas production of the to-be-deployed encryption adjustment well, and calculating the number and the horizontal section length of the to-be-deployed encryption adjustment well under the investment condition. According to the gas reservoir encryption adjustment well deployment method integrating geology, gas reservoir and economic evaluation, the method is suitable for tight sandstone gas reservoirs developed in a depletion mode, the problem that the recovery efficiency cannot be improved through encryption adjustment due to the fact that economic evaluation is unqualified is solved, long-term stable production of gas fields is facilitated, and a scientific basis is provided.

Description

Technical Field

[0001] This invention relates to the field of gas field development research technology, specifically a method for deploying infill and adjustment wells in tight sandstone gas reservoirs. Background Technology

[0002] Infill drilling in tight sandstone gas reservoirs is one of the most important methods to improve gas recovery. Due to the characteristics of tight sandstone gas reservoirs, such as thin individual sandstone bodies, small scale, poor reservoir properties, strong heterogeneity, and well-developed internal interlayers, single-layer controlled reserves in gas wells are low, resulting in generally low recovery rates. Development experience shows that infill drilling can increase reserve utilization, expand the swept area, and improve gas well recovery rates. However, in practice, the economic benefits of improving recovery rates through infill drilling are relatively low. Achieving both improved gas recovery rates and good economic efficiency is a key challenge in development. Therefore, infill drilling that meets economic requirements is the foundation for efficient and sustainable gas reservoir development, providing a scientific basis for the effective development of gas fields.

[0003] For example, the invention patent with publication number CN201710990712.6 discloses an optimal well location deployment method and device for small fault-block oil reservoirs, belonging to the field of oil extraction technology. The method includes: Step 1: Determining the injection-production unit ratio within the block; Step 2: Extracting the geometric boundary of the block; Step 3: Determining the initial well location within the geometric boundary of the block; Step 4: Based on the initial well location, adding injection-production units one by one and optimizing the well location of the newly added injection-production units until the recovery rate or net present value no longer increases; Step 5: Selecting the most suitable number of injection-production units based on the relationship curve between the number of injection-production units and the recovery rate and the actual target. This optimal well location deployment method and device for small fault-block oil reservoirs has good convergence, fully considering factors such as the planar geometry of the fault block, the size of the fault block, the spatial distribution characteristics of the oil sand bodies, the heterogeneity of the reservoir, and the directionality of permeability, and can improve the oil recovery rate or net present value of the reservoir.

[0004] Although this optimal well location deployment method and device for small fault-block oil reservoirs selects the most suitable number of injection-production units based on the relationship curve between the number of injection-production units and the recovery rate and the actual target, this method is suitable for water-injected oil reservoirs in small fault blocks, but not for tight sandstone gas reservoirs developed through depletion. Furthermore, the lack of an injection-production well network during the development of tight sandstone gas reservoirs makes it difficult to achieve the predetermined target; further improvements are needed. Summary of the Invention

[0005] The purpose of this invention is to provide a method for deploying infill and adjustment wells in tight sandstone gas reservoirs. This method aims to improve upon existing methods that are suitable for water injection development of oil reservoirs in small fault blocks but not for tight sandstone gas reservoirs developed through exhaustion. Furthermore, the lack of an injection-production well network during the development of tight sandstone gas reservoirs makes it difficult to achieve the intended goals.

[0006] This invention is implemented as follows: a method for deploying infill and adjustment wells in tight sandstone gas reservoirs, the specific steps of which are as follows:

[0007] S100. Select gas reservoirs with infill and adjustment potential in the gas field, and determine the current state of the gas reservoir's reserve utilization and formation pressure.

[0008] S200. Calculate the remaining reserves based on formation pressure, and calculate the controlled reserves and cumulative gas production in the control area of ​​the proposed infill well.

[0009] S300. Through economic evaluation, calculate the capacity construction investment when the internal rate of return reaches 8% under the condition of cumulative gas production of the proposed infill adjustment wells, and calculate the number of infill adjustment wells and the length of the horizontal section to be deployed under this investment condition.

[0010] Preferably, the formation pressure in S100 is calculated by formation pressure monitoring or flow mass balance method to determine the current formation pressure in the potential target area.

[0011] Preferably, in step S200, under the current formation pressure conditions, the remaining reserves are calculated using the volumetric method. The calculation method is shown in the formula: Gi = 0.01 × A × h × φ × Sg × Tsc × Pi (Psc × T × Zi);

[0012] Gi: Remaining natural gas reserves, in units of 10. 8 m 3 ;

[0013] A: Gas-bearing area, unit: km² 2 ;

[0014] H: Effective thickness of the gas reservoir, in meters;

[0015] Φ: Effective porosity of the gas reservoir, unit: decimal;

[0016] Sg: Gas saturation, unit: decimal;

[0017] T: Air layer temperature, unit: K;

[0018] Tsc: Ground standard temperature, unit: K;

[0019] Psc: Ground standard condition pressure, unit: MPa;

[0020] Pi: Current formation pressure of the gas reservoir, unit: MPa;

[0021] Zi: Gas deviation coefficient under current conditions, dimensionless quantity.

[0022] Preferably, in step S200, the expected cumulative gas production of adjacent wells in the same gas reservoir is calculated using the mass balance method, and then the recovery rate of adjacent wells in the same gas reservoir is obtained by combining the controlled reserves of a single well.

[0023] Preferably, when calculating the cumulative gas production of a single well using the fluid mass balance method, wellhead oil pressure or casing pressure can be used instead of formation pressure, as shown in the formula:

[0024] G: Current controlled reserves per well under formation pressure conditions, unit: 10 8 m 3 ;

[0025] Gp: Cumulative gas production per well under current formation pressure conditions, unit: 10 g / L 8 m 3 ;

[0026] PR: Wellhead pressure when a gas well is abandoned, unit: MPa;

[0027] P: Current wellhead pressure of the gas well, unit: MPa;

[0028] ZR: Gas deviation coefficient when a gas well is abandoned; dimensionless.

[0029] Z: Gas deviation coefficient under current conditions, dimensionless.

[0030] Preferably, the cumulative gas production of the gas well is the gas production since commissioning and the cumulative gas production of a single well under the current formation pressure conditions calculated by the fluid mass balance method, i.e.: G I =Q+G p ;

[0031] G I Cumulative gas production of a single well over its entire life cycle, in units of 10. 8 m 3 ;

[0032] Q: Gas production volume since commissioning, in units of 10. 8 m 3 .

[0033] Preferably, the recovery rate of the controlled reserves of the gas well is the percentage of the cumulative gas production over the entire life cycle of the gas well to the controlled reserves of the well, i.e.

[0034] ER: Recovery rate per well, unit: decimal;

[0035] Gn: Controlled reserves per well, unit: 10 8 m 3 .

[0036] Preferably, in the S300 economic evaluation, the cash flow method is used to calculate the capacity construction investment when the internal rate of return reaches 8% under the condition of cumulative gas production of a single well. The number of infill adjustment wells to be deployed is determined by combining the well spacing of the infill adjustment wells and the remaining reserves, and finally the horizontal section length of the single well to be deployed is determined.

[0037] Compared with the prior art, the beneficial effects of the present invention are:

[0038] This invention establishes an integrated method for deploying infill wells in tight sandstone gas reservoirs, encompassing geological, reservoir, and economic evaluations. This method is applicable to tight sandstone gas reservoirs developed through depletion processes, improves reservoir recovery, and solves the problem of failing to improve recovery rates through infill well deployment due to unsatisfactory economic evaluations. It contributes to the long-term stable production of gas fields and provides a scientific basis for the rational development of gas fields. Attached Figure Description

[0039] Figure 1 This is a schematic flowchart of the method for deploying infill and adjustment wells in tight sandstone gas reservoirs according to the present invention. Detailed Implementation

[0040] In this invention, unless otherwise explicitly specified and limited, the terms "installation," "connection," "linking," and "fixing," etc., should be interpreted broadly. For example, they can refer to a fixed connection, a detachable connection, or an integral part; they can refer to a mechanical connection or an electrical connection; they can refer to a direct connection or an indirect connection through an intermediate medium; they can refer to the internal communication of two components or the interaction between two components. Those skilled in the art can understand the specific meaning of the above terms in this invention according to the specific circumstances.

[0041] The following description, in conjunction with the accompanying drawings and specific embodiments, provides further details:

[0042] Example 1

[0043] like Figure 1 As shown, a method for deploying infill and adjustment wells in a tight sandstone gas reservoir is characterized by the following specific steps:

[0044] S100. Select gas reservoirs with infill and adjustment potential in the gas field, and determine the current state of the gas reservoir's reserve utilization and formation pressure.

[0045] The formation pressure in S100 is calculated by using formation pressure monitoring or the flow mass balance method to determine the current formation pressure within the potential target area.

[0046] S200. Calculate the remaining reserves based on formation pressure, and calculate the controlled reserves and cumulative gas production in the control area of ​​the proposed infill well.

[0047] In S200, under the current formation pressure conditions, the remaining reserves are calculated using the volumetric method. The calculation method is shown in the formula: Gi=0.01×A×h×φ×Sg×Tsc×Pi(Psc×T×Zi)

[0048] Gi: Remaining natural gas reserves, in units of 10. 8 m 3 ;

[0049] A: Gas-bearing area, unit: km² 2 ;

[0050] H: Effective thickness of the gas reservoir, in meters;

[0051] Φ: Effective porosity of the gas reservoir, unit: decimal;

[0052] Sg: Gas saturation, unit: decimal;

[0053] T: Air layer temperature, unit: K;

[0054] Tsc: Ground standard temperature, unit: K;

[0055] Psc: Ground standard condition pressure, unit: MPa;

[0056] Pi: Current formation pressure of the gas reservoir, unit: MPa;

[0057] Zi: Gas deviation coefficient under current conditions, dimensionless quantity.

[0058] In S200, the expected cumulative gas production of adjacent wells in the same gas reservoir is calculated using the flow material balance method, and then the recovery rate of adjacent wells in the same gas reservoir is obtained by combining the single-well controlled reserves.

[0059] When calculating the cumulative gas production of a single well using the fluid mass balance method, wellhead oil pressure or casing pressure can be used instead of formation pressure. The calculation is shown in the formula:

[0060] G: Current controlled reserves per well under formation pressure conditions, unit: 10 8 m 3 ;

[0061] Gp: Cumulative gas production per well under current formation pressure conditions, unit: 10 g / L 8 m 3 ;

[0062] PR: Wellhead pressure when a gas well is abandoned, unit: MPa;

[0063] P: Current wellhead pressure of the gas well, unit: MPa;

[0064] ZR: Gas deviation coefficient when a gas well is abandoned; dimensionless.

[0065] Z: Gas deviation coefficient under current conditions, dimensionless.

[0066] The cumulative gas production of a gas well is the gas production since it was put into operation and the cumulative gas production of a single well under the current formation pressure conditions calculated by the fluid mass balance method, i.e.: G I =Q+G p ;

[0067] G I Cumulative gas production of a single well over its entire life cycle, in units of 10. 8 m 3 ;

[0068] Q: Gas production volume since commissioning, in units of 10. 8 m 3 .

[0069] The recovery rate of controlled reserves in a single gas well is the percentage of cumulative gas production over the well's entire lifespan relative to the controlled reserves of that well.

[0070] ER: Recovery rate per well, unit: decimal;

[0071] Gn: Controlled reserves per well, unit: 10 8 m 3 .

[0072] S300. Through economic evaluation, calculate the capacity construction investment when the internal rate of return reaches 8% under the condition of cumulative gas production of the proposed infill adjustment wells, and calculate the number of infill adjustment wells and the length of the horizontal section to be deployed under this investment condition.

[0073] In the S300 economic evaluation, the cash flow method is used to calculate the capacity construction investment when the internal rate of return reaches 8% under the condition of cumulative gas production of a single well. The number of infill adjustment wells to be deployed is determined by combining the well spacing of the infill adjustment wells and the remaining reserves, and finally the horizontal section length of the single well to be deployed is determined.

[0074] Example 2

[0075] like Figure 1 As shown in the figure, the specific steps of the method for deploying infill and adjustment wells in a tight sandstone gas reservoir according to this embodiment are as follows:

[0076] S100. Based on the production status of existing wells and the distance between existing wells, select target areas with infill drilling potential for the T2 gas reservoir and determine the current formation pressure. For the selected potential target areas for deploying infill adjustment wells in the T2 gas reservoir, calculate the remaining reserves of existing gas wells in the potential target areas according to Formula 1. The specific results are shown in Table 1.

[0077] S200. Based on the gas well production characteristics, predict the cumulative gas production of a single well under current conditions. Combined with the current gas production, use formula G... I =Q+G p The cumulative gas production over the entire lifecycle of existing gas wells was calculated, and the results are shown in Table 1. Combined with the original geological reserves of existing wells, the formula was used... The recovery rate of existing gas wells in the same gas reservoir was calculated, and the average recovery rate of existing gas wells in the potential target area of ​​T2 gas reservoir was calculated. The specific results are shown in Table 1.

[0078] Table 1: Cumulative Gas Production and Recovery Rate Data of Adjacent Wells in the Target Area of ​​the T2 Gas Reservoir Potential

[0079]

[0080] The original geological reserves and remaining reserves within the potential target area are calculated using the formula Gi = 0.01 × A × h × φ × Sg × Tsc × Pi (Psc × T × Zi). The recovery rate of adjacent wells at the same stratigraphic level is then used in conjunction with the formula... The cumulative gas production of the proposed infiltration and adjustment wells was calculated, and the specific calculation results are shown in Table 2.

[0081] Table 2: Data on Original Geological Reserves and Remaining Reserves in the Target Area of ​​the T2 Gas Reservoir

[0082]

[0083] S300. Obtain the cumulative gas production of the proposed infill adjustment well. Combine the production patterns of adjacent wells in the same stratum to obtain the production model of the proposed infill adjustment well under normalized conditions. The production model of the proposed infill adjustment well is shown in Table 3.

[0084] Table 3: Production Model of Proposed Infill Adjustment Wells in the Potential Target Area of ​​T2 Gas Reservoir

[0085]

[0086] The obtained production capacity model for the proposed infill adjustment wells was used to calculate the production capacity construction investment when the internal rate of return (IRR) reaches 8% under the condition of cumulative gas production of the proposed infill adjustment wells, using the cash flow method. The number of proposed infill adjustment wells was determined based on the well spacing and remaining reserves. The calculated production capacity construction investment when the IRR reaches 8% under the condition of cumulative gas production of the proposed infill adjustment wells is 21.77 million yuan. Considering the well spacing of 1000-1100 meters and the remaining reserves of 1.548×108 m3 in the proposed deployment area, one infill adjustment well was determined to be deployed, with a well spacing of 500-550 meters after infilling.

[0087] Based on the existing relationships between the number of fracturing sections corresponding to the horizontal section length and the single-section fluid injection and sand addition, the horizontal section length of the single well to be deployed for infiltration and adjustment under this investment condition is calculated. Based on the number and scale of fracturing stages corresponding to the horizontal sections of the infill and adjustment wells and old wells in the T2 gas reservoir over the past three years, the new infill and adjustment wells are designed to fracture every 60-80 meters, with a single stage injection volume of 600-800 cubic meters and a single stage sand addition volume of 60-80 cubic meters. The horizontal section length of the proposed infill and adjustment well is calculated to be 1200 meters, and the single-well controlled reserves are calculated to be 1.488×10⁸ m³. The initial stable daily gas production is designed to be 2.5×10⁴ m³ / d, with a predicted cumulative gas production of 4848×10⁴ m³ over 20 years and 5584×10⁴ m³ over 30 years. After the well is deployed, the initial stable daily gas production is 3.1×10⁴ m³ / d, with a predicted cumulative gas production of 5973×10⁴ m³ over 20 years and 6920×10⁴ m³ over 30 years, achieving the design goals and demonstrating good infill and adjustment effects.

[0088] The above are merely preferred embodiments of the present invention and are not intended to limit the present invention. For those skilled in the art, the present invention can 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.

Claims

1. A method for deploying infill and adjustment wells in tight sandstone gas reservoirs, characterized in that, The specific steps for deploying infill and adjustment wells in this tight sandstone gas reservoir are as follows: S100. Select gas reservoirs with infill and adjustment potential in the gas field, and determine the current state of the gas reservoir's reserve utilization and formation pressure. S200. Calculate the remaining reserves based on formation pressure, and calculate the controlled reserves and cumulative gas production in the control area of ​​the proposed infill well. S300. Through economic evaluation, calculate the capacity construction investment when the internal rate of return reaches 8% under the condition of cumulative gas production of the proposed infill adjustment wells, and calculate the number of infill adjustment wells and the length of the horizontal section to be deployed under this investment condition.

2. The method for deploying infill and adjustment wells in a tight sandstone gas reservoir according to claim 1, characterized in that, The formation pressure in S100 is calculated by formation pressure monitoring or the flow mass balance method to determine the current formation pressure in the potential target area.

3. The method for deploying infill and adjustment wells in a tight sandstone gas reservoir according to claim 1, characterized in that, In S200, under the current formation pressure conditions, the remaining reserves are calculated using the volumetric method. The calculation method is shown in the formula: Gi=0.01×A×h×φ×Sg×Tsc×Pi(Psc×T×Zi); Gi: Remaining natural gas reserves, in units of 10. 8 m 3 : A: Gas-bearing area, unit: km² 2 ; H: Effective thickness of the gas reservoir, in meters; Φ: Effective porosity of the gas reservoir, unit: decimal; Sg: Gas saturation, unit: decimal; T: Air layer temperature, unit: K; Tsc: Ground standard temperature, unit: K; Psc: Ground standard condition pressure, unit: MPa; Pi: Current formation pressure of the gas reservoir, unit: MPa; Zi: Gas deviation coefficient under current conditions, dimensionless quantity.

4. The method for deploying infill and adjustment wells in a tight sandstone gas reservoir according to claim 1, characterized in that, In S200, the expected cumulative gas production of adjacent wells in the same gas reservoir is calculated using the flow mass balance method, and then the recovery rate of adjacent wells in the same gas reservoir is obtained by combining the single-well controlled reserves.

5. The method for deploying infill and adjustment wells in a tight sandstone gas reservoir according to claim 4, characterized in that, When calculating the cumulative gas production of a single well using the fluid mass balance method, wellhead oil pressure or casing pressure can be used instead of formation pressure. The calculation is shown in the formula: G: Current controlled reserves per well under formation pressure conditions, unit: 10 8 m 3 ; Gp: Cumulative gas production per well under current formation pressure conditions, unit: 10 g / L 8 m 3 ; PR: Wellhead pressure when a gas well is abandoned, unit: MPa; P: Current wellhead pressure of the gas well, unit: MPa; ZR: Gas deviation coefficient when a gas well is abandoned; dimensionless. Z: Gas deviation coefficient under current conditions, dimensionless.

6. The method for deploying infill and adjustment wells in a tight sandstone gas reservoir according to claim 5, characterized in that, The cumulative gas production of the gas well is the gas production since commissioning and the cumulative gas production of a single well under the current formation pressure conditions calculated by the fluid mass balance method, i.e.: G I =Q+G p ; G I Cumulative gas production of a single well over its entire life cycle, in units of 10. 8 m 3 ; Q: Gas production volume since commissioning, in units of 10. 8 m 3 .

7. The method for deploying infill and adjustment wells in a tight sandstone gas reservoir according to claim 6, characterized in that, The recovery rate of the controlled reserves of a single gas well is the percentage of the cumulative gas production over the entire life cycle of the gas well relative to the controlled reserves of that single well. ER: Recovery rate per well, unit: decimal; Gn: Controlled reserves per well, unit: 10 8 m 3 .

8. The method for deploying infill and adjustment wells in a tight sandstone gas reservoir according to claim 6, characterized in that, In the S300 economic evaluation, the cash flow method is used to calculate the capacity construction investment when the internal rate of return reaches 8% under the condition of cumulative gas production of a single well. The number of infill adjustment wells to be deployed is determined by combining the well spacing of the infill adjustment wells and the remaining reserves, and finally the horizontal section length of the single well to be deployed is determined.

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