Gas reservoir numerical simulation method based on gas storage

Abstract

The invention relates to the technical field of oil-gas exploration, and discloses a gas reservoir numerical simulation method based on a gas storage, which comprises the following steps: establishing a geological simulation model based on the geological characteristics of the gas storage and the type of a gas reservoir, establishing a numerical simulation model based on the geological simulation model, and realizing gas reservoir production dynamic history fitting with a set time span. The geological simulation model and the numerical simulation model are corrected and perfected, and the corrected and perfected geological simulation model and the corrected and perfected numerical simulation model are used for production tracking of the gas injection well and the gas recovery well of the gas storage; wherein the correction refers to error data correction, and the perfection refers to data supplementation. According to the method, the problems of low multi-cycle injection-production pressure and yield fitting precision and the like in the prior art are solved.

Description

Technical Field

[0001] The present invention relates to the technical field of oil and gas exploration, and in particular to a gas reservoir numerical simulation method based on a gas storage facility. Background Art

[0002] Gas storage, a crucial link in the natural gas industry chain, is the most economical and effective method for storing and shaving natural gas. As of the end of 2021, there were 661 gas storage facilities worldwide, with a total working gas volume of 421.8 billion cubic meters, accounting for approximately 10.7% of global natural gas consumption. They have a daily production capacity of 7.3 billion cubic meters and a total backfill volume of 375 billion cubic meters (data source: CEDIGAZ Annual Report - UNDERGROUND GAS STORAGE IN THE WORLD - 2020STATUS). Oil and gas reservoir-type gas storage accounts for approximately 80% of the total working gas volume, followed by salt cavern-type storage at 11%, and aquifer-type storage at 9%. The average working gas volume of these storage facilities is 518 million cubic meters. 550 gas storage facilities, representing 76%, have a storage capacity of less than 500 million cubic meters.

[0003] Controllable factors affecting a gas storage facility's gas storage capacity include five geological and engineering factors: upper and lower operating pressure limits, maximum production pressure differential, number and type of injection and production wells, and tubing size. Raising the upper operating pressure limit is the most direct and effective way to increase working gas volume, offering significant technical and economic advantages and comprehensive benefits. This approach increases the maximum allowable injection pressure, boosting the total working gas volume and enhancing the instantaneous peak-shaving capacity of individual wells and the storage facility. It also allows for the partial utilization of existing surface equipment, requiring minimal engineering investment. However, increasing the well pattern density and increasing the tubing size both require significant engineering investment.

[0004] The evaluation of the gas storage mechanism is based on detailed geological research on the gas storage. Geomechanics is introduced to establish a four-dimensional geomechanical model of the gas storage. The entire process is described, in which the changes in the properties and characteristics of rocks and fluids in the trap caused by alternating injection and production are changed. At the same time, the phase permeability hysteresis and non-Darcy flow effects are taken into account, and key technologies for numerical simulation of the gas storage are established. Finally, special attention is paid to multi-factor sensitivity analysis and evaluation, and injection and production operation technical indicators are predicted, laying an important theoretical foundation for the safety and optimized operation of the gas storage and providing a scientific basis.

[0005] The industry attaches great importance to comprehensive and detailed geological research on gas storage facilities, encompassing gas reservoir structures and traps as a whole. High-precision three-dimensional geological models are being developed to lay a solid geological foundation for the scientific construction and operation of gas storage facilities. Geological research on gas storage facilities needs to expand beyond the gas-bearing zone to encompass the entire trap, including reservoirs, water bodies, caprocks, and faults. Comprehensive research, including high-precision three-dimensional seismic, standard and special well logging, sedimentary microfacies, and dynamic characteristics, is being conducted to establish high-precision three-dimensional geological and numerical models, enabling a detailed characterization of the spatial distribution of trap structures and fluid distribution patterns.

[0006] The industry attaches great importance to the impact of changes in the rock skeleton and formation fluids before reservoir construction. It makes full use of gas reservoir development data, introduces geomechanics, recalibrates and characterizes the geological bodies within the gas storage trap, and establishes a four-dimensional fine stress coupling geological model that conforms to the characteristics of the gas storage. It is mainly used to solve three key problems: the first is the evaluation of the dynamic sealing of the trap under cyclic injection and production conditions; the second is the changing characteristics of storage and permeability during gas reservoir development and cyclic injection and production operations; and the third is a detailed description of the reservoir fluid distribution and its changing characteristics before reservoir construction, laying an important geological foundation for scientifically determining the scale of the gas reservoir and ensuring safe operation.

[0007] However, current numerical simulation methods have problems such as low fitting accuracy of multi-cycle injection-production pressure and production. Summary of the Invention

[0008] In order to overcome the shortcomings of the existing technology, the present invention provides a gas reservoir numerical simulation method based on a gas storage facility to solve the problems of low fitting accuracy of multi-cycle injection and production pressure and production in the existing technology.

[0009] The technical solution adopted by the present invention to solve the above problems is:

[0010] A gas storage-based gas reservoir numerical simulation method establishes a geological simulation model based on the geological characteristics and gas reservoir type of the gas storage, and then establishes a numerical simulation model based on the geological simulation model to achieve dynamic historical fitting of gas reservoir production within a set time span, correct and improve the geological simulation model and the numerical simulation model, and use the corrected and improved geological simulation model and the numerical simulation model to track the production of gas injection wells and gas production wells in the gas storage; wherein, correction refers to correcting erroneous data, and improvement refers to supplementing data.

[0011] As a preferred technical solution, the following steps are included:

[0012] S1, model initialization: Based on the dynamic response characteristics of the injection and production reservoir of the gas storage, the geological simulation model is regionally and differentially coarsened. Based on the pressure system and initial saturation analysis, and the comprehensive analysis of the gas storage reservoir fluid and core relative permeability experimental data, the coarsened geological simulation model and numerical simulation model are initialized;

[0013] S2, Gas Reservoir Depletion Development History Fitting: Using the interpretation results of gas reservoir development and gas storage as the basis for adjusting numerical simulation history fitting parameters and hard data constraints, the history fitting of formation pressure and single well static pressure is completed by analyzing the distribution of reservoir physical properties;

[0014] S3, gas storage injection and production history matching: dynamic analysis and history matching of injection and production wells are performed to obtain the pressure distribution and fluid distribution of each cycle.

[0015] As a preferred technical solution, in step S1, when performing zoning difference coarsening, the differences considered include one or more of the following: reservoir plane zoning differences, differences between gas-bearing areas and peripheral areas, and differences between reservoirs and caprocks.

[0016] As a preferred technical solution, in step S1, when performing zone difference coarsening, the porosity is coarsened using the net-to-gross ratio and volume weighted average method, and the permeability is coarsened using the harmonic weighted average method.

[0017] As a preferred technical solution, in step S1, the three-dimensional two-phase model in Intersect is selected as the numerical simulation model based on the gas reservoir type, seepage mechanism, reservoir characteristics and fluid type.

[0018] As a preferred technical solution, in step S1, when initializing the numerical simulation model, one or more of the following factors are used: structural and property model, gas-water relationship, initial pressure field, reservoir fluid, rock saturation function, well trajectory and completion data, vertical pipe flow table, historical observation data, and well production control strategy.

[0019] As a preferred technical solution, in step S1, when initializing the numerical simulation model, use the definition scheme simulation process label to help easily create a new numerical simulation example or create a new example based on the existing example by modifying the scheme parameters; use the grid label to set the input of the model grid properties; use the function label to set the rock saturation function, rock compaction curve, and high-pressure physical properties of the gas reservoir fluid; use the scheme label to implement the production control strategy for the well; use the add, insert, or result label to control the number of parallel cores for the currently defined example, the loading of the results after the calculation, and the output of 2D / 3D results.

[0020] As a preferred technical solution, in step S2, the history fitting of formation pressure and single well static pressure includes one or more of the following: pressure and production fitting, reserve production and pressure distribution fitting, development index fitting, and pressure distribution fitting.

[0021] As a preferred technical solution, in step S3, when performing dynamic analysis and history matching on the injection and production wells, the parameters for partition optimization and adjustment include one or more of the following: attribute fields between wells, near faults / fractures, wellbore quality, pressure sensitivity, and permeability.

[0022] As a preferred technical solution, ECLIPSE is used to establish a numerical simulation model.

[0023] Compared with the prior art, the present invention has the following beneficial effects:

[0024] (1) The fitting of the 34-year low-rate depletion development history of seven wells shows that the gas reservoir has good connectivity and balanced production. The cumulative gas production of the five wells before the construction of the reservoir was 4.024 billion cubic meters, and the remaining reserves were 366 million cubic meters compared with the proven reserves (4.39 billion cubic meters). The pressure change trend of each well was consistent, with no obvious pressure drop funnel. The formation pressure dropped from 28.5 MPa to 2.4 MPa. The pressure in the northern marginal water area was higher than that in the gas reservoir development area, and the water body was inactive, which laid a solid foundation for the reservoir construction parameters.

[0025] (2) The dynamic analysis and historical fitting of the "10 injection and 8 production" model of 22 wells show that the gas production pressure profile presents a "three-zone" feature due to the limitation of gas production days, the limited diffusion range of high-speed flow pressure, and the influence of local reservoir heterogeneity;

[0026] (3) Taking into account factors such as inter-well interference, inter-well heterogeneity, reservoir capacity utilization, and northern water bodies, zoning optimization and adjustment of parameters such as attribute fields, wellbore quality, and pressure sensitivity between wells and near faults / fractures is an effective means to improve the accuracy of multi-cycle injection and production fitting. The inventory at the end of the 22-23 injection cycle was 4.399 billion cubic meters, which was 1.6% different from the dynamic analysis evaluation (4.406 billion cubic meters). BRIEF DESCRIPTION OF THE DRAWINGS

[0027] Figure 1 Updated technology roadmap for gas reservoir models;

[0028] Figure 2 Figure 1 is the well point permeability interpolation model and the corrected permeability model diagram;

[0029] Figure 3 This is the recent production simulation curve of No. 3 and No. 8 injection and production station wells;

[0030] Figure 4 This is the recent production simulation curve of No. 1 and No. 12 injection and production station wells;

[0031] Figure 5 This is the numerical simulation flow chart;

[0032] Figure 6 Cell inside out attribute distribution map;

[0033] Figure 7 Cell Volume attribute distribution diagram;

[0034] Figure 8 This is a comparison chart before and after porosity coarsening;

[0035] Figure 9 This is one of the gas and water distribution maps;

[0036] Figure 10 This is the second gas-water distribution map;

[0037] Figure 11 This is the third gas-water distribution map;

[0038] Figure 12 is a curve diagram of volume coefficient and viscosity changing with pressure;

[0039] Figure 13 This is the completion string and perforation model diagram;

[0040] Figure 14 It is the flow curve diagram of the production wellbore;

[0041] Figure 15 This is the injection wellbore flow curve;

[0042] Figure 16 This is the production curve diagram of the development stage + gas storage "10 injection and 8 production";

[0043] Figure 17 This is the cumulative production curve of production wells in the development stage;

[0044] Figure 18 This is a cross-sectional diagram of production wells during the development phase;

[0045] Figure 19 Wellhead pressure data diagram of production wells in the development stage;

[0046] Figure 20 This is the pressure drop curve diagram during the development stage;

[0047] Figure 21 Initialize the interface diagram for the numerical simulation model. DETAILED DESCRIPTION

[0048] The present invention will be further described in detail below with reference to the embodiments and the accompanying drawings, but the embodiments of the present invention are not limited thereto.

[0049] Example 1

[0050] like Figures 1 to 21 As shown in the figure, numerical simulation is one of the important methods for studying gas reservoirs and gas storages. This method can reproduce the movement and pressure distribution of underground fluids during gas reservoir development and gas storage operation, and study and solve practical problems of multi-cycle alternating injection and production in gas reservoir development and gas storage.

[0051] Based on the improved and updated gas reservoir geological model, a numerical simulation model was created according to the numerical simulation integrated workflow ( Figure 1The system comprehensively displays the basic static information of the gas reservoir and the simulation results of the dynamic numerical simulation model, including the calculation results of production indicators such as output and pressure. This allows gas reservoir engineers to comprehensively evaluate the constructed dynamic model and conduct a more in-depth analysis of the dynamic laws of gas storage production and development based on the simulation results of the gas reservoir numerical model, such as the changing trends of gas reservoir capacity and formation pressure, to assist in decision-making for subsequent development and production management.

[0052] Current situation analysis:

[0053] As part of the first batch of research projects for an underground gas storage project, as early as 2015, the gas storage management office established a Carboniferous geological model and numerical simulation model using ECLIPSE, based on the geological characteristics and reservoir type of the gas storage. The numerical simulation employed a three-dimensional, gas-water two-phase black oil model. The research completed a historical fit of the production performance of the Carboniferous gas reservoir, spanning 34 years from 1977 to 2011, and revised and improved both the geological and numerical simulation models. A dynamic tracking simulation of gas injection was completed for 879 days, from June 29, 2013, to November 25, 2015. The model fitted the injection performance of the injection wells, including measured data such as wellhead pressure and bottomhole static pressure. The model results were used to optimize subsequent injection and production well locations and types, optimize the gas injection rate per well during the trial run, and track pressure and fluid distribution during the trial run. The model was then used to continuously track the production of the gas storage's injection and production wells.

[0054] From 2019 to 2020, during the study of the mechanical integrity of a gas storage facility, research on gas reservoir engineering was also conducted based on the geological model. Based on the original seismic and well logging data, the well dynamics and related well test data were integrated to fit and predict the production dynamics during gas production and injection. Figure 2 , Figure 2 (Image: Center, left: wellpoint permeability interpolation model; right: revised permeability model). Based on data available at the time, the study evaluated and compared a baseline plan, a plan for increasing upper pressure limits, a plan for reducing lower pressure limits, seasonal peak shaving, and emergency plans. Further expansion of storage capacity was also discussed, establishing a principle of achieving capacity expansion and production targets in a phased manner, first on the surface and then underground, to ensure manageable operational risks and economic feasibility of the gas storage.

[0055] Demand Analysis:

[0056] After the geological model of a gas storage facility is updated, it is used in subsequent workflows, requiring production fitting for old wells in the Carboniferous gas reservoir and all wells in the gas storage facility.

[0057] Especially with the successive commissioning of injection and production stations No. 3, No. 8, No. 1, and No. 12, it is necessary to calibrate the gas reservoir model in the numerical simulation model based on actual gas production data, monitoring pressure data, or related dynamic monitoring data to avoid overestimation or underestimation of the production of the well due to deviations in the production capacity of the gas reservoir model wells, thereby affecting the application of the integrated coupling model of the gas reservoir-wellbore-surface pipeline network.

[0058] This study used Schlumberger's Intersect software, which integrates geological research and oil and gas reservoir engineering research. It can switch freely between geological modeling and numerical simulation, facilitating model modification and quantitative parameter calculation.

[0059] Model initialization:

[0060] On the basis of improving and updating the three-dimensional fine geological model of the gas storage reservoir, focusing on the dynamic response characteristics of the multi-cycle high-speed injection and production reservoir of the gas storage, the fine geological model is roughened by zoning differences (taking into account the differences in reservoir plane zoning, differences between gas-bearing areas and peripheral areas, and differences between reservoirs and caprocks, etc.). According to the pressure system and initial saturation analysis, and the comprehensive analysis of the gas storage reservoir fluid and core relative permeability experimental data, the roughened model is initialized ( Figure 3 ).

[0061] Model selection:

[0062] A Carboniferous gas reservoir has a rich reservoir of pores, caves, and fractures. Although the reservoir type is fracture-porous, the fractures are evenly distributed, with a network of fractures predominating, and dynamically exhibit the characteristics of a seemingly homogeneous formation. Based on the reservoir type, seepage mechanism, reservoir characteristics, and fluid type, a three-dimensional two-phase (gas-water) model in Intersect was used for simulation.

[0063] Simulate roughening and quality correction:

[0064] It is based on the numerical simulation geological model formed by coarsening the static geological model grid.

[0065] (1) Grid coarsening: The horizontal grid step size is 20m*20m, the vertical reservoir coarsening is 5 layers, and the total number of grid cells is 777×1323×5=5139855. The Cell inside out property ensures that there are no deformed grids, and the Cell volume property ensures that there are no negative grid volumes.

[0066] (2) Attribute coarsening: Porosity was coarsened using NTG (net-to-gross ratio) and volume-weighted average, and permeability was coarsened using the harmonic weighted average method. The distribution of attributes before and after coarsening was consistent, and both satisfied the normal distribution.

[0067] (3) Gas-water distribution: Gas-water interface -1986m, gas-water distribution plane and vertical direction are consistent with the previous understanding ( Figure 9 、 Figure 10 According to the pressure measurement, the original formation pressure gradient of a gas reservoir is 1.24MPa / 100m, which belongs to a normal pressure system. According to the hydrodynamic balance initialization method, the pressure field and saturation field can be calculated in sequence.

[0068] Phase permeability model:

[0069] The normalized relative permeability curves show two types of characteristics. The high-permeability reservoir, represented by Phase Reservoir 10, has low irreducible water saturation (average 18.3%), an average residual gas saturation of 12.6%, and a wide co-permeability range (average 6.1%). The other three wells have high irreducible water saturation (average 58%) and a narrow co-permeability range (average 31.3%), indicating the seepage characteristics of low-permeability reservoirs (Table 1).

[0070] Table 1 Phase permeability endpoint values ​​under different physical conditions

[0071]

[0072] PVT phase model:

[0073] This reservoir is a typical dry gas reservoir. During the depletion development phase, the CH4 content is 97%, the CO2 content is 1.8%, and there is no H2S. During the gas storage phase, the CH4 content is 95%, with a slight increase in ethane content and a CO2 content of 1.8%, with no H2S. Since PVT testing is not available in this area, a PVT curve was calculated based on the well flow composition.

[0074] Wellbore flow model (VFP model):

[0075] Based on the correction of data such as well trajectory, casing and tubing length, casing and tubing size, perforation depth, and measure well section, a wellbore flow model is established using completion data and wellbore pipe flow theory, and wellbore lift curves for production and injection wells are generated, providing a basis for the conversion of wellhead pressure and bottomhole pressure of injection and production wells.

[0076] Production dynamic model:

[0077] A Carboniferous gas reservoir was put into production on November 14, 1977, with a "low-speed" development model. After conversion to a gas storage facility in June 2013, it underwent cyclical "high-speed" injection and production. Following the standard format requirements of Petrel software, various types of formation dynamic data, including gas production data from old wells during the reservoir development phase, injection and production data from injection and production wells in the gas storage facility, static and flowing pressure monitoring data, and continuous monitoring data from monitoring wells, were compiled. A production dynamics model for 1977 was established in Petrel Re based on production data from the development phase and the "10 injection and 8 production" cycle of the gas storage facility.

[0078] The production performance of slow-rate depletion gas reservoirs shows significant variation in the contribution of individual wells to total production. Wells 16 and 25 are only 584 meters apart, and interference between them during production results in relatively low production rates (cumulative production of 260 to 400 million cubic meters). The other three wells produce 800 to 1.32 billion cubic meters.

[0079] Pressure changes in five wells—Faces 14, 16, 18, 25, and 30—are relatively consistent, with no apparent pressure drop funnel. Pressure monitoring data from wells in Phases 10 and 12 are consistent with the pressure drop curves of the production wells, indicating good gas connectivity and balanced production within the reservoir, making it a typical isochoric gas reservoir with an estimated dynamic reserve of 4.39 billion cubic meters. Well 13 deviates from the pressure drop curve, indicating energy replenishment from marginal water bodies.

[0080] Model initialization:

[0081] Initialize the numerical simulation model of "a gas reservoir + gas storage facility" based on Intersect based on the structural and attribute models, gas-water relationship, initial pressure field, gas reservoir fluid, rock saturation function, well trajectory and completion data, vertical pipe flow table, historical observation data, well production control strategy, etc. Specifically: Define simulation case process helps to easily create a new numerical simulation case, or modify the case parameters based on an existing case to quickly create a new case. The Grid tab is for inputting model grid properties; the Function tab contains settings related to rock saturation function, rock compaction curve, high-pressure physical parameters of gas reservoir fluid, etc.; Strategies is the production control strategy implemented for the well; Advanced, INTERSECT or Results tabs can be used to control the number of parallel cores for the calculation of the currently defined case, loading of results after calculation, 2D / 3D result output, etc.

[0082] History matching of low-rate depletion development of gas reservoirs:

[0083] History matching is a key step in revising reservoir properties and fitting geological reserves in geological models. The quality of history matching directly impacts the accuracy of the model and subsequent predictions. Based on static geological understanding and detailed evaluation, interpretation results from reservoir development and multi-cycle injection and production testing at the gas storage facility, as well as pressure monitoring, serve as the basis for adjusting numerical simulation history matching parameters and providing "hard data" constraints. First, through a detailed analysis of reservoir property distribution, history matching of formation pressure and single-well static pressure is completed. Based on the principles of seepage mechanics and numerical simulation experience, the main parameters adjusted during this stage are local reservoir permeability, conductivity, and net-to-gross ratio. Less certain parameters such as porosity and rock and fluid compressibility are adjusted slightly or not at all. The error in history matching for single-well static pressure is generally required to be less than 0.1 MPa. The completion of historical matching of 34 years of slow-rate depletion development in seven wells clarified the pressure and fluid distribution before library construction, consolidating the foundation for library construction parameters.

[0084] Fitting of the whole area:

[0085] Since it was put into production on November 14, 1977, all wells except Phase 10 and 12, which were not put into production due to formation water, and Phase 13, which is a water well, have not produced formation water. The highest monthly water production in the well area is 24 cubic meters, and the cumulative water production over the years is 1,903 cubic meters. The water produced in the well area is condensate water. Therefore, water production is not historically fitted.

[0086] (1) Pressure and output fitting

[0087] The error in fitting gas production and pressure across the entire region is small, with a fitting accuracy greater than 98%. Before the reservoir was built, the five wells produced a cumulative 4.024 billion cubic meters of gas, and the formation pressure dropped from 28.5 MPa to 2.4 MPa, with a cumulative gas production of 156 million cubic meters per unit pressure drop.

[0088] (2) Reserve utilization and pressure distribution

[0089] Prior to the reservoir's construction, the five wells produced a cumulative 4.024 billion cubic meters of gas, leaving 366 million cubic meters of proven reserves compared to 4.39 billion cubic meters. The reservoir's connectivity is good, and the formation pressure has dropped from 28.5 MPa to 2.4 MPa. The pressure in the northern marginal water area is higher than in the reservoir development zone.

[0090] Single well fitting:

[0091] Fitting formation pressure, wellhead pressure, and production for the five development wells demonstrates a single-well history fitting accuracy exceeding 98%. The contributions of individual wells to total production vary significantly, with Phase 18 and Phase 14 producing significantly (accounting for 60% of the cumulative gas production), while Phase 16 and Phase 25 produce relatively low volumes (due to interference between the two wells, which are only 584 meters apart).

[0092] (1) Development index fitting

[0093] Well No. 18 was put into production in November 1977, with a maximum daily output of 900,000 cubic meters and a cumulative gas production of 1.356 billion cubic meters. During the production period, only a small amount of condensate water was produced, with a maximum water production of 0.3m 3 / d. After 1993, due to the decline in liquid carrying capacity, water production basically stopped. The cumulative condensate production over the years was 863m 3 , the fitting error of gas production and pressure is small.

[0094] Well No. 14 was put into production in June 1979, with a maximum daily output of 400,000 cubic meters and a cumulative gas production of 1.16 billion cubic meters. The predicted dynamic reserves are 1.19 billion cubic meters. During the production period, only a small amount of condensate water was produced, with a maximum water production of 0.3m 3 / d. After 1989, due to the decline in liquid carrying capacity, water production basically stopped. The cumulative condensate production over the years was 234m 3 , the fitting error of gas production and pressure is small.

[0095] Well 30 was put into production in July 1979, with a maximum daily output of 370,000 cubic meters and a cumulative gas production of 825 million cubic meters. During the production period, only a small amount of condensate water was produced, with a maximum water production of 0.2m 3 / d. After 2004, due to the decline in liquid carrying capacity, water production basically stopped. The cumulative condensate production over the years was 219m 3 , the fitting error of gas production and pressure is small.

[0096] Well No. 25 was put into production in July 1977, with a maximum daily output of 340,000 cubic meters and a cumulative gas production of 416 million cubic meters. During the production period, only a small amount of condensate water was produced, with a maximum water production of 0.4m 3 / d. After 1995, due to the decline in liquid carrying capacity, water production basically stopped. The cumulative condensate production over the years was 384m 3 , the fitting error of gas production and pressure is small.

[0097] Well No. 16 was put into production in May 1979, with a maximum daily output of 315,000 cubic meters and a cumulative gas production of 267 million cubic meters. During the production period, only a small amount of condensate water was produced, with a maximum water production of 0.18m 3 / d. After 1994, due to the decline in liquid carrying capacity, water production basically stopped. The cumulative condensate production over the years was 133m 3 , the fitting error of gas production and pressure is small.

[0098] (2) Pressure distribution

[0099] The pressure trends across all wells are consistent, with no apparent pressure drop funnels. The wells demonstrate good connectivity and balanced production. The fitted bottomhole pressures indicate a synchronous decrease in pressure across all producing wells, indicating good reservoir connectivity. Water well pressures and liquid levels continue to decline with production. Manometer data from water well Facies 13, as well as Facies 10 and 12, which later experienced water production, indicate that as production pressure in the gas zone decreases, water zone pressure also decreases, indicating limited edge water and an inactive water body.

[0100] Historical matching of "10 injections and 8 productions" in gas storage:

[0101] Characteristics of the cyclic injection and production phase:

[0102] Phase I project (2013-2019): operating pressure 13.2~28MPa, working gas volume 22.8×10 8 m 3 , deploying 13 injection and production wells. Expansion and production (2020-2021): the lower limit pressure is reduced to 13MPa, the working gas volume is 23.0×10 8 m 3 , 8 new injection and production wells were deployed. Pressure expansion (2022-): operating pressure expanded to 11.6~30MPa, storage capacity 45.0×10 8 m 3 , working gas volume 26.0×10 8 m 3 , the maximum daily gas injection volume is 2100×10 4 m 3 、Maximum daily emergency gas production capacity 3800×10 4 m 3 .

[0103] Table 2 Design table of storage capacity parameters of a gas storage reservoir

[0104]

[0105] A gas storage facility, commissioned in June 2013, currently operates 22 wells and has experienced a period of "10 injections and 8 productions," and is currently in its 11th injection phase. As of June 9th, a cumulative gas injection of 15.5 billion cubic meters and production of 12.8 billion cubic meters have been achieved, with a maximum daily injection rate of 15.18 million cubic meters and a maximum daily production rate of 28.84 million cubic meters. From cycles 15-16 to 22-23, the multi-cycle operating curve based on the relationship between formation pressure and storage volume has largely coincided with the design curve, indicating stable operation of the gas storage.

[0106] Affected by high-speed injection and production, the reservoir exhibits certain heterogeneity, which is mainly manifested in three aspects.

[0107] ① The test well permeability is 19-1200mD, generally greater than 100mD. The effective permeability of the high structural part in the middle is higher than that at the south and north ends.

[0108] ② The injection and production capacity is strong, the connectivity is good, and the interference between wells is not obvious. The unimpeded flow rate of the injection and production wells in the central area is above 6 million cubic meters per day, and 50% of the wells have an injection and production volume of more than 1 million cubic meters per day (Table 3).

[0109] Table 3 Statistics of unobstructed flow rate of injection and production wells

[0110]

[0111] ③ The formation pressure profile at the end of the multi-cycle gas production balance period shows good overall reservoir connectivity, and the magnitude of formation pressure fluctuations within the gas storage at the end of the multi-cycle gas production balance period is relatively consistent. However, due to the limited gas production days, the limited diffusion range of high-speed flow pressure, and the influence of local reservoir heterogeneity, the pressure profile exhibits a "three-zone" pattern. At the end of gas production, wells Phase Reservoir 3 and Phase Reservoir 17 are well connected, with a large pressure drop funnel, representing Zone I. The six wells south of Well Phase Reservoir 3 have higher pressures, at the same pressure drop level as wells Phase Reservoir 17 to Phase Reservoir 21, representing Zone II. Meanwhile, wells Phase Reservoir 13 and Phase Monitoring 1 in the north have the highest pressures, representing Zone III.

[0112] Cyclic injection and production history matching:

[0113] Taking into account factors such as inter-well interference, inter-well heterogeneity, reservoir capacity utilization, and northern water bodies, the attribute fields, wellbore quality, pressure sensitivity, permeability and other parameters between wells and near faults / fractures were optimized and adjusted in different zones. The dynamic analysis and historical fitting of the "ten injection and eight production" model of 22 wells were completed, and the pressure and fluid distribution of each cycle were clarified, providing a model basis for the efficient operation of the gas storage.

[0114] 4.5.2.1 Full-area fitting

[0115] The fitting accuracy of pressure and injection and production gas volume is >98%, and the inventory volume at the end of the 22-23 injection cycle is 4.399 billion cubic meters, with an error of 1.6% compared with the dynamic analysis evaluation.

[0116] 4.5.2.2 Fitting of 22 Wells

[0117] With wellhead / bottom pressure and fluid monitoring indicators as targets, by adjusting the skin factor, PI, VFP table, permeability, grid volume, etc. of individual wells, the grid pressure and oil pressure of 13 wells in the first phase of the project, 8 newly drilled wells, and 1 phase monitoring well, totaling 22 wells, were fitted. The fitting accuracy of the single-well injection and production indicators was >98%.

[0118] (1) Phase I Project

[0119] The fitting accuracy of gas injection and production volume and wellhead pressure / monitoring pressure of 13 wells is >98%.

[0120] ①Well spacing, well-controlled effective gas storage volume and permeability are the main factors affecting the gas injection and production rates of nine wells, namely, 01, 08, 03, 07, 04, 15, 11, 19 and 22.

[0121] The cumulative gas injection volume of Phase Storage 01 Well over the years is 2.758 billion cubic meters, and the cumulative gas production volume is 1.926 billion cubic meters. The permeability around the well is high and the effective gas storage space controlled by the well is large.

[0122] Well Xiangchu 08 has a large effective gas storage space, with a cumulative gas injection volume of 1.634 billion cubic meters and a cumulative gas production volume of 1.510 billion cubic meters over the years.

[0123] Well Xiangchu 03 has a large effective gas storage space, with a cumulative gas injection volume of 1.434 billion cubic meters and a cumulative gas production volume of 905 million cubic meters over the years.

[0124] Well Xiangchu 07 has a high circumferential permeability and a large effective gas storage space controlled by the well. The cumulative gas injection volume over the years is 1.306 billion cubic meters, and the cumulative gas production volume is 903 million cubic meters.

[0125] The well control range of Xiangchu 04 is large, and it is 1,430m and 933m away from Xiangchu 3 and 6 wells. The cumulative gas injection volume over the years is 1.222 billion cubic meters, and the cumulative gas production volume is 743 million cubic meters.

[0126] The well control range of Phase Reservoir 15 is large, and it is 658m and 607m away from Phase Reservoir 16 and 17 wells, respectively. However, Well 17 was put into production later, with a cumulative gas injection volume of 1.124 billion cubic meters and a cumulative gas production volume of 722 million cubic meters over the years.

[0127] Phase Reservoir 11 has a large well control range, and is 1,456m and 1,007m away from Phase Reservoir 2 and Phase Reservoir 19 respectively. The cumulative gas injection volume over the years is 1.046 billion cubic meters, and the cumulative gas production volume is 1.002 billion cubic meters.

[0128] Phase Reservoir 19 has a large well control range, and is 1,007 meters away from Phase Reservoir 11 and Phase Reservoir 22 respectively. The cumulative gas injection volume over the years is 1.025 billion cubic meters, and the cumulative gas production volume is 933 million cubic meters.

[0129] Well Phase Reservoir 22 is 1,007 meters away from Well Phase Reservoir 19. The southern well was put into production later and has a larger well control range. The cumulative gas injection volume over the years is 654 million cubic meters and the cumulative gas production volume is 924 million cubic meters.

[0130] ②Poor reservoir properties and inter-well interference are the main factors affecting the gas injection and production volumes of four wells, namely, Xiangpu 16, 02, 06, and 10.

[0131] The physical properties of Phase Reservoir 16 well are worse than those of the surrounding areas. The cumulative gas injection volume over the years is 827 million cubic meters, and the cumulative gas production volume is 604 million cubic meters.

[0132] The physical properties of Phase Storage 02 Well are worse than those of its surrounding areas. The cumulative gas injection volume over the years is 686 million cubic meters, and the cumulative gas production volume is 633 million cubic meters.

[0133] Well Xiangchu 06, influenced by the small well spacing (490m) of Well Xiangchu 1, good connectivity between the two wells and high production allocation of Well Xiangchu 1, has formed a competitive gas production. The cumulative gas injection volume over the years is 614 million cubic meters and the cumulative gas production volume is 563 million cubic meters.

[0134] Phase Reservoir 10 well has worse physical properties than its surrounding areas. It is 583m away from Phase Reservoir 8 well, resulting in serious interference between the wells. The cumulative gas production over the years is 361 million cubic meters.

[0135] (2) Capacity expansion and pressure expansion projects

[0136] The fitting accuracy of injection and production gas volume and wellhead pressure / monitoring pressure of 8 newly drilled wells and 1 phase monitored well is >98%.

[0137] Well Phase Reservoir 17 has good physical properties and a large effective gas storage space controlled by the well. The cumulative gas injection volume over the years is 164 million cubic meters, and the cumulative gas production volume is 250 million cubic meters.

[0138] The physical properties of Phase Reservoir 05 well are good. It is 681 and 664 meters away from Phase Reservoir 18 and Phase Reservoir 21 wells respectively, and the interference between the wells is serious. The cumulative gas injection volume over the years is 120 million cubic meters, and the cumulative gas production volume is 100 million cubic meters.

[0139] Phase Reservoir 09 is 557 and 398 meters away from Phase Reservoir 6 and Phase Reservoir 4 respectively, with serious interference between the wells. The cumulative gas production over the years is 290 million cubic meters.

[0140] Well Xiangjian 1 has poor physical properties and small effective gas storage space controlled by the well. The cumulative gas injection volume over the years is 78 million cubic meters, and the cumulative gas production volume is 124 million cubic meters.

[0141] Well Phase Reservoir 13 has poor physical properties and small effective gas storage space controlled by the well, with a cumulative gas production of 23 million cubic meters over the years.

[0142] Well 21 of Phase Reservoir is 664m away from Well 5 of Phase Reservoir, and there is serious interference between the wells. The cumulative gas injection volume over the years is 125 million cubic meters, and the cumulative gas production volume is 87 million cubic meters.

[0143] Well Phase Reservoir 18 is 681 and 600 meters away from Well Phase Reservoir 5 and Well Phase Reservoir 17, respectively. There is serious interference between the wells. The cumulative gas injection volume over the years is 139 million cubic meters, and the cumulative gas production volume is 189 million cubic meters.

[0144] There are 20 wells in the phase storage, and the effective gas storage space controlled by the wells is small. The cumulative gas injection volume over the years is 125 million cubic meters, and the cumulative gas production volume is 139 million cubic meters.

[0145] There are 12 wells for gas storage, and the effective gas storage space controlled by the wells is small. The cumulative gas injection volume over the years is 131 million cubic meters, and the cumulative gas production volume is 151 million cubic meters.

[0146] Main understanding of numerical simulation:

[0147] (1) The fitting of the 34-year low-rate depletion development history of seven wells shows that the gas reservoir has good connectivity and balanced production. The cumulative gas production of the five wells before the construction of the reservoir was 4.024 billion cubic meters, and the remaining reserves were 366 million cubic meters compared with the proven reserves (4.39 billion cubic meters). The pressure change trend of each well was consistent, with no obvious pressure drop funnel. The formation pressure dropped from 28.5 MPa to 2.4 MPa. The pressure in the northern marginal water area was higher than that in the gas reservoir development area, and the water body was inactive, which laid a solid foundation for the reservoir construction parameters.

[0148] (2) The dynamic analysis and historical fitting of the "10 injection and 8 production" model of 22 wells show that the gas production pressure profile presents a "three-zone" feature due to the limitation of gas production days, the limited diffusion range of high-speed flow pressure, and the influence of local reservoir heterogeneity;

[0149] (3) Taking into account factors such as inter-well interference, inter-well heterogeneity, reservoir capacity utilization, and northern water bodies, zoning optimization and adjustment of parameters such as attribute fields, wellbore quality, and pressure sensitivity near wells and faults / fractures is an effective means to improve the accuracy of multi-cycle injection and production pressure fitting. The inventory at the end of the 22-23 injection cycle was 4.399 billion cubic meters, which was 1.6% lower than the dynamic analysis evaluation (4.406 billion cubic meters).

[0150] (4) Well spacing, well-controlled effective gas storage volume, permeability, and inter-well interference are the main factors affecting the injection and production gas volume.

[0151] As described above, the present invention can be preferably implemented.

[0152] All features disclosed in all embodiments in this specification, or steps in all methods or processes implicitly disclosed, except for mutually exclusive features and / or steps, can be combined and / or expanded or replaced in any manner.

[0153] The above description is merely a preferred embodiment of the present invention and does not constitute any form of limitation to the present invention. Based on the technical essence of the present invention and within the spirit and principles of the present invention, any simple modification, equivalent replacement and improvement of the above embodiment shall still fall within the scope of protection of the technical solution of the present invention.

Claims

1. A gas reservoir numerical simulation method based on a gas storage facility, characterized in that: Based on the geological characteristics of the gas storage and the type of gas reservoir, a geological simulation model is established, and based on the geological simulation model, a numerical simulation model is established to achieve dynamic historical fitting of gas reservoir production within a set time span. The geological simulation model and the numerical simulation model are corrected and improved, and the production of gas injection wells and gas production wells in the gas storage is tracked using the corrected and improved geological simulation model and the numerical simulation model. Among them, correction refers to correcting erroneous data, and improvement refers to supplementing data.

2. A gas reservoir numerical simulation method based on a gas storage facility according to claim 1, characterized in that: The following steps are involved: S1, model initialization: Based on the dynamic response characteristics of the injection and production reservoir of the gas storage, the geological simulation model is regionally and differentially coarsened. Based on the pressure system and initial saturation analysis, and the comprehensive analysis of the gas storage reservoir fluid and core relative permeability experimental data, the coarsened geological simulation model and numerical simulation model are initialized; S2, Gas Reservoir Depletion Development History Fitting: Using the interpretation results of gas reservoir development and gas storage as the basis for adjusting numerical simulation history fitting parameters and hard data constraints, the history fitting of formation pressure and single well static pressure is completed by analyzing the distribution of reservoir physical properties; S3, gas storage injection and production history matching: dynamic analysis and history matching of injection and production wells are performed to obtain the pressure distribution and fluid distribution of each cycle.

3. A gas reservoir numerical simulation method based on a gas storage facility according to claim 2, characterized in that: In step S1, when performing zone difference coarsening, the differences considered include one or more of the following: reservoir plane zone difference, gas-bearing zone and peripheral zone difference, and reservoir and caprock difference.

4. A gas reservoir numerical simulation method based on a gas storage facility according to claim 2, characterized in that: In step S1, when performing zone-differential coarsening, the porosity is coarsened using the net-to-gross ratio and volume weighted average method, and the permeability is coarsened using the harmonic weighted average method.

5. The gas reservoir numerical simulation method based on a gas storage facility according to claim 2, characterized in that: In step S1, the three-dimensional two-phase model in Intersect is selected as the numerical simulation model according to the gas reservoir type, seepage mechanism, reservoir characteristics and fluid type.

6. A gas reservoir numerical simulation method based on a gas storage facility according to claim 5, characterized in that: In step S1, when initializing the numerical simulation model, one or more of the following factors are used: structural and property models, gas-water relationship, initial pressure field, reservoir fluid, rock saturation function, well trajectory and completion data, vertical pipe flow table, historical observation data, and well production control strategy.

7. A gas reservoir numerical simulation method based on a gas storage facility according to claim 6, characterized in that: In step S1, when initializing the numerical simulation model, the Define Scheme Simulation Process tab is used to help easily create a new numerical simulation case or create a new case based on an existing case by modifying the scheme parameters; the Mesh tab is used to set the input of the model mesh properties; Use the function tags to set the rock saturation function, rock compaction curve, and high-pressure physical properties of gas reservoir fluids; use the solution tags to implement production control strategies for wells; use the add, insert, or result tags to control the number of parallel cores for the currently defined case, the loading of post-calculation results, and the output of 2D / 3D results.

8. The gas reservoir numerical simulation method based on a gas storage facility according to claim 2, characterized in that: In step S2, the history fitting of formation pressure and single well static pressure includes one or more of the following: pressure and production fitting, reserve production and pressure distribution fitting, development index fitting, and pressure distribution fitting.

9. The gas reservoir numerical simulation method based on a gas storage facility according to claim 2, characterized in that: In step S3, when performing dynamic analysis and history matching on the injection and production wells, the parameters for zone optimization and adjustment include one or more of the following: attribute fields between wells, near faults / fractures, wellbore quality, pressure sensitivity, and permeability.

10. A gas reservoir numerical simulation method based on a gas storage facility according to any one of claims 1 to 9, characterized in that: ECLIPSE was used to establish the numerical simulation model.

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