A method for evaluating the gas injection capacity of a gas storage facility

Abstract

This invention belongs to the field of oil and gas resource development technology, specifically relating to a method for evaluating the gas injection capacity of a gas storage facility. The method includes the following steps: 1) Based on a derived binomial theoretical equation for injection capacity; 2) Designing the operating regime and deploying a pressure gauge to measure the bottom hole pressure, obtaining pressure-temperature gradients at different well depths and measurement data for different operating regimes of the injection well; 3) Processing the obtained data and substituting it into the above equation to calculate its coefficients, thus obtaining the injection capacity equation; and 4) Predicting the maximum natural gas injection volume of the corresponding injection well under different formation pressure conditions based on the injection capacity equation. This invention can accurately obtain stable formation pressure data from test wells, predict the gas injection capacity under different formation pressures and injection pressures, and the testing process and analysis methods are simple and easy to implement, providing a basis for site selection for storage facility construction, optimization of the gas injection well network, and selection of optimal injection enhancement measures.

Description

Technical Field

[0001] This invention belongs to the technical fields of underground natural gas storage, gas injection and production engineering, and oil and gas resource development, and specifically relates to a method for evaluating the gas injection capacity of a gas storage facility. Background Technology

[0002] Gas storage facilities are built on the basis of depleted and abandoned gas reservoirs or oil reservoirs that have been exploited to a certain extent, to solve the problem of excess natural gas production in summer and insufficient supply in winter. The gas injection and production capacity of the storage facility directly determines its supply guarantee capacity, and accurate evaluation is crucial for the site selection, construction, and operation of the storage facility.

[0003] Currently, the evaluation of injection capacity of gas injection wells mainly uses geological analysis based on static data from the early stage of oil and gas reservoir exploration and development and dynamic data from the development process. However, as the formation pressure decreases in the later stages of oil and gas extraction, the formation pore structure, permeability, and fluid distribution have all changed significantly. Practice has shown that this method of evaluating injection capacity using original formation parameters will produce a large error.

[0004] For field testing and evaluation of injection capacity, since there is no standardized method for evaluating injection capacity, the evaluation equation for the production capacity of gas well exploration wells is applied.

[0005] To address the issue of evaluating the injection capacity of gas wells in gas storage facilities before the construction of the facility in the absence of natural gas sources, some researchers have proposed using nitrogen instead of natural gas as the injection medium. Chinese invention patent application CN111927444A discloses a method for evaluating the gas injection capacity of depleted oil and gas reservoirs, employing an exploratory well production capacity evaluation equation. This method effectively solves the problem of evaluating whether injection wells can inject gas. However, its shortcomings include limited nitrogen production capacity, low nitrogen supply, short nitrogen injection time, and difficulty in stabilizing bottomhole flowing pressure, thus reducing the accuracy of quantitative analysis of reservoir parameters and injection capacity.

[0006] When natural gas supply is sufficient, many gas storage facilities directly apply the testing and evaluation methods for exploration well production capacity. This method requires that the formation pressure field be basically stable before the test. While the formation pressure is stable before exploration well testing, the gas injection capacity test of a gas storage facility is conducted during intensive injection within the facility. This results in significant pressure interference between wells and an unstable formation pressure field, leading to substantial errors when applying the exploration well testing methods. Summary of the Invention

[0007] The purpose of this invention is to provide a method for evaluating the gas injection capacity of a gas storage facility, in order to solve the problem that the evaluation of the gas injection capacity of injection wells is inaccurate when directly applying the production capacity testing and evaluation methods of exploration wells under the conditions of strong injection and production in gas storage facilities.

[0008] To address the aforementioned technical problems, this invention provides a method for evaluating the gas injection capacity of a gas storage facility. The method involves collecting the bottom-hole flowing pressure and formation pressure of a test well, and substituting these values ​​into the relationship equation between the bottom-hole flowing pressure, formation pressure, and gas injection volume to obtain the maximum natural gas injection volume corresponding to the test well. This relationship equation is derived based on the Darcy flow equation, and the production capacity equation coefficients in the relationship equation are derived using multiple sets of test data, including bottom-hole flowing pressure, formation pressure, and gas injection volume, obtained after testing the test well.

[0009] Its beneficial effects are as follows: Directly applying the production capacity testing and evaluation methods of exploratory wells under strong injection and production conditions in gas storage facilities can lead to inaccurate evaluation of the gas injection capacity of injection wells. This invention obtains stable formation pressure through testing, and then conducts further testing to obtain multiple sets of bottomhole flowing pressure, formation pressure, and injection volume data of the tested wells. Substituting these multiple sets of data into the derivation equation of the Darcy flow formula determines the equation coefficients, thereby obtaining the relational equation. The relational equation is used to calculate the maximum natural gas injection volume of the corresponding gas injection wells under different formation pressure conditions, so as to accurately obtain stable formation pressure data of the test wells and predict the gas injection capacity under different formation pressures and injection pressures. Moreover, the testing process and analysis methods are simple and easy to implement, providing a basis for the selection of gas storage facility sites, optimization of gas injection well networks, and selection of optimal injection enhancement measures.

[0010] Furthermore, the relational equation is:

[0011] P wf 2 -P R 2 =Aq+Bq 2

[0012] Among them, P R Formation pressure; P wf q represents the bottom hole flowing pressure; q represents the gas injection rate; A and B are the production capacity equation coefficients in the relational equation.

[0013] Its beneficial effects are: deriving an evaluation equation that reflects the gas injection capacity of well logging, identifying relevant parameters that affect the injection volume of wells, which is conducive to the prediction and analysis of the wells being logged, and provides a basis for reservoir construction site selection, optimization of gas injection well network and selection of injection enhancement measures.

[0014] Furthermore, the steps for testing the test well include: conducting a pressure drop test on the test well; and conducting an injection capacity test on the test well according to multiple set test operating procedures, wherein the test operating procedures refer to injecting gas at a set injection volume; and obtaining the required test data based on the test results of the two test experiments.

[0015] Its beneficial effects are: it calculates test data under multiple different injection volume conditions, so as to solve the production capacity equation coefficients of the injection capacity evaluation equation, which is conducive to calculating the maximum natural gas injection volume of the corresponding gas injection well under different formation pressure conditions, so as to accurately obtain stable formation pressure data of the test well and predict the gas injection capacity under different formation pressures and gas injection pressures.

[0016] Furthermore, the testing time requirement of the testing work system shall not exceed the maximum testing time, and the maximum testing time shall be determined by the numerical well test volume control method.

[0017] Its beneficial effects are: reducing the interference from adjacent wells, making the test results more accurate, and making it more conducive to obtaining more accurate stable formation pressure data of test wells and predicting the gas injection capacity under different formation pressures and gas injection pressures.

[0018] Furthermore, the required testing time under the testing work system is slightly longer than the minimum testing time. The formula for calculating the minimum testing time is as follows:

[0019]

[0020] Among them, t s Minimum test time; Porosity; μ is gas viscosity; C t r is the formation compressibility coefficient. e Where is the discharge radius of the flow system; K is the effective permeability.

[0021] Its beneficial effects are as follows: Since the gas flow time directly affects the accuracy of data analysis, the bottom hole pressure must be stable under each working cycle. Therefore, the test time for each working cycle must be slightly longer than the minimum test time to reduce the impact of testing on production, while reducing test risks and costs. Attached Figure Description

[0022] Figure 1 This is a schematic diagram of the simulated curves of the bottom-hole flow pressure and gas injection volume changing over time in the gas injection capacity test of this invention.

[0023] Figure 2 This is a simulation diagram of the overall test time determined by the present invention (the area within the black circle represents the stable pressure field);

[0024] Figure 3 This is a measured diagram of the pressure drop curve of the present invention;

[0025] Figure 4 Measured curves are provided for different systems of this invention;

[0026] Figure 5 This is a static pressure positive gradient analysis curve of the present invention;

[0027] Figure 6 This is a double logarithmic curve fitting analysis diagram of the present invention;

[0028] Figure 7 This is a curve showing the predicted injection capability of the present invention.

[0029] Figure 8 This is a flowchart of the method of the present invention. Detailed Implementation

[0030] The basic concept of this invention is as follows: based on the derived binomial theoretical equation of injection capacity; design the working conditions and send pressure gauges to measure the bottom hole pressure, obtain the pressure and temperature gradients at different depths of the wellbore and the measurement data of different working conditions of the gas injection well; perform preliminary processing and well test analysis on the pressure gradients, and substitute the parameters under each working condition into the above equation to calculate their coefficients, thereby obtaining the injection capacity equation, and predict the maximum natural gas injection volume of the corresponding gas injection well under different formation pressure conditions based on the injection capacity equation.

[0031] The present invention will now be described in detail with reference to the accompanying drawings and method embodiments.

[0032] Method Implementation Examples:

[0033] The present invention provides a method for evaluating the gas injection capacity of a gas storage facility, the flowchart of which is shown below. Figure 8 As shown, the specific implementation steps include:

[0034] Step 1: Derive and establish the evaluation equation for injection capability.

[0035] For gases under high pressure conditions, like liquids at room temperature, the compressibility coefficient C can be considered a constant. Based on Darcy's flow equation, the binomial theoretical equation for injection capacity (i.e., the equation relating bottom-hole flowing pressure, formation pressure, and gas injection rate) can be derived:

[0036]

[0037]

[0038] P wf 2 -P R 2 =Aq+Bq 2

[0039] in, Porosity; μ is gas viscosity; C t A is the formation compressibility coefficient; A and B are the production capacity equation coefficients; K is the effective permeability; h is the production layer thickness; P R Formation pressure; P wf q is the bottom hole flowing pressure; r is the gas injection rate; w Where is the wellbore radius; S is the skin coefficient.

[0040] Step two involves conducting pressure drop tests and injection capacity tests to obtain formation parameters, which are then used to calculate the coefficients of the binomial theoretical equation for injection capacity from step one.

[0041] 1) Pressure drop test.

[0042] A pressure gauge is lowered into the wellbore, and pressure and temperature gradients at various depths are measured during the lowering process. The placement position of the pressure gauge is determined based on the burial depth of the gas injection layer and the tubing structure, and the pressure gauge is placed as close as possible to the middle and deep parts of the reservoir.

[0043] In order to prevent the testing instrument from getting stuck during the lowering process, a steel wire rope is used for deployment before testing; and the counterweight of the testing tool string is determined according to the current wellhead pressure and sealing packing friction of the gas injection well in the gas storage facility; when the well inclination exceeds 25°, the pressure gauge is deployed to a depth that does not exceed the pipe shoe.

[0044] 2) Injection capability test, the test simulation curve is as follows: Figure 1 As shown.

[0045] ① Use numerical well test analysis to determine the formation pressure distribution around the gas injection well, and determine the testing procedure based on the size of the stable pressure distribution area.

[0046] In the injection capacity test, the "backpressure test" method was selected to shorten the test time and reduce the pressure impact on the tubing string. To reduce the error in the analysis results caused by the pressure backpressure effect, an incremental production sequence was adopted and the production gap between each regime was widened. Four test points were selected for the injection capacity test, evenly distributed between 20% and 80% of the current maximum gas injection volume. When calculating the injection capacity equation in step three, there are two unknown coefficients, A and B. Theoretically, the values ​​of A and B can be obtained from two operating regimes. However, due to the instability of pressure and flow data, deviations are easily generated. Usually, at least three operating regimes are required. Generally, stable gas injection volume and injection pressure data under four regimes are conducive to accurately regressing the values ​​of A and B.

[0047] ② Determine the maximum and minimum test times for each work system.

[0048] Due to the close proximity of the gas storage wells, to minimize interference from adjacent wells, the numerical well test volume control method was used to determine the maximum test time for each injection regime, avoiding pressure interference from adjacent wells. The simulation diagram is shown below. Figure 2 As shown.

[0049] The duration of gas flow directly affects the accuracy of data analysis. Backpressure testing requires that the bottom hole pressure must reach a stable level under each operating cycle; therefore, the test time for each operating cycle must be slightly greater than t. sTo minimize the impact of testing on production, while reducing testing risks and costs, the minimum testing time for each injection regime is:

[0050]

[0051] Among them, t s To ensure stable flow time; Porosity; μ is gas viscosity; C t r is the formation compressibility coefficient. e Where is the discharge radius of the flow system; K is the effective permeability.

[0052] ③ After the bottom hole pressure reaches a stable level under each working condition, the pressure gauge acquires pressure data for the gas injection well under different working conditions.

[0053] 3) Calculate the coefficients of the binomial theoretical equation of injection capacity to obtain the injection capacity equation.

[0054] First, the pressure gradient test data obtained from the pressure drop test is preliminarily processed using the pressure gradient reduction algorithm to obtain accurate pressure data at the mid-deep location of the reservoir. Then, pressure drop well test analysis is performed on the processed pressure data at the mid-deep location of the reservoir to obtain formation characteristic parameters such as formation pressure, formation coefficient, permeability, and skin coefficient. Substituting the formation pressure and pressure data and gas injection volume data under various working conditions into the binomial theory equation of injection capacity, the coefficients A and B of the binomial equation of gas injection capacity are obtained, thus obtaining the injection capacity equation.

[0055] Among them, well test analysis was performed using a double logarithmic curve fitting method; the A and B values ​​of the regression already included the influence of permeability and skin coefficient.

[0056] Step 3: Calculate the maximum natural gas injection volume of the corresponding gas injection well under different formation pressure conditions based on the injection capacity equation, so as to evaluate the injection capacity of the gas storage facility.

[0057] The following is a specific example of evaluating the injection capacity of a gas reservoir-type gas storage facility:

[0058] The relative density of natural gas is 0.6; the reservoir depth is 2802.6-3054.3m; the completion string ball seat is located at 2883.33m; continuous injection testing was conducted for 3 months prior to the test. The "backpressure test" method was selected, first shutting in the well to measure the pressure drop, and then conducting injection capacity tests under four operating conditions.

[0059] During normal well opening, wireline drilling was performed to 2860m to ensure unobstructed wellbore flow; a pressure gauge was lowered to 2850m using a suspended wireline, with flow pressure and temperature gradients measured along the way.

[0060] Numerical well test pressure distribution simulation results were used to determine the shut-in time and the test times for the four duty cycles using the volume control method. The shut-in test lasted 140 hours, and the injection capacity test lasted 8 hours for each cycle. The measured pressure curves are shown below. Figure 3 As shown. Among them, based on the maximum gas injection production in the early stage of the injection well, the injection capacity testing regime is designed to be 15×10. 4 m 3 / d、25×10 4 m 3 / d、35×10 4 m 3 / d and 45×10 4 m 3 / d, obtain pressure data of the gas injection well under the above four working conditions, such as Figure 4 As shown.

[0061] Preliminary processing of the static pressure positive gradient test data was performed to obtain the wellbore pressure and temperature gradient. The converted static pressure and static temperature data for the middle and deep formations are shown in Table 1 below, and the fitted curves are as follows. Figure 5 As shown.

[0062] Table 1

[0063]

[0064] Then, well test analysis was performed on the pressure data obtained from the mid-deep reservoir after processing. A double logarithmic curve fitting was performed using a "homogeneous + impermeable boundary" model. Figure 6 As shown in the figure; the formation parameters obtained through fitting are shown in Table 2 below:

[0065] Table 2

[0066] parameter numerical values dimension Formation pressure 33.082 MPa stratigraphic coefficient 926.705 mD·m Effective penetration rate 6.725 mD Total epidermal coefficient -1.02 Fault distance 37.4 m Detection radius 283.0 m Well storage coefficient 1.627 <![CDATA[m 3 / MPa]]>

[0067] Substituting the parameters under the four operating conditions into the binomial theoretical equation of injection capacity, we obtain the coefficients of the binomial equation for the gas injection well, resulting in the injection capacity equation:

[0068] P wf 2 -P R 2 =0.86047q + 0.01526q 2

[0069] The maximum natural gas injection rate of injection wells under different formation pressure conditions is predicted using the injection capacity equation, such as... Figure 7 As shown.

[0070] This invention enables accurate acquisition of stable bottom hole pressure data of test wells during intensive gas injection in gas storage facilities, even under conditions of significant inter-well interference. It also allows for prediction of gas injection capacity under different injection pressures using a gas injection capacity evaluation equation. The testing process and analysis methods are simple and easy to implement, providing technical support for efficient gas injection in gas storage facilities.

Claims

1. A method for evaluating the gas injection capacity of a gas storage facility, characterized in that, Step 1: Based on Darcy's flow equation, derive and establish the relationship equation between bottom hole flowing pressure, formation pressure and gas injection rate; Step two, derive the coefficients of the production capacity equation in the relational equation as follows: 1) Conduct pressure drop test: Measure the pressure gradient at each depth in the wellbore during the process of lowering the pressure gauge into the wellbore; 2) Perform injection capability testing as follows: ① The formation pressure distribution around the gas injection well is determined using numerical well test analysis, and the test working regime is determined based on the size of the stable pressure distribution area; the test working regime refers to injecting gas at a set injection rate; ② Determine the maximum and minimum test times t for the testing work system. s The test time requirement is slightly greater than t. s And not exceeding the maximum test time, which is determined using the numerical well test volume control method to reduce the impact of pressure interference from adjacent wells; t s for: Porosity is given by μ, gas viscosity is given by C. t r is the formation compressibility coefficient. e Where K is the discharge radius of the flow system, and K is the effective permeability. ③ After the bottom hole pressure reaches a stable level under each working condition, pressure data under different working conditions are obtained using a pressure gauge; 3) Calculate the coefficients of the production capacity equation in the relational equation as follows to obtain the relational equation: The pressure gradient reduction algorithm is used to process the data obtained from the pressure drop test to obtain the pressure data at the mid-deep location of the reservoir. Then, the pressure drop well test analysis is performed on the processed pressure data at the mid-deep location of the reservoir to obtain formation characteristic parameters including formation pressure, formation coefficient, and permeability. The formation pressure and the pressure data and gas injection data under various working conditions are substituted into the relationship equation to obtain the production capacity equation coefficients. Step 3: Calculate the maximum natural gas injection volume of the corresponding injection well under different formation pressure conditions based on the relationship equation.

2. The method for evaluating the gas injection capacity of a gas storage facility according to claim 1, characterized in that, The relational equation is: Among them, P R Formation pressure; P wf q represents the bottom hole flowing pressure; q represents the gas injection rate; A and B are the production capacity equation coefficients in the relational equation.

3. The method for evaluating the gas injection capacity of a gas storage facility according to claim 1, characterized in that, The shut-in time was determined using the volume control method.

4. The method for evaluating the gas injection capacity of a gas storage facility according to claim 1, characterized in that, Well test analysis was performed using a double logarithmic curve fitting method.

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