A gas channeling risk identification and early warning method for oilfield separate layer natural gas injection

Abstract

The application discloses a kind of gas channeling risk identification and early warning method of oilfield separate layer injection natural gas, comprising the following steps: including the following steps: step one, establish separate layer injection natural gas system separate layer injection model;Step two, select wellhead or some point in well full-flow section as reference point, record the pressure of reference point, and wellhead or separate layer flowmeter indication value;Step three, single layer natural gas injection is carried out to natural gas injection well, and the pressure of reference point and gas injection amount are recorded;Step four, under the condition that each layer is injected in well, the pressure of reference point and full-well gas injection amount are recorded.Step five, establish gas injection-pressure characteristic curve of separate layer and full well;Step six, according to the change of characteristic curve measured in time succession, if the starting pressure of a layer decreases and the flow coefficient increases, the layer has gas channeling risk or has occurred gas channeling.The application has the characteristics of easy operation, can be warned before gas channeling occurs, adjustment measures are taken to avoid gas channeling.

Description

Technical Field

[0001] This invention relates to the field of petroleum development technology, and more specifically, to a method for identifying and warning of gas channeling risks in stratified natural gas injection in oil fields. Background Technology

[0002] In oil development, stratified natural gas injection technology has been applied to both offshore and onshore high-permeability and low-permeability oilfields. Stratified natural gas injection allows for the balanced utilization of multiple reservoirs, significantly improving recovery rates. The stratified natural gas injection process typically involves combining multiple perforated layers based on reservoir properties such as permeability. Layers with similar permeability and adjacent layers are usually grouped into one segment. Generally, the entire well is divided into 2 to 7 segments, typically 3 to 5. The reservoir management department develops an injection plan based on reservoir properties, specifying the required natural gas flow rate for each layer. The engineering services department, through on-site construction, uses downhole tools to adjust the switching sleeves of the injectors for each layer. For nozzle-controlled injection, the appropriate nozzle diameter needs to be adjusted. Appropriate nozzle diameter series are selected for each layer to ensure that the natural gas injection flow rate for each layer meets the plan values. However, gas channeling has always been a serious problem affecting crude oil production during natural gas injection development. If gas channeling occurs, the corresponding production well will produce a large amount of natural gas. Gas channeling occurs when the formation from the injection well to the production well becomes interconnected, creating a dominant gas flow path. Gas channeling in one layer can suppress all other producing layers, leading to a rapid decrease in well production. Therefore, the primary development issue is to prevent gas channeling, and assessing the risk of gas channeling before it occurs is a pressing problem to be solved.

[0003] Currently, there is no efficient, low-cost, and reliable method for quantitative identification of gas channeling, nor is there a suitable early warning method for gas channeling before it occurs. Current gas channeling identification methods mostly involve measuring the gas-liquid ratio of the production well, changes in the injection well profile, and performing pressure recovery tests in the injection well to determine the reservoir flow coefficient, combined with static characteristics such as reservoir porosity and permeability for comprehensive analysis and evaluation. Gas channeling can also be evaluated using gas tracers; the production of tracer gas can be monitored in the produced well. If the tracer gas volume suddenly increases, it indicates that gas channeling has occurred. However, these methods are costly, complex to implement, and cannot achieve online monitoring and early warning.

[0004] Existing technologies already employ big data analysis methods for early warning. Chinese patent document CN109389331B discloses a gas channeling risk assessment method and software system, which uses optimal scaling regression to perform big data analysis on obtained production data, including production data, gas injection rate, and gas injection intensity. These parameters show a strong correlation with gas channeling. However, the correlation is indirect and cannot predict the situation of different layers within the well. Chinese patent document CN111720116B discloses a method for determining nitrogen-driven gas channeling in fractured-vuggy reservoir units, which uses the method of measuring the nitrogen content in the produced well; however, on-site construction is complex and real-time monitoring is not possible. Summary of the Invention

[0005] The purpose of this invention is to design and develop a method for identifying and warning of gas channeling risks in stratified natural gas injection in oil fields. By combining the flow rate of each layer of the injection well with the pressure at a reference point, it is possible to provide early warning before gas channeling occurs, thus preventing gas channeling from happening.

[0006] The technical solution provided by this invention is as follows:

[0007] A method for identifying and warning of gas channeling risks in stratified natural gas injection in oil fields includes the following steps:

[0008] Step 1: Establish a parallel model of the stratified gas injection system;

[0009] Step 2: Select any point at the wellhead or along the entire flow range in the well as a reference point;

[0010] Among them, a depth of 20m above the uppermost gas injection layer can be selected as the reference point, and a pressure gauge can be lowered to monitor the pressure at the reference point; if the wellhead is used as the reference point, the reading of the wellhead pressure gauge is recorded.

[0011] Step 3: Perform single-layer gas injection at each layer of the natural gas injection well;

[0012] The process involves using a drop-and-retrieve tool to open the sliding sleeve of a single layer and close the sliding sleeves of other layers. Using the wellhead control valve, 5-8 injection volumes are set at reasonable intervals, with at least 3 working points. Starting from zero injection volume, the maximum injection volume must be higher than the given injection scheme, but the pressure must be kept below the formation's safe injection pressure. After the injection volume stabilizes for 20-30 minutes, the flow meter reading at the wellhead is recorded, and the pressure value corresponding to the reference point is measured. Using the pressure at the reference point as the abscissa and the injection volume as the ordinate, an injection volume-pressure experimental data distribution map is created for each layer. The experimental data distribution map is then fitted using linear least squares to obtain the injection volume-pressure characteristic curves for each layer. The starting pressure and flow coefficient of each layer are then calculated through this fitting process.

[0013] Step 4: With the sliding sleeves of all injection layers in the well open and under normal gas injection conditions, measure the gas injection volume-pressure characteristic curve of the entire well. Using the control valve at the wellhead, set 5 to 8 total gas injection volumes at reasonable gas injection intervals, with at least 3 values. Start from zero flow rate, and the highest gas injection volume should be higher than the planned value, but the pressure should be lower than the formation safe injection pressure. After the gas injection volume stabilizes for 20 to 30 minutes, record the reading of the wellhead flow meter and the pressure value corresponding to the reference point. Plot the gas injection volume-pressure experimental data distribution map of the entire well with the pressure of the reference point as the abscissa and the total gas injection volume at the wellhead as the ordinate. Perform linear fitting on the experimental data distribution map to obtain the gas injection volume-pressure characteristic curve of the entire well. The starting pressure and flow coefficient of the entire well are obtained through fitting.

[0014] Step 5: Based on the historical drift of the gas injection volume-pressure characteristic curves of single layers and the entire well, i.e., the changes in starting pressure and flow coefficient of single layers or the entire well, and combined with the specific conditions of the reservoir in this block, determine the appropriate range of change. For example, if the starting pressure of the entire well decreases by 3 MPa compared to the previous test, or the flow coefficient increases by 2 times compared to the previous test, and the corresponding gas-liquid ratio of the well increases by more than 1 times, then gas channeling is considered to have occurred. If the starting pressure and flow coefficient have changed significantly, but have not yet reached the gas channeling standard, then gas channeling risk is considered to exist. If it is determined that gas channeling has occurred or is facing the risk of gas channeling in the entire well, then based on the drift of the characteristic curves of the layers, i.e., the historical drift changes of the starting pressure and flow coefficient of the layers, determine which layer the gas channeling occurred in.

[0015] Step Six: If injection profile logging data is available, and the gas injection volume for each layer and the entire well can be obtained, then under the condition that all downhole sliding sleeves are open, at least under three operating conditions, i.e. three total gas injection volumes, the gas injection volume for each layer can be measured using a production logging flow meter. At the same time, the pressure at the reference point (which can be selected at a location above the top gas injection layer, such as 20m) or the wellhead can be recorded. In this way, the layered gas injection volume-pressure characteristic curve for each layer can be obtained. Then, the method in Step Five can be used to determine whether gas channeling has occurred.

[0016] Preferably, the parallel model of the stratified gas injection system is an equivalent circuit parallel model.

[0017] Preferably, the single-layer natural gas injection specifically includes: lowering the retrieval device into the well to the target layer via a steel wire or cable, connecting the retrieval device to the sliding sleeve switch of each layer, so that the sliding sleeve of each layer opens or closes, injecting natural gas when it is open; and closing the sliding sleeve when it is stopped.

[0018] Preferably, step three further includes: if the starting pressure of the injection well decreases year by year and the overall flow coefficient of the well increases year by year, it indicates that the risk of gas channeling in the injection well is increasing year by year.

[0019] Wherein, the starting pressure of the gas injection well is the intercept of the characteristic curve on the pressure axis, and the overall well flow coefficient is the slope of the characteristic curve with pressure as the horizontal axis and gas injection volume as the vertical axis.

[0020] Preferably, step four further includes: since there is only a single layer injected, the injection flow rate of the single layer is equal to the flow rate metering value at the wellhead. For the pressure-flow characteristic curve of the whole well, the total flow rate of the whole well is indicated by the flow meter reading at the wellhead.

[0021] Preferably, step five further includes: if gas channeling occurs, based on the actual situation of a certain block, if the starting pressure decreases to a certain value (for example, 3 MPa less than the starting pressure of the well or the starting pressure of the adjacent well), or if the slope of the gas injection volume-pressure fitting line and the flow coefficient decrease to a certain value (for example, the starting pressure of the whole well decreases by 3 MPa compared to the previous test), or the flow coefficient increases by 2 times compared to the previous test, and the corresponding oil well gas-liquid ratio increases by more than 1 times, then it is determined that gas channeling exists, and the tool can be run down into the well to close the sliding sleeve of the layer, or the gas injection volume of the layer can be reduced.

[0022] Preferably, step six further includes: if there is injection profile logging data from previous years, measurements can be taken at multiple total injection volumes to obtain the injection volume-pressure characteristic curves from previous years, and the risk of gas channeling or gas channeling has already occurred can be determined based on the change in the slope of the curves.

[0023] The beneficial effects of this invention are as follows:

[0024] This invention presents a method for identifying and warning of gas channeling risks in stratified natural gas injection in oilfields. The required data, including injection volume and pressure data, are readily available. The acquired strata's initiation pressure and flow coefficient are directly correlated with gas channeling. Comparing the variation amplitude and trend of these two parameters across different historical periods can be used to monitor gas channeling in injection wells, assess and warn of risks, and locate strata where gas channeling is likely to occur or where there is a significant risk. Corresponding measures can be taken before gas channeling occurs. For example, injection volumes can be stopped or reduced in strata where gas channeling is likely or where the risk is high, controlling or delaying gas channeling, extending the lifespan of the injection-production well group, and improving the recovery rate of the development block. Attached Figure Description

[0025] Figure 1 This is a flowchart illustrating the gas channeling risk identification and early warning method for stratified natural gas injection in oilfields as described in this invention.

[0026] Figure 2 This is the gas injection volume-pressure characteristic curve for the first layer in 2014 in the embodiment of the present invention.

[0027] Figure 3This is the second layer gas injection volume-pressure characteristic curve in 2014 in the embodiment of the present invention.

[0028] Figure 4 This is the third layer gas injection volume-pressure characteristic curve in 2014 in the embodiment of the present invention.

[0029] Figure 5 This is the 2014 whole-well gas injection volume-pressure characteristic curve in the embodiment of the present invention.

[0030] Figure 6 This is the gas injection volume-pressure characteristic curve for the first layer in 2019 in the embodiment of the present invention.

[0031] Figure 7 This is the second layer gas injection volume-pressure characteristic curve in 2019 in the embodiment of the present invention.

[0032] Figure 8 This is the third layer gas injection volume-pressure characteristic curve in 2019 in the embodiment of the present invention.

[0033] Figure 9 This is the 2019 whole-well gas injection volume-pressure characteristic curve in the embodiment of the present invention.

[0034] Figure 10 This is the gas injection volume-pressure characteristic curve for the first layer in 2020 in the embodiment of the present invention.

[0035] Figure 11 This is the second layer gas injection volume-pressure characteristic curve in 2020 in the embodiment of the present invention.

[0036] Figure 12 This is the third layer gas injection volume-pressure characteristic curve in 2020 in the embodiment of the present invention.

[0037] Figure 13 This is the 2020 whole-well gas injection volume-pressure characteristic curve in the embodiment of the present invention.

[0038] Figure 14 These are the full-well gas injection volume-pressure characteristic curves measured three times over six years as described in this invention. Detailed Implementation

[0039] The present invention will now be described in further detail so that those skilled in the art can implement it based on the description.

[0040] like Figure 1 As shown, the present invention provides a method for identifying and warning of gas channeling risks in stratified natural gas injection in oil fields, specifically including:

[0041] Step 1: Based on the principle of hydroelectric similarity and according to parameters such as the number of layers in the stratified injection wells, establish a parallel model of the stratified natural gas injection system. This parallel model can be equivalent to a circuit network. For a multi-layer injection system, assume the injection wells are divided into n layers, typically n = 2 to 7, and in most cases n = 3 to 5.

[0042] Under linear Darcy flow conditions (which are typically met in oilfields), the following equation is satisfied:

[0043] pf = Riqi + ps

[0044] In the formula, p f This refers to the injection pressure at the wellhead of the injection well. The reference point here is chosen at the wellhead, but it can also be selected based on actual conditions, such as if pressure test data for the entire flow range (above the perforated section) of the well is available. R i R is called the formation seepage resistance of the i-th layer in the injection well, where i = 1 to n. i The flow resistance is related to factors such as formation permeability and thickness; the reciprocal of the flow resistance is the flow coefficient. The smaller the flow resistance, i.e., the larger the flow coefficient, the easier it is for oil or gas to flow in that formation. i This represents the gas injection volume for the i-th layer in the injection well.

[0045] Wellhead injection pressure p f Total gas injection volume q of the whole well t The following relationship must be satisfied:

[0046] pf = Rqt

[0047] In the formula, R represents the total seepage resistance of the entire well. R reflects the comprehensive resistance characteristics of each injected layer, and the reciprocal of the total seepage resistance is the total flow coefficient. The smaller the seepage resistance, the larger the flow coefficient, and the easier it is for gas to flow in the formation.

[0048] Let the total gas injection rate of the well be q. t The total gas injection volume is the sum of the gas injection volumes of each layer:

[0049]

[0050] In the formula

[0051]

[0052] Therefore, the reciprocal of the total equivalent seepage resistance R of the entire well is the sum of the reciprocals of the seepage resistance of each section, that is:

[0053]

[0054] When the reservoir is under a uniform pressure system, each layer of the injection well is equivalent to a "resistor" in a circuit, and the fluid seepage resistance of each layer is in parallel. Based on this principle, as long as the relationship between the gas injection volume of each layer and the wellhead pressure is established, the gas injection volume of each layer can be estimated based on the wellhead pressure, and the total gas injection volume can also be calculated based on the wellhead pressure.

[0055] Long-term gas injection into the formation can lead to gas channeling, where injected gas breaks through from the formation into the well. At this point, the flow resistance and initiation pressure decrease dramatically, or the flow coefficient increases dramatically. Even a slight increase in the wellhead pressure will significantly increase the formation's gas intake. Before gas channeling occurs, the rate at which the flow resistance and initiation pressure decrease is faster than during normal production. When gas channeling occurs, these values ​​reach a very small value and gradually stabilize as gas breaks through. Therefore, formations prone to gas channeling can be identified based on their flow resistance and initiation pressure, and the rate at which these parameters decrease can provide early warning of gas channeling.

[0056] Step 2: Select any point at the wellhead or in the entire flow range of the well as a reference point. For example, a depth of 20m above the uppermost gas injection layer can be selected as a reference point. Run a pressure gauge down to monitor the pressure at the reference point. If the wellhead is used as the reference point, record the reading of the wellhead pressure gauge without running the pressure gauge down into the well.

[0057] Step 3: Perform single-layer gas injection at each formation of the natural gas injection well. Use a drop-and-retrieve tool to enter the well, open the sliding sleeve of one formation, and close the sliding sleeves of all other formations. Using the wellhead control valve, set 5-8 injection rates at reasonable intervals, starting from zero flow and increasing the rate. The maximum injection rate should be slightly higher than the planned value, but the pressure must be kept below the formation's safe injection pressure. After the injection rate stabilizes for approximately 20-30 minutes, record the wellhead flowmeter reading and simultaneously measure the pressure at the reference point. Plot the injection rate-pressure experimental data distribution for that formation with the pressure at the reference point on the x-axis and the injection rate on the y-axis. Perform linear fitting on the experimental data distribution to obtain the injection rate-pressure characteristic curve for each formation. Through fitting, determine the starting pressure (i.e., the intercept of the characteristic curve on the pressure axis) and the flow coefficient for each formation, which is the reciprocal of the seepage resistance (i.e., the slope of the characteristic curve with pressure on the x-axis and injection rate on the y-axis). Then lower the retrieval tool, start another layer for testing, obtain the gas injection volume-pressure characteristic curve, until all layers are completed.

[0058] Taking the first gas injection layer as an example, the retrieval device is lowered into the well to open the sliding sleeve of this layer, while closing the sliding sleeves of the remaining layers. Natural gas is injected into the wellhead, and the wellhead control valve is adjusted. When the injection pressure reaches the starting pressure of this layer, natural gas begins to be injected into the formation. Then, the injection volume is gradually increased until it exceeds the injection volume of the injection scheme for this layer. The reference point pressure and the injection volume indicated by the wellhead flow meter are recorded at this time. Since only one layer is open, the injection volume of this layer is the reading of the wellhead flow meter. Starting from zero, the injection volume is increased, and at least three sets of data are recorded. Each set of data includes the reference point pressure and the injection volume of each layer. A characteristic curve is established based on the recorded reference point pressure and the injection volume of each layer. The injection volume should be kept stable when recording each set of data.

[0059] After the first layer of measurements is completed and the characteristic curve is established, the retrieval device is lowered into the well. The sliding sleeve is controlled to close the layer, and the second layer is opened. The above steps are repeated to record data for the second layer and establish the characteristic curve. In this way, data for all layers are recorded and characteristic curves are established.

[0060] Linear least squares fitting was used to determine the flow coefficient (slope of the characteristic curve) and formation initiation pressure (intercept of the pressure axis) for each layer. The collected multi-component layered flow rate and pressure data were plotted on a Cartesian coordinate system with pressure on the x-axis and flow rate on the y-axis to create a gas injection rate-pressure data distribution map. Linear least squares fitting was then performed on the experimental data distribution map to obtain the gas injection rate-pressure characteristic curve for each layer. The initiation pressure (i.e., the intercept of the characteristic curve on the pressure axis) and the flow coefficient of each layer were calculated from the fitted lines; these are the reciprocals of the seepage resistance (i.e., the slope of the gas injection rate-pressure characteristic curve).

[0061] Step 4: With all injection layers in the downhole open and under normal gas injection conditions, measure the gas injection volume-pressure characteristic curve for the entire well. Set 5-8 total gas injection volumes at reasonable intervals and record the wellhead gas injection volume and pressure data. Starting from zero flow, the maximum gas injection volume should be higher than the injection flow rate provided by the reservoir department, but the pressure must be lower than the formation's safe injection pressure. For each measuring point, wait approximately 20-30 minutes for the gas injection volume to stabilize, then record the wellhead flowmeter reading and the corresponding pressure value at the reference point. Plot the gas injection volume-pressure experimental data distribution map with the pressure at the reference point on the x-axis and the total wellhead gas injection volume on the y-axis. Perform linear least squares fitting on the experimental data to obtain the gas injection volume-pressure characteristic curve for the entire well. Through fitting, determine the starting pressure of the entire well (i.e., the intercept of the characteristic curve on the pressure axis) and the overall well flow coefficient, which is the reciprocal of the seepage resistance (i.e., the slope of the characteristic curve with pressure on the x-axis and gas injection volume on the y-axis).

[0062] Step 5: Based on the drift of the gas injection volume-pressure characteristic curves of single layers and the entire well measured over the years, i.e., the changes in the starting pressure and flow coefficient (seepage resistance) of single layers or the entire well, and combined with the specific conditions of the reservoir in this block, determine an appropriate range of change as the judgment standard. For example, if the starting pressure of the entire well decreases by 3 MPa compared to the previous test, or the flow coefficient increases by 2 times compared to the previous test, and the corresponding gas-liquid ratio of the well increases by more than 2 times, then the well is considered to have experienced gas channeling. If the starting pressure and flow coefficient have changed significantly, but have not yet reached the above standard, then there is a risk of gas channeling. If it is determined that gas channeling has occurred or is facing a risk of gas channeling in the entire well, then the drift of the characteristic curves of each layer, i.e., the drift of the starting pressure and flow coefficient (seepage resistance) of each layer over the years, is used to determine which layer the gas channeling occurred in. After determining the layer with a high risk of gas channeling, a dropper can be used to control the sliding sleeve to close the layer, or the gas nozzle can be adjusted to reduce the gas injection volume to control gas channeling or reduce the risk of gas channeling.

[0063] Step Six: If injection profile logging data is available, the gas injection volume for each layer and the entire well can be obtained. Then, with all downhole sliding sleeves open, at least three operating conditions (i.e., three total injection volumes) can be used to measure the gas injection volume for each layer using a production logging flowmeter. Simultaneously, the pressure at a reference point (which can be selected at a location above the top perforated layer, for example, 20m away) or the wellhead can be recorded. This will also yield the layered gas injection volume-pressure characteristic curve for each layer. Then, the method from Step Five can be used to determine if gas channeling has occurred.

[0064] Implementation Examples

[0065] Well A2, a natural gas injection well in an offshore oil field, consists of three injection stages. Production logging data from injection profiles recorded three times between 2014, 2019, and 2020 were used for processing. Multi-stage injection volume and pressure data were recorded using injection profile flow logging data. The stratified natural gas injection system was modeled as a parallel system. The injection well has three stages (n=3), with a reference point at a depth of 3500m, located above the perforated section.

[0066] 2014 Test Data Analysis:

[0067] Table 1 shows four pressure values ​​at the reference point for Well A2 in 2014, along with the corresponding stratified gas injection volume and total well gas injection volume. The negative injection volume in the first segment is due to backflow caused by tubing factors within the well, but this does not affect the application of this method. The table shows that the higher the pressure at the reference point, the greater the total well gas injection volume and the gas injection volume for each stratum. Based on the corresponding data, least squares fitting is used to derive the gas injection volume-pressure characteristic curves for the entire well and each stratum.

[0068] Table 1. Test data of Well A2 in 2014

[0069]

[0070] Figures 2-4 The injection volume-pressure characteristic curves are for the first, second, and third layers, respectively. Figure 5 The figure shows the total well gas injection volume-pressure characteristic curve. As can be seen from the figure, the linear relationship between each layer and the entire well is good, indicating good data quality. According to the fitting results, the flow coefficients of the first layer, second layer, third layer, and the entire well are 4.39 × 10⁻⁶. 4 m 3 / d / MPa, 18.50×10 4 m 3 / d / MPa, 4.35×10 4 m 3 / d / MPa, 18.14×10 4 m 3 / d / MPa; the starting pressures for the first, second, and third layers, and the entire well, are 23.25MPa, 23.21MPa, 23.25MPa, and 23.21MPa, respectively. Since the well was only put into gas injection for 12 months, based on the geological conditions of the area, it was determined that there was no risk of gas channeling between the layers of well A2 in 2014.

[0071] 2019 Test Data Analysis:

[0072] As shown in Table 2, the table gives the pressure and static pressure (total well gas injection volume 0) and total well gas injection volume 30 × 10⁻⁶ for Well A2 at the reference point in 2019. 4 m 3 / d and total well gas injection volume 40×10 4 m 3 A comparison of the total well gas injection volume-pressure and single-layer gas injection volume-pressure under the three conditions of / d shows that the greater the injection pressure, the greater the gas injection volume.

[0073] Table 2A2 Well Test Data in 2019

[0074]

[0075] Based on the data, a linear relationship between the gas injection volume and pressure of each layer and the entire well was established, such as... Figures 6-9 As shown in the figure, the linear correlation coefficient of the gas injection rate curves for each layer exceeds 0.9, basically conforming to a linear relationship, indicating that the data quality is acceptable. Based on the fitting results, the flow coefficients for the first, second, and third layers, and the entire well, are 12.22 × 10⁻⁶. 4 m 3 / d / MPa, 26.67×10 4 m3 / d / MPa, 28.47×10 4 m 3 / d / MPa, 67.36×10 4 m 3 / d / MPa; the starting pressures for the first, second, and third layers, and the entire well, were 17.52MPa, 17.51MPa, 17.54MPa, and 17.53MPa, respectively. Compared to 2014, over five years, the starting pressures for the entire well and each layer decreased by nearly 6MPa, while the overall well flow coefficient increased by nearly three times, and the flow coefficients for the first and third layers increased by nearly two and five times, respectively. This indicates that gas channeling has occurred or poses a significant risk.

[0076] 2020 Analysis:

[0077] As shown in Table 3, the table gives the pressure at the reference point of Well A2 in 2020 under three total gas injection conditions, as well as the corresponding stratified gas injection volume and the total gas injection volume of the well.

[0078] Table 3. Test data of Well A2 in 2020

[0079]

[0080]

[0081] Based on the data, a linear relationship between gas injection volume and pressure for stratified and whole-well operations in 2020 was established, such as... Figures 10-13 As shown in the figure, the linear correlation coefficient of the gas injection rate curves for each layer exceeds 0.9, indicating a linear relationship. Based on the fitting results, the flow coefficients for the first, second, and third layers, and the entire well, are 30.84 × 10⁻⁶. 4 m 3 / d / MPa, 21.93×10 4 m 3 / d / MPa, 66.72×10 4 m 3 / d / MPa, 119.49×10 4 m 3 / d / MPa; the starting pressures for the first, second, and third layers, and the entire well, were 17.50MPa, 17.55MPa, 17.51MPa, and 17.51MPa, respectively. Compared to 2019, the starting pressures for the entire well and each layer remained at a low level without change, while the overall well flow coefficient doubled, and the flow coefficients for the first and third layers also increased significantly. This indicates that gas channeling has occurred.

[0082] Plot the injection volume-pressure characteristic curves from three tests over a six-year period on a coordinate system, such as... Figure 14As shown, the characteristic curves for 2019 and 2020 show a significant shift towards lower pressure, with a steeper slope leading to a noticeably steeper curve. The determined flow coefficients and starting pressures are listed in Table 4. The table shows that compared to 2014, the flow coefficients in 2019 and 2020 significantly increased (seepage resistance coefficient decreased), being 3.7 times and 6.6 times that of 2014, respectively. The starting pressure decreased by approximately 6 MPa. Therefore, it can be inferred that the well had already begun to break through before 2019, and a relatively severe gas channeling occurred in 2020. The gas-oil ratio of the produced fluid from the connected well A12b began to rise in 2016, reaching 900 in 2017, and reaching 1400 in February 2020, consistent with the aforementioned test data analysis results.

[0083] Table 4. Changes in whole-well flow coefficient and start-up pressure after processing three test data over six years.

[0084]

[0085] Examining the flow coefficients and start-up pressure data for each layer revealed a significant increase in the flow coefficients of the first and third layers, while the second layer showed no significant change. This suggests that gas channeling is more likely occurring in the first and third layers, while the second layer is operating normally. Considering that the flow rate of the third layer is greater than that of the first layer, and that by 2020 the gas injection volume of this layer was three times that of the first layer, it can be concluded that gas channeling primarily occurred in the third layer.

[0086] Therefore, it is evident that using time-lapse measurements of flow-pressure characteristic curves for strata and the entire well, and assessing gas channeling risk based on curve drift, is an effective method.

[0087] This invention presents a method for identifying gas channeling risks in injection-production well groups of stratified natural gas injection systems in offshore or onshore oilfields. It establishes a multi-layer parallel model, making it easy to acquire the required data. The obtained stratified seepage resistance and initiation pressure are directly correlated with gas channeling. This method enables monitoring of natural gas injection wells, assessment and early warning of the magnitude of gas channeling risks, and allows for corresponding measures to be taken before gas channeling occurs, thus delaying its occurrence and extending the lifespan of the injection-production well group.

[0088] Although embodiments of the present invention have been disclosed above, they are not limited to the applications listed in the specification and embodiments. They can be applied to various fields suitable for the present invention. For those skilled in the art, other modifications can be easily made. Therefore, without departing from the general concept defined by the claims and their equivalents, the present invention is not limited to the specific details and embodiments shown and described herein.

Claims

1. A method for identifying and warning of gas channeling risks in stratified natural gas injection in oil fields, characterized in that, Includes the following steps: Step 1: Establish a parallel model of the stratified gas injection system; Step 2: Select any point at the wellhead or along the entire flow range in the well as a reference point; If the wellhead is used as a reference point, the reading of the wellhead pressure gauge is recorded. Step 3: Perform single-layer gas injection at each layer of the natural gas injection well; The process involves using a drop-and-retrieve tool to open the sliding sleeve of a single layer and close the sliding sleeves of other layers. Using the wellhead control valve, 5-8 injection rates are set according to the injection rate interval, starting from zero. The maximum injection rate must be higher than the given injection plan, but the pressure must be kept below the formation's safe injection pressure. After the injection rate stabilizes for 20-30 minutes, the flow meter reading at the wellhead is recorded, and the pressure value corresponding to the reference point is measured. Using the pressure at the reference point as the x-axis and the injection rate as the y-axis, an injection rate-pressure experimental data distribution map is created for each layer. The experimental data distribution map is then fitted using the linear least squares method to obtain the injection rate-pressure characteristic curve for each layer. The starting pressure and flow coefficient of each layer are then calculated through this fitting process. Step 4: With the sliding sleeves of all injection layers in the well open, measure the gas injection volume-pressure characteristic curve of the entire well. Using the control valve at the wellhead, set 5 to 8 total gas injection volumes according to the gas injection volume interval, starting from zero flow. The maximum gas injection volume should be higher than the planned value, but the pressure should be lower than the formation safe injection pressure. After the gas injection volume stabilizes for 20 to 30 minutes, record the reading of the wellhead flow meter and the pressure value corresponding to the reference point. Plot the gas injection volume-pressure experimental data distribution map of the entire well with the pressure of the reference point as the abscissa and the total gas injection volume at the wellhead as the ordinate. Perform linear fitting on the experimental data distribution map to obtain the gas injection volume-pressure characteristic curve of the entire well. The starting pressure and flow coefficient of the entire well are obtained through fitting. Step 5: Based on the drift of the gas injection volume-pressure characteristic curves of single layers and the whole well over the years, and combined with the specific conditions of the reservoir in this block, determine the magnitude of the change. If gas channeling occurs, according to the actual situation of a certain block, if the starting pressure decreases to the first threshold, or the slope of the gas injection volume-pressure fitting line and the flow coefficient decrease to the second threshold, then gas channeling is considered to have occurred. If the starting pressure and flow coefficient have changed significantly, but have not yet reached the gas channeling standard, then gas channeling risk is considered to exist. If it is determined that gas channeling has occurred in the whole well or is facing the risk of gas channeling, then the drift of the characteristic curves of each layer is used to determine which layer the gas channeling occurred in. Step 6: If there is data from injection profile logging to obtain the gas injection volume for each layer and the entire well, then with all the downhole sliding sleeves open, at the three total gas injection volumes, use a production logging flow meter to measure the gas injection volume for each layer separately, and simultaneously record the pressure at the reference point or wellhead. This will also obtain the layered gas injection volume-pressure characteristic curve for each layer. Then, use the method in Step 5 to determine whether gas channeling has occurred.

2. The method for identifying and warning of gas channeling risks in stratified natural gas injection in oilfields as described in claim 1, characterized in that, The parallel model of the stratified gas injection system is an equivalent circuit parallel model.

3. The method for identifying and warning of gas channeling risks in stratified natural gas injection in oilfields as described in claim 2, characterized in that, The single-layer gas injection specifically includes: lowering the retrieval device into the well to the target layer via a steel wire or cable; connecting the retrieval device with the sliding sleeve switch of each layer to open or close the sliding sleeve of each layer; injecting natural gas when the sliding sleeve is open; and closing the sliding sleeve when the sliding sleeve is stopped.

4. The method for identifying and warning of gas channeling risks in stratified natural gas injection in oilfields as described in claim 3, characterized in that, Step three also includes: if the starting pressure of the gas injection well decreases year by year and the flow coefficient of the whole well increases year by year, it indicates that the risk of gas channeling in the gas injection well is increasing year by year. Wherein, the starting pressure of the gas injection well is the intercept of the characteristic curve on the pressure axis, and the overall well flow coefficient is the slope of the characteristic curve with pressure as the horizontal axis and gas injection volume as the vertical axis.

5. The method for identifying and warning of gas channeling risks in stratified natural gas injection in oilfields as described in claim 4, characterized in that, Step four also includes: since there is only a single layer injected, the injection flow rate of the single layer is equal to the flow rate metering value at the wellhead. For the pressure-flow characteristic curve of the whole well, the flow rate of the whole well is indicated by the flow meter at the wellhead.

6. The method for identifying and warning of gas channeling risks in stratified natural gas injection in oilfields as described in claim 5, characterized in that, Step five also includes: determining that gas channeling has occurred, lowering the tool into the well to close the sliding sleeve of the layer, or reducing the gas injection volume of the layer.

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