A method for identifying the corresponding relationship of multiple wells of an oil-water well in a horizontal well zone

Abstract

The present application provides a kind of horizontal well area multi-well corresponding relationship identification method, specific steps are as follows: step one, select the multi-injection well of needing to verify corresponding relationship, and inject the gas slug with tracer in the wellhead of multi-injection well respectively;Step two, restore normal water injection at the end of water well;Step three, observe the change situation of the production performance of the oil well around multi-injection well, and can qualitatively preliminarily judge the connectivity priority of oil and water well and the size of dominant channel according to the response time and change degree of surrounding oil well;Step four, again, the output gas of the oil well with dynamic response is sampled and analyzed by tracer analysis method, and the corresponding situation of the oil well and other single or multi-injection well is comprehensively identified according to the tracer analysis result combined with dynamic analysis result.The present application first judges dynamically, and then carries out fixed-point test, not only greatly improves the identification efficiency, but also greatly reduces the sampling blindness, reduces the workload, and improves the accuracy of test.

Description

Technical Field

[0001] This invention belongs to the field of petroleum testing, specifically relating to a method for identifying the correspondence between multiple oil and water wells in a horizontal well area. Background Technology

[0002] As water injection continues in oilfields, the water cut in wells gradually increases, especially in low-permeability and ultra-low-permeability fractured horizontal wells. These wells involve large-scale modifications and numerous production stages, making the identification of the relationship between oil and water wells complex. Conventional identification methods include dynamic verification, tracer testing, and pressure response methods. All of these require changes to the operating procedures of oil and water wells, continuous long-term sampling, and specialized equipment or methods for laboratory observation. Therefore, in field applications, they are not only labor-intensive, costly, and time-consuming, but also lack intuitiveness, necessitating the use of specialized equipment or professional personnel.

[0003] As water injection continues in oilfields, the water cut in wells gradually increases, especially in low-permeability and ultra-low-permeability fractured horizontal wells. These wells involve large-scale renovations and numerous production stages, making the identification of the relationship between oil and water wells complex. Conventional identification methods include dynamic verification, tracer testing, and pressure response methods. All of these require changes to the operating procedures of oil and water wells and continuous long-term sampling. The sampling workload is large and highly unpredictable. Therefore, in field applications, these methods are not only labor-intensive, costly, and time-consuming, but also lack intuitiveness, requiring specialized equipment or professional personnel.

[0004] Existing channel identification technologies mainly include: (1) Patent application number 201110318567.X (A method and system for identifying dominant water flow channels in high water-cut oilfields) is a numerical simulation identification method that uses parameters collected from oil and water wells in high water-cut oilfields at the layer level for statistical analysis. It is a numerical simulation method.

[0005] (2) Patent application number 201710160830.4 (Method and apparatus for identifying water injection dominant channels and selecting microsphere plugging particle size), which identifies water injection dominant channels based on the core permeability of marine clastic rocks in a single well and the boundary value of the water injection dominant channels. It is an indirect judgment made through core data.

[0006] (3) Patent application number 201810196801.8 (Method for determining the degree of development of dominant water flow channels), which obtains characterization parameters affecting the development of dominant water flow channels in the target reservoir, scores each characterization parameter, adds up the scores of multiple characterization parameters, and performs normalization processing. It is determined by numerical calculation.

[0007] (4) Parameter control, such as patent application number 201810457055.3 (method and device for identifying dominant water flow channels in sandstone reservoirs), which uses a specific method to identify the slope of the double logarithmic-derivative fitting graph of formation pressure for each well. It is judged by mathematical calculation and comparison.

[0008] (5) Production dynamic verification method: Some wells have unclear dynamic characteristics and cannot be judged. Changing the working system has a certain impact on production. The operation is troublesome and the cycle is long. Moreover, multiple wells interfere with each other, which makes it difficult to accurately judge the correspondence.

[0009] (6) The tracer testing cycle is long, requiring professional testing and analysis to determine the results. It also requires long-term sampling of all surrounding wells without differentiation, resulting in strong blindness and a large amount of ineffective work.

[0010] These patents and methods mainly use numerical simulation for calculation and analysis, which have high requirements for models and algorithms, are not intuitive, and are not very accurate, and are fundamentally different from this technology. Summary of the Invention

[0011] To overcome the challenges of identifying oil-water relationships in horizontal wells, which are typically larger and have more complex fracture networks compared to directional wells, conventional methods often require changes to well operating procedures, continuous long-term sampling, and are characterized by high workload, high randomness, high cost, and poor intuitiveness. This invention provides a method for identifying the relationships between multiple oil and water wells in a horizontal well area. This method first uses dynamic judgment followed by fixed-point testing, significantly improving identification efficiency, greatly reducing sampling randomness, decreasing workload, and enhancing testing accuracy.

[0012] The technical solution adopted in this invention is as follows: A method for identifying the correspondence between multiple oil and water wells in a horizontal well area, the specific steps of which are as follows: Step 1: Select multiple water injection wells whose correspondence needs to be verified, and inject gas slugs containing tracers into the wellheads of the multiple water injection wells respectively; Step two: Restore normal water injection at the well end; Step 3: Observe the changes in the production dynamics of the oil wells around the multiple water injection wells, and make a preliminary qualitative judgment on the priority of oil-water well connectivity and the size of the dominant channel based on the response time and degree of change of the surrounding oil wells. Step four: The tracer analysis method is then used to sample and analyze the produced gas from the oil well with dynamic response. Based on the tracer analysis results and the dynamic analysis results, the correspondence between the oil well and other single or multiple water injection wells is comprehensively determined.

[0013] The gas slug is an inert, non-toxic, and harmless gas that is not present in the reservoir environment.

[0014] The gas slug is one or a mixture of N2, CO2, air, and deoxygenated air.

[0015] In step one, different tracers are injected into different injection wells.

[0016] In step one, the tracer is a gaseous tracer.

[0017] The gas tracer is a fluorinated gas tracer, which includes two or more combinations of difluorochloromethane, difluorodichloromethane, difluorochlorobromomethane, tetrafluoroethane, difluoroethane, difluoromethane, tetrafluorochloroethane, heptafluoropropane, and hexafluoropropane.

[0018] In step two, the normal water injection is the amount of water injected based on the geological conditions before the test or the actual amount of water that should be injected.

[0019] In step three, the production dynamics of the surrounding oil wells include changes in fluid production, oil production, water cut, dynamic fluid level, gas production, and dynamometer card.

[0020] The oil wells with dynamic response are those whose production dynamics change by at least ±10% before and after the test.

[0021] In step one, the amount of tracer added is 0.5 to 1.5% of the volume of the injected gas slug.

[0022] The beneficial effects of this invention are as follows: This invention involves injecting a set volume of gas slug into the injection wellhead, with a tracer added inside the gas slug, and then resuming normal water injection. A preliminary judgment is made based on the dynamic changes in the production of the oil well. Then, tracer samples are taken from the responding oil wells for analysis. Finally, the oil well is comprehensively judged in relation to other single or multiple water injection wells based on the tracer analysis results and the dynamic analysis results.

[0023] This invention utilizes the fact that the flow rate of gas in a reservoir is several to tens of times faster than that of liquid, thus allowing for rapid observation of dynamic responses. Compared to traditional dynamic methods using water as a medium, this significantly shortens the testing cycle. Furthermore, for multi-well testing, relying solely on production dynamics cannot identify which well is affected. This invention first uses dynamic assessment before conducting targeted analysis, greatly improving identification efficiency, significantly reducing sampling blindness, decreasing workload, and enhancing testing accuracy.

[0024] This invention has low operating costs and is easy to implement, making it easy to promote and apply. It can be implemented using only existing equipment and personnel, without the need to purchase expensive equipment or hire professional companies. It can also replace or supplement existing testing methods to a certain extent.

[0025] The following will provide further explanation in conjunction with the accompanying drawings. Attached Figure Description

[0026] Figure 1 The diagram shows the distribution of two water wells and multiple oil wells in this invention.

[0027] 1. Oil well one; 2. Oil well two; 3. Oil well three; 4. Oil well four; 5. Oil well five; 6. Oil well six; 7. Water injection well A; 8. Water injection well B. Specific Implementation

[0028] Example 1: To overcome the challenges of identifying oil-water relationships in horizontal wells, which are typically larger and have more complex fracture networks compared to directional wells, conventional methods often require changes to well operating procedures, continuous long-term sampling, and are characterized by high workload, high randomness, high cost, and poor intuitiveness. This invention provides a method for identifying the relationships between multiple oil and water wells in a horizontal well area. This method first uses dynamic judgment followed by fixed-point testing, significantly improving identification efficiency, greatly reducing sampling randomness, decreasing workload, and enhancing testing accuracy.

[0029] A method for identifying the correspondence between multiple oil and water wells in a horizontal well area, the specific steps of which are as follows: Step 1: Select multiple water injection wells whose correspondence needs to be verified, and inject gas slugs containing tracers into the wellheads of the multiple water injection wells respectively; Step two: Restore normal water injection at the well end; Step 3: Observe the changes in the production dynamics of the oil wells around the multiple water injection wells, and make a preliminary qualitative judgment on the priority of oil-water well connectivity and the size of the dominant channel based on the response time and degree of change of the surrounding oil wells. Step four: The tracer analysis method is then used to sample and analyze the produced gas from the oil well with dynamic response. Based on the tracer analysis results and the dynamic analysis results, the correspondence between the oil well and other single or multiple water injection wells is comprehensively determined.

[0030] This invention is a method that involves injecting a set volume of gaseous slug containing a tracer into the end of a water injection well, then resuming normal water injection, making a preliminary judgment based on the dynamic changes in the production of the oil well, then sampling and analyzing the tracer in the responding wells, and finally comprehensively identifying the oil well's correspondence with other single or multiple water injection wells based on the tracer analysis results and the dynamic analysis results.

[0031] This invention utilizes the fact that the flow rate of gas in a reservoir is several to tens of times that of liquid, thus allowing for rapid observation of dynamic responses. Compared with traditional dynamic methods using water as a medium, this invention can significantly shorten the testing cycle.

[0032] For multi-well testing where relying solely on production dynamics is insufficient to identify which specific well is affected, this invention first uses dynamic assessment followed by targeted testing. This significantly improves identification efficiency, greatly reduces sampling randomness, decreases workload, and enhances testing accuracy. This invention offers significant advantages in terms of operating costs, implementation difficulty, and ease of application. It can be implemented using existing equipment and personnel, eliminating the need to purchase expensive equipment or hire specialized companies. Furthermore, it can, to some extent, replace or supplement existing testing methods.

[0033] Example 2: Based on Example 1, in this embodiment, preferably, the gas slug is an inert, non-toxic and harmless gas that is not present in the reservoir environment.

[0034] Preferably, the gas slug is one or a mixture of N2, CO2, air, and deoxygenated air.

[0035] In this invention, the gas slug can also use relatively expensive gases. It ensures that the gas slug uses gases not present in the reservoir environment. This allows for an effective and intuitive understanding of the dynamic response of oil wells surrounding the water well.

[0036] Preferably, in step one, different tracers are injected into different injection wells.

[0037] In this invention, multiple water injection wells are selected, and a unique tracer is added to each well. This ensures that the tracer in each well is different. After sampling and detecting the tracer in the surrounding oil wells, it can be determined which water well has good connectivity and a large channel between the oil well and the oil well.

[0038] Preferably, in step one, the tracer is a gaseous tracer.

[0039] In this invention, a gas slug is chosen because the flow velocity of gas in the reservoir is several to tens of times that of liquid, thus allowing for rapid observation of dynamic responses. Compared to traditional dynamic methods using water as the medium, this significantly shortens the testing cycle. The gas tracer added within the gas slug effectively determines the connectivity and dominant channel size between the oil well and the corresponding water well.

[0040] Preferably, the gas tracer is a fluorinated gas tracer, which includes two or more combinations of difluorochloromethane, difluorodichloromethane, difluorochlorobromomethane, tetrafluoroethane, difluoroethane, difluoromethane, tetrafluorochloroethane, heptafluoropropane, and hexafluoropropane.

[0041] In this invention, fluorinated gaseous tracers are added to water injection wells, and then the gaseous tracers are detected in the surrounding oil wells. Samples of the substances exiting the oil wells are taken, and the tracer content in the samples is analyzed to determine the concentration of various gaseous tracers. This further determines the connectivity between the oil wells and the water wells.

[0042] In this invention, samples are taken every 12±1 hours in the initial stage after the injection of fluorinated gas tracer, every 24±1 hours after the tracer is detected in the sample, and every 12±1 hours after the tracer content in the sample exceeds the peak value. The entire sampling cycle is 60 to 100 days.

[0043] The injection volume, pressure, and rate of the tracer are determined based on the on-site gas production, formation pressure, and gas production rate. The injection volume of the tracer depends on the volume and background of the reservoir being evaluated, as well as the minimum detection limit of the analytical instrument. When the background value is high, the injection volume of the tracer is mainly determined by whether it can mask the background value. To ensure that all monitoring wells in the oil production area achieve tracer penetration and have a sufficiently high peak concentration, a conservative algorithm is adopted within economic limits to maximize the amount of gas tracer used to ensure the success of the test.

[0044] Fluorinated gas tracers exhibit excellent chemical stability, low background concentrations in formations, high temperature resistance, low water solubility, and resistance to hydrolysis. Furthermore, when multiple fluorinated gases are used in combination, they are well-compatible with the indicated gas (especially water vapor), do not adsorb on formation surfaces, do not partition in oil or water, do not react with formation minerals, and are easily detected, highly sensitive, non-toxic, safe, inexpensive, and require only tens or hundreds of kilograms of injection, making them ideal gas tracers. In addition, the gas tracer of this invention has a lower limit of detection of 10⁻¹⁵ (v / v).

[0045] The fluorinated gas tracer provided by this invention can effectively identify the propulsion speed and direction of injected gas (especially water vapor), its impact, the heterogeneity of the reservoir and the formation connectivity, understand the effect relationship between injection wells and production wells, analyze the causes of problems in the production process, better grasp the production dynamics, and provide a reliable basis for adjusting the plan and formulating measures.

[0046] This invention employs a gas chromatography-ECD detector, which can detect the fluorinated gas tracers of this invention with high sensitivity. It can simultaneously detect more than 6 gas tracers, and the detection limit is 10-10 v / v (ppt level).

[0047] The gas tracer provided by this invention exhibits good stability at vapor temperature, low solubility (hydrolysis), and a solubility (hydrolysis rate) of less than 1% compared to the control sample, meeting the requirements for gas tracer use. The fluorinated gas tracer provided by this invention can essentially eliminate some detection interference factors in petroleum gases, which is beneficial for improving detection accuracy and increasing the number of samples that can be tested.

[0048] Preferably, in step two, the normal water injection volume is the geologically allocated water injection volume before the test or the actual required water injection volume. This volume can be adjusted according to the actual reservoir conditions, production needs, and testing requirements.

[0049] Preferably, in step three, the production dynamics of the surrounding oil wells include changes in fluid production, oil production, water cut, dynamic fluid level, gas production, and dynamometer card.

[0050] Preferably, the oil well with dynamic response is an oil well whose production dynamics change by at least ±10% before and after the test.

[0051] Preferably, in step one, the amount of tracer added is 0.5 to 1.5% of the volume of the injected gas slug.

[0052] In this invention, a dynamic analysis method is first used to compare the production dynamics of surrounding production wells before and after testing. After excluding other influences, the priority of oil-water well connectivity and the size of the dominant channel are preliminarily determined based on the dynamic response time and the degree of change. Then, a tracer analysis method is used to sample and analyze the gas produced by the oil well with dynamic response. Based on the tracer analysis results and the dynamic analysis results, the correspondence between this oil well and other single or multiple water injection wells is comprehensively identified.

[0053] Sampling for analysis is performed using a sampling bag at the wellhead or metering chamber of the monitoring well. If sampling cannot be performed at the wellhead due to special reasons (such as excessive wellhead pressure making sampling too difficult), sampling can be performed at the inlet of the separator in the metering chamber.

[0054] The implementation method of the present invention is as follows: In this invention, such as Figure 1 As shown, there are two water wells. Gas tracer A and gas tracer B are added to the gas slugs within both wells. Gas tracer A is preferably a mixture of dichlorofluoromethane and dichlorofluoromethane. Gas tracer B is preferably a mixture of tetrafluoroethane and difluoroethane. The specific real-time process is as follows: Step 1: Select the water injection well A7 that needs to be verified for correspondence. Use a gas pump to inject 2000 standard cubic meters of tracer A into the N2 slug through the tubing at the wellhead of water injection well A7. Use a liquid pump to squeeze clean water through the tubing to displace the gas into the reservoir. Then restore the water injection process of water injection well A and resume normal water injection according to the original water injection parameters.

[0055] Step 2: Following the method in Step 1, use a gas pump to inject 2000 standard cubic meters of tracer B into the N2 slug of the injection well B8 through the wellhead of the injection well B8 via the tubing. Then, use a liquid pump to squeeze clean water through the tubing to displace the gas into the reservoir. Restore the water injection process of the injection well B and resume normal water injection according to the original water injection parameters.

[0056] Step 3: Resume normal water injection at the water well end and normal production at the oil well end. Record and closely observe the production dynamics of the surrounding oil wells (Well 1, Well 2, Well 3, Well 4, Well 5, and Well 6) according to the existing production management system. Pay attention to any changes in casing pressure, production volume, oil production, water cut, dynamic fluid level, or dynamometer card. After eliminating other influencing factors (in the case of production stoppage), Well 2 showed an increase in both production volume and oil production 10 days after the test; Well 4 showed an increase in oil production and a decrease in water cut 18 days after the test. After 23 days of testing, the production of oil well 46 first increased and then decreased, and the gas production at the wellhead increased significantly. Oil wells 11 and 33 showed no dynamic changes. It can be preliminarily determined that oil wells 22, 44, and 66 are connected to water injection well A or B, and the connection priority of oil well 22 is higher than that of oil well 44. There is no obvious correspondence between oil wells 11 and 33 and water injection well A or B.

[0057] Step 4: After the oil wells respond, samples of the produced gas from the responding wells 2 (2), 4 (4), and 6 (6) were promptly taken and analyzed. The results showed that tracer A was detected in the produced gas from wells 2 (2) and 6 (6), with concentrations of 20 and 80%, respectively. Tracers A and B were detected in the produced gas from well 4 (4), with concentrations of 36 and 94%, respectively. Therefore, it can be determined that wells 2 (2) and 6 (6) correspond to water injection well A7, and well 6 (6) has a more developed dominant channel. Well 4 (4) corresponds to both water injection wells A7 and B8, with the main dominant channel located in the direction of water injection well B8.

[0058] In this invention, in the detection of gas tracers, the final content of the gas tracer is determined by the detected peak value or by taking the average value of the peak value over 5-10 days, wherein the content unit is g / ml.

[0059] In this invention, when a gaseous tracer is detected, the total content of the detected gaseous tracer can be used to determine the connectivity and channel dominance between the oil well and the water well. The higher the detected gaseous tracer content, the better the connectivity and the larger the dominant channel.

[0060] Unless otherwise stated, the terms used herein (including technical terms) have their common meaning as understood by one of ordinary skill in the art. Furthermore, it is understood that terms defined in commonly used dictionaries should be understood to have a meaning consistent with the context of their relevant field, and not to be interpreted as having an idealized or overly formal meaning.

[0061] The examples above are merely illustrative of the present invention and do not constitute a limitation on the scope of protection of the present invention. All designs that are the same as or similar to the present invention fall within the scope of protection of the present invention. Device structures and method steps not described in detail in this invention are prior art and will not be further described in this invention.

Claims

1. A method for identifying the correspondence between multiple oil and water wells in a horizontal well area, characterized in that: The specific steps are as follows: Step 1: Select at least two water injection wells from which the correspondence needs to be verified, and inject a gas slug containing a tracer into the wellhead of each well; wherein, the gas slug is one or a mixture of several of N2, CO2, and deoxygenated air; the amount of tracer added to the gas slug is 0.5~1.5% of the volume of the injected gas slug; the tracer is a fluorinated gas tracer; Step 2: After the gas slug injection is completed, each injection well resumes normal water injection. The normal water injection refers to the geological water injection volume before the test or the actual water injection volume that should be injected. Step 3: Observe the dynamic changes in production of the oil wells around each water injection well. The dynamic changes in production include changes in fluid production, oil production, water cut, dynamic fluid level, gas production, and dynamometer card. Based on the response time and degree of change of the oil wells, qualitatively determine the priority of oil-water well connectivity and the size of the dominant channel. Oil wells whose dynamic changes in production before and after the test exceed ±10% are preliminarily identified as oil wells with dynamic response. Step 4: For the oil wells with dynamic response identified in Step 3, perform fixed-point sampling of the produced gas. Step 5: Analyze the sample taken in Step 4 using tracer analysis to obtain the tracer analysis results; Step Six: Based on the tracer analysis results obtained in Step Five and the dynamic analysis results obtained in Step Three, comprehensively determine the correspondence between oil wells and water injection wells; In the detection of gas tracers, the final content of the gas tracer is determined based on the detected peak value or the average value of the peak value over 5-10 days, where the content unit is g / ml.

2. The method for identifying the correspondence between multiple oil and water wells in a horizontal well area according to claim 1, characterized in that: In step one, different tracers are injected into different injection wells.

3. The method for identifying the correspondence between multiple oil and water wells in a horizontal well area according to claim 1, characterized in that: The fluorinated gas tracers include two or more combinations of difluorochloromethane, difluorodichloromethane, difluorochlorobromomethane, tetrafluoroethane, difluoroethane, difluoromethane, tetrafluorochloroethane, heptafluoropropane, and hexafluoropropane.

Images