Shale gas well high flowback geological risk evaluation method

Abstract

The application discloses a shale gas well high flowback geological risk evaluation method and relates to the technical field of shale gas exploitation. b In the establishing process, the main geological control factors (faults, water saturation, natural fractures and the like) causing the high flowback phenomenon are fully considered, an F b exponent for evaluating the high flowback risk of the shale gas well is established, and the high flowback risk of the gas well is divided into three types, i.e., high risk, medium risk and low risk, according to the flowback rate data of a large number of gas wells in a block which has been put into large-scale production at present. The method is reliable in principle, feasible in calculation and accurate in result, can provide theoretical and technical support for optimizing well site deployment and flowback and production system, is favorable for further improving the production effect of the shale gas well, and has a wide application range and a good application prospect.

Description

Technical Field

[0001] This invention relates to the technical field of shale gas extraction, specifically to a method for assessing the geological risk of high runoff from shale gas wells. Background Technology

[0002] Shale gas, as a new type of unconventional natural gas, is mainly distributed in mudstone and shale in the form of free and adsorbed states. Shale gas reservoirs only have industrial exploitation value when subjected to large-scale volumetric fracturing. Hydraulic fracturing technology has been increasingly widely used as one of the most effective measures to increase production and improve recovery rate.

[0003] During hydraulic fracturing in shale gas reservoirs, a large amount of fracturing fluid is injected into the reservoir, and most of the injected fluid is flowed back during production. Production data from shale gas wells in southern Sichuan show that the flowback rate of wells that have been producing for more than 3 years is mainly between 45% and 65%, but some wells have flowback rates exceeding 60%, a phenomenon defined as high flowback. Statistical analysis of shale gas well production data reveals a negative correlation between production efficiency and flowback rate. Specifically, for the same fracturing scale and production time, high-yield wells generally have lower flowback rates, while wells with high flowback rates generally have poorer production performance. Therefore, conducting pre-fracturing geological risk assessments for shale gas wells and clarifying the high flowback risk level is beneficial for developing targeted measures in advance to prevent high flowback, thereby further improving the performance of individual gas wells and extending their lifespan.

[0004] Shale gas well flowback rates are mainly affected by multiple factors, including geological conditions (such as faults, natural fractures, and water saturation) and construction scale (fracture morphology, fracturing scale, and reservoir stress sensitivity). However, the regional geological conditions before fracturing are the primary controlling factor affecting the flowback rate of shale gas wells. Different geological conditions have varying degrees of impact on the flowback rate of shale gas wells with the same technology and production methods. Currently, there is a lack of effective methods and means to evaluate the geological risk of high flowback in shale gas wells, so as to guide the formulation of corresponding measures to avoid high flowback in gas wells and affect production efficiency. Summary of the Invention

[0005] The purpose of this invention is to address the current lack of effective methods and means for evaluating the geological risk of high flowback in shale gas wells, and to guide the formulation of corresponding measures to avoid the impact of high flowback on production efficiency. This invention provides a method for evaluating the geological risk of high flowback in shale gas wells. Using this method, the high flowback risk level before fracturing can be evaluated based on relevant regional geological parameters. Gas wells can be classified according to the risk level, and rational suggestions can be made for fracturing and drainage processes for different types of gas wells. Furthermore, by formulating targeted measures to address potential high flowback phenomena, the aforementioned problems are solved.

[0006] The technical solution of the present invention is as follows:

[0007] A method for assessing the geological risk of high flowback in shale gas wells, comprising:

[0008] Step S1: Using seismic data, determine the location and displacement of faults within the preset area of ​​the shale gas well to be deployed. Based on the location of the faults, obtain the distance of each fault from the shale gas well and calculate the influence coefficient of the faults on the high backflow phenomenon of the shale gas well to be deployed.

[0009] Step S2: Collect logging data from appraisal wells around the proposed shale gas well, calculate the water saturation of the existing appraisal wells, draw a water saturation contour map, and obtain the water saturation of the proposed shale gas well.

[0010] Step S3: Calculate the influence coefficient of natural fractures on high flowback phenomenon based on the area of ​​the well control zone of the proposed shale gas well, the average length of natural fractures in the well control zone, the average displacement of natural fractures in the well control zone, and the number of natural fracture directions in the well control zone.

[0011] Step S4: Combining the results of steps S1 to S3, calculate and evaluate the F-level of the high flowback risk of the proposed shale gas well. b index;

[0012] Step S5: Calculate F for shale gas wells in areas that have achieved large-scale production. b The index, along with F based on regional gas well flowback rate data. b The indices are categorized to form a high runoff risk assessment table for shale gas wells;

[0013] Step S6: Transfer the F-type shale gas well with a high flowback risk level to the proposed deployment site. b The index was compared with the high flowback risk assessment table for shale gas wells to complete the geological risk assessment of high flowback for the proposed shale gas wells.

[0014] Furthermore, the calculated influence coefficient of the fault on the high flowback phenomenon of the proposed shale gas well includes:

[0015]

[0016] in:

[0017] D-Influence coefficient of fault on high flowback phenomenon of shale gas wells to be deployed;

[0018] h i - The fault displacement of the i-th fault;

[0019] L i - The distance from the i-th fault to the deployed shale gas well;

[0020] n D- The number of faults within the preset area.

[0021] Furthermore, the well control area of ​​the proposed shale gas well includes:

[0022] S = a × b

[0023] in:

[0024] S - Area of ​​the well control zone where the proposed shale gas well is to be deployed;

[0025] a - Length of the horizontal section of the proposed shale gas well;

[0026] b - The well spacing of the proposed shale gas wells.

[0027] Furthermore, the average length of natural fractures within the well-controlled area includes:

[0028]

[0029] in:

[0030] - Average length of natural fractures within the well-controlled area;

[0031] l i -Length of the i-th natural crack;

[0032] n - The number of natural fractures within the well-controlled area.

[0033] Furthermore, the average displacement of natural fractures within the well-controlled area includes:

[0034]

[0035] in:

[0036] - Average displacement of natural fractures within the well-controlled area;

[0037] q i - The displacement of the i-th natural crack.

[0038] Furthermore, the number of natural fracture directions within the well-controlled area includes:

[0039] The distribution map of natural fractures in the well control area of ​​the proposed shale gas well was obtained based on the processing and interpretation of 3D seismic data.

[0040] The number of natural fracture directions (d) within the well-controlled area is obtained from the natural fracture distribution map.

[0041] Furthermore, the calculation of the influence coefficient of natural cracks on the high flowback phenomenon includes:

[0042]

[0043] in:

[0044] P f -Evaluate the influence coefficient of natural cracks on high backflow phenomenon.

[0045] Furthermore, the calculation evaluates the high flowback risk level of the proposed shale gas well deployment using the F... b Indices, including:

[0046] F b =D×S w ×P f

[0047] in:

[0048] F b - An index for evaluating the high flowback risk level of shale gas wells to be deployed;

[0049] S w - The water saturation of the shale gas wells to be deployed.

[0050] Furthermore, the shale gas well high flowback risk assessment table includes:

[0051] When F b When the index is greater than 0.02, the high flowback risk level of shale gas wells is classified as: high risk;

[0052] When F b When the index is between 0.01 and 0.02, the high flowback risk level of shale gas wells is classified as: medium risk;

[0053] When F b When the index is less than 0.01, the high flowback risk level of shale gas wells is classified as: low risk.

[0054] Furthermore, the predetermined area for the proposed deployment of shale gas wells includes:

[0055] The proposed shale gas wells will be deployed within a 2km radius.

[0056] Compared with existing technologies, the advantages of this invention are:

[0057] 1. A geological risk assessment method for high flowback in shale gas wells. During its development, this method fully considers the main geological controlling factors (faults, water saturation, natural fractures, etc.) that cause high flowback phenomena, and establishes an F-value for evaluating the high flowback risk of shale gas wells. bThe index, based on the flowback rate data of a large number of gas wells in currently large-scale production blocks, classifies gas wells into three categories: high risk, medium risk, and low risk. This method is reliable in principle, feasible in calculation, and accurate in results. It can provide theoretical and technical support for optimizing well location deployment and drainage systems, which is conducive to further improving the production efficiency of shale gas wells. At the same time, with the increasing exploration and development of shale gas as a clean energy source, this method not only has a wide range of applications but also has good application prospects. Attached Figure Description

[0058] Figure 1 A flowchart illustrating the steps of a geological risk assessment method for high flowback in shale gas wells;

[0059] Figure 2 This is a fault distribution map of the N1 well area;

[0060] Figure 3 This is a plane contour map of water saturation in the N1 well area;

[0061] Figure 4 This is a schematic diagram of the well-controlled area of ​​well N1;

[0062] Figure 5 This is a map showing the distribution of natural fractures in well N1. Detailed Implementation

[0063] It should be noted that relational terms such as "first" and "second" are used merely to distinguish one entity or operation from another, and do not necessarily require or imply any such actual relationship or order between these entities or operations. Furthermore, the terms "comprising," "including," or any other variations thereof are intended to cover non-exclusive inclusion, such that a process, method, article, or apparatus that comprises a list of elements includes not only those elements but also other elements not expressly listed, or elements inherent to such a process, method, article, or apparatus. Without further limitations, an element defined by the phrase "comprising one..." does not exclude the presence of other identical elements in the process, method, article, or apparatus that includes said element.

[0064] The features and performance of the present invention will be further described in detail below with reference to embodiments.

[0065] Example 1

[0066] Conducting pre-compression geological risk assessments for shale gas wells and clarifying the high runoff risk level of shale gas wells is beneficial for developing targeted measures in advance to prevent high runoff, thereby further improving the performance of individual gas wells and extending their life cycle. However, there is currently a lack of effective methods and means to evaluate the geological risk of high runoff in shale gas wells to guide the development of corresponding measures to avoid high runoff from affecting production performance.

[0067] This embodiment addresses the aforementioned problems by proposing a geological risk assessment method for high flowback in shale gas wells. It fully considers the main geological controlling factors (faults, water saturation, natural fractures, etc.) that cause high flowback phenomena and establishes an F-value for evaluating the high flowback risk of shale gas wells. b The index, along with data on the flowback rates of numerous gas wells in currently high-production blocks, classifies gas wells into those with high flowback risks. This method is reliable in principle, feasible in calculation, and accurate in results. It can provide theoretical and technical support for optimizing well location deployment and drainage systems, and is conducive to further improving the production efficiency of shale gas wells.

[0068] Before proceeding with a detailed description of the steps, the key terms of this patent will be defined.

[0069] Flowback rate: The ratio of the cumulative flowback fluid volume of a shale gas well to the total fracturing fluid volume is the flowback rate.

[0070] High flowback phenomenon: The phenomenon that the flowback rate of shale gas wells exceeds 60% after one year of production is called high flowback phenomenon.

[0071] Please see Figure 1 A geological risk assessment method for high flowback in shale gas wells, based on geological parameters such as fault characteristics, water saturation, and the degree of development of natural fractures, specifically includes the following steps:

[0072] Step S1: Using seismic data, determine the fault locations and displacements within a preset area from the planned shale gas well. Based on the fault locations, obtain the distances from each fault to the shale gas well, and calculate the influence coefficients of the faults on the high flowback phenomenon of the planned shale gas well. Preferably, the preset area is 2 km, i.e., determining the fault locations and displacements within 2 km of the planned shale gas well. The seismic data refers to the fault distribution map obtained through seismic data processing and interpretation.

[0073] Step S2: Collect logging data from appraisal wells around the proposed shale gas well, calculate the water saturation of the existing appraisal wells, draw a water saturation contour map, and obtain the water saturation of the proposed shale gas well.

[0074] Step S3: Calculate the influence coefficient of natural fractures on high flowback phenomenon based on the area of ​​the well control zone of the proposed shale gas well, the average length of natural fractures in the well control zone, the average displacement of natural fractures in the well control zone, and the number of natural fracture directions in the well control zone.

[0075] Step S4: Combining the results of steps S1 to S3, calculate and evaluate the F-level of the high flowback risk of the proposed shale gas well. b index;

[0076] Step S5: Calculate F for shale gas wells in areas that have achieved large-scale production. b The index, along with F based on regional gas well flowback rate data. b The indices are categorized to form a high-flowback risk assessment table for shale gas wells, as shown in Table 1. Preferably, the high-flowback risk assessment table for shale gas wells includes:

[0077] When F b When the index is greater than 0.02, the high flowback risk level of shale gas wells is classified as: high risk;

[0078] When F b When the index is between 0.01 and 0.02, the high flowback risk level of shale gas wells is classified as: medium risk;

[0079] When F b When the index is less than 0.01, the high flowback risk level of shale gas wells is classified as: low risk;

[0080] Table 1. Regional High Return-to-Paste Risk Assessment Table

[0081]

[0082]

[0083] Step S6: Transfer the F-type shale gas well with a high flowback risk level to the proposed deployment site. b The index is compared with the high flowback risk assessment table for shale gas wells to complete the geological risk assessment of high flowback for the proposed shale gas wells; that is, to determine the F level of high flowback risk for the proposed shale gas wells. b The index falls within a certain range to assess the geological risk level of high flowback in the proposed shale gas wells; then, rational suggestions are made for fracturing and drainage processes for different types of gas wells, and targeted measures are developed to address potential high flowback phenomena.

[0084] In this embodiment, specifically, the calculation of the influence coefficient of the fault on the high flowback phenomenon of the shale gas well to be deployed includes:

[0085]

[0086] in:

[0087] D-Fault influence coefficient on high flowback phenomenon of shale gas wells to be deployed, dimensionless;

[0088] h i - The fault displacement of the i-th fault, in km;

[0089] L i - The distance from the i-th fault to the deployed shale gas well, in km;

[0090] n D - The number of faults within the preset area.

[0091] In this embodiment, specifically, the well control area of ​​the proposed shale gas well includes:

[0092] S = a × b

[0093] in:

[0094] S - The well control area of ​​the proposed shale gas well, in km² 2 ;

[0095] a - Length of the horizontal section of the proposed shale gas well, in km;

[0096] b - The distance between the proposed shale gas wells, in km.

[0097] In this embodiment, specifically, based on three-dimensional seismic data, the number of natural fractures n and the lengths l1, l2, ..., l1 of each fracture within the well-controlled area are obtained. n Then, the average length of the natural crack is calculated. The three-dimensional seismic data refers to: a map showing the distribution of naturally formed fractures;

[0098] The average length of natural fractures within the well-controlled area includes:

[0099]

[0100] in:

[0101] - Average length of natural fractures within the well-controlled area, in km;

[0102] l i - Length of the i-th natural fissure, in km;

[0103] n - The number of natural fractures within the well-controlled area.

[0104] In this embodiment, specifically, based on three-dimensional seismic data, the displacement q1, q2, ..., q of each natural fracture within the well-controlled area is obtained. nThen, the average displacement of natural fractures within the well-controlled area is calculated.

[0105] The average displacement of natural fractures within the well-controlled area includes:

[0106]

[0107] in:

[0108] - Average displacement of natural fractures within the well-controlled area, in km;

[0109] q i - The displacement of the i-th natural crack, in km.

[0110] In this embodiment, specifically, the number of natural fracture directions within the well-controlled area includes:

[0111] The distribution map of natural fractures in the well control area of ​​the proposed shale gas well was obtained based on the processing and interpretation of 3D seismic data.

[0112] The number of natural fracture directions (d) within the well-controlled area is obtained from the natural fracture distribution map.

[0113] In this embodiment, specifically, calculating the influence coefficient of natural cracks on the high flowback phenomenon includes:

[0114]

[0115] in:

[0116] P f -Evaluate the influence coefficient of natural cracks on high backflow phenomenon.

[0117] In this embodiment, specifically, the calculation of F, which evaluates the high flowback risk level of the proposed shale gas well, is... b Indices, including:

[0118] F b =D×S w ×P f

[0119] in:

[0120] F b - An index for evaluating the high flowback risk level of shale gas wells to be deployed;

[0121] S w - The water saturation of the shale gas wells to be deployed.

[0122] Example 2

[0123] Example 2 uses Well N1 as the proposed shale gas well and further explains Example 1. Components that are identical will not be described again here; please refer to [link / reference]. Figure 1-5 .

[0124] (1) Using seismic data, determine the location and displacement h of each fault within a 2km radius of well N1, and obtain the distance L from each fault to well N1 based on the fault location; such as Figure 2 As shown, Figure 2 This is a fault distribution map of the N1 well area.

[0125] (2) Calculate the influence coefficient D of the fault on the high backflow phenomenon in well N1.

[0126]

[0127] (3) Collect logging data from appraisal wells surrounding Well N1, compile statistics on water saturation of appraised wells, and draw water saturation contour maps (e.g., ...). Figure 3 As shown), the water saturation S of well N1 was further obtained. w =40% = 0.4;

[0128] (4) Calculate the area S of the well control zone of well N1. Figure 4 (Schematic diagram of the controlled area of ​​well N1);

[0129] S = a × b = 1.8 × 0.3 = 0.54 km 2

[0130] (5) Based on the three-dimensional seismic data, obtain the number of natural fractures n and the lengths l1, l2, ..., l within the well-controlled area of ​​well N1. n ( Figure 5 (This is a map showing the distribution of natural fractures in well N1), and the average length of the natural fractures is then calculated.

[0131]

[0132] (6) Similarly, using three-dimensional seismic data, the displacements q1, q2, ..., q of each natural fracture within the well-controlled area of ​​well N1 were obtained. n ( Figure 5 (See the natural fracture distribution map for well N1). Calculate the average displacement of the natural fractures.

[0133]

[0134] (7) Natural fracture distribution map obtained by processing and interpreting three-dimensional seismic data. Figure 5 (See the distribution map of natural fractures in well H1). Obtain the number of fracture directions d=2 within the well-controlled area of ​​well N1.

[0135] (8) Based on the relevant data obtained in (4) to (7), calculate the influence coefficient P of natural cracks on the high backflow phenomenon. f ;

[0136]

[0137] (9) Based on the combined analysis results of (2), (3), and (8), calculate the F-value for evaluating the high backflow risk level of well H1. b index;

[0138]

[0139] (10) Based on the calculated F of well N1 b The index, referring to Table 1, is used to evaluate the high flowback risk of this well, N1 well F b With an index of 0.025, it was rated as a high-risk well with high runoff.

[0140] Well N1 is currently in production, and the project is progressing normally. As of June 1, 2022, the well had been producing for 966 days with a flowback rate of 79.34%, confirming it as a high flowback well. This is consistent with the results verified by this method, proving that the method is accurate and reliable.

[0141] The embodiments described above merely illustrate specific implementation methods of this application, and while the descriptions are detailed and specific, they should not be construed as limiting the scope of protection of this application. It should be noted that those skilled in the art can make various modifications and improvements without departing from the concept of the technical solution of this application, and these modifications and improvements all fall within the scope of protection of this application.

Claims

1. A method for assessing the geological risk of high flowback in shale gas wells, characterized in that, include: Step S1: Using seismic data, determine the location and displacement of faults within the preset area of ​​the shale gas well to be deployed. Based on the location of the faults, obtain the distance of each fault from the shale gas well and calculate the influence coefficient of the faults on the high backflow phenomenon of the shale gas well to be deployed. Step S2: Collect logging data from appraisal wells around the proposed shale gas well, calculate the water saturation of the existing appraisal wells, draw a water saturation contour map, and obtain the water saturation of the proposed shale gas well. Step S3: Calculate the influence coefficient of natural fractures on high flowback phenomenon based on the area of ​​the well control zone of the proposed shale gas well, the average length of natural fractures in the well control zone, the average displacement of natural fractures in the well control zone, and the number of natural fracture directions in the well control zone. Step S4: Combining the results of steps S1 to S3, calculate and evaluate the high flowback risk level of the proposed shale gas wells. index; Step S5: Calculate the shale gas wells in areas where production has already reached a certain scale. The index, along with data on gas well flowback rates within the region, is used to... The indices are categorized to form a high runoff risk assessment table for shale gas wells; Step S6: Identify shale gas wells with a high risk of flowback. The index was compared with the high flowback risk assessment table for shale gas wells to complete the geological risk assessment of high flowback for the proposed shale gas wells. The calculated influence coefficient of faults on the high flowback phenomenon of the proposed shale gas wells includes: in: D -Influence coefficient of fault on high flowback phenomenon of shale gas wells to be deployed; -No. i The fault displacement of the strip fault; -No. i The distance between the fault and the deployed shale gas well; - The number of faults within the preset area.

2. The geological risk assessment method for high flowback in shale gas wells according to claim 1, characterized in that, The well control area of ​​the proposed shale gas well includes: in: -The area of ​​the well control zone where the proposed shale gas wells will be deployed; - Length of the horizontal section of the proposed shale gas well; - The well spacing of the proposed shale gas wells.

3. The geological risk assessment method for high flowback in shale gas wells according to claim 2, characterized in that, The average length of natural fractures within the well-controlled area includes: in: - Average length of natural fractures within the well-controlled area; -No. i Length of the natural crack; n - The number of natural fractures within the well-controlled area.

4. The geological risk assessment method for high flowback in shale gas wells according to claim 3, characterized in that, The average displacement of natural fractures within the well-controlled area includes: in: - Average displacement of natural fractures within the well-controlled area; -No. i The displacement of a natural crack.

5. The geological risk assessment method for high flowback in shale gas wells according to claim 4, characterized in that, The number of natural fracture directions within the well-controlled area includes: The distribution map of natural fractures in the well control area of ​​the proposed shale gas well was obtained based on the processing and interpretation of 3D seismic data. The number of natural fracture directions within the well-controlled area is obtained from the natural fracture distribution map. .

6. The geological risk assessment method for high flowback in shale gas wells according to claim 5, characterized in that, The calculation of the influence coefficient of natural fractures on high flowback phenomenon includes: in: -Evaluate the influence coefficient of natural cracks on high backflow phenomenon.

7. The geological risk assessment method for high flowback in shale gas wells according to claim 6, characterized in that, The calculation evaluates the high flowback risk level of the proposed shale gas wells. Indices, including: in: - An index for evaluating the high flowback risk level of shale gas wells to be deployed; - The water saturation of the shale gas wells to be deployed.

8. The geological risk assessment method for high flowback in shale gas wells according to claim 1, characterized in that, The shale gas well high flowback risk assessment table includes: when When the index is greater than 0.02, the high flowback risk level of shale gas wells is classified as: high risk; when When the index is between 0.01 and 0.02, the high flowback risk level of shale gas wells is classified as: medium risk; when When the index is less than 0.01, the high flowback risk level of shale gas wells is classified as: low risk.

9. The geological risk assessment method for high flowback in shale gas wells according to claim 1, characterized in that, The pre-defined area for the proposed deployment of shale gas wells includes: The proposed shale gas wells will be deployed within a 2km radius.

Images