A method of dynamic drilling and completion of horizontal wells

Abstract

The application provides a horizontal well dynamic drilling and completion method and relates to the technical field of unconventional oil and gas stimulation and reconstruction, and the horizontal well dynamic drilling and completion method at least comprises the following steps: S1, real-time monitoring of while-drilling gamma data and logging cutting data, and control of a drilling trajectory in an optimal layer position according to the while-drilling gamma data and the logging cutting data; S2, real-time monitoring of drilling trajectory data, and determination of a limit horizontal section length of horizontal well drilling according to the drilling trajectory data; and S3, determination of an optimal fracturing position according to the while-drilling gamma data and the logging cutting data. The horizontal well dynamic drilling and completion method can realize differential drilling, completion and fracturing design, and fully tap the production of a gas well.

Description

Technical Field

[0001] This invention relates to the field of unconventional oil and gas production enhancement and stimulation technology, and in particular to a dynamic drilling and completion method for ultra-long horizontal wells in shale gas. Background Technology

[0002] Horizontal well fracturing technology is a crucial core method for enhancing shale gas reservoir production. With the increasing urgency to extract resources from shale gas reservoirs, field practices have adopted methods such as increasing the length of horizontal sections to expand the scope of single-well stimulation and thus increase gas well production. Simultaneously, by reducing drilling in vertical sections, costs are significantly reduced.

[0003] A horizontal well with a horizontal section length exceeding 1800m can be defined as an ultra-long horizontal well. Currently, domestic ultra-long horizontal wells generally have horizontal section lengths of 2000-2500m. However, in practice, fracturing ultra-long horizontal sections in gas wells does not necessarily result in better production enhancement, especially since most of the fracturing sections do not produce gas. This is related to insufficient dynamic analysis during drilling and completion. The increased length of the horizontal section brings more and more complex challenges compared to conventional horizontal sections. Due to the increased length, the drilling guidance difficulty of horizontal wells increases, necessitating effective guidance methods to determine the drilling location most conducive to fracturing. The increased length also increases wellbore friction, making gas-liquid two-phase flow more difficult, and the well trajectory morphology has a crucial impact on gas well production. Furthermore, the increased length leads to significant variations in geological parameters, large formation dip angles, and large geomechanical differences, potentially requiring the horizontal section to be broken down and designed with differentiated main parameters for effective development. However, currently, no comprehensive technology or methodology has been developed, either domestically or internationally, to address these issues.

[0004] In view of this, based on years of experience in production and design in this and related fields, the inventor has designed a dynamic drilling and completion method for horizontal wells through repeated experiments, in order to solve the problems existing in the prior art. Summary of the Invention

[0005] The purpose of this invention is to provide a dynamic drilling and completion method for horizontal wells, which can realize differentiated drilling, completion and fracturing designs to fully tap the production of gas wells.

[0006] To achieve the above objectives, this invention proposes a dynamic drilling and completion method for horizontal wells, wherein the dynamic drilling and completion method for horizontal wells includes at least:

[0007] Step S1: Monitor the drilling gamma data and logging cuttings data in real time, and control the drilling trajectory within the optimal formation based on the drilling gamma data and logging cuttings data;

[0008] Step S2: Monitor drilling trajectory data in real time, and determine the maximum horizontal section length of the horizontal well based on the drilling trajectory data;

[0009] Step S3: Determine the optimal fracturing location based on the drilling gamma data and the logging cuttings data.

[0010] Compared with the prior art, the present invention has the following features and advantages:

[0011] The dynamic drilling and completion method for horizontal wells proposed in this invention effectively improves the drilling and completion efficiency of long horizontal wells, enables gas wells to encounter the most favorable fracturing zones, explores the limit length of gas wells, enables gas wells to undergo differentiated fracturing and transformation, and allows for real-time adjustments to enhance the gas production capacity of gas wells. Attached Figure Description

[0012] The accompanying drawings described herein are for illustrative purposes only and are not intended to limit the scope of the invention in any way. Furthermore, the shapes and proportions of the components in the drawings are merely illustrative to aid in understanding the invention and do not specifically limit the shapes and proportions of the components. Those skilled in the art, guided by the teachings of this invention, can select various possible shapes and proportions to implement the invention according to specific circumstances.

[0013] Figure 1 This is a flowchart of the dynamic drilling and completion method for horizontal wells proposed in this invention;

[0014] Figure 2 This is a diagram showing the positional relationship between a horizontal well and an already exploited well in one embodiment of the present invention;

[0015] Figure 3 This is the post-production logging evaluation result of a horizontal well in one embodiment of the present invention. Detailed Implementation

[0016] The details of the present invention can be more clearly understood by referring to the accompanying drawings and the description of specific embodiments. However, the specific embodiments of the present invention described herein are for illustrative purposes only and should not be construed as limiting the invention in any way. Under the teachings of this invention, those skilled in the art can conceive of any possible modifications based on the invention, and these should all be considered to fall within the scope of the invention.

[0017] like Figure 1 As shown, this invention proposes a dynamic drilling and completion method for horizontal wells, which includes at least the following:

[0018] Step S1: Monitor the gamma-ray data and cuttings data while drilling in real time, and control the drilling trajectory within the optimal formation based on the gamma-ray data and cuttings data while drilling;

[0019] Step S2: Monitor drilling trajectory data in real time and determine the maximum horizontal section length of the horizontal well based on the drilling trajectory data;

[0020] Step S3: Determine the optimal fracturing location based on the drilling gamma data and logging cuttings data.

[0021] The dynamic drilling and completion method for horizontal wells proposed in this invention improves the engineering technology of long horizontal gas wells, realizes differentiated drilling, completion and fracturing designs, and fully taps the production capacity of gas wells.

[0022] The dynamic drilling and completion method for horizontal wells proposed in this invention effectively improves the drilling and completion efficiency of long horizontal wells, enables gas wells to encounter the most favorable fracturing zones, explores the limit length of gas wells, enables gas wells to undergo differentiated fracturing and transformation, and allows for real-time adjustments to enhance the gas production capacity of gas wells.

[0023] This invention presents a dynamic drilling and completion method for horizontal wells, offering a new approach to enhancing shale gas reservoir production under complex geological and structural conditions. It particularly addresses challenges encountered during the drilling and completion of long horizontal gas wells in the current environment of cost reduction and efficiency improvement, such as significant elevation differences in the horizontal section, high wellbore friction, unclear drilling guidance, low encounter rates with favorable formations, and unsatisfactory fracturing results due to the lack of modularity in fracturing parameters. This invention addresses these shortcomings and compensates for deficiencies in the drilling and completion processes of long horizontal gas wells both domestically and internationally. Furthermore, this invention enables the construction of a dynamic approach to the entire drilling and completion process, allowing for mutual interaction between the defined optimal fracturing layers, fracturing locations, and fracturing intervals, achieving an integrated model.

[0024] In an optional embodiment of the present invention, step S1 includes:

[0025] Step S1a: Monitor the gamma data while drilling. Read the gamma value once every fixed drilling distance and adjust the drilling trajectory up or down in a timely manner to keep the gamma value within the first control range.

[0026] Step S1b: Monitor the logging cuttings data. Read the logging cuttings data once every fixed drilling distance. The logging cuttings data includes the silica mineral content fraction and the carbonate mineral content fraction. Adjust the drilling trajectory up or down in a timely manner to keep the silica mineral content fraction within the second control range and the carbonate mineral content fraction within the third control range.

[0027] In one optional example of this implementation, the fixed distance is 0.125m, the first control range is 150 to 400 API, the second control range is 40% to 60%, and the third control range is 0 to 20%.

[0028] In an optional example of this implementation, in step S1, if the real-time reading of the drilling gamma value is between 300 and 400 API and the carbonate mineral content is consistently greater than 15%, the drilling trajectory is controlled to keep the gamma value between 300 and 400 API.

[0029] In one optional example of this implementation, if the silica mineral content is greater than 60%, the drilling trajectory is controlled to bring the gamma value close to the 400 API region; otherwise, no restriction is imposed.

[0030] In an optional example, in step S1, if the real-time reading of the gamma value is between 300 and 400 API and the carbonate mineral content remains less than 15%, the drilling trajectory is controlled to reduce the gamma value to between 150 and 300 API.

[0031] In an optional example, in step S1, if the real-time gamma value is between 150 and 300 API, the drilling trajectory is controlled to ensure that the carbonate mineral content is not less than 10% and the silica mineral content is not less than 50%.

[0032] In step S1, real-time monitoring of gamma-ray data and cuttings data during drilling ensures that drilling occurs within the optimal formation:

[0033] Monitor the gamma data while drilling, and read a value every 0.125m of drilling. The gamma data should be controlled within 150 to 400 API. If the gamma value is lower than 150 API or higher than 400 API, the drilling trajectory should be raised or lowered to the control range in a timely manner.

[0034] Monitor the cuttings data during drilling, taking one value every 0.125m. The silica mineral content should be controlled within 40% to 60%, and the carbonate mineral content should be controlled within 0% to 20%. If the silica mineral content is below 40% or above 60%, or if the carbonate mineral content is above 20%, the drilling trajectory should be raised or lowered to the control range in a timely manner.

[0035] When the real-time gamma value is between 300 and 400 API, and the carbonate mineral content is consistently greater than 15%, it indicates that the well is located in a high-resource-rich, high-brittleness, and high-stress area within the well control zone. Therefore, the drilling zone should be controlled between 300 and 400 API. Furthermore, if the silica mineral content is greater than 60% at this time, the drilling zone should be further controlled to be in an area with a gamma value close to 400 API; otherwise, no restrictions are imposed.

[0036] When the real-time gamma value is between 300 and 400 API, and the carbonate mineral content is intermittently greater than 15% or continuously less than 15%, it indicates that the well is located in a high-resource-abundance, medium-to-high-brittleness, and medium-to-high-stress area within the well-controlled zone. Therefore, the drilling zone should be controlled to have a gamma value between 150 and 300 API. When the real-time gamma value is between 150 and 300 API, the sum of the silica mineral content and the carbonate mineral content should be kept relatively high, ensuring that the carbonate mineral content is not less than 10% and the silica mineral content is not less than 50%.

[0037] Using the above parameters as limits, ensure that drilling is carried out within the optimal stratum.

[0038] In an optional embodiment of the present invention, in step S2, the drilling trajectory data includes the test depth, vertical depth and inclination of the horizontal well drilling.

[0039] In one optional example, the test depth is the length of the horizontal wellbore from the wellhead to each drilling depth, the vertical depth is the vertical length of the horizontal wellbore from the wellhead to each drilling depth, and the inclination is the ratio of the difference in vertical depth between the horizontal section's entry point and a certain drilling position to the difference in test depth.

[0040] In an optional example of this implementation, step S2 includes:

[0041] Step S2a: Record the horizontal entry point of the target as point A, and the test depth and vertical depth of point A as x0 and y0, respectively. The position corresponding to the i-th drilling point is recorded as Bi, and the test depth and vertical depth of point Bi are recorded as xi and yi, respectively. The inclination can be recorded as follows:

[0042]

[0043] In the formula,

[0044] Dev – Inclination at the end of the drilled horizontal section, dimensionless;

[0045] Step S2b: While ensuring the drilling location is within the specified stratum, record the inclination of the drilled horizontal section in real time. When drilling reaches the i-th location, the average inclination of the drilled horizontal section is recorded as follows:

[0046]

[0047] In the formula,

[0048] Devaverage – Average inclination of drilled horizontal sections, dimensionless;

[0049] Step S2c, establish the relationship between the inclination and the length of the limit horizontal segment as follows:

[0050]

[0051] In the formula,

[0052] L – Length of the ultimate horizontal section of a single well, in meters.

[0053] In an optional embodiment of the present invention, step S3 includes:

[0054] Step S3a: Read the gamma-ray data and cuttings data of each data point in the horizontal well, and classify each data point according to the read gamma-ray data and cuttings data.

[0055] Step S3b: Based on the classification of each data point, determine the optimal fracturing location and divide the horizontal section of the horizontal well into fracturing zones.

[0056] In an optional example of this implementation, in step S3a, when the gamma value at the data point is between 300 and 400 API, the carbonate mineral content fraction is consistently greater than 15%, indicating that the formation where the data point is located is a high-resource-abundance, high-brittleness, and high-stress area within the well-controlled region.

[0057] In another optional example of this implementation, in step S3a, when the carbonate mineral content of the data point is between 15% and 20% and the gamma value is between 350 and 400 API, the data point is defined as a Class I fracturing location.

[0058] When the carbonate mineral content of the data point is between 15% and 20% and the gamma value is between 300 and 350 API, the data point is defined as a Class II fracturing location.

[0059] When the carbonate mineral content of the data point is greater than 20% or less than 15% and the gamma value is between 350 and 400 API, the data point is defined as a Class III fracturing location.

[0060] When the carbonate mineral content of the data point is greater than 20% or less than 15% and the gamma value is between 300 and 350 API, the data point is defined as a Class IV fracturing location.

[0061] In an optional example of this implementation, in step S3a, when the gamma value of the data point is between 300 and 400 API, the carbonate mineral content fraction is intermittently greater than 15% or continuously less than 15%, indicating that the formation where the data point is located is a high resource abundance, medium-high brittleness, and medium-high stress area within the well-controlled area.

[0062] In an optional example of this implementation, in step 3a, when the sum of the carbonate mineral content fraction and the silica mineral content fraction of the data point is greater than 60% and the gamma value is between 150 and 200 API, the data point is defined as a Class I fracturing location.

[0063] When the sum of the carbonate mineral content fraction and the silica mineral content fraction of the data point is greater than 60% and the gamma value is between 200 and 300 API, the data point is defined as a Class II fracturing location.

[0064] When the sum of the carbonate mineral content fraction and the silica mineral content fraction of the data point is between 40% and 60%, and the gamma value is between 150 and 200 API, the data point is defined as a Class III fracturing location.

[0065] When the sum of the carbonate mineral content fraction and the silica mineral content fraction of the data point is between 40% and 60%, and the gamma value is between 200 and 300 API, the data point is defined as a Class IV fracturing location.

[0066] In one optional example of this implementation, the Type I fracturing location is the optimal fracturing location.

[0067] In an optional example of this implementation, in step S3a, the gamma value, silica mineral content fraction, and carbonate mineral content fraction are read every 0.125m.

[0068] In an optional example of this implementation, in step S3b,

[0069] Starting from the first Type I fracturing location, a continuous segment with at least 480 data points that are all Type I fracturing locations is taken as the first optimal fracturing interval, with no upper limit on the number of data points;

[0070] Starting from the first Type II fracturing location read, a continuous segment with at least 480 data points that are all Type II fracturing locations is taken as the first Type II fracturing interval, with no upper limit on the number of data points;

[0071] Starting from the first Type III fracturing location read, a continuous segment consisting of at least 480 data points all being Type III fracturing locations is designated as the first Type III fracturing interval. There is no upper limit to the number of data points.

[0072] Starting from the first Class IV fracturing location read, a continuous segment with at least 480 data points that are all Class IV fracturing locations is taken as the first Class IV fracturing interval, with no upper limit on the number of data points.

[0073] In an optional example, when there are more than 480 data points, a data point group is allowed to contain 5% of data points that do not meet the criteria for that type of fracturing location. When the number of data points that do not meet the criteria exceeds 5%, the group proceeds to the next fracturing zone division.

[0074] In an optional example, if none of the above conditions are met after reading 480 data points, the number of fracturing locations of types I, II, III, and IV is counted among the 480 data points. The one with the most data points is selected as the fracturing interval type within the 40m, and then the next fracturing interval is divided.

[0075] If, within 480 data points, the largest proportion of invalid fracturing sections are those where the horizontal drilling location does not meet the above requirements due to geological structure or other reasons, then these sections are considered invalid fracturing sections and proceed to the next fracturing interval division.

[0076] In step S3, collect and organize the gamma-ray data while drilling and the cuttings data to determine the optimal fracturing location:

[0077] When the real-time gamma value is between 300 and 400 API, the carbonate mineral content is consistently greater than 15%, indicating that the layer in which the well is located is a high-resource-rich, high-brittle, and high-stress area within the well-controlled zone.

[0078] When the carbonate mineral content at a certain depth is between 15% and 20% and the gamma value is between 350 and 400 API, this point is defined as an optimal Class I fracturing location; when the carbonate mineral content at a certain depth is between 15% and 20% and the gamma value is between 300 and 350 API, this point is defined as a Class II fracturing location; when the carbonate mineral content at a certain depth is greater than 20% or less than 15% and the gamma value is between 350 and 400 API, this point is defined as a Class III fracturing location; when the carbonate mineral content at a certain depth is greater than 20% or less than 15% and the gamma value is between 300 and 350 API, this point is defined as a Class IV fracturing location. If the location of the horizontal drilling section does not meet the above requirements due to geological structure or other reasons, this horizontal section is considered an invalid fracturing section, and fracturing operations will not be carried out in subsequent fracturing processes.

[0079] When the real-time gamma value is between 300 and 400 API, and the carbonate mineral content is intermittently greater than 15% or continuously less than 15%, it indicates that the well is located in a layer with high resource abundance, medium to high brittleness, and medium to high stress within the well-controlled area.

[0080] When the sum of the carbonate and silica mineral content at a certain depth is greater than 60% and the gamma value is between 150 and 200 API, this point is defined as an optimal Class I fracturing location; when the sum is greater than 60% and the gamma value is between 200 and 300 API, this point is defined as a Class II fracturing location; when the sum is between 40% and 60% and the gamma value is between 150 and 200 API, this point is defined as a Class III fracturing location; and when the sum is between 40% and 60% and the gamma value is between 200 and 300 API, this point is defined as a Class IV fracturing location. If the location of the horizontal drilling section does not meet the above requirements due to geological structure or other reasons, this horizontal section is considered an invalid fracturing section and will not be fracturing in subsequent fracturing operations.

[0081] The horizontal section is divided into fracturing zones. According to the aforementioned claims, gamma ray, silica mineral content, and carbonate mineral content are read every 0.125m. Referring to the current minimum length of approximately 60m for a single fracturing section in a horizontal well, a minimum of 480 data points is set.

[0082] Starting with the first Type I fracturing location, a continuous segment containing at least 480 data points that are all Type I fracturing locations is designated as the first optimal fracturing interval, with no upper limit on the number of data points. When the number of data points exceeds 480, a data point group is allowed to contain 5% of data points that do not meet the criteria for a Type I fracturing location. Once the number of data points that do not meet the criteria exceeds 5%, the next fracturing interval is defined.

[0083] Starting with the first Type II fracturing location read, a continuous segment containing at least 480 data points that are all Type II fracturing locations is designated as the first Type II fracturing interval, with no upper limit on the number of data points. When the number of data points exceeds 480, a data point group is allowed to contain 5% of data points that do not meet the criteria for a Type II fracturing location. Once the number of data points that do not meet the criteria exceeds 5%, the next fracturing interval is defined.

[0084] Starting with the first Type III fracturing location read, a continuous segment containing at least 480 data points that are all Type III fracturing locations is designated as the first Type III fracturing interval, with no upper limit on the number of data points. When the number of data points exceeds 480, a data point group is allowed to contain 5% of data points that do not meet the criteria for a Type III fracturing location. Once the number of data points that do not meet the criteria exceeds 5%, the next fracturing interval division begins.

[0085] Starting with the first Type IV fracturing location read, a continuous segment containing at least 480 data points that are all Type IV fracturing locations is designated as the first Type IV fracturing interval, with no upper limit on the number of data points. When the number of data points exceeds 480, a data point group is allowed to contain 5% of data points that do not meet the criteria for a Type IV fracturing location. Once the number of data points that do not meet the criteria exceeds 5%, the next fracturing interval is defined.

[0086] If none of the above conditions are met after reading 480 data points, the number of fracturing locations of types I, II, III, and IV is counted among the 480 data points. The one with the highest number is selected as the fracturing interval type within that 40m, and then the next fracturing interval is divided. If, within the 480 data points, the largest proportion of invalid fracturing intervals are those where the horizontal drilling location does not meet the above requirements due to geological structures or other reasons, then these are considered invalid fracturing intervals and proceed to the next fracturing interval division.

[0087] In an optional embodiment of the present invention, the horizontal well dynamic completion method further includes:

[0088] Step S4: Collect basic logging data, obtain the original geostress value, divide the horizontal section into multiple parts according to the change of geostress value, and formulate a fracturing parameter design scheme for each part.

[0089] In an optional example of this implementation, step S4 includes:

[0090] Step S4a: Collect basic logging data with a fixed distance as the value step size;

[0091] Step S4b: Obtain the original ground stress value, calculate the change in ground stress value, and then divide the horizontal segment into multiple parts based on the change in ground stress value;

[0092] Step S4c: Develop fracturing parameter design schemes for each part of the horizontal section.

[0093] In an optional example, in step S4a, the basic logging data includes P-wave logging data and density logging data from a single well.

[0094] In an optional example, step S4b includes:

[0095] Obtain Poisson's ratio data:

[0096] ν i = -0.0002AC i 2 +0.0196AC i -0.1251 (4)

[0097] In the formula,

[0098] ACi — the sound wave at each recording point, us / ft;

[0099] νi — Poisson's ratio for each recording point, dimensionless;

[0100] Calculate vertical stress:

[0101]

[0102] In the formula,

[0103] Svi — Vertical stress corresponding to each recording point, in MPa;

[0104] ρoverburden—average density of the overlying rock strata, taken as 2.56 g / cm³;

[0105] ρi — Shale logging density corresponding to each recording point, g / cm3;

[0106] Calculate the maximum and minimum horizontal principal stresses:

[0107] In the formula,

[0108] Syi — the maximum horizontal principal stress corresponding to each recording point, in MPa;

[0109] Sxi — Minimum horizontal principal stress at each recording point, in MPa;

[0110] Calculate the horizontal stress difference:

[0111]

[0112] In the formula,

[0113] Sy i —The maximum horizontal principal stress corresponding to each recording point, in MPa;

[0114] Sx i —Minimum horizontal principal stress corresponding to each recording point, MPa.

[0115] Calculate the horizontal stress difference:

[0116] Sxy i =Sy i -Sx i (7)

[0117] In the formula,

[0118] Sxyi — The difference in horizontal ground stress corresponding to each recording point, in MPa.

[0119] In an optional example, the entry point of the horizontal segment is recorded as point A, and the end point of the horizontal segment is recorded as point B. In step S4b,

[0120] Starting from point A, record the stress difference Sxy0 at point A until a stress difference Sxyi at point M is higher or lower than that at point A by 1.5 MPa. Then divide the area from point A to point M into one part. Starting from point M, continue until the next point N appears. If the stress difference between the two points is 1.5 MPa, divide the area from point M to point N into another part.

[0121] In an optional example, in step S4b,

[0122] When the difference between the maximum and minimum ground stress at points A and B in the entire horizontal segment exceeds 4.5 MPa, the horizontal segment is divided into 3 parts based on 1 / 3 of the actual maximum difference.

[0123] If the difference between the maximum and minimum ground stress at points A and B in the entire horizontal segment is less than 1.5 MPa, then the horizontal segment is divided into two parts by equal proportions in the middle.

[0124] In step S4, basic logging data is collected to obtain the original geostress value. Based on the change in geostress value, the ultra-long horizontal section is divided into multiple parts, and different fracturing parameter design schemes are formulated for each part.

[0125] Collect basic logging data, including single-well P-wave logging data (AC) and density logging data (DEN), with a step size of 0.125m, corresponding to the gamma, mineral content fraction, and vertical depth sounding data in the above claims.

[0126] Obtain the original ground stress value, and divide the ultra-long horizontal segment into multiple parts based on the changes in ground stress value, including the following steps:

[0127] Obtain Poisson's ratio data:

[0128] ν i = -0.0002AC i 2 +0.0196AC i -0.1251 (4)

[0129] In the formula,

[0130] ACi – the sound wave at each recording point, us / ft.

[0131] νi — Poisson's ratio for each recording point, dimensionless.

[0132] Calculate vertical stress:

[0133]

[0134] In the formula,

[0135] Svi — Vertical stress corresponding to each recording point, in MPa;

[0136] ρoverburden—average density of the overlying rock strata, taken as 2.56 g / cm³;

[0137] ρi — Shale logging density corresponding to each recording point, g / cm3.

[0138] Calculate the maximum and minimum horizontal principal stresses:

[0139]

[0140] In the formula,

[0141] Syi — the maximum horizontal principal stress corresponding to each recording point, in MPa;

[0142] Sxi — the minimum horizontal principal stress corresponding to each recording point, in MPa.

[0143] Calculate the horizontal stress difference:

[0144] Sxy i =Sy i -Sx i (7)

[0145] In the formula,

[0146] S xyi —Horizontal stress difference corresponding to each recording point, MPa.

[0147] The difference in in-situ stress will affect the design of fracturing parameters. Generally, in an upward-inclined well, the in-situ stress difference gradually decreases from point A to the end point B, while in a downward-inclined well, the in-situ stress difference gradually increases from point A to the end point B. Starting from the target point A, record the in-situ stress difference value Sxy0 at point A until a point M has an in-situ stress difference value Sxyi that is higher or lower than that at point A by 1.5 MPa. Then, divide the area from A to that point into a segment. Starting from M, continue until the next point N has an in-situ stress difference of 1.5 MPa, and then divide it into another segment. In principle, a horizontal well should not be divided into more than three segments.

[0148] When the difference between the maximum and minimum geostress at point A and point B at the end of the horizontal section of the entire horizontal well exceeds 4.5 MPa, i.e., three 1.5 MPa, it is divided into three parts based on one-third of the actual maximum difference.

[0149] If the difference between the maximum and minimum geostress at point A and point B at the end of the horizontal well is less than 1.5 MPa, then the horizontal section of the horizontal well is divided into two equal parts from the middle.

[0150] Different fracturing parameter design schemes were developed for each part of the horizontal section:

[0151] Each section of the design is 60m long, and the fluid strength used in a single well is 30m. 3 / m, single-well sand addition intensity 3t / m, single-section perforation number 48 holes, when the horizontal section is divided into three parts, let the nodes of the three parts be AM, MN, and NB respectively. For the AM part, each section uses 6 clusters, the cluster spacing is 10m, and the discharge rate is 16m³ / s. 3 Construction operations are carried out at a rate of / min; for section MN, 8 clusters are used per segment, with a cluster spacing of 7.5m and a discharge rate of 15m. 3 Construction operations are carried out at a rate of / min; for the NB section, 11 clusters are used per segment, with a cluster spacing of 5.5m and a discharge rate of 14m³ / min. 3 Construction operations can be carried out at a rate of / min. For fracturing sections corresponding to Class I fracturing locations, the fluid strength can be increased to 35m. 3 / m, increase sand strength to 4t / m or above for high-strength modification; for fracturing sections corresponding to Class II fracturing locations, the fluid strength can be increased to 35m. 3 For fracturing sections at Class III fracturing locations, the sand strength can be increased to 3-3.5 t / m or above for high-strength modification; for fracturing sections at Class IV fracturing locations, the original design parameters should be maintained.

[0152] Each section of the design is 60m long, and the fluid strength used in a single well is 30m. 3 / m, single-well sand addition intensity 3t / m, single-section perforation number 48 holes, when the horizontal section is divided into two parts, let the nodes of the two parts be AD and DB respectively. For the AD part, each section uses 6 clusters, the cluster spacing is 10m, and the discharge rate is 15-16m³ / s. 3 Construction operations are carried out at a rate of / min; for the DB section, 8 clusters are used per section, with a cluster spacing of 7.5m and a discharge rate of 13-14m³ / min. 3 Construction operations are carried out at a rate of / min. If there are long-producing gas wells near the horizontal section, to avoid excessive hydraulic fractures during fracturing that could cause pressure channeling with adjacent gas wells, the AD section uses 8 clusters per section, with a cluster spacing of 7.5m and a displacement of 15-16m³ / min. 3 Construction operations are carried out at a rate of / min; for the DB section, 11 clusters are used per segment, with a cluster spacing of 5.5m and a discharge rate of 13-14m³ / min. 3 Construction operations can be carried out at a rate of / min. For fracturing sections corresponding to Class I fracturing locations, the fluid strength can be increased to 35m. 3 / m, increase sand strength to 4t / m or above for high-strength modification; for fracturing sections corresponding to Class II fracturing locations, the fluid strength can be increased to 35m. 3For fracturing sections at Class III fracturing locations, the sand strength can be increased to 3-3.5 t / m or above for high-strength modification; for fracturing sections at Class IV fracturing locations, the original design parameters should be maintained.

[0153] In an optional embodiment of the present invention, the horizontal well dynamic completion method further includes step S5, collecting single-stage fracturing construction parameters, obtaining the actual geostress value of the subsequent fracturing stage, and optimizing the fracturing parameters to ensure the best stimulation effect.

[0154] In an optional example of this implementation, step S5 includes:

[0155] Step 5a: Collect single-stage fracturing construction parameters, including the average construction pressure P, orifice friction Pp, wellbore friction Pw, hydrostatic pressure Pf, construction displacement q, average minimum horizontal principal stress Psx, and average Poisson's ratio v for a single stage.

[0156] Step 5b: Obtain the actual in-situ stress value of the subsequent fracturing section:

[0157] Read the average construction pressure, which is the average pressure from the time the pump is started to the time the pump is stopped;

[0158] Obtain the perforation friction, displacement 8m 3 / min or less, 8-9m 3 / min, 9~12m 3 / min, 12~14m 3 / min, 14m 3 For speeds above 1 / min, the values ​​are 1.2 MPa, 1.5 MPa, 1.8 MPa, 2.1 MPa, and 2.4 MPa, respectively.

[0159] The following formula is used to calculate wellbore friction:

[0160]

[0161] In the formula,

[0162] Pw—Wellbore friction, MPa;

[0163] q — Construction displacement, m 3 / min;

[0164] d——wellbore inner diameter, m;

[0165] y — the average test depth of the fracturing section, in meters;

[0166] The hydrostatic pressure is calculated using the following formula:

[0167]

[0168] In the formula,

[0169] Pf—Real-time static pressure of the sand-carrying tubing in each fracturing section, MPa;

[0170] ρ frac —Real-time fracturing fluid density for each fracturing section, taken as 1050 kg / m³ 3 ;

[0171] g—acceleration due to gravity, m / s² 2 The value is 9.8;

[0172] x — the average vertical depth of the fracturing section, in meters;

[0173] The net pressure of the nth segment is calculated using the following formula:

[0174] Pnet n =P n +Pf n -Pw n -Pp n -Sx n

[0175] In the formula,

[0176] Pnet n —Net pressure of segment n, MPa;

[0177] P n —The average construction pressure of the nth segment, in MPa;

[0178] Pf n —Pressure of the nth hydrostatic column, MPa;

[0179] Pw n —The frictional resistance of the nth wellbore, in MPa;

[0180] Pp n — Frictional resistance of the nth orifice, MPa;

[0181] Sx n —The average minimum horizontal principal stress of the nth segment, in MPa;

[0182] Calculate the difference in induced stress between segment n and segment n+1:

[0183]

[0184] In the formula,

[0185] Δσ — The induced stress of segment n acting on segment n+1, in MPa;

[0186] x n —The average test depth of the nth segment, in m;

[0187] x n+1 —The average test depth of the (n+1)th segment, in m;

[0188] v n —The average Poisson's ratio of the nth segment, dimensionless;

[0189] Step 5c: Optimize fracturing parameters to ensure the best modification effect:

[0190] When Δσ is between 0 and 0.5 MPa, the maximum construction discharge rate of the (n+1)th section remains unchanged from the design value; when Δσ is between 0.5 and 1 MPa, the maximum construction discharge rate of the (n+1)th section decreases by 0.5 m³ from the design value. 3 / min; when Δσ is between 1 and 1.5 MPa, the maximum construction discharge rate of the (n+1)th segment is reduced by 1 m from the design rate. 3 / min; when Δσ is between 1.5 and 2 MPa, the maximum construction discharge rate for the (n+1)th segment is reduced by 1.5 m from the design rate. 3 / min; When Δσ is greater than 2MPa, the maximum construction discharge rate of the (n+1)th segment is reduced by 2m based on the design. 3 / min.

[0191] In an optional embodiment of the present invention, the horizontal well dynamic completion method further includes step S6, evaluating the production effect after pressure to track the gas well production capacity.

[0192] Please refer to Figure 1 , Figure 2 and Figure 3 The following is a detailed explanation of the dynamic well completion method for horizontal wells proposed in this invention, in conjunction with an experimental process:

[0193] Step S1: Monitor the gamma data and cuttings data while drilling in real time to ensure that drilling is within the optimal formation.

[0194] The experiment selected the X21-5 shale gas reservoir and recorded the gamma ray value, silica mineral content, and carbonate content during the drilling process. The gamma ray value remained between 150 and 400 API, the silica mineral content remained between 40% and 60%, and the carbonate mineral content remained between 0% and 20%. Overall, no adjustments were required, and the drilling results were good.

[0195] When the gamma reading of this well was between 300 and 400 API, the carbonate mineral content was less than 15%. Therefore, during the drilling process, a gamma value between 150 and 300 API was selected as the drilling guidance standard to ensure that the drilling was carried out in the optimal formation.

[0196] Step S2: Monitor drilling trajectory data in real time to determine the maximum length of horizontal well drilling.

[0197] The well trajectory data is recorded in real time. The geological location of the well is relatively flat, and the inclination of the starting position of the horizontal section is always between 0 and 0.1. According to Formula 3, taking the inclination as 0.1, the optimal length of the horizontal section of the well can be 3000m.

[0198] Step S3: Collect and organize drilling gamma data and logging cuttings data to determine the optimal fracturing location.

[0199] The parameters of the horizontal section were read. The sum of the carbonate mineral content and silica mineral content at each recorded point of the well was above 60%, and the gamma value was between 200 and 300 API. The well was defined as a Class II fracturing location with good compressibility. The entire well section could be divided into 60m sections, and all of them were Class II intervals, as shown in Table 1.

[0200] Table 1 Average logging parameters every 60m

[0201]

[0202]

[0203] Step S4: Collect basic logging data, obtain the original geostress value, divide the ultra-long horizontal section into multiple parts according to the changes in geostress value, and formulate different fracturing parameter design schemes for each part.

[0204] Calculations show (see Table 2) that the stress difference at point A is 9.73 MPa and the stress difference at point B is 11.05 MPa. Therefore, the overall stress difference in this well is less than 2 MPa, and thus it is divided into two parts. Considering that there are already producing wells nearby (see Appendix...),... Figure 1 Therefore, the length of each section is 60m, and the fluid strength used in a single well is 30m. 3 / m, single-well sand addition intensity 3t / m, single-section perforation number 48 holes, for AD section, each section uses 8 clusters, cluster spacing 7.5m, discharge rate 15~16m³ / m³. 3 Construction operations are carried out at a rate of / min; for the DB section, 11 clusters are used per segment, with a cluster spacing of 5.5m and a discharge rate of 13-14m³ / min. 3 Construction operations are carried out at a rate of / min. The inner diameter of the wellbore is 114.3mm.

[0205] Table 2 Comparison of parameters at points A and B in well X21-5

[0206] Location Vertical depth AC DEN v SV SX SY SXY A 2500 67.17 2.51 0.23 63.98 57.28 66.96 9.73 B 2840 67.18 2.50 0.23 72.68 65.02 76.07 11.05

[0207] Step S5: Collect single-stage fracturing parameters, obtain the actual in-situ stress values ​​for subsequent fracturing stages, and optimize fracturing parameters to ensure the best modification effect. Specific adjustments are shown in Table 3.

[0208] Table 3 Real-time Adjustment Scheme for Well X21-5

[0209]

[0210]

[0211]

[0212] Step S6 involves tracking the production capacity of gas wells to adjust the well location layout and establish a suitable model for fully reviving multiple ultra-long horizontal wells.

[0213] Production logging interpretation of the well was conducted, and the overall results were good. Gas was supplied throughout the wellbore, essentially achieving the goal of full-bore gas production. Currently, the well's production casing pressure is 8 MPa, and it has maintained a daily production of 20 × 10⁴ m³ for four consecutive months. 3 It became a benchmark well for long horizontal gas wells in the work area.

[0214] The detailed explanations of the above embodiments are intended only to explain the present invention so as to facilitate a better understanding of the present invention. However, these descriptions should not be construed as limiting the present invention for any reason. In particular, the various features described in different embodiments can be arbitrarily combined with each other to form other embodiments. Unless there is an explicit description to the contrary, these features should be understood to be applicable to any embodiment, and not limited to the described embodiments.

Claims

1. A method of dynamic drilling and completion of horizontal wells, characterized in that, The horizontal well dynamic drilling and completion method at least comprises: Step S1, monitoring real-time logging while drilling gamma data and logging cuttings data, and controlling drilling trajectory within the optimal layer according to the logging while drilling gamma data and the logging cuttings data; The step S1 comprises: Step S1a, monitoring the logging while drilling gamma data, reading the gamma value every fixed distance drilled, and timely lifting or lowering the drilling trajectory to make the gamma value within the first control range; Step S1b, monitoring the logging cuttings data, reading the value of the logging cuttings data every fixed distance drilled, the logging cuttings data including the mass fraction of siliceous minerals and the mass fraction of carbonate minerals, and timely lifting or lowering the drilling trajectory to make the mass fraction of siliceous minerals within the second control range and the mass fraction of carbonate minerals within the third control range; Step S2, monitoring real-time drilling trajectory data, and determining the limit horizontal section length of the horizontal well drilling according to the drilling trajectory data; Step S3, determining the best fracturing position according to the logging while drilling gamma data and the logging cuttings data; The step S3 comprises: Step S3a, reading the logging while drilling gamma data and the logging cuttings data of each data point of the horizontal well, and classifying each data point according to the read logging while drilling gamma data and the logging cuttings data; Step S3b, determining the best fracturing position and dividing the horizontal section of the horizontal well according to the classification of each data point; In the step S3a, when the gamma value of the data point is 300-400 API, and the mass fraction of carbonate minerals is intermittently greater than 15% or continuously less than 15%, it indicates that the formation where the data point is located is a high resource abundance, medium-high brittleness, and medium-high stress area within the well control area; In the step S3a, when the sum of the mass fraction of carbonate minerals and the mass fraction of siliceous minerals of the data point is greater than 60%, and the gamma value is 150-200 API, the data point is defined as a class I fracturing position; When the sum of the mass fraction of carbonate minerals and the mass fraction of siliceous minerals of the data point is greater than 60%, and the gamma value is 200-300 API, the data point is defined as a class II fracturing position; When the sum of the mass fraction of carbonate minerals and the mass fraction of siliceous minerals of the data point is 40%-60%, and the gamma value is 150-200 API, the data point is defined as a class III fracturing position; When the sum of the mass fraction of carbonate minerals and the mass fraction of siliceous minerals of the data point is 40%-60%, and the gamma value is 200-300 API, the data point is defined as a class IV fracturing position; The class I fracturing position is the best fracturing position.

2. The method of claim 1, wherein, The fixed distance is 0.125 m, the first control range is 150-400 API, the second control range is 40%-60%, and the third control range is 0-20%.

3. The method of claim 2, wherein, In the step S1, if the gamma value read in real time is between 300 and 400 API and the carbonate mineral mass fraction continuously is greater than 15%, the drilling trajectory is controlled to make the gamma value between 300 and 400 API.

4. The method of claim 3, wherein, If the siliceous mineral mass fraction is greater than 60%, the drilling trajectory is controlled to make the gamma value close to the region of 400 API, otherwise, no limitation is made.

5. The method of claim 2, wherein, In the step S1, if the gamma value read in real time is between 300 and 400 API and the carbonate mineral mass fraction continuously is less than 15%, the drilling trajectory is controlled to make the gamma value between 150 and 300 API.

6. The method of claim 2, wherein, In the step S1, if the gamma value read in real time is between 150 and 300 API, the drilling trajectory is controlled to make the carbonate mineral mass fraction not less than 10% and the siliceous mineral mass fraction not less than 50%.

7. The method of claim 1, wherein, In the step S2, the drilling trajectory data includes the test depth, the vertical depth and the inclination of the horizontal well drilling.

8. The method of claim 1, wherein, The step S2 includes: Step S2a, record the horizontal section into the target point as A point, A point test depth, vertical depth respectively recorded as x0, y0, drilling to the i corresponding position is recorded as B i , Bi point test depth, vertical depth respectively recorded as x i , y i , the inclination can be recorded as follows: , wherein, Dev - the inclination of the end of the drilled horizontal section, dimensionless; Step S2b, in the case of ensuring that the drilled layer is in the specified layer, the inclination of the drilled horizontal section is recorded in real time, and when drilling to the i-th, the average inclination of the part of the drilled horizontal section is recorded as the following formula: ， In the formula, Devaverage - the average inclination of the drilled horizontal section, dimensionless; Step S2c, the relationship between the inclination and the limit horizontal section length is established and recorded as the following formula: ， In the formula, L - the limit horizontal section length of a single well, unit: m.

9. The method of claim 1, wherein, In the step S3a, when the gamma value at the data point is between 300 and 400 API and the carbonate mineral mass fraction continuously is greater than 15%, it indicates that the formation where the data point is located is a high resource abundance, high brittleness and high stress region in the well control region.

10. The method of claim 9, wherein, In the step S3a, when the carbonate mineral mass fraction of the data point is between 15% and 20% and the gamma value is between 350 and 400 API, the data point is defined as a class I fracturing position. When the carbonate mineral mass fraction of the data point is between 15% and 20% and the gamma value is between 300 and 350 API, the data point is defined as a class II fracturing position. When the carbonate mineral mass fraction of the data point is greater than 20% or less than 15% and the gamma value is between 350 and 400 API, the data point is defined as a class III fracturing position. When the carbonate mineral mass fraction of the data point is greater than 20% or less than 15% and the gamma value is between 300 and 350 API, the data point is defined as a class IV fracturing position.

11. The method of claim 1, wherein, In the step S3a, the reading of the gamma value, the siliceous mineral mass fraction and the carbonate mineral mass fraction is performed every 0.125 m.

12. The method of claim 11, wherein, In the step S3b, Since the first class I fracturing position is read, at least 480 data points in the continuous section where all the data points are class I fracturing positions are taken as the first optimal fracturing interval, and the number of data points has no upper limit. In the step S3b, At least 480 data points in a continuous section of the II-type fracturing position are taken as the first II-type fracturing interval since the first II-type fracturing position is read, and the number of data points has no upper limit; At least 480 data points in a continuous section of the III-type fracturing position are taken as the first III-type fracturing interval since the first III-type fracturing position is read, and the number of data points has no upper limit, At least 480 data points in a continuous section of the IV-type fracturing position are taken as the first IV-type fracturing interval since the first IV-type fracturing position is read, and the number of data points has no upper limit.

13. The method of claim 12, wherein, When the number of data points exceeds 480, the data point group is allowed to contain 5% of data points that do not meet the standard of the type of fracturing position, and when the number of data points that do not meet the standard exceeds 5%, the next fracturing interval is divided.

14. The method of claim 1, wherein, The horizontal well dynamic completion method further comprises: Step S4, collecting basic logging data, obtaining original in-situ stress values, dividing the horizontal section into multiple parts according to the change of the in-situ stress values, and formulating a fracturing parameter design scheme for each part.

15. The method of claim 14, wherein, The step S4 comprises: Step S4a, collecting the basic logging data with a fixed distance as a value step; Step S4b, obtaining the original in-situ stress values, calculating the change of the in-situ stress values, and dividing the horizontal section into multiple parts according to the change of the in-situ stress values; Step S4c, formulating a fracturing parameter design scheme for each part of the horizontal section.

16. The method of horizontal well dynamic drilling and completion of claim 15, wherein, In the step S4a, the basic logging data comprises longitudinal wave logging data and density logging data of a single well.

17. The method of claim 15, wherein, The step S4b comprises: Obtaining Poisson's ratio data: wherein, AC i - acoustic wave at each recording point, us / ft; ν i - Poisson's ratio corresponding to each recording point, dimensionless; Calculating the vertical stress: wherein, Sv i — vertical stress corresponding to each recording point, MPa; p overburden - average density of overburden, taken as 2.56 g / cm 3 ; ρ i Shale density corresponding to each recording point, g / cm 3 ; Calculating the maximum and minimum horizontal principal stress: wherein, Sy i - maximum horizontal principal stress, MPa, corresponding to each recording point; Sx i - minimum horizontal principal stress, MPa, corresponding to each recording point; Calculating the horizontal in-situ stress difference: wherein, Sxy i Horizontal stress difference, MPa, corresponding to each recording point.

18. The method of claim 17, wherein, Recording the target entry point of the horizontal section as point A and the end of the horizontal section as point B in the step S4b, Starting from point A, record the geostress difference S at point A. xy0 Until the stress difference S at a certain point M occurs. xyi If the stress is 1.5 MPa higher or lower than point A, then the area from point A to point M is divided into one part. Starting from point M, the process continues until the next point N appears. The difference in ground stress between the two points is 1.5 MPa. Then, the area from point M to point N is divided into another part.

19. The method of claim 18, wherein, In the step S4b, When the difference between the maximum in-situ stress difference and the minimum in-situ stress difference of the A point and the B point of the entire horizontal section exceeds 4.5 MPa, the horizontal section is divided into three parts according to 1 / 3 of the actual maximum difference; When the difference between the maximum in-situ stress difference and the minimum in-situ stress difference of the A point and the B point of the entire horizontal section is less than 1.5 MPa, the horizontal section is divided into two parts from the middle.

20. The method of claim 1, wherein, The horizontal well dynamic completion method further comprises: Step S5, collecting single-section fracturing construction parameters, obtaining actual in-situ stress values of subsequent fracturing sections, and optimizing fracturing parameters to ensure the best reconstruction effect.

21. The method of horizontal well dynamic drilling and completion of claim 20, wherein, The step S5 comprises: Step 5a, collecting single-section fracturing construction parameters, wherein the single-section fracturing construction parameters include average construction pressure P, hole friction Pp, wellbore friction Pw, static fluid column pressure Pf, construction discharge q, average minimum horizontal principal stress Psx, and average Poisson's ratio v of a single section; Step 5b, obtaining actual in-situ stress values of subsequent fracturing sections: Reading the average construction pressure, obtaining the hole friction, Calculating the wellbore friction according to the following formula: wherein, Pw is the wellbore friction, MPa; q is the construction discharge, m³ / min; d is the inner diameter of the wellbore, m; y is the average test depth of the fracturing section, m; Calculating the static fluid column pressure according to the following formula: wherein, Pf—real-time sand-carrying string static pressure of each fracturing section, MPa; ρ frac — each fracturing section real-time fracturing fluid density, take 1050 kg / m 3 ; g - acceleration due to gravity, m / s 2 , with a value of 9.8; x—average vertical depth of the fracturing section, m; The net pressure of the nth section is calculated as follows: In the formula, Pnet n — Net pressure of the nth segment, MPa; P n - average construction pressure of the nth segment, MPa; Pf n - n-th segment of static liquid column pressure, MPa; Pw n - n-th segment wellbore friction, MPa; Pp n - n-th segment hole pressure, MPa; Sx n — Average minimum horizontal principal stress of nth segment, MPa; The induced stress difference of the nth section to the (n+1)th section is calculated as follows: （11） In the formula, Δσ—induced stress of the nth section acting on the (n+1)th section, MPa; x n - average test depth of the nth segment, m; x n+1 - average test depth of the n+1 segment, m; v n - average Poisson's ratio of the nth segment, dimensionless; Step 5c, optimizing fracturing parameters to ensure the best reconstruction effect: When Δσ is between 0 and 0.5 MPa, the highest construction discharge of the (n+1)th section is maintained unchanged on the basis of the design; When Δσ is between 0.5 and 1 MPa, the highest construction discharge of the (n+1)th section is reduced by 0.5 m³ / min on the basis of the design; When Δσ is between 1 and 1.5 MPa, the highest construction discharge of the (n+1)th section is reduced by 1 m³ / min on the basis of the design; When Δσ is between 1.5 and 2 MPa, the highest construction discharge of the (n+1)th section is reduced by 1.5 m³ / min on the basis of the design; When Δσ is greater than 2 MPa, the highest construction discharge of the (n+1)th section is reduced by 2 m³ / min on the basis of the design.

22. The method of claim 1, wherein, The horizontal well dynamic completion method further comprises: Step S6, evaluating the production effect after fracturing and tracking the gas well production capacity.

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