A comprehensive division method for post-pressure backflow drainage stages of shale gas horizontal wells

Abstract

The present invention discloses a comprehensive division method of the drainage stage after fracturing of a shale gas horizontal well, including drawing a curve of the increase of the drainage time of daily gas production and daily water production; statistically analyzing the reservoir parameters and burial depth of the target layer of the production well; drawing a curve of the correlation parameters between the reservoir parameters, burial depth and cumulative drainage rate and the drainage time; drawing a curve of the change between the total mineralization of the fracturing drainage fluid and the drainage time; determining the termination time of the wellbore drainage stage, the termination time of the drainage stage of the main fracture and the larger secondary fracture, the termination time of the drainage stage of the secondary fracture, and the termination time of the drainage stage of the micropore fracture; and dividing the curve of the increase of the drainage time of daily gas production and daily water production into five stages. The present invention directly clarifies the drainage characteristics of water after fracturing in a shale gas well, and divides the stages of wellbore drainage, drainage of the main fracture and the larger secondary fracture, drainage of the secondary fracture, drainage of the micropore fracture, and drainage of the pore, which is of great significance for optimizing the fracturing drainage process measures and improving the single well production capacity.

Description

Technical Field

[0001] The invention relates to a comprehensive division method of the post-fracture return water discharge stage of a shale gas horizontal well, belonging to the technical field of shale reservoir fracturing. Background Art

[0002] Since shale reservoirs are dense and have extremely low porosity and permeability characteristics, horizontal well technology and hydraulic fracturing technology are needed to achieve commercial exploitation of shale gas. After hydraulic fracturing, shale gas wells usually go through three stages: shut-in, flowback, and production. To achieve efficient exploitation of shale gas wells, a scientific and reasonable flowback system must be established. After shale reservoir fracturing, cracks of different sizes will be formed, which are mainly divided into three categories: primary cracks, secondary cracks, and micro cracks. After gas well fracturing, a large amount of fracturing fluid will be retained in the shale reservoir, destroying the original microscopic gas-water distribution pattern of the shale gas reservoir, and having a great impact on gas seepage. Fully understanding the drainage characteristics of shale gas well flowback-production process is of great significance for adjusting flowback measures.

[0003] Under the combined effects of capillary force, osmotic pressure, hydration force, hydrogen bond force, van der Waals force, adsorption on the surface of micro-fractures, and gas breakthrough, the water phase is difficult to flow back and is retained in the micro-fractures. Yang Hai et al. analyzed the two-phase flow experiment and believed that the retained fracturing fluid has a liquid phase support effect in the micro-fracture network of shale reservoirs, so that the gas phase permeability is not a monotonic function of water saturation, and there is an optimal flowback rate to maximize the gas phase permeability. Therefore, clarifying the flowback characteristics of water after fracturing in shale gas wells, such as wellbore drainage, main fracture drainage, secondary fracture drainage, and micro-fracture and pore drainage, is of great significance for optimizing fracturing flowback process measures and improving single well production capacity. Unfortunately, there is a lack of relevant methods for the division of fracturing flowback stages in shale gas wells at this stage. Therefore, it is necessary to divide the fracturing flowback stages based on geological-gas well production characteristics to promote the increase of shale gas well production. Summary of the invention

[0004] The purpose of the present invention is to provide a comprehensive division method for the post-pressure return water discharge stages of a shale gas horizontal well in response to the problems existing in the prior art.

[0005] The technical solution provided by the present invention to solve the above technical problems is: a comprehensive division method of the backflow and drainage stages of shale gas horizontal wells after pressure reduction, comprising the following steps:

[0006] Step 1: Obtain daily gas production data, daily water production data and fracturing water consumption of production wells in the target shale gas production block;

[0007] Step 2: Calculate the cumulative flowback rate of the production wells in the target shale gas production block as the flowback time increases based on the daily gas production data and the daily water production data, and draw the curves of the increase of the daily gas production and daily water production flowback time;

[0008] Step 3: According to the logging data of the production wells in the target shale gas production block, the reservoir parameters and burial depth of the target layer of the production wells are counted;

[0009] Step 4: Make a correlation cross plot of reservoir parameters, burial depth and fracturing flowback rate at different times to obtain correlation parameters between reservoir parameters, burial depth and cumulative flowback rate;

[0010] Step 5: draw the correlation curve between reservoir parameters, burial depth and cumulative backflow rate and the backflow time;

[0011] Step 6: Collect the fracturing flowback fluid from the production wells of the target shale gas production block the day after fracturing, test the total mineralization of the fracturing flowback fluid, and draw a curve of the change between the total mineralization of the fracturing flowback fluid and the flowback time;

[0012] Step 7: Determine the end time of the wellbore drainage stage according to the change curve between the total mineralization and the backflow drainage time;

[0013] Step 8: Determine the termination time of the drainage stage of the main crack and the larger secondary crack according to the change curve between the correlation parameter between the burial depth and the cumulative backflow rate and the backflow time;

[0014] Step nine, determining the termination time of the secondary fracture drainage stage and the termination time of the micropore drainage stage according to the change curve between the correlation parameter between the reservoir parameter and the cumulative backflow rate and the backflow drainage time;

[0015] Step 10. According to the termination time of the wellbore drainage stage, the termination time of the main fracture and larger secondary fracture drainage stage, the termination time of the secondary fracture drainage stage, and the termination time of the micropore drainage stage, the curve of increasing daily gas production and daily water flowback time is divided into the wellbore drainage stage, the main fracture and larger secondary fracture drainage stage, the secondary fracture drainage stage, the micropore drainage stage, and the pore drainage stage.

[0016] A further technical solution is that the reservoir parameters include TOC content, mineral composition, porosity, and water saturation.

[0017] A further technical solution is that the corresponding flowback time when the total mineralization of the fracturing flowback fluid reaches 2000 mg / L in step seven is the termination time of the wellbore drainage stage.

[0018] A further technical solution is that the corresponding backflow time when the correlation parameter between the burial depth and the cumulative backflow rate reaches a maximum value in step eight is the termination time of the drainage stage of the main cracks and the larger secondary cracks.

[0019] A further technical solution is that in step nine, when the correlation parameter between the reservoir parameters and the cumulative flowback rate reaches 0.36 and 0.57, the corresponding flowback times are the termination time of the secondary fracture drainage stage and the termination time of the micropore drainage stage, respectively.

[0020] A further technical solution is to respectively determine the flowback time corresponding to when the correlation parameter between TOC content and cumulative flowback rate reaches 0.36 and 0.57, and the flowback time corresponding to when the correlation parameter between porosity and cumulative flowback rate reaches 0.36 and 0.57 in step nine, and then take the average time between the two as the final termination time of the secondary fracture drainage stage and the termination time of the micropore drainage stage.

[0021] A further technical solution is that the time period between 0 and the end time of the wellbore drainage stage divided in step ten is the wellbore drainage stage, the time period between the end time of the wellbore drainage stage and the end time of the main crack and larger secondary crack drainage stage is the main crack and larger secondary crack drainage stage, the time period between the end time of the main crack and larger secondary crack drainage stage and the end time of the secondary crack drainage stage is the secondary crack drainage stage, the time period between the end time of the secondary crack drainage stage and the end time of the micropore drainage stage is the micropore drainage stage, and the time period greater than the end time of the micropore drainage stage is the pore drainage stage.

[0022] Beneficial effects of the invention: The invention directly clarifies the flowback characteristics of water after fracturing in shale gas wells, and divides the stages into wellbore drainage, main fracture and larger secondary fracture drainage, secondary fracture drainage, micropore drainage, and pore drainage, which is of great significance for optimizing fracturing flowback process measures and improving single well productivity. BRIEF DESCRIPTION OF THE DRAWINGS

[0023] Figure 1 It is a curve diagram showing the variation between the total mineralization of fracturing flowback fluid and the flowback time;

[0024] Figure 2 It is a curve diagram showing the correlation parameters between the burial depth and the cumulative backflow rate and the backflow time;

[0025] Figure 3 It is the variation curve diagram between the correlation parameter between TOC content and cumulative backflow rate and backflow time;

[0026] Figure 4 It is the variation curve diagram between the correlation parameter between porosity and cumulative backflow rate and backflow time;

[0027] Figure 5 Schematic diagram of the division of fracturing return water stages. DETAILED DESCRIPTION

[0028] The technical solution of the present invention will be described clearly and completely below in conjunction with the accompanying drawings. Obviously, the described embodiments are only part of the embodiments of the invention, not all of them. Based on the embodiments of the present invention, all other embodiments obtained by ordinary technicians in this field without creative work are within the scope of protection of the present invention.

[0029] The present invention provides a comprehensive division method for the post-pressure return water discharge stage of a shale gas horizontal well, comprising the following steps:

[0030] Step 1: Obtain daily gas production data, daily water production data and fracturing water consumption of production wells in the target shale gas production block;

[0031] Step 2: Calculate the cumulative flowback rate (cumulative water production / fracturing water consumption × 100%) of the production wells in the target shale gas production block as the flowback time increases based on the daily gas production data and daily water production data, and draw curves of the increase in the flowback time of daily gas production and daily water production;

[0032] Step 3: According to the logging data of the production wells in the target shale gas production block, the average values ​​and buried depths of the reservoir parameters (TOC content, mineral composition, porosity, water saturation, etc.) of the target layer of the production wells are calculated;

[0033] Step 4: Make a correlation cross plot of reservoir parameters, burial depth and fracturing flowback rate at different times (with 10-day intervals) to obtain correlation parameters between reservoir parameters, burial depth and cumulative flowback rate;

[0034] Step 5: draw the correlation curve between reservoir parameters, burial depth and cumulative backflow rate and the backflow time;

[0035] Step 6: Collect the fracturing flowback fluid from the production wells of the target shale gas production block the day after fracturing, test the total mineralization of the fracturing flowback fluid, and draw a curve of the change between the total mineralization of the fracturing flowback fluid and the flowback time;

[0036] Step 7: In the curve between total salinity and flowback time, the corresponding flowback time (10 days) when the total salinity of the fracturing flowback fluid reaches 2000 mg / L is taken as the end time of the wellbore drainage stage;

[0037] Step 8: In the variation curve between the correlation parameter between the burial depth and the cumulative backflow rate and the backflow time, the backflow time (60 days) corresponding to the time when the correlation parameter between the burial depth and the cumulative backflow rate reaches the maximum value is taken as the termination time of the drainage stage of the main cracks and the larger secondary cracks;

[0038] Step 9: Determine in the variation curve between the correlation parameter between the TOC content and the cumulative flowback rate and the flowback time that the corresponding flowback time when the correlation parameter between the TOC content and the cumulative flowback rate reaches 0.36 and 0.57 is 160 days and 270 days respectively;

[0039] The correlation parameter between porosity and cumulative flowback rate and the change curve between flowback time and the correlation parameter between porosity and cumulative flowback rate were 0.36 and 0.57, and the corresponding flowback time was 160 days and 270 days respectively.

[0040] Then the average time between the two times is taken as the final termination time of the secondary fracture drainage stage (160 days) and the termination time of the microporous fracture drainage stage (270 days).

[0041] Step 10: According to the termination time of the wellbore drainage stage (10 days), the termination time of the main fracture and larger secondary fracture drainage stage (60 days), the termination time of the secondary fracture drainage stage (160 days), and the termination time of the microporous fracture drainage stage (270 days), the curve of the increase of daily gas production and daily water return time is divided into the wellbore drainage stage, the main fracture and larger secondary fracture drainage stage, the secondary fracture drainage stage, the microporous fracture drainage stage, and the pore drainage stage, that is, Figure 5 As shown, stage I: wellbore drainage (0-10 days); stage II: primary and larger secondary fracture drainage (10-60 days); stage III: secondary fracture drainage (60-160 days); stage IV: microporous fracture drainage (160-270 days); stage V: pore drainage (>270 days).

[0042] The above description is not intended to limit the present invention in any form. Although the present invention has been disclosed through the above embodiments, it is not intended to limit the present invention. Any technician familiar with the profession can make some changes or modifications to equivalent embodiments of equivalent changes using the technical contents disclosed above without departing from the scope of the technical solution of the present invention. However, any simple modification, equivalent change and modification made to the above embodiments based on the technical essence of the present invention without departing from the content of the technical solution of the present invention still falls within the scope of the technical solution of the present invention.

Claims

1. A comprehensive division method for the post-pressure return water discharge stage of a shale gas horizontal well, characterized in that: The following steps are involved: Step 1: Obtain daily gas production data, daily water production data and fracturing water consumption of production wells in the target shale gas production block; Step 2: Calculate the cumulative flowback rate of the production wells in the target shale gas production block as the flowback time increases based on the daily gas production data and the daily water production data, and draw the curves of the increase of the daily gas production and daily water production flowback time; Step 3: According to the logging data of the production wells in the target shale gas production block, the reservoir parameters and burial depth of the target layer of the production wells are counted; The reservoir parameters include TOC content, mineral composition, porosity, and water saturation; Step 4: Make a correlation cross plot of reservoir parameters, burial depth and fracturing flowback rate at different times to obtain correlation parameters between reservoir parameters, burial depth and cumulative flowback rate; Step 5: draw the correlation curve between reservoir parameters, burial depth and cumulative backflow rate and the backflow time; Step 6: Collect the fracturing flowback fluid from the production wells of the target shale gas production block the day after fracturing, test the total mineralization of the fracturing flowback fluid, and draw a curve of the change between the total mineralization of the fracturing flowback fluid and the flowback time; Step 7: Determine the end time of the wellbore drainage stage according to the change curve between the total mineralization and the backflow drainage time; The return flow time corresponding to the total mineralization of the fracturing return fluid reaching 2000 mg / L is taken as the end time of the wellbore drainage stage; Step 8: Determine the termination time of the drainage stage of the main crack and the larger secondary crack according to the change curve between the correlation parameter between the burial depth and the cumulative backflow rate and the backflow time; Step nine, determining the termination time of the secondary fracture drainage stage and the termination time of the micropore drainage stage according to the change curve between the correlation parameter between the reservoir parameter and the cumulative backflow rate and the backflow drainage time; According to the correlation parameters between reservoir parameters and cumulative flowback rate, when the correlation parameters reach 0.36 and 0.57, the corresponding flowback times are the termination time of secondary fracture drainage stage and the termination time of microporous fracture drainage stage respectively; The corresponding flowback time when the correlation parameter between TOC content and cumulative flowback rate reaches 0.36 and 0.57, and the corresponding flowback time when the correlation parameter between porosity and cumulative flowback rate reaches 0.36 and 0.57, respectively, are determined, and then the average time between the two is taken as the final termination time of the secondary fracture drainage stage and the termination time of the microporous fracture drainage stage; Step 10. According to the termination time of the wellbore drainage stage, the termination time of the main fracture and larger secondary fracture drainage stage, the termination time of the secondary fracture drainage stage, and the termination time of the micropore drainage stage, the curve of increasing daily gas production and daily water flowback time is divided into the wellbore drainage stage, the main fracture and larger secondary fracture drainage stage, the secondary fracture drainage stage, the micropore drainage stage, and the pore drainage stage.

2. A comprehensive division method for the post-pressure return water flow stage of a shale gas horizontal well according to claim 1, characterized in that: In the step eight, the corresponding backflow time when the correlation parameter between the burial depth and the cumulative backflow rate reaches the maximum value is the termination time of the drainage stage of the main cracks and the larger secondary cracks.

3. The comprehensive division method of the post-pressure return water flow stage of a shale gas horizontal well according to claim 1 is characterized in that: In the step 10, the time period between 0 and the end time of the wellbore drainage stage is divided into the wellbore drainage stage, the time period between the end time of the wellbore drainage stage and the end time of the main crack and larger secondary crack drainage stage is divided into the main crack and larger secondary crack drainage stage, the time period between the end time of the main crack and larger secondary crack drainage stage and the end time of the secondary crack drainage stage is divided into the secondary crack drainage stage, the time period between the end time of the secondary crack drainage stage and the end time of the micropore drainage stage is divided into the micropore drainage stage, and the time period greater than the end time of the micropore drainage stage is divided into the pore drainage stage.

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