A method for determining effective transformation volume

Abstract

The present invention provides a method for determining an effective transformation volume, which comprises: when a first horizontal well or a first highly deviated well is completed, lowering a distributed temperature sensing optical fiber outside the casing to perform temperature monitoring, and then performing fracturing; drilling a second horizontal well or a second highly deviated well near the first horizontal well or the first highly deviated well and completing the well in an open hole; determining the position of the hydraulic main fracture of the first horizontal well or the first highly deviated well; lowering downhole pressure gauges corresponding to the positions of several hydraulic main fractures of the first horizontal well or the first highly deviated well observed in the second horizontal well or the second highly deviated well, and isolating each downhole pressure gauge in the second horizontal well or the second highly deviated well; starting production in the first horizontal well or the first highly deviated well, shutting down the second horizontal well or the second highly deviated well, and measuring the pressure change of the first horizontal well or the first highly deviated well; performing long-term fracture simulation on temperature, pressure and production data, and determining the effective transformation volume of the first horizontal well or the first highly deviated well at different times.

Description

Technical Field

[0001] The invention relates to a method for determining an effective transformation volume, and in particular to a method for determining an effective transformation volume after transformation of an oil and gas well reservoir. Background Art

[0002] In oil and gas wells with multi-layer reservoirs, thicker reservoirs or long horizontal well sections, the general construction of fracturing and acid fracturing can only transform a certain part of the reservoir, so it is necessary to transform in layers or sections to ensure that all reservoir sections are effectively transformed. However, the effective transformation volume cannot be determined in this field at present, which will have an adverse impact on the prediction of oil and gas production and the adjustment of exploration and development plans. Although microseismicity is commonly used in this field to monitor the transformation volume, the academic and industrial circles generally believe that the transformation volume determined by this method is obviously too large, and the transformation volume determined by microseismicity may be an order of magnitude higher than the actual effective transformation volume, and there is currently no existing technology reported that can accurately determine the effective transformation volume.

[0003] Therefore, providing a method for accurately determining the effective transformation volume has become a technical problem that urgently needs to be solved in this field. Summary of the invention

[0004] In order to solve the above-mentioned shortcomings and deficiencies, an object of the present invention is to provide a method for determining the effective transformation volume.

[0005] In order to achieve the above object, the present invention provides a method for determining an effective transformation volume, wherein the method for determining an effective transformation volume comprises:

[0006] Step 1: Drill the first horizontal well or the first high-angle well in the target study area and complete the well. During completion, run a distributed temperature sensing optical fiber outside the casing to monitor the temperature before fracturing.

[0007] Step 2: Drill a second horizontal well or a second highly deviated well near the first horizontal well or the first highly deviated well and complete the well in open hole;

[0008] Step 3: Perform imaging logging on the second horizontal well or the second highly deviated well to determine the location of the main hydraulic fracture in the first horizontal well or the first highly deviated well;

[0009] Step 4: Downhole pressure gauges are placed in the second horizontal well or the second most deviated well at locations corresponding to the locations where several hydraulic main fractures in the first horizontal well or the first most deviated well are observed, and each downhole pressure gauge in the second horizontal well or the second most deviated well is isolated by using a packer;

[0010] Step 5: the first horizontal well or the first highly deviated well is started for production, the second horizontal well or the second highly deviated well is shut down, and the pressure change of the first horizontal well or the first highly deviated well is measured by the downhole pressure gauge;

[0011] Step 6: Perform long-term fracture simulation on the temperature data, pressure data and production data of the first horizontal well or the first highly deviated well to determine the effective transformation volume of the first horizontal well or the first highly deviated well at different times.

[0012] As a specific implementation of the above method of the present invention, the first horizontal well or the first highly deviated well is a horizontal well or a highly deviated well in a carbonate rock, shale, volcanic rock, sandstone, or conglomerate reservoir.

[0013] As a specific implementation of the above method of the present invention, in step 1, the completion is casing completion.

[0014] The present invention does not make any special requirements on the distributed temperature sensing optical fiber used in step 1. Any type of optical fiber that can meet the formation temperature and fracturing requirements can be used in the present invention.

[0015] As a specific implementation of the above method of the present invention, in step 1, the distributed temperature sensing optical fiber outside the casing is used to monitor the average temperature changes of the reservoir before, during and after fracturing of the first horizontal well or the first highly deviated well.

[0016] As a specific implementation of the above method of the present invention, the distributed temperature sensing optical fiber outside the casing monitors the average temperature change of the reservoir within 16 days after the first horizontal well or the first high-angle well is fractured.

[0017] As a specific implementation of the above method of the present invention, in step 2, a second horizontal well is drilled at a position 10-300m away from the horizontal section of the first horizontal well.

[0018] As a specific implementation of the above method of the present invention, in step 2, a second highly deviated well is drilled at a distance of 10-300 m from the first highly deviated well.

[0019] As a specific implementation of the above method of the present invention, in step 3, the imaging logging is performed in water-based mud.

[0020] As a specific implementation of the above method of the present invention, in step 3, the positions of 10-30 main hydraulic fractures in the first horizontal well or the first high-angle well are determined by the imaging logging.

[0021] As a specific implementation of the above method of the present invention, in step 4, the number of downhole pressure gauges is 10-30.

[0022] The present invention does not make any special requirements on the downhole pressure gauge used, and any downhole pressure gauge that can meet the formation temperature and pressure requirements can be used in the present invention.

[0023] As a specific implementation of the above method of the present invention, in step 4, the packer is a permanent packer.

[0024] As a specific implementation of the above method of the present invention, in step 5, the downhole pressure gauge measures the pressure changes of several hydraulic main fractures in the first horizontal well or the first high-angle well within 1000 days for calculation of the effective transformation volume.

[0025] In step 4 of the above-mentioned method for determining the effective transformation volume provided by the present invention, each downhole pressure gauge in the second horizontal well or the second highly inclined well is isolated by using a packer, so that the downhole pressure gauge measures only the pressure change data of the reservoir located between the two packers of the first horizontal well or the first highly inclined well.

[0026] As a specific implementation of the above method of the present invention, the method includes the following specific steps:

[0027] Step 1: After drilling the first horizontal well or the first highly deviated well in the target study area, the casing is completed, and a distributed temperature sensing optical fiber is lowered outside the casing to monitor the temperature during completion, and then fracturing is performed; the distributed temperature sensing optical fiber outside the casing is used to monitor the average temperature change of the reservoir before, during and within 16 days after fracturing of the first horizontal well or the first highly deviated well;

[0028] Step 2: Drill a second horizontal well at a distance of 10-300 m from the horizontal section of the first horizontal well and complete the well in an open hole, or drill a second highly deviated well at a distance of 10-300 m from the first highly deviated well and complete the well in an open hole;

[0029] Step 3: performing imaging logging on the second horizontal well or the second highly deviated well in water-based mud, so as to determine the positions of 10-30 main hydraulic fractures in the first horizontal well or the first highly deviated well by the imaging logging;

[0030] Step 4: 10-30 downhole pressure gauges are placed in the second horizontal well or the second most deviated well at locations where several hydraulic main fractures of the first horizontal well or the first most deviated well are observed, and each downhole pressure gauge in the second horizontal well or the second most deviated well is isolated by using a permanent packer;

[0031] Step 5: The first horizontal well or the first highly deviated well is started for production, the second horizontal well or the second highly deviated well is shut down, and the pressure changes of several hydraulic main fractures in the first horizontal well or the first highly deviated well within 1000 days are measured by the downhole pressure gauge for calculation of the effective transformation volume;

[0032] Step 6: Perform long-term fracture simulation on the temperature data, pressure data and production data of the first horizontal well or the first highly deviated well to determine the effective transformation volume of the first horizontal well or the first highly deviated well at different times.

[0033] As a specific implementation of the above method of the present invention, the first horizontal well or the first highly deviated well is a horizontal well or a highly deviated well in a carbonate rock, shale, volcanic rock, sandstone, or conglomerate reservoir.

[0034] Compared with the prior art, the method for determining the effective transformation volume provided by the present invention can achieve the following unexpected technical effects:

[0035] The method for determining the effective transformation volume provided by the present invention introduces the pressure change of multiple hydraulic main fractures that can last up to 1000 days for the calculation of the effective transformation volume, which can make the calculation of the effective volume more accurate;

[0036] The method for determining the effective transformation volume provided by the present invention introduces the temperature change of the reservoir before, during and after fracturing for up to 16 days for calculating the effective transformation volume, which can make the calculation of the effective volume more accurate;

[0037] The method for determining the effective transformation volume provided by the present invention simultaneously utilizes the distributed pressure, distributed temperature, and historical production data to calculate the effective transformation volume, which can make the calculation of the effective volume more accurate.

[0038] In summary, the method for determining the effective transformation volume provided by the present invention takes into account the changes in temperature, pressure and time of horizontal wells or highly deviated wells at the same time, and can determine the effective transformation volume more accurately. The method provided by the present invention is suitable for horizontal wells and highly deviated wells in carbonate rock, shale, volcanic rock, sandstone, and conglomerate reservoirs. BRIEF DESCRIPTION OF THE DRAWINGS

[0039] In order to more clearly illustrate the embodiments of the present invention or the technical solutions in the prior art, the drawings required for use in the description of the embodiments will be briefly introduced below. Obviously, the drawings described below are some embodiments of the present invention. For ordinary technicians in this field, other drawings can be obtained based on these drawings without paying creative work.

[0040] Figure 1This is a schematic diagram of the positions of 12 downhole pressure gauges lowered into the horizontal well A202H2-2 at a depth of 3993-4633 m in Example 1 of the present invention.

[0041] Figure 2 This is the production data of horizontal well A202H2-1 in Example 1 of the present invention.

[0042] Figure 3 This is a schematic diagram of the positions of 10 downhole pressure gauges lowered into the horizontal well L203H1-2 at a depth of 4881-5521 m in Example 2 of the present invention.

[0043] Figure 4 This is the production data of horizontal well L203H1-1 in Example 2 of the present invention. DETAILED DESCRIPTION

[0044] In order to have a clearer understanding of the technical features, purposes and beneficial effects of the present invention, the technical scheme of the present invention is now described in detail in conjunction with the following specific embodiments, but it should not be understood as limiting the applicable scope of the present invention.

[0045] Example 1

[0046] This embodiment provides a method for determining an effective transformation volume, wherein the method comprises the following specific steps:

[0047] Step 1: Horizontal well A202H2-1 was drilled in the south wing of the Weiyuan Zhongaoding structure. The drilling layer was the Longmaxi Formation, with a formation pressure of 63.7 MPa and a formation temperature of 101°C / 4280 m. After that, casing completion was performed, and a distributed temperature sensing optical fiber was lowered outside the casing for temperature monitoring before fracturing.

[0048] Step 2: Drill horizontal well A202H2-2 at a distance of 10-300 m from the horizontal section of horizontal well A202H2-1 and complete the well in open hole;

[0049] Step 3: Perform imaging logging on the horizontal well A202H2-2, and determine the locations of 12 main hydraulic fractures in the horizontal well A202H2-1 based on the imaging logging results;

[0050] Wherein, the imaging logging is performed in water-based mud;

[0051] Step 4: 12 downhole pressure gauges were placed in the horizontal well A202H2-2 at the locations of the 12 main hydraulic fractures in the horizontal well A202H2-1. The schematic diagram of the locations of the 12 downhole pressure gauges placed in the horizontal well A202H2-2 at depths of 3993-4633 m is shown in the figure below: Figure 1 As shown;

[0052] Step 5: Use a permanent packer to isolate each downhole pressure gauge in the horizontal well A202H2-2;

[0053] Step 6: Horizontal well A202H2-1 is started for production, horizontal well A202H2-2 is shut down, and the pressure change of horizontal well A202H2-1 is measured by 12 downhole pressure gauges;

[0054] In this embodiment, the specific depth positions of the 12 downhole pressure gauges lowered into the horizontal well A202H2-2 at a depth of 3993-4633 m, the distance between the horizontal well A202H2-2 and the horizontal well A202H2-1, the initial pressure measured by the 12 downhole pressure gauges, the pressure at 540 days, and the pressure at 1080 days are shown in the following Table 1:

[0055] Table 1

[0056]

[0057]

[0058] In this embodiment, the distributed temperature sensing optical fiber outside the casing monitors the average temperature of the reservoir at a depth of 4086.2-4177.6 m in the horizontal well A202H2-1 before fracturing (0 day), during fracturing (1 day), and 2-16 days after fracturing as shown in Table 2 below:

[0059] Table 2

[0060] Number of days Temperature(℃) 0 101.0 1 32.3 2 51.0 3 64.9 4 72.1 5 78.8 6 83.8 7 89.3 8 93.2 9 95.4 10 97.1 11 98.2 12 99.3 13 99.9 14 100.4 15 101.0 16 101.0

[0061] Step 7: Use Schlumberger Kinetx Shale (2018 version) software to analyze the temperature data, pressure data and Figure 2 The production data of the horizontal well A202H2-1 shown in the figure is used for fracture simulation to determine the effective transformation volume of the horizontal well A202H2-1. In this embodiment, the effective transformation volume of the horizontal well A202H2-1 determined is 7.3222 million cubic meters.

[0062] Example 2

[0063] This embodiment provides a method for determining an effective transformation volume, wherein the method comprises the following specific steps:

[0064] Step 1: Drill the horizontal well L203H1-1 on the north wing of the Zhongaoding structure in Luzhou. The completed layer is the Longmaxi Formation, with a formation pressure of 83.5MPa and a formation temperature of 139℃ / 5168m. Then, the casing is completed and a distributed temperature sensing optical fiber is run outside the casing for temperature monitoring before fracturing.

[0065] Step 2: Drill horizontal well L203H1-2 at a distance of 10-300 m from the horizontal section of horizontal well L203H1-1 and complete the well in open hole;

[0066] Step 3: Perform imaging logging on the horizontal well L203H1-2, and determine the locations of 10 main hydraulic fractures in the horizontal well L203H1-1 according to the imaging logging results; wherein the imaging logging is performed in water-based mud;

[0067] Step 4: Ten downhole pressure gauges are placed in the horizontal well L203H1-2 at the locations where the ten main hydraulic fractures in the horizontal well L203H1-1 are observed; the schematic diagram of the locations of the ten downhole pressure gauges placed in the horizontal well L203H1-2 at depths of 4881-5521 m is shown in the figure. Figure 3 As shown;

[0068] Step 5: Use a permanent packer to isolate each downhole pressure gauge in the horizontal well L203H1-2;

[0069] Step 6: Horizontal well L203H1-1 is started for production, horizontal well L203H1-2 is shut down, and the pressure change of horizontal well A202H2-1 is measured by 10 downhole pressure gauges;

[0070] In this embodiment, the specific depth positions of the 10 downhole pressure gauges lowered into the horizontal well L203H1-2 at a depth of 4881-5521 m, the distance between the horizontal well L203H1-2 and the horizontal well L203H1-1, the initial pressure measured by the 10 downhole pressure gauges, the pressure at 360 days, and the pressure at 810 days are shown in the following Table 3:

[0071] Table 3

[0072]

[0073]

[0074] In this embodiment, the distributed temperature sensing optical fiber outside the casing monitors the average temperature of the reservoir at a depth of 4974-5063m in the horizontal well L203H1-1 before fracturing (0 day), during fracturing (1 day), and 2-16 days after fracturing as shown in Table 4 below:

[0075] Table 4

[0076] Number of days Temperature(℃) 0 139.0 1 32.3 2 72.3 3 89.0 4 102.9 5 110.1 6 116.8 7 121.8 8 127.3 9 131.2 10 133.4 11 135.1 12 136.2 13 137.3 14 137.9 15 138.4 16 139.0

[0077] Step 7: Use Schlumberger Kinetx Shale (2018 version) software to analyze the temperature data, pressure data and Figure 4The production data shown in the figure are used for fracture simulation to determine the effective transformation volume of the horizontal well L203H1-1. In this embodiment, the effective transformation volume of the horizontal well L203H1-1 determined is 12,655,800 cubic meters.

[0078] Comparative Example 1

[0079] This comparative example provides a method for determining the effective transformation volume of horizontal well A202H2-1 using microseismic method, which includes the following specific steps:

[0080] Microseismic monitoring of horizontal well A202H2-1 revealed a fracture network with a length of 2900 m, a width of 346.5 m, and a height of 42 m. The effective transformation volume of horizontal well A202H2-1 was calculated to be 42203700.0 m 3 This data is obviously larger than the effective transformation volume (7.3222 million cubic meters) of the horizontal well A202H2-1 calculated by pressure, temperature and production data in Example 1.

[0081] Comparative Example 2

[0082] This comparative example provides a method for determining the effective transformation volume of the horizontal well L203H1-1 using the microseismic method, which includes the following specific steps:

[0083] Microseismic monitoring of horizontal well L203H1-1 revealed a fracture network with a length of 3040 m, a width of 337.7 m, and a height of 42 m. The effective transformation volume of horizontal well L203H1-1 was calculated to be 43113280.0 m 3 This data is obviously larger than the effective transformation volume (12,655,800 cubic meters) of the horizontal well L203H1-1 calculated by pressure, temperature and production data in Example 2.

[0084] The reason why the effective transformation volume of the horizontal well calculated by the microseismic method in Comparative Example 1-2 is larger than the effective transformation volume obtained in Example 1-2 of the present invention is:

[0085] Microseismic monitoring gives the fracture position of the hydraulic fracture of shear fracture. After multi-stage fracturing of the horizontal well, all the points showing microseismic events are enveloped by a cube, and the volume of this cube is the transformation volume given by microseismic monitoring. The method for determining the effective transformation volume provided by the embodiment of the present invention introduces the pressure changes of multiple hydraulic main fractures for up to 1000 days for the calculation of the effective transformation volume, which can make the calculation of the effective volume more accurate. The temperature changes of the reservoir for up to 16 days before, during and after fracturing are introduced for the calculation of the effective transformation volume, which can make the calculation of the effective volume more accurate. At the same time, the effective transformation volume is calculated using distributed pressure, distributed temperature and historical production data, which can make the calculation of the effective volume more accurate.

[0086] The above is only a specific embodiment of the present invention, and cannot be used to limit the scope of the invention. Therefore, the replacement of equivalent components, or equivalent changes and modifications made according to the protection scope of the patent of the present invention, should still fall within the scope of this patent. In addition, the technical features of the present invention can be freely combined with each other, with each other and with each other, and with each other.

Claims

1. A method for determining an effective transformation volume, characterized in that: The method for determining the effective transformation volume comprises: Step 1: Drill the first horizontal well or the first highly deviated well in the target study area and complete the well. During completion, a distributed temperature sensing optical fiber is run outside the casing to monitor the temperature before fracturing. The distributed temperature sensing optical fiber outside the casing is used to monitor the average temperature change of the reservoir before, during and within 16 days after fracturing of the first horizontal well or the first highly deviated well. Step 2: Drill a second horizontal well at a location 10-300 m away from the horizontal section of the first horizontal well and complete the well in an open hole, or drill a second highly deviated well at a location 10-300 m away from the first highly deviated well and complete the well in an open hole; Step 3: performing imaging logging on the second horizontal well or the second highly deviated well, and determining the positions of 10-30 main hydraulic fractures in the first horizontal well or the first highly deviated well by the imaging logging; Step 4: Downhole pressure gauges are placed in the second horizontal well or the second most deviated well at locations corresponding to the locations where several hydraulic main fractures in the first horizontal well or the first most deviated well are observed, and each downhole pressure gauge in the second horizontal well or the second most deviated well is isolated by using a packer; Step 5: The first horizontal well or the first highly deviated well is started for production, the second horizontal well or the second highly deviated well is shut down, and the pressure changes of several hydraulic main fractures in the first horizontal well or the first highly deviated well within 1000 days are measured by the downhole pressure gauge for calculation of the effective transformation volume; Step 6: Perform long-term fracture simulation on the temperature data, pressure data and production data of the first horizontal well or the first highly deviated well to determine the effective transformation volume of the first horizontal well or the first highly deviated well at different times.

2. The method according to claim 1, characterized in that The first horizontal well or the first highly deviated well is a horizontal well or a highly deviated well in a carbonate rock, shale, volcanic rock, sandstone or conglomerate reservoir.

3. The method according to claim 1, characterized in that In step 1, the completion is casing completion.

4. The method according to claim 1, characterized in that: In step 3, the imaging logging is performed in water-based mud.

5. The method according to claim 1, characterized in that In step 4, there are 10 to 30 downhole pressure gauges.

6. The method according to claim 1, characterized in that In step 4, the packer is a permanent packer.

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