Fractured horizontal well fracture network form identification method for tight oil reservoir

Abstract

The invention relates to the technical field of unconventional tight oil reservoir development, in particular to a tight oil reservoir fractured horizontal well fracture network form identification method, which comprises the following steps of: (1) acquiring production data of a horizontal well, including daily oil production qt, production time t, original formation pressure Pi and flowing bottomhole pressure Pwf; (2) calculating normalized pressure # imgabs0 #; (3) establishing a double logarithmic analysis curve of the derivative of the normalized pressure # imgabs1 # and the material balance time by using software KAPPA; and (4) according to the double logarithm analysis curve in the step (3), judging the seam net form. The method has the advantages of simple process, wide application range and high accuracy.

Description

Technical Field

[0001] The invention relates to the technical field of unconventional tight oil reservoir development, and in particular to a method for identifying the morphology of a tight oil reservoir fractured horizontal well network. Background Art

[0002] Unconventional tight oil reservoirs have the characteristics of poor reservoir properties and large oil and gas flow resistance. Conventional vertical well exploitation is difficult to achieve high production. The use of horizontal well volume fracturing development can effectively improve the development effect of tight oil reservoirs. After the reservoir is transformed by horizontal well fracturing, a fracture network of natural and artificial fractures is formed, which can greatly reduce the oil and gas seepage resistance.

[0003] The fracture morphology after reservoir fracturing directly affects the development effect. The higher the complexity of the fractures, the larger the connected seepage area and the higher the horizontal well production capacity. Therefore, accurately identifying whether a complex fracture network is formed in the reservoir after fracturing is the key to evaluating the effect of fracturing transformation.

[0004] The existing technology generally adopts microseismic mine monitoring means to show the geometric morphology of fractures by monitoring the tiny seismic events generated during the fracturing construction process, but it is easily affected by many factors such as noise, signal strength, and the distribution position of the detector, and it is difficult to ensure the accuracy of seismic wave picking. Therefore, it is not only a large amount of work to intuitively judge whether the reservoir has formed a complex fracture network through microseismic events, but also difficult to accurately characterize the geometric morphology of the fractures, and the accuracy of the judgment result is difficult to control. On the other hand, the current mine monitoring methods all require the selection of a vertical well that has been drilled around the monitored horizontal well or a certain (or several) horizontal wells in the monitored horizontal well group as monitoring wells. Often, there are inappropriate situations such as the vertical well is far away from the monitored well, the vertical well condition is problematic, or there are no vertical wells around, which makes it difficult to implement mine monitoring on site; for mine monitoring of horizontal well groups, if one of the wells is selected as a monitoring well, it will face the problem that the monitoring well itself cannot be monitored during the subsequent fracturing process. Therefore, the existing technology is not enough to meet the current actual needs.

[0005] Chinese patent application CN109268004A discloses a method for coupling the medium structure of shale gas reservoirs and identifying the fracture network morphology. The method first uses the improved Brazilian splitting experiment to conduct a fracturing test on the shale core and classify the fracture network morphology; secondly, the shale matrix-fracture structure and stress sensitivity experimental test are conducted on the cores with different fracture morphologies; thirdly, the stress sensitivity constant range of different fracture network morphologies is obtained based on the indoor core data; finally, based on the indoor core stress sensitivity experiment and combined with the actual production, a fracture network morphology identification chart is drawn. This chart can be applied to actual fracturing wells, and the fracture morphology is directly identified by real-time effective stress and normalized flow. However, this method needs to be based on indoor fracturing experiment simulation and stress sensitivity test, and the materials required for the experiment are actual cores, which are not easy to obtain. The experimental process is complicated and difficult to implement. In addition, the indoor experimental conditions cannot completely restore the formation conditions. Many factors such as whether the core used is representative affect the accuracy of the judgment results.

[0006] Therefore, it is very necessary to develop a method for identifying the morphology of horizontal well fracture networks in tight oil reservoirs that can solve the above technical problems. Summary of the invention

[0007] The purpose of the present invention is to overcome the shortcomings of the prior art and provide a method for identifying the fracture network morphology of horizontal wells in tight oil reservoirs with simple process, wide application range and high accuracy. The present invention can identify whether a complex fracture network is formed according to the actual seepage characteristics of the fluid in the formation, without the need for monitoring wells, and can be analyzed using the production data of the well, thus solving the problem that the prior art cannot effectively determine whether a complex fracture network is formed after reservoir fracturing.

[0008] The present invention is achieved through the following technical solutions:

[0009] A method for identifying the morphology of fracture networks of horizontal wells in tight oil reservoirs comprises the following steps:

[0010] (1) Obtaining horizontal well production data, including daily oil production q t , production time t, original formation pressure P i , bottom hole pressure P wf ;

[0011] (2) Calculation of normalized pressure The calculation formula is:

[0012]

[0013] Where: P i is the original formation pressure, MPa;

[0014] P wf is the bottom hole flowing pressure corresponding to any production time, MPa;

[0015] q t is the daily oil production corresponding to any production time point, t;

[0016] N is the nozzle size corresponding to any production time point, mm;

[0017] (3) Use KAPPA software to establish normalized pressure Double logarithmic analysis curve of the derivative and material equilibrium time;

[0018] (4) Determine the seam network morphology based on the double logarithmic analysis curve in step (3).

[0019] Normalized pressure The physical meaning is: the pressure value required to produce 1 ton of oil at any production time point of the oil well with a unit nozzle size.

[0020] Preferably, in step (3), the normalized pressure in step (2) is first Substitute the calculation formula into the Topaze well test analysis module in the KAPPA software, and then use the KAPPA software to establish the normalized pressure Double logarithmic analysis curve of the derivative and material equilibrium time.

[0021] Preferably, the material balance time in step (3) is calculated as follows:

[0022]

[0023] Where: t0 is the start time of production, day;

[0024] t n is any production time, days;

[0025] q tn is the production time t n The corresponding daily oil production.

[0026] Preferably, in step (4), if the double logarithmic analysis curve has a concave feature, the fracture network morphology is a complex fracture network.

[0027] The physical meaning of complex fracture network is that after fracturing, the reservoir fractures and matrix as a whole constitute a dual-medium seepage system. The double logarithmic analysis curve of the horizontal well production data after fracturing shows the dual-medium seepage characteristics, that is, the double logarithmic analysis curve shows a concave feature.

[0028] Preferably, in step (4), if the double logarithmic analysis curve does not have a concave feature, the seam network morphology is a single strip seam.

[0029] If the formation fractures are highly developed after fracturing and there is cross-flow between the matrix and the fractures, then the matrix + fractures as a whole constitute a dual-medium seepage system, which is shown as a typical concave feature in the double logarithmic analysis curve, indicating that the seepage in the formation exists in the matrix + complex fractures, and the fractures in the reservoir develop to form a complex fracture network after fracturing. Otherwise, the seepage exists in the matrix + single-strip fracture, and the double logarithmic analysis curve does not have the dual-medium seepage characteristics, and the reservoir has not formed a complex fracture network flow system.

[0030] The beneficial effects of the present invention are:

[0031] The present invention identifies whether there is a complex fracture network in the formation based on the actual seepage characteristics of the fluid in the formation, solving the problem that conventional methods are limited to the difficulty in identifying the geometric morphology of fractures, the limited implementation process in the mine, and the inability to effectively determine whether a complex fracture network is formed after reservoir fracturing. The method of the present invention is easy to obtain data and has an efficient analysis process, further providing an effective method for identifying fracture networks in horizontal wells of unconventional tight oil reservoirs and evaluating the fracturing effect. BRIEF DESCRIPTION OF THE DRAWINGS

[0032] Figure 1 It is a comparison chart of double logarithmic analysis curves of different flow characteristics of fractured horizontal wells;

[0033] Figure 2A This is a schematic diagram of the complex fracture network of a fractured horizontal well;

[0034] Figure 2B This is a schematic diagram of a single strip seam in a fractured horizontal well;

[0035] Figure 3 This is a comparison diagram of double logarithmic analysis curves of Well A and Well B in Example 2;

[0036] Figure 4 This is a comparison chart of the microseismic event monitoring results of Well A and Well B in Example 2. DETAILED DESCRIPTION

[0037] The present invention will be further described below in conjunction with specific embodiments, and the advantages and features of the present invention will become clearer as the description proceeds. However, these embodiments are exemplary only and do not constitute any limitation to the scope of the present invention. It should be understood by those skilled in the art that the details and forms of the technical solution of the present invention may be modified or replaced without departing from the spirit and scope of the present invention, but these modifications and replacements all fall within the scope of protection of the present invention.

[0038] Example 1

[0039] (1) First, the physical meaning of the complex fracture network is introduced: after fracturing, the reservoir fractures + matrix as a whole constitute a dual-medium seepage system. The production data of the horizontal well after fracturing are interpreted through well testing. Its double logarithmic well test curve shows the dual-medium seepage characteristics, that is, the double logarithmic well test curve shows a concave feature.

[0040] (2) Obtaining horizontal well production data, including daily oil production q t , production time t, original formation pressure P i , bottom hole pressure P wf ;

[0041] (3) Calculate the improved normalized pressure Its physical meaning is: the pressure value required to produce 1 ton of oil at any production time point of the oil well under the unit nozzle size. The calculation method is:

[0042]

[0043] Where: P i is the original formation pressure, MPa;

[0044] P wf is the bottom hole flowing pressure corresponding to any production time, MPa;

[0045] q t is the daily oil production corresponding to any production time point, t;

[0046] N is the nozzle size corresponding to any production time point, mm;

[0047] (4) Using the Topaze well test analysis module in the existing commercial software KAPPA, the original normalized pressure calculation formula in the software is modified to correspond to the improved normalized pressure calculation formula in step (3), and the derivative of the normalized pressure is established using the software Equilibrium time with material Double logarithmic analysis curve (Comparison of double logarithmic analysis curves of different flow characteristics is shown in the figure below) Figure 1 shown).

[0048] (5) Determine whether a complex fracture network is formed based on the characteristics of the double logarithmic analysis curve. If the formation fractures are highly developed after fracturing and there is crossflow between the matrix and the fractures, then the matrix + fractures as a whole constitute a dual-medium seepage system, which is shown as a typical concave feature in the double logarithmic analysis curve, indicating that the seepage in the formation exists in the matrix + complex fractures, and the fractures in the reservoir develop to form a complex fracture network after fracturing. Otherwise, the seepage exists in the matrix + single-band fracture, and the double logarithmic analysis curve does not have the dual-medium seepage characteristics, and the reservoir has not formed a complex fracture network flow system. The schematic diagram of the fracture network of the fractured horizontal well is shown in Figure 1. Figure 2A and Figure 2B As shown. Among them, Figure 2A Schematic diagram of complex seam network. Figure 2B Schematic diagram of a single strip seam.

[0049] Example 2

[0050] (1) Obtain production data for horizontal wells A and B, including daily oil production q t , production time t, original formation pressure P i , bottom hole pressure P wf ;

[0051] (2) Calculate the improved normalized pressure Its physical meaning is: the pressure value required to produce 1 ton of oil at any production time point of the oil well under the unit nozzle size. The calculation method is:

[0052]

[0053] Where: P i is the original formation pressure, MPa;

[0054] P wf is the bottom hole flowing pressure corresponding to any production time, MPa;

[0055] q t is the daily oil production corresponding to any production time point, t;

[0056] N is the nozzle size corresponding to any production time point, mm;

[0057] (3) Using the Topaze well test analysis module in the existing commercial software KAPPA, the original normalized pressure calculation formula in the software was modified to correspond to the improved normalized pressure calculation formula in step (2), and the software was used to establish a double logarithmic analysis curve of the derivative of the normalized pressure and the material balance time. The double logarithmic analysis curves of Well A and Well B are shown in Figure 2. Figure 3 shown.

[0058] (4) Determine whether a complex fracture network is formed based on the characteristics of the double logarithmic analysis curve.

[0059] Depend on Figure 3 It can be seen that the double logarithmic analysis curve of Well A shows a typical concave feature, and the matrix + fractures as a whole constitute a dual medium seepage system, which indicates that a complex fracture network has been formed in the reservoir of Well A.

[0060] The double logarithmic analysis curve of Well B is a smooth upward curve without obvious concave features, that is, it does not have dual medium seepage characteristics. The reservoir of Well B has not formed a complex fracture network flow system, but a single strip fracture.

[0061] The microseismic event monitoring results are used to verify the complexity of the fractures in Well A and Well B. Figure 4 As shown. Figure 4It can be seen that the microseismic event monitoring results record the distribution characteristics of the cracks after the reservoir is fractured. The microseismic event points of the reservoir in Well A after fracturing are densely distributed, and the microseismic event points between different fracturing well sections are intertwined and connected with each other, showing a network distribution feature overall, indicating that the cracks are highly complex, the fracture network is large in scale, and the fracturing forms a complex fracture network. The microseismic event points of the reservoir in Well B after fracturing are sparse and the vertical wellbore presents a strip distribution feature, indicating that the fractures have limited expansion along the horizontal section and the fracturing forms a single strip fracture. The microseismic monitoring results are consistent with the identification results of the method of the present invention, further verifying that the identification method of the present invention is simple to operate and has strong reliability.

[0062] The above detailed description is a specific description of one feasible embodiment of the present invention. The embodiment is not intended to limit the patent scope of the present invention. Any equivalent implementation or modification that does not deviate from the present invention should be included in the scope of the technical solution of the present invention.

Claims

1. A method for identifying the fracture network morphology of horizontal wells in tight oil reservoir fracturing, characterized in that: The steps include: (1) Obtaining horizontal well production data, including daily oil production q t , production time t, original formation pressure P i , bottom hole pressure P wf ; (2) Calculation of normalized pressure The calculation formula is: Where: P i is the original formation pressure, MPa; P wf is the bottom hole flowing pressure corresponding to any production time, MPa; q t is the daily oil production corresponding to any production time point, t; N is the nozzle size corresponding to any production time point, mm; (3) Use KAPPA software to establish normalized pressure Double logarithmic analysis curve of the derivative and material equilibrium time; (4) Determine the seam network morphology based on the double logarithmic analysis curve in step (3).

2. The method according to claim 1, characterized in that In step (4), if the double logarithmic analysis curve has a concave feature, the fracture network morphology is a complex fracture network.

3. The method according to claim 1, characterized in that In step (4), if the double logarithmic analysis curve does not have a concave feature, the seam network morphology is a single-strip seam.

4. The method according to claim 1, characterized in that: In step (3), the normalized pressure in step (2) is first Substitute the calculation formula into the Topaze well test analysis module in the KAPPA software, and then use the KAPPA software to establish the normalized pressure Double logarithmic analysis curve of the derivative and material equilibrium time.

5. The method according to claim 1, characterized in that The material balance time is calculated as: Where: t0 is the start time of production, day; t n is any production time, days; is the production time t n The corresponding daily oil production.

6. The method according to claim 1, characterized in that Normalized pressure It is the pressure value required for the oil well to produce 1 ton of oil at any production time point with unit nozzle size.

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