A low-pressure test method based on reflux

Abstract

The present invention discloses a low-pressure test method based on reflux flowback, which belongs to the field of oil and gas field development technology and includes the following steps: S1, calculating the maximum injection displacement and injection volume of fracturing fluid for a specific reservoir in a well site, and determining the pumping time; S2, injecting the fracturing fluid and recording the injection data, briefly shutting down the well after completing the injection of the fracturing fluid, immediately performing constant-speed flowback, and recording the flowback data; S3, performing quality assessment and correction on the data collected in S2, calculating the closing pressure, reservoir pressure, and reservoir productivity index, and completing the low-pressure test. The present invention can complete the test in just a few hours by adopting a reflux flowback method, avoiding the process of shutting down the well for a long time to wait for the pressure drop in the traditional low-pressure test, and significantly improving the efficiency of the test; it can avoid errors caused by overestimating the oil well productivity index and waiting for a long time, improve the accuracy and reliability of the test results, help optimize the volume fracturing construction plan, and improve the efficiency of oil and gas field development.

Description

Technical Field

[0001] The invention relates to the technical field of oil and gas field development, and in particular to a low-pressure testing method based on reflux flowback. Background Art

[0002] In the field of petroleum engineering, unconventional oil and gas are characterized by low porosity, low permeability, and strong reservoir heterogeneity. Their development typically requires reservoir transformation using volumetric fracturing technology. Before volumetric fracturing, low-pressure testing is required to obtain information such as fracture extension pressure, closure pressure, reservoir pressure, number of effective fluid-feeding holes, fracture tortuosity friction, fluid efficiency, fluid loss coefficient, and permeability.

[0003] However, traditional low-pressure testing uses an injection / shut-in method, recording the pressure drop over time after shutting in the well. This pressure drop is primarily caused by filtration of the fracturing fluid. In unconventional reservoirs, fracturing fluid filtration is slow, resulting in a prolonged pressure drop, often taking days, weeks, or even months. This results in significant errors in traditional low-pressure testing and an inability to quickly obtain information on reservoir parameters, slowing construction progress.

[0004] Therefore, how to provide an efficient and accurate low-pressure testing method is an urgent problem that needs to be solved by those skilled in the art. Summary of the Invention

[0005] The purpose of the present invention is to provide a low-pressure testing method based on reflux flowback to solve the problems in the background technology.

[0006] To achieve the above object, the present invention provides a low-pressure testing method based on reflux flowback, comprising the following steps:

[0007] S1. Calculate the maximum injection rate and injection volume of the fracturing fluid for the specific reservoir at the well site and determine the pumping time;

[0008] S2. Inject the fracturing fluid according to the result obtained in S1 and record the injection data. After the injection of the fracturing fluid is completed, shut down the well briefly and immediately perform a constant flowback, and record the flowback data.

[0009] S3: Perform quality assessment and correction on the data collected in S2. Calculate the closure pressure, reservoir pressure and reservoir productivity index based on the corrected data to complete the low-pressure test.

[0010] Preferably, in S1, the calculation formula for the maximum injection displacement is:

[0011]

[0012] Where k is the reservoir permeability, h is the reservoir thickness, and p fis the formation fracture pressure, p i is the original formation pressure of the reservoir, μ is the fluid viscosity, β is the fluid volume coefficient, r e is the discharge radius, r w is the wellbore radius, and S is the skin coefficient.

[0013] Preferably, in S1, the calculation formula for the injection amount is:

[0014] Q inj =(0.06Ap net Kt / μ)+2x f w f H;

[0015] Where A is the crack surface area, p net is the net pressure, K is the reservoir permeability, t is the time, x f is the half length of the crack, H is the height of the crack, w f is the width of the hydraulic fracture during the fracturing process, w f The calculation formula is:

[0016] w f =πp net H(1-v 2 ) / 2000E;

[0017] Where v is the Poisson's ratio of the formation rock, and E is the Young's modulus of the formation rock.

[0018] Preferably, in S2, the constant flowback flow rate is 2%-5% of the maximum injection displacement calculated in S1.

[0019] Preferably, in said S2, the injection data includes injection pressure and injection flow rate;

[0020] Flowback data includes flowback volume, flowback pressure and flowback rate.

[0021] Preferably, in S3, the quality assessment process specifically includes: performing data integrity and continuity assessment, and identifying and removing abnormal data;

[0022] This process ensures that all data points (injection pressure, injection rate, flowback pressure, and flowback rate) are collected, and the continuity of the data is checked to ensure there are no obvious jumps or jumps. Outliers in the data are analyzed and removed to ensure that they do not affect subsequent calculations.

[0023] The correction process is as follows: During the flowback phase, the fluid velocity in the fracture decreases. The fluid velocity in the fracture is measured and the flow pressure is corrected based on the fluid velocity in the fracture to prevent the surface-measured velocity from being too high, which would result in an overestimation of the well productivity index. The friction near the wellbore and the perforation holes is estimated based on the difference in flow pressure to determine whether re-perforation is necessary.

[0024] Under low return flow rate conditions, the effect of near-wellbore friction on the minimum horizontal stress estimation is negligible. However, during the return flow stage, as the fracture begins to close, the friction of the fluid within the fracture gradually increases, causing the flow velocity within the fracture to decrease rapidly and gradually deviate from the rate measured on the surface. At this time, the wellbore unloading effect becomes dominant, delaying the decline of the flow velocity within the fracture, resulting in an overestimation of the surface-measured flow velocity and an overestimation of the well productivity index. Therefore, it is necessary to correct the flow pressure at this time by measuring the fluid flow velocity within the fracture and estimate the friction near the wellbore and perforation holes based on the difference.

[0025] Preferably, in S3, the calculation process of the closing pressure is: using the incremental flowback method, estimating the closing pressure based on the curve relationship between the stable flowback pressure and the flowback liquid volume increment in the flowback data.

[0026] Preferably, in S3, the calculation process of the reservoir pressure is:

[0027] 1) The fluid flow state during the reflux process is determined using the double logarithmic curves of the normalized water production pressure RNP and the derivative of the normalized water production pressure RNP′ and the material balance time tc;

[0028] 2) The pressure at the point where the control flow just begins to appear near the boundary of the fracture area in the double logarithmic curve is selected as the estimated value of the reservoir pressure.

[0029] Preferably, the calculation formula of the water production normalized pressure RNP is:

[0030]

[0031] Where, P ref is the bottom hole pressure when backflow starts, P wf (t) is the bottom hole pressure corresponding to time t, q w (t) is the water production rate corresponding to time t;

[0032] The calculation formula of the derivative of the normalized pressure of water production RNP′ is:

[0033]

[0034] In the formula, ln(t c ) is the material equilibrium time t c The natural logarithm of

[0035] Material balance time tc The calculation formula is:

[0036]

[0037] Where Q w (t) is the cumulative water production corresponding to time t.

[0038] Preferably, in S3, the calculation process of the reservoir productivity index is:

[0039] Define the initial data of the near-fracture area, perform characteristic curve analysis on the data of the boundary control flow stage, and draw a functional relationship curve between RNP and standard cumulative water production;

[0040] The functional relationship between RNP and standard cumulative water production is expressed as:

[0041]

[0042] Where c t is the overall compressibility of the system, p i-FBR is the initial pressure near the crack area, m FMB is the slope of the curve, b FMB is the y-intercept of the curve;

[0043] Initial water content in the area near the crack IWIP FBR Expressed as:

[0044]

[0045] J FMB =b FMB ;

[0046] Where, J FMB is the oil well productivity index.

[0047] Therefore, the low-pressure testing method based on reflux flowback of the present invention has the following beneficial effects:

[0048] (1) By adopting the injection / return flowback method, the pressure drop and flowback volume change curves during the return phase are recorded. The test can be completed in just a few hours, avoiding the long-term process of shutting down the well and waiting for the pressure drop in traditional low-pressure testing, and significantly improving the efficiency of the test.

[0049] (2) Through data quality assessment, flow pressure correction, estimation of friction near the wellbore and perforation holes, and a short testing process, errors caused by overestimation of the oil well productivity index and long waiting times can be avoided, the accuracy and reliability of the test results can be improved, and it is helpful to optimize the volume fracturing construction plan and improve the efficiency of oil and gas field development.

[0050] The technical solution of the present invention is further described in detail below through the accompanying drawings and embodiments. BRIEF DESCRIPTION OF THE DRAWINGS

[0051] Figure 1 A schematic diagram of a flow chart of an embodiment of the present invention;

[0052] Figure 2 is a curve showing the relationship between the stable pressure and the reflux volume increment according to an embodiment of the present invention;

[0053] Figure 3 is a double logarithmic curve according to an embodiment of the present invention;

[0054] Figure 4 : is a functional relationship curve between RNP and standard cumulative water production according to an embodiment of the present invention. DETAILED DESCRIPTION

[0055] The technical solution of the present invention is further described below with reference to the accompanying drawings and embodiments.

[0056] In order to make the purpose, technical solutions and advantages of the embodiments of the present invention clearer, the technical solutions in the embodiments of the present invention will be clearly and completely described below in conjunction with the drawings in the embodiments of the present invention. Obviously, the described embodiments are only part of the embodiments of the present invention, not all of the embodiments.

[0057] Example

[0058] Before conducting the test, it is necessary to ensure that all necessary equipment and tools are ready, including pump trucks, fracturing fluid tanks, high-pressure manifolds, pressure gauges, flow meters, etc.; clean the well site to ensure there is enough space for equipment layout and operation; finally, conduct a safety inspection to ensure the safety of the entire testing process.

[0059] like Figure 1 As shown, the present invention provides a low-pressure testing method based on reflux flowback, comprising the following steps:

[0060] S1. Calculate the maximum injection rate and injection volume of the fracturing fluid for the specific reservoir at the well site and determine the pumping time, specifically:

[0061] 1) Based on the radial Darcy flow formula, the maximum injection displacement under specific reservoir conditions can be derived. The calculation formula for the maximum injection displacement is:

[0062]

[0063] Where k is the reservoir permeability, h is the reservoir thickness, and p f is the formation fracture pressure, p i is the original formation pressure of the reservoir, μ is the fluid viscosity, β is the fluid volume coefficient, r e is the discharge radius, rw is the wellbore radius, and S is the skin coefficient.

[0064] 2) The injection volume is calculated according to the volume equation.

[0065] The volume balance equation is:

[0066] Q inj =Q L +Q F ;

[0067] Among them, Q L is the filtration loss, Q F is the volume of fluid in the fracture, Q inj is the injection volume;

[0068] ①Q L The calculation formula is:

[0069] Q L =0.06A pnet Kt / μ;

[0070] Where p net is the net pressure, K is the reservoir permeability, t is the time, A is the fracture surface area, and the calculation formula of A is:

[0071] A=2x f H;

[0072] Where x f is the half length of the crack, H is the height of the crack;

[0073] ②Q L The calculation formula is:

[0074] Q F The calculation formula is:

[0075] Q F =w f A;

[0076] Where w f is the width of the hydraulic fracture during the fracturing process, w f The calculation formula is:

[0077] w f =πp net H(1-v 2 ) / 2000E;

[0078] Where v is the Poisson's ratio of the formation rock, and E is the Young's modulus of the formation rock. This formula can characterize the rock deformation and hydraulic fracture width during fracturing.

[0079] but:

[0080] Qinj =(0.06Ap net Kt / μ)+2x f w f H.

[0081] Given the crack height H and crack half length x f Under the conditions, the injection volume can be estimated, and then the pumping time can be determined by the maximum injection displacement.

[0082] S2. Start the fracturing truck and inject the fracturing fluid according to the results obtained in S1 and record the injection data. After the formation fracture pressure is reached, the pressure drops suddenly. Continue to inject the fracturing fluid for a while to complete the injection. Then, turn off the pump and shut down the well briefly. Immediately perform a constant rate flowback and record the flowback data.

[0083] The constant flowback flow rate is 2%-5% of the maximum injection displacement calculated by S1; the injection data includes the injection pressure and injection flow rate; and the flowback data includes the flowback liquid volume, flowback pressure and flowback rate.

[0084] S3: Perform quality assessment and correction on the data collected in S2. Calculate the closure pressure, reservoir pressure, and reservoir productivity index based on the corrected data and complete the low-pressure test. Specifically:

[0085] 1) The quality assessment process specifically includes: conducting data integrity and continuity assessments to ensure that all injection and flowback data are collected, checking data continuity to ensure there are no obvious omissions or jumps, and identifying and removing abnormal data after reasonable analysis to ensure that they do not affect subsequent calculations;

[0086] 2) The calibration process is as follows:

[0087] Under low return flow rate conditions, the effect of near-wellbore friction on the minimum horizontal stress estimation is negligible; however, during the return flow stage, as the fracture begins to close, the friction of the fluid in the fracture gradually increases, causing the flow velocity in the fracture to drop rapidly and gradually deviate from the velocity measured on the surface. At this time, the wellbore unloading effect dominates, delaying the decline of the flow velocity in the fracture, resulting in a higher flow velocity measured on the surface and an overestimation of the oil well productivity index. Therefore, it is necessary to correct the flow pressure based on the fluid flow velocity in the fracture to prevent the surface measured flow velocity from being too high, which will cause an overestimation of the oil well productivity index. The friction near the wellbore and the perforation hole can be estimated based on the difference in flow pressure to determine whether re-perforation operations are needed.

[0088] 3) The calculation process of closing pressure is:

[0089] Closure pressure is an inherent property of the reservoir and is not affected by the return velocity and flow rate. Incremental flowback method does not require precise control of the return rate. Instead, it measures the increment of the return fluid volume each time and records the stable return pressure of the return pipe at that time. The closure pressure is estimated based on the curve relationship between the stable return pressure and the return fluid volume increment in the return data, such as Figure 2 shown.

[0090] 4) The calculation process of reservoir pressure is:

[0091] ① Using the normalized pressure RNP and the derivative RNP′ of the normalized pressure RNP and the material balance time t c The double logarithmic curve is used to determine the fluid flow state during the reflux process;

[0092] The calculation formula of the normalized pressure RNP of water production is:

[0093]

[0094] Where, P ref is the bottom hole pressure when backflow starts, P wf (t) is the bottom hole pressure corresponding to time t, q w (t) is the water production rate corresponding to time t;

[0095] The calculation formula of the derivative of the normalized pressure of water production RNP′ is:

[0096]

[0097] In the formula, ln(t c ) is the material equilibrium time t c The natural logarithm of

[0098] Material balance time t c The calculation formula is:

[0099]

[0100] Where Q w (t) is the cumulative water production corresponding to time t.

[0101] ② If Figure 3 As shown in Figure 2, the pressure at the point where the control flow begins to appear near the fracture boundary in the double logarithmic curve (the starting point of FR6) is selected as the estimated reservoir pressure. This point indicates that the dominant effect of the near-fracture region begins to subside and the reservoir pressure begins to dominate the flow of fluid. At the same time, the double logarithmic curve can also determine the closure pressure, that is, the starting point of FR4, indicating that the fracture is mechanically closed.

[0102] 5) If Figure 4 As shown in Figure 2, the calculation process of the reservoir productivity index is:

[0103] Perform characteristic curve analysis on the data of the boundary control flow stage, define the initial data of the near-fracture area, including the original pressure, compressibility and water compressibility of the near-fracture area, and plot RNP and standard cumulative water production. The functional relationship curve is expressed as:

[0104]

[0105] Among them, c t is the overall compressibility of the system, p i-FBR is the initial pressure near the crack area, m FMB is the slope of the curve, the x-intercept of the curve That is the initial water content IWIP in the area near the crack FBR , y-intercept b FMB , which is the oil well productivity index J FMB estimated value of;

[0106] System overall compressibility c t The calculation formula is:

[0107] C t =C w +C FBR ;

[0108] Where C w is the compressibility of water, C FBR It is the compressibility of the formation in the area near the fracture.

[0109] In addition, flowback data can also be used to calculate parameters such as formation pressure, fluid efficiency, fluid loss coefficient, and permeability.

[0110] Therefore, the present invention provides a low-pressure testing method based on reflux flowback. By adopting an injection / reflux reflux flowback method, the pressure drop and flowback volume change curves during the reflux stage are recorded. The test can be completed in just a few hours, avoiding the long process of shutting down the well to wait for the pressure drop in traditional low-pressure testing, and significantly improving the efficiency of the test.

[0111] By assessing data quality, correcting flow pressure, estimating friction near the wellbore and perforations, and completing a short testing process, errors caused by overestimating the well productivity index and long waiting times can be avoided, improving the accuracy and reliability of test results, and helping to optimize volume fracturing construction plans and enhance the efficiency of oil and gas field development.

[0112] Finally, it should be noted that the above embodiments are only used to illustrate the technical solutions of the present invention rather than to limit the same. Although the present invention has been described in detail with reference to the preferred embodiments, those skilled in the art should understand that they can still modify or replace the technical solutions of the present invention with equivalents, and these modifications or equivalent replacements cannot cause the modified technical solutions to deviate from the spirit and scope of the technical solutions of the present invention.

Claims

1. A low-pressure test method based on reflux flowback, characterized in that: The following steps are involved: S1. Calculate the maximum injection rate and injection volume of the fracturing fluid for the well site reservoir and determine the pumping time; S2. Inject the fracturing fluid according to the result obtained in S1 and record the injection data. After the injection of the fracturing fluid is completed, shut down the well briefly and immediately perform a constant flowback, and record the flowback data. S3: Perform quality assessment and correction on the injection data and flowback data collected in S2. Calculate the closure pressure, reservoir pressure, and reservoir productivity index based on the corrected data to complete the low-pressure test. The quality assessment process specifically includes: conducting data integrity and continuity assessments, identifying and removing abnormal data; The calibration process is as follows: During the flowback phase, the fluid velocity in the fracture decreases. The fluid velocity in the fracture is measured, and the flow pressure is corrected based on the fluid velocity in the fracture. The friction near the wellbore and the perforation holes is estimated based on the difference in flow pressure to determine whether re-perforation is needed. The calculation process of closing pressure is as follows: using the incremental flowback method, the closing pressure is estimated based on the curve relationship between the stable flowback pressure and the flowback fluid volume increment in the flowback data; The calculation process of reservoir pressure is: 1) The fluid flow state during the reflux process is determined using the double logarithmic curves of the normalized pressure of water production and the derivative of the normalized pressure of water production and the material balance time; 2) Select the pressure at the point where the controlled flow just begins to appear near the boundary of the fracture area in the double logarithmic curve as the estimated reservoir pressure; The calculation process of reservoir productivity index is: The characteristic curve analysis is performed on the data of the boundary control flow stage to define the initial data of the near-crack area, including the original pressure, compressibility and water compressibility of the near-crack area, and draw the Compared with the standard cumulative water production The functional relationship curve is expressed as: ； Where, is the pressure-normalized water production rate, is the overall compressibility of the system, is the initial pressure near the crack area, is the slope of the curve, is the y-intercept of the curve; for The cumulative water production corresponding to the time, for The bottom hole pressure corresponding to the time; Initial water content near the crack area Expressed as: ； ； Where, is the oil well productivity index.

2. A low-pressure testing method based on reflux flowback according to claim 1, characterized in that: In S1, the calculation formula for the maximum injection displacement is: ； Where, is the maximum injection displacement, is the reservoir permeability, is the reservoir thickness, is the formation fracture pressure, is the original formation pressure of the reservoir, is the fluid viscosity, is the fluid volume coefficient, is the discharge radius, is the wellbore radius, is the skin factor.

3. The low-pressure testing method based on reflux flowback according to claim 2, characterized in that: In S1, the calculation formula for the injection amount is: ； Where, is the injection volume, is the crack surface area, is the net pressure, is the reservoir permeability, For time, The crack is half length, is the crack height, is the width of the hydraulic fracture during the fracturing process, The calculation formula is: ； Where, is the Poisson's ratio of the formation rock, is the Young's modulus of the formation rock.

4. The low-pressure testing method based on reflux flowback according to claim 1, characterized in that: In S2, the constant flowback flow rate is 2%-5% of the maximum injection displacement calculated in S1.

5. The low-pressure testing method based on reflux flowback according to claim 1, characterized in that: In said S2, the injection data includes injection pressure and injection flow rate; Flowback data includes flowback volume, flowback pressure and flowback rate.

6. The low-pressure testing method based on reflux flowback according to claim 1, characterized in that: The calculation formula for the water production normalization pressure is: ； Where, To normalize the water production pressure, is the bottom hole pressure when backflow starts, for The bottom hole pressure corresponding to the time, for The water production rate corresponding to the moment; The formula for calculating the derivative of the normalized pressure of water production is: ； Where, is the derivative of the normalized pressure of water production, is the material equilibrium time The natural logarithm of The calculation formula for material balance time is: ； Where, is the material equilibrium time, for The cumulative water production corresponding to the time.

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