Method for identifying steamflood front in horizontal wells

Abstract

The present application relates to the field of heavy oil thermal recovery, and discloses a method for identifying steam drive thermal front of horizontal well, comprising the following steps: S1, fitting flow pressure difference integral and cumulative injection relationship curve, namely integral curve, according to steam drive production dynamic data; S2, calculating first order numerical derivative of integral curve according to the integral curve; S3, identifying whether steam cavity is formed in the reservoir by combining the integral curve and the first order derivative curve and based on the pseudo-steady-state percolation theory; S4, calculating the steam cavity expansion radius according to production data after the steam cavity is formed in the reservoir. The method can accurately identify the phase state change of displacement front, improve the identification accuracy, provide basis and support for the field application of steam drive in offshore heavy oil thermal recovery, and fill the gap of interwell monitoring.

Description

Technical Field

[0001] This invention relates to the field of heavy oil thermal recovery, specifically to a method for identifying the steam drive front of a horizontal well. Background Technology

[0002] When using horizontal well steam drive technology to develop offshore heavy oil reservoirs, the lack of identification methods commonly used in onshore oilfields, such as observation wells or 4D seismic data, currently necessitates relying primarily on single numerical simulation methods for displacement front prediction. However, during field development, timely and accurate dynamic identification of the displacement front, combined with production dynamic data, is essential. This provides theoretical support for determining the formation of steam drive and enables further precise control to ensure the successful implementation of steam drive.

[0003] Integral curves are a commonly used characteristic curve for water-driven states. By observing the relationship between the integral of the flow pressure difference and the cumulative injection volume, changes in the vapor chambers that may occur within the formation can be analyzed. However, in offshore heavy oil development, conventional integral curves often obscure some key indicative information due to thermal effects, resulting in indistinct curve slope changes and an inability to accurately identify the physical state changes at the displacement front. Summary of the Invention

[0004] The purpose of this invention is to overcome the problem that the existing technology of identifying physical changes at the displacement front through integral curves is not very accurate, and to provide a method for identifying the steam-driven thermal front of horizontal wells. This method can accurately identify the physical changes at the displacement front, improve the identification accuracy, provide a basis and support for the field application of steam drive in offshore heavy oil thermal recovery, and fill the gap in inter-well monitoring.

[0005] To achieve the above objectives, the present invention provides a method for identifying the steam-driven front of a horizontal well, comprising the following steps:

[0006] S1. Fit the curve of the relationship between the integral of the flow pressure difference and the cumulative injection volume based on the dynamic data of steam-driven production, i.e., the integral curve;

[0007] S2. Calculate the first numerical derivative of the integral curve based on the integral curve.

[0008] S3. Combine the integral curve and the first derivative curve, and based on the quasi-steady-state seepage theory, identify whether a vapor cavity has formed in the reservoir.

[0009] S4. After a steam cavity is formed in the reservoir, the expansion radius of the steam cavity is calculated based on production data.

[0010] Preferably, in step S1, the steam-driven production dynamic data includes daily injection data and injection pressure data.

[0011] More preferably, the method for fitting the relationship curve between the integral of the flow pressure difference and the cumulative injection volume based on daily injection data and injection pressure data includes:

[0012] S11. Calculate the cumulative injection amount using daily injection data;

[0013] Calculate the integral of the flow pressure difference using the injection pressure data;

[0014] S12. Fit the relationship curve between the integral of the flow pressure difference and the cumulative injection volume.

[0015] More preferably, in step S11, the formula for calculating the cumulative injection amount using daily injection data is:

[0016] W it =∫i w dt;

[0017] In the formula, W it i represents the cumulative injection amount. w t represents the daily injection volume, and t represents time.

[0018] Preferably, in step S11, the formula for calculating the integral of the flow pressure difference using the injected pressure data is:

[0019] PI=∫(P wf -P e )dt;

[0020] In the formula, PI is the integral of the flow pressure difference, P wf For the bottom hole flowing pressure, P e To inject leading-edge pressure, (P wf -P e ) represents the injection pressure difference, and t represents time.

[0021] Preferably, in step S2, the formula for calculating the first numerical derivative of the integral curve based on the integral curve is:

[0022]

[0023] FD HIn =0, ((W it ) n =(W it ) n-1 );

[0024] In the formula, FD HIn PI represents the first-order numerical derivative of the integral curve at different time steps. n PI n-1 The integrals of the flow pressure difference at the nth and (n-1)th points are respectively, (W i t) n 、(W it) n-1 These represent the cumulative injection amounts at the nth and (n-1)th points, respectively.

[0025] Preferably, in step S3, the method of combining the integral curve and the first derivative curve includes: plotting the integral curve and the first derivative curve on a single graph, with the cumulative injection volume as the horizontal axis, placing the flow pressure difference integral and the first derivative in a coordinate system, and combining the integral curve and the first derivative curve.

[0026] More preferably, in step S3, the method for identifying whether a vapor cavity has formed in the reservoir includes: when the integral curve and the first derivative curve completely coincide, a vapor cavity has not formed in the reservoir; when the first derivative curve is above the integral curve, a vapor cavity has formed in the reservoir and is gradually expanding; when the first derivative curve is below the integral curve, a vapor cavity has not formed in the reservoir.

[0027] Preferably, in step S4, the method for calculating the expansion radius of the steam cavity based on production data includes: calculating the dynamically changing expansion radius of the steam cavity based on the cumulative injection volume after the formation of the steam cavity.

[0028] More preferably, the formula for calculating the dynamically changing expansion radius of the steam cavity based on the cumulative injection volume after the formation of the steam cavity is as follows:

[0029]

[0030] In the formula, W is R represents the cumulative injection volume after the steam cavity is formed. eh Where is the radius of the steam chamber leading edge, B is the crude oil expansion coefficient, 2L is the horizontal well length, and h is the reservoir thickness. Porosity, S or This represents the residual oil saturation.

[0031] Through the above technical solution, the identification method provided by this invention can identify the thermal front in real time using integral curves and their first derivative curves, and can accurately calculate the expansion range of the steam cavity, improving identification accuracy. Based on this, the injection regime can be accurately implemented and adjusted in a timely and precise manner, thereby effectively ensuring the smooth implementation of steam drive. The identification method provided by this invention has a wide range of applications and is flexible in use, providing a basis and support for the field application of steam drive in offshore heavy oil thermal recovery, filling the gap in inter-well monitoring. Attached Figure Description

[0032] Figure 1 This is a curve showing the integral of the steam-driven injection pressure difference as a function of the cumulative injection volume in a heavy oil reservoir at sea.

[0033] Figure 2This is the curve showing the change of the first numerical derivative of the steam drive of a heavy oil reservoir at sea as a function of the cumulative injection volume.

[0034] Figure 3 This is a comparison curve of the integral of the steam-driven injection pressure difference and the first numerical derivative of the steam injection volume in a heavy oil reservoir at sea as a function of the cumulative injection volume.

[0035] Figure 4 This is a curve showing the change in the radius of the leading edge of the steam chamber of a heavy oil reservoir at sea over time. Detailed Implementation

[0036] The endpoints and any values ​​of the ranges disclosed herein are not limited to the precise ranges or values, and these ranges or values ​​should be understood to include values ​​close to these ranges or values. For numerical ranges, the endpoint values ​​of the various ranges, the endpoint values ​​of the various ranges and individual point values, and individual point values ​​can be combined with each other to obtain one or more new numerical ranges, which should be considered as specifically disclosed herein.

[0037] As mentioned above, the basic embodiment of the present invention provides a method for identifying the steam drive front of a horizontal well, such as... Figure 1 As shown, it includes the following steps:

[0038] S1. Fit the curve of the relationship between the integral of the flow pressure difference and the cumulative injection volume based on the dynamic data of steam-driven production, i.e., the integral curve;

[0039] S2. Calculate the first numerical derivative of the integral curve based on the integral curve.

[0040] S3. Combine the integral curve and the first derivative curve, and based on the quasi-steady-state seepage theory, identify whether a vapor cavity has formed in the reservoir.

[0041] S4. After a steam cavity is formed in the reservoir, the expansion radius of the steam cavity is calculated based on production data.

[0042] The identification method provided in the above-described basic embodiments of the present invention identifies the thermal front in real time through integral curves and their first derivative curves, and can accurately calculate the expansion range of the steam chamber. Based on this, the injection regime can be accurately implemented and adjusted in a timely and precise manner, thereby effectively ensuring the smooth implementation of steam drive. Moreover, the identification method provided by the present invention has a wide range of applications and is flexible in use, providing a basis and support for the field application of steam drive in offshore heavy oil thermal recovery, filling the gap in inter-well monitoring.

[0043] In one specific embodiment of the present invention, in step S1, the steam-driven production dynamic data includes daily injection data and injection pressure data. The cumulative injection volume and the integral of the flow pressure difference can be accurately calculated using the daily injection data and injection pressure data, thereby making the relationship curve between the integral of the flow pressure difference and the cumulative injection volume closer to the actual data, and thus enabling accurate identification of whether a steam cavity has formed in the reservoir.

[0044] Specifically, the method for fitting the relationship curve between the integral of the flow pressure difference and the cumulative injection volume based on daily injection data and injection pressure data includes: S11, calculating the cumulative injection volume using daily injection data; calculating the integral of the flow pressure difference using injection pressure data; S12, fitting the relationship curve between the integral of the flow pressure difference and the cumulative injection volume. More specifically, in step S11, the formula for calculating the cumulative injection volume using daily injection data is: W it =∫i w dt; where W it i represents the cumulative injection amount. w Where t is the daily injection volume and t is time. The formula for calculating the integral of the flow pressure difference using the injection pressure data is: PI=∫(P wf -P e )dt; where PI is the integral of the flow pressure difference, P wf For the bottom hole flowing pressure, P e To inject leading-edge pressure, (P wf -P e ) represents the injection pressure difference, and t represents time.

[0045] In one specific embodiment of the present invention, it further includes a relationship curve between the integral of the flow differential pressure and the cumulative injection volume, in which PI is the vertical axis and W... it The x-axis represents the slope of the curve, which changes in real time with the injection dynamics.

[0046] In one specific embodiment of the present invention, in step S2, the method for calculating the first-order numerical derivative of the integral curve based on the integral curve includes: calculating the slope between two consecutive points based on the integral curve to obtain the first-order numerical reciprocal of the integral curve. Specifically, the formula for calculating the first-order numerical derivative of the integral curve based on the integral curve is:

[0047]

[0048] FD HIn =0, ((W it ) n =(W it ) n-1 );

[0049] In the formula, FD HInPI represents the first-order numerical derivative of the integral curve at different time steps. n PI n-1 The integrals of the flow pressure difference at the nth and (n-1)th points are respectively, (W it ) n 、(W it ) n-1 These represent the cumulative injection amounts at the nth and (n-1)th points, respectively.

[0050] Specifically, when (W it ) n ≠(W it ) n-1 When the integral curve is calculated, the formula for calculating the first numerical derivative of the integral curve is: When (W) it ) n =(W it ) n-1 When the integral curve is calculated, the formula for calculating the first-order numerical derivative of the integral curve is: FD HIn =0. It can accurately calculate the first numerical derivative of the integral curve.

[0051] As a specific embodiment of the present invention, in step S3, the method of combining the integral curve and the first derivative curve includes: plotting the integral curve and the first derivative curve on a single graph, with the cumulative injection volume as the horizontal axis, placing the integral of the flow pressure difference and the first derivative in a coordinate system, and combining the integral curve and the first derivative curve. The method for identifying whether a vapor cavity has formed in the reservoir includes: when the integral curve and the first derivative curve completely coincide, no vapor cavity has formed in the reservoir; when the first derivative curve is above the integral curve, a vapor cavity has formed and is gradually expanding in the reservoir; when the first derivative curve is below the integral curve, no vapor cavity has formed in the reservoir. The above method can accurately determine whether a vapor cavity has formed in the reservoir.

[0052] Specifically, when the first derivative curve is above the integral curve, the integral curve opens upwards; when the first derivative curve is below the integral curve, the integral curve opens downwards.

[0053] In one specific embodiment of the present invention, in step S4, the method for calculating the expansion radius of the steam cavity based on production data includes: calculating the dynamically changing expansion radius of the steam cavity based on the cumulative injection volume after the formation of the steam cavity. Specifically, the formula for calculating the dynamically changing expansion radius of the steam cavity based on the cumulative injection volume after the formation of the steam cavity is as follows:

[0054]

[0055] Among them, W isR represents the cumulative injection volume after the steam cavity is formed. eh Where is the radius of the steam chamber leading edge, B is the crude oil expansion coefficient, 2L is the horizontal well length, and h is the reservoir thickness. Porosity, S or This represents the residual oil saturation.

[0056] According to a particularly preferred embodiment of the present invention, a method for identifying the steam drive front of a horizontal well is provided, comprising the following steps:

[0057] S1, according to formula W it =∫i w dt(W it i represents the cumulative injection amount. w (where t is the daily injection volume and t is the time) The cumulative injection volume is calculated using the daily injection data in the dynamic data of steam-driven production.

[0058] According to the formula PI=∫(P wf -P e )dt(PI is the integral of the flow pressure difference, P wf For the bottom hole flowing pressure, P e To inject leading-edge pressure, (P wf -P e (where t is the injection pressure difference and t is time) Calculate the integral of the flow pressure difference using the injection pressure data;

[0059] S2. Fit the relationship curve between the integral of the flow pressure difference and the cumulative injection volume, i.e., the integral curve, where PI is the vertical axis and W... it The slope of the curve changes in real time with the injection dynamics, with the x-axis representing the horizontal axis.

[0060] S3. Based on the integral curve, calculate the slope between two consecutive points to obtain the first numerical derivative of the integral curve. The formula for calculating the first numerical derivative of the integral curve is:

[0061]

[0062] FD HIn =0, ((W it ) n =(W it ) n-1 );

[0063] In the formula, FD HIn PI represents the first-order numerical derivative of the integral curve at different time steps. n PI n-1 The integrals of the flow pressure difference at the nth and (n-1)th points are respectively, (W it ) n 、(W it ) n-1These are the cumulative injection amounts at the nth and (n-1)th points, respectively.

[0064] S4. Plot the integral curve and the first derivative curve on the same graph, with the cumulative injection volume as the horizontal axis. Place the integral of the flow pressure difference and the first derivative in the same coordinate system. Combine the integral curve and the first derivative curve. When the integral curve and the first derivative curve completely coincide, no vapor cavity has formed in the reservoir. When the first derivative curve is above the integral curve, a vapor cavity has formed in the reservoir and is gradually expanding. When the first derivative curve is below the integral curve, no vapor cavity has formed in the reservoir.

[0065] S5. After a vapor chamber is formed in the reservoir, according to the formula... (W is R represents the cumulative injection volume after the steam cavity is formed. eh Where is the radius of the steam chamber leading edge, B is the crude oil expansion coefficient, 2L is the horizontal well length, and h is the reservoir thickness. Porosity, S or The dynamically changing steam chamber expansion radius is calculated based on the residual oil saturation.

[0066] The identification method provided by the preferred embodiments of the present invention can identify reservoir thickness h and porosity based on these parameters. Basic physical properties of the block and daily injection volume i w Bottom-hole flowing pressure P wf Injection leading edge pressure P e By analyzing dynamic production data, including integral curves and their first derivative curves, the thermal front can be identified in real time, and the expansion range of the steam cavity can be accurately calculated. Based on this, the injection regime can be accurately implemented and adjusted in a timely and precise manner, thereby effectively ensuring the smooth implementation of steam drive. The identification method provided by this invention has a wide range of applications and is flexible in use. It can provide a basis and support for the field application of steam drive in offshore heavy oil thermal recovery, filling the gap in inter-well monitoring.

[0067] In the development of a heavy oil reservoir at sea, horizontal well steam drive was adopted. Steam injection began in a central horizontal well in June 2020, but due to frequent boiler malfunctions, the injection medium was hot water. In March 2021, after the boiler was replaced, the injection medium changed to steam, with a measured bottomhole dryness of 0.7-0.8. During this period, the daily injection rate was i w =0.6~297.3m3 / d, injection pressure difference (P) wf -P e The injection pressure is 0.8-9.8 MPa, and the specific injection details are shown in Table 1. The horizontal section length of this injection well is 2L = 350 m, the reservoir porosity is φ = 0.34, the oil layer thickness is h = 6.0 m, the volume factor is B = 1.04, and the residual oil saturation during the steam drive stage is S. or =0.

[0068] Based on the daily injection volume, injection pressure differential, and daily injection rate obtained from on-site measurements, the corresponding cumulative injection volume and injection pressure differential integral are calculated, and plotted on a rectangular coordinate system to obtain the injection pressure differential integral - cumulative injection volume curve, as shown below. Figure 1 As shown. Based on the integral of the obtained injection pressure difference, its first numerical derivative is calculated and plotted on a rectangular coordinate system to obtain the first numerical derivative-cumulative injection volume curve, as shown. Figure 2 As shown, neither the single injection differential pressure integral-cumulative injection rate curve nor the first-order numerical derivative-cumulative injection rate curve can effectively identify the steam front due to the thermal effect masking the indicator information.

[0069] Plotting the obtained integral curve and first derivative on a single coordinate system yields the curve of injection pressure differential integral & first-order numerical derivative - cumulative injection volume. The combined results are as follows: Figure 3 As shown in the results, from June 2020 to March 2021, the integral curve and the first derivative curve almost overlapped, indicating that the steam cavity in the reservoir had not yet formed at this time. Due to frequent boiler failures, the injection was in an unstable state, with significant variations in daily injection volume, injection pressure, and daily injection rate, failing to effectively heat the reservoir. After replacing the boiler with a brand new one in March 2021, the first numerical derivative curve was above the integral curve after 16 days, and the curve of injection pressure difference integral & first numerical derivative - cumulative injection volume opened upwards, indicating that the steam cavity began to form and gradually expand, and a steam cavity appeared in the reservoir. The measured bottomhole dryness was between 0.7 and 0.8, confirming the reliability of this identification method.

[0070] The radius of the underground steam cavity expansion front was calculated based on parameters such as the horizontal section length of the injection well, reservoir pore volume, oil layer thickness, volume factor, cumulative steam injection rate, and residual oil saturation during the steam drive stage. The results are as follows: Figure 4 As shown, the current leading edge extension radius is 43 meters. The calculation results of this invention method are basically consistent with the prediction results of traditional reservoir numerical simulation methods.

[0071] Table 1. Steam drive development data of a horizontal well in a heavy oil reservoir at sea.

[0072]

[0073]

[0074]

[0075]

[0076]

[0077]

[0078]

[0079]

[0080]

[0081]

[0082]

[0083] The preferred embodiments of the present invention have been described in detail above; however, the present invention is not limited thereto. Within the scope of the inventive concept, various simple modifications can be made to the technical solutions of the present invention, including combinations of various technical features in any other suitable manner. These simple modifications and combinations should also be considered as the content disclosed in the present invention and are all within the protection scope of the present invention.

Claims

1. A method for identifying the steam-driven heat front of a horizontal well, characterized in that, Includes the following steps: S1. Fit the curve of the relationship between the integral of the flow pressure difference and the cumulative injection volume based on the dynamic data of steam-driven production, i.e., the integral curve; S2. Calculate the first derivative curve of the integral curve based on the integral curve. S3. Combine the integral curve and the first derivative curve, and based on the quasi-steady-state seepage theory, identify whether a vapor cavity has formed in the reservoir; S4. After a steam cavity is formed in the reservoir, the expansion radius of the steam cavity is calculated based on production data; In step S1, the steam-driven production dynamic data includes daily injection data and injection pressure data; Methods for fitting the curve of the relationship between the integral of the flow pressure difference and the cumulative injection volume based on daily injection data and injection pressure data include: S11. Calculate the cumulative injection amount using daily injection data; Calculate the integral of the flow pressure difference using the injection pressure data; S12. Fit the relationship curve between the integral of the flow pressure difference and the cumulative injection volume; In step S3, the method of combining the integral curve and the first derivative curve includes: plotting the integral curve and the first derivative curve on a single graph, with the cumulative injection volume as the horizontal axis, placing the integral of the flow pressure difference and the first derivative in a coordinate system, and combining the integral curve and the first derivative curve; the method of identifying whether a vapor cavity has formed in the reservoir includes: when the integral curve and the first derivative curve completely coincide, a vapor cavity has not formed in the reservoir; when the first derivative curve is above the integral curve, a vapor cavity has formed in the reservoir and is gradually expanding; when the first derivative curve is below the integral curve, a vapor cavity has not formed in the reservoir.

2. The identification method according to claim 1, characterized in that, In step S11, the formula for calculating the cumulative injection amount using daily injection data is: ； In the formula, This is the cumulative injection amount. Daily injection volume t For time.

3. The identification method according to claim 1, characterized in that, In step S11, the formula for calculating the integral of the flow pressure difference using the injected pressure data is: ； In the formula, For the integral of the flow pressure difference, For bottom hole flowing pressure, To inject leading-edge pressure, To inject differential pressure, t For time.

4. The identification method according to any one of claims 1 to 3, characterized in that, In step S2, the formula for calculating the first numerical derivative of the integral curve based on the integral curve is as follows: ， ； ， ； In the formula, For the first-order numerical derivative of the integral curve at different time steps, , The first n The, the n-1 Integral flow pressure difference at each point , The first n The, the n-1 The cumulative injection amount at each point.

5. The identification method according to any one of claims 1 to 3, characterized in that, In step S4, the method for calculating the expansion radius of the steam cavity based on production data includes: calculating the dynamically changing expansion radius of the steam cavity based on the cumulative injection volume after the formation of the steam cavity.

6. The identification method according to claim 5, characterized in that, The formula for calculating the dynamically changing expansion radius of the steam cavity based on the cumulative injection volume after the steam cavity is formed is as follows: ； In the formula, This represents the cumulative injection volume after the steam chamber is formed. The radius of the leading edge of the steam cavity. The coefficient of expansion of crude oil, 2 L For reservoir thickness, Porosity This represents the residual oil saturation.

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