Method for determining fluid flow characteristics of pipeline by utilizing characteristics of pipe waves

Abstract

A method for characterizing a flow characteristic of a fluid within a pipe includes measuring a pressure of the fluid flowing within the pipe. The pressure of the fluid in the pipeline is changed from the first pressure to the second pressure. Pipe waves are generated in the pipeline by changing the pressure. A location along the pipe is determined based on the event in the measured pressure that the pipe wave is generated: (i) the magnitude of the change in the pipe inner diameter, or (ii) the coefficient of friction of the pipe fluid flow. In some embodiments, changing the pressure is achieved by changing the flow rate of the fluid within the conduit.

Description

Technical Field

[0001] This disclosure relates to the field of assessing the flow conditions inside a fluid-filled pipe or conduit (e.g., an underground well or pipeline (buried or exposed)). More specifically, this disclosure relates to methods for assessing the fluid flow characteristics of a conduit by utilizing the pipe wave characteristics generated in the fluid within such conduits, such as locating and estimating the amount of diameter reduction caused by the accumulation of scale or other diameter-reducing substances, or the increased frictional resistance to fluid flow due to increased surface roughness of the pipe caused by corrosion. Background Technology

[0002] In wells drilling through underground formations to extract oil and gas, it is common for the tubing (such as casing, liners, or tubing) to accumulate a substance known as scale. The main types of scale in these oil and gas production wells include mineral scale, bituminous and other organic scale often found in produced water, as well as diameter-reducing natural gas hydrate aggregates. Common locations for scale buildup in these wells include: where the tubing penetrates the bottom of the water column, at the far end of the well, near the well's surface outlet, and in surface collection and piping facilities. Scale is also known to accumulate in other pipelines, such as sewers, gas lines, water pipes, food processing lines, or other pipelines transporting slurries.

[0003] There are many reasons why scale buildup occurs in pipelines, one of which is chemical imbalance, which can be exacerbated by pressure or temperature changes or the mixing of different fluids. Therefore, scale buildup can be related to valves, pipe connections, inlets / outlets of pipes or wells from the outside to the inside, junctions of multiple fluids, and other devices.

[0004] Scale buildup reduces the inner diameter of affected pipes, thereby reducing the flow area. This reduced flow area leads to a greater pressure drop between the inlet and outlet of the affected pipe. In producing wells, the inlet pressure is determined by reservoir conditions, and the outlet pressure cannot be less than zero; therefore, scale buildup hinders fluid production from the underground reservoir.

[0005] In wells used for injecting fluids into underground formations, such as for water injection or other secondary / tertiary oil recovery methods, or for waste disposal, scale buildup can reduce the pipe diameter, resulting in excessive pressure drop along the well. This makes it impossible to achieve the required fluid injection rate even without an increase in reservoir pressure. Consequently, the pressure required to maintain the injection rate may exceed the pressure limits of the surface equipment used for fluid injection.

[0006] Furthermore, due to the chemical incompatibility between scale and pipeline materials, well pipelines may experience accelerated corrosion; scale buildup can prevent the normal operation of moving parts, for example, a quick-closing valve may become stuck in the open position; and changes in the pipeline's inner diameter can affect the mixing rate of various fluids. Corrosion also increases the surface roughness of the inner walls of pipes or pipelines, thereby reducing flow rate or requiring additional energy to move fluids through the pipes or pipelines.

[0007] Methods and apparatus known in the art for detecting scale and corrosion and characterizing their effects on pipelines include the following:

[0008] This involves inserting measuring or imaging equipment (such as calipers, pigs, or sonic imagers) into the well or pipeline. Limitations of this method include difficulty in accessing the well and operating the equipment (risk of loss or equipment becoming stuck), and the need to stop (shut down) fluid flow in the well or pipeline.

[0009] The pressure drop (ΔP) between two known points is monitored at a known flow rate (Q), and ΔP / Q is calculated. The limitations of the above method and apparatus are that it requires measuring the pressure at different locations and the flow rate Q. For inaccessible pipelines, the system needs to be installed inside the pipeline before installation.

[0010] Conduct well tests and observe early changes in well condition after shut-in. The limitation of this method is the need to shut down the well or pipeline. Restarting flow can damage pipelines and related equipment. This does not include lost production time and related economic losses.

[0011] Therefore, there is a need to improve the technology and equipment to detect and characterize the fluid flow characteristics in wells and pipelines, preferably without shutting them down. Summary of the Invention

[0012] One aspect of this disclosure is a method for determining the fluid flow characteristics of a pipe or conduit. The method includes measuring the pressure of fluid flow within the pipe. The pressure of the fluid within the pipe changes from a first pressure to a second pressure. By changing the pressure, a pipe wave is generated in the pipe. Based on the pipe wave generation event in the measured pressure, the location along the pipe is determined to be at least one of the following: (i) the magnitude of the change in the pipe's inner diameter, or (ii) the coefficient of friction of the fluid flow in the pipe.

[0013] According to another aspect of this disclosure, a non-transient computer-readable medium includes logic operable to cause a programmable computer to perform the operations described above, and in some embodiments, to perform the operations shown below.

[0014] In some embodiments, the pressure change is caused by a change in the flow rate of the fluid in the pipe from a first flow rate to a second flow rate.

[0015] In some embodiments, the amplitude is determined by measuring the rate of change of pressure over time, which is the time between the first pressure change caused by the change in flow rate and the second pressure change caused by the reflection of pipe waves in the pipe.

[0016] In some embodiments, the location is determined by measuring the time between the execution of a flow rate change and the detection of pipe wave reflections caused by the change in inner diameter.

[0017] In some embodiments, the time between performing a flow rate change and detecting pipe wave reflections caused by the change in inner diameter is determined by determining the elapsed time between consecutive peaks or troughs in the time derivative of the measured pressure.

[0018] Some embodiments also include repeatedly measuring the pressure of the flowing fluid at at least one selected time, repeatedly changing the rate from a first rate to a second rate, and determining the position and amplitude along the pipe to characterize the changes in position and amplitude over time.

[0019] In some embodiments, the determination of the location along the pipe and at least one of the following, based on the pipe wave generation event, includes inverting the measured pressure: (i) the magnitude of the pipe inner diameter change or (ii) the fluid flow friction coefficient of the pipe.

[0020] In some embodiments, the inversion process is performed relative to the time derivative of the measured pressure.

[0021] In some embodiments, the pipe diameter and friction coefficient are determined based on a lookup table of pre-calculated pressure changes and pressure decay after pressure drop caused by known flow rates and flow rate changes.

[0022] In some embodiments, the pre-calculated lookup table includes a parameter band related to determining the uncertainty of pressure decay and pressure change.

[0023] Other aspects and potential advantages will become apparent from the following description and claims. Attached Figure Description

[0024] Figure 1 shows a device that can be used to generate tube waves in pipelines (such as underground wells or pipelines) (shown as buried underground, but may also be exposed).

[0025] Figure 2 shows a graph of fluid pressure in the pipe as the flow rate changes from a first value to a second value, where pipe wave events can be detected in the fluid pressure.

[0026] Figure 3 shows the graph of Figure 2 and interprets the pressure response within a specific portion of the graph.

[0027] Figure 4 shows a diagram similar to Figure 3, in which a portion of the pipe has a reduced diameter at one end due to scaling.

[0028] Figure 4A shows a cross-section inside the pipe, which produces the pressure diagram in Figure 4.

[0029] Figure 5 shows a diagram similar to Figure 4, where the reduced diameter portion of the pipe is located between the two ends of the pipe.

[0030] Figure 5A shows a cross-section inside the pipe, which produces the pressure diagram in Figure 5.

[0031] Figure 6 shows a pressure map of a pressure measurement taken at a low rate, which is for a specific example of internal scaling in a pipeline.

[0032] Figure 7 shows a pressure map of pressure measurements sampled at a higher rate than in Figure 6, where specific characteristics of the pressure can be identified.

[0033] Figure 8 shows a flowchart of an exemplary implementation of the inversion process for determining the pipe diameter and friction coefficient.

[0034] Figures 9A, 9B, and 9C show the changes in pressure and the pressure time derivative over time, which are related to the flow / pressure changes in the pipe in response to the first section of the pipe.

[0035] Figures 10A, 10B, and 10C show the changes in pressure and the pressure time derivative over time, which are related to the flow / pressure changes in the pipe in response to the second section of the pipe.

[0036] Figures 11A, 11B, and 11C show the pressure and pressure-time derivative, which are related to the flow / pressure changes in the pipe in response to the second section of the pipe, where the initially selected length of the second section was incorrect.

[0037] Figures 12A and 12B show nodal plots that can be used to determine pipe diameter and friction coefficient based on pressure drop and pre-calculated values ​​of pressure decay after pressure drop under known conditions.

[0038] Figures 13A, 13B, and 13C show nodal plots corresponding to Figures 12A and 12B, where uncertainties exist in determining pressure drops and pressure decays in the pipeline.

[0039] Figures 14A to 14C illustrate how the time derivative of the measured pressure is used to calculate the flow characteristics of a section of the pipeline after a change in its properties.

[0040] Figure 15 illustrates a computer system that can be used to implement the methods of this disclosure. Detailed Implementation

[0041] Figure 1 illustrates an example arrangement of equipment that can be used in the method according to this disclosure. A subsurface well or wellbore 103 (used interchangeably herein) can be drilled through one or more rock formations 108 to recover fluid to the surface or treat fluid pumped from the surface. The surface equipment, generally shown as 100 in the figure, may include a flow control device (not shown separately) capable of changing the flow rate of fluid flowing into formation 108 or out of well 103 to the surface. Such a control device (not shown) may include, for example, pumps, valves, etc. Such a control device only needs to be able to change the flow rate sufficiently quickly and by an amount sufficient to generate a pipe wave 104 propagating in the fluid within well 103, which can be detected by measuring the fluid pressure within well 103. A conduit 105, such as a liner, casing, or tubing, may be inserted into well 103; for convenience, it may be referred to herein as a “conduit” or “pipeline.”

[0042] The device 100 may include one or more pressure sensors and recording devices (not shown separately) for recording changes in fluid pressure in the well 103 over time. According to this disclosure, such recording can be used to determine the location within the well 103 and characterize one or more obstructions 106, such as obstructions 106 that may be caused by fouling or increased surface roughness, thereby reducing the inner diameter of the well 103, thus reducing the effective flow area of ​​the well 103, and / or altering the coefficient of friction of the flowing fluid on the inner surface of the pipe or conduit 105. The recording devices (not shown separately) in the device 100 may be arranged in entirely different locations and are not necessarily part of the device 100.

[0043] Accordingly, in the pipeline or conduit used as pipeline 102, one or more locations along pipeline 102 may be provided with a device 100 that performs a function similar to the device used on well 103 described above. The pipeline device 100 may have a flow control device, a pressure sensor, and a recording device, wherein the flow control device is capable of generating pipe waves in the fluid in pipeline 102. According to this disclosure, one or more flow obstructions 106 in pipeline 102 can be located and characterized using records of pressure changes over time. In this disclosure, such flow obstructions may be due to a reduction in the inner diameter of the pipeline caused by scale buildup.

[0044] Figure 2 shows fluid pressure diagrams before and after a change in the flow rate of a fluid flowing through a conduit (e.g., a well or pipeline as explained in Figure 1). As described above, the fluid flow rate changes rapidly enough to generate pipe waves (e.g., due to water hammer) propagating in the conduit. At 21, the fluid flows at a first rate Q1 until a sudden change in flow rate occurs at 22. In this example, the flow rate decreases from the first flow rate Q1 to a lower second flow rate Q2. The flow rate can be increased according to the scope of this disclosure. At 22, the fluid pressure measured within the conduit (e.g., when the conduit is located in a well, the fluid pressure measured at the surface end as explained in Figure 1) decreases rapidly as the flow rate decreases. Due to the effects of pipe friction on fluid flow and pipe wave propagation within the conduit, at 23, after the change in flow rate, the measured pressure continues to decrease over a period of time. For convenience, this pressure decrease may be referred to herein as "pressure decay". The rate at which the pressure decreases over time is related to the effects of pipe friction on fluid flow and pipe wave propagation. When the pipe wave reaches a location in the pipeline where reflection may occur, such as the formation in the well shown in Figure 1, a location where the fluid flow characteristics of the pipeline change (e.g., a location where the inner diameter changes), or the end of the pipeline shown in Figure 1, the reflected pipe wave eventually reaches the pressure sensor, and a sudden increase in pressure may be observed, as shown at 24, until the pressure stabilizes at the final value at 25. In the pressure measurement section at 25, pipeline friction causes a slight increase in pressure over time. The description herein is based on the process of generating a pipe wave in a well, pipeline, or conduit, based on a decrease in flow rate and the resulting pressure drop. The scope of this disclosure also covers increasing the flow rate by increasing pressure to generate a pipe wave, thereby performing the method according to this disclosure.

[0045] Furthermore, while exemplary embodiments of the methods disclosed herein induce pressure changes by altering the flow rate of fluid within a pipe, the scope of this disclosure also covers inducing pressure changes in a pipe through other means. As an example of such other means, a flow control device, such as a valve, may be located downstream of a pressure sensor (measuring point) in a well or pipeline. In this context, "downstream" refers to a location further away from the reference point along the direction of fluid flow. When these valves open or close, the pressure in the well or pipeline changes accordingly without altering the rate at which fluid enters the pipe upstream of the pressure sensor. Regardless of the method used, whether by changing the flow rate or pressure, it suffices to change the pressure in the well or pipeline, thereby generating pipe waves within the well or pipeline.

[0046] To determine the characteristics of a well or pipeline positioned at a distance dX from a pressure measurement point (i.e., the location of the pressure sensor) (the detection point), it is sufficient to measure the pressure within a short period after a pressure drop (caused by changes in flow rate) that the characteristics of the detection point influence the pressure at the measurement point. The time interval dT between the pressure pulse passing through the measurement point, reflecting from the detection point, and returning to the measurement point can be determined based on the known distance between the detection point and the measurement point, as well as the known pipe wave velocity C. T It is calculated using the following expression:

[0047]

[0048] Before dT, the position beyond the well or pipeline is dX = dT * C. T An object at a distance of 2 / 2 will not affect the pressure measurement because the pressure (pipe) wave must propagate to the detection point and return to the pressure sensor (measurement point) location; the propagation speed of the pressure (pipe) wave cannot exceed the propagation speed of the pipe wave.

[0049] The pressure diagram in Figure 3 has similar characteristics to that in Figure 2 and illustrates the effect of pipe friction on the measured pressure during the time between the change in fluid flow rate and the detection of reflected pipe waves in the measured pressure. At point 31, the fluid flows in the pipe at a first rate Q1. At point 32, the flow rate changes rapidly and significantly enough to generate pipe waves within the pipe. At point 33, the pressure within the pipe continues to decrease due to pipe friction. The pressure reduction within the pipe is related to the following expression:

[0050]

[0051] Where ρ = density; f = pipe friction coefficient; D = pipe diameter; Q = fluid flow rate; L pipe = Pipe length.

[0052] The pressure slope over the time period (between the flow rate change and the return of the reflected tube wave) at point 33 is related to the following:

[0053]

[0054] If the pipe diameter is small or the wellbore friction coefficient is high (e.g., possibly due to surface roughness), the slope of the pressure curve at 33 (during pressure decay), as shown at 38, will be greater. Conversely, a larger pipe diameter or a lower friction coefficient will result in a smaller slope of the pressure curve at 36 when using the interval at 33.

[0055] As shown in segment 35 of the pressure curve, after detecting the reflected pipe wave (34), the characteristics of the pipe friction effect can be that the slope at 35B is greater when the pipe diameter is small, the friction coefficient is large, or both. In the pressure curve segment at 35A, the inverse relationship between diameter and friction effect can be observed.

[0056] Figure 4A shows a cross-section of a section of a pipe or well, where the inner diameter is reduced, for example, due to the accumulation of scale. The illustrated pipe section has its diameter decreasing from the nominal inner diameter D1 towards one end of the pipe to a smaller inner diameter D2 at a certain location. Expected pressure measurements in such a pipe or well can be observed in Figure 4. At 41, the fluid flows in the pipe at a first flow rate Q1, where the pressure is as shown. At 42, in this example, the flow rate changes to a lower rate Q2 to generate pipe waves in the pipe. The instantaneous pressure drop Δp within the pipe... inst Related to the following expressions:

[0057]

[0058] Where C T Here, ρ is the propagation velocity of the pipe wave in the fluid, A1 is the cross-sectional area of ​​the larger diameter section of the pipe (e.g., the section unaffected by fouling), and ΔQ is the change in fluid flow rate. It should be understood that to determine the various fluid frictional characteristics of a pipe or conduit, the propagation velocity C of the fluid must be obtained. T And a reasonably accurate value for density ρ. The above expression can be rewritten as:

[0059]

[0060] Allows for changes in flow rate ΔQ (e.g., which can be directly measured using a flow meter) and pressure Δp. inst To calculate C T Density can be determined by measuring a fluid sample, or it can be known in advance based on the fluid composition; alternatively, it can be derived without knowing the density by the propagation time of a reflected pressure wave event to a known feature in the well or pipeline. T The expression is C t =2*DX / TWT, where DX is the distance between the measurement point and the feature (reflection point), and TWT is the two-way propagation time of the tube wave between these two locations. Combining the latter method with the former method allows for the simultaneous determination of fluid density and tube wave propagation velocity.

[0061] The time between the change in flow rate and the detection of reflected pipe waves can be related to the pressure response corresponding to the change in inner diameter, as shown in Figure 4A. At 43A, the pressure continues to decrease after the change in flow rate due to pipe friction effects in the larger diameter section of the pipe (D1 in Figure 4A) (e.g., the section of the pipe unaffected by scaling). The rate of pressure change at 43A is related to the following:

[0062]

[0063] Where f1 is the friction coefficient of the larger diameter (D1) portion of the pipe. At 43°C, a sudden pressure drop occurs due to the pipe wave acting on the change in pipe diameter. As shown in Figure 4A, this may occur, for example, when scaling begins in the pipe. The magnitude of the pressure drop at 43°C is related to the change in pipe diameter and the change in flow rate as shown in the following expression:

[0064]

[0065] Where A2 is the cross-sectional area of ​​the portion of the pipe where the diameter decreases (D2).

[0066] At point 43B, the pressure measured in the pipe can continue to decrease, but due to the increased frictional effect in the smaller diameter section (D2) of the pipe, the rate of pressure decrease can differ from (e.g., be greater) than the pressure curve at point 43A. The rate of pressure change at point 43B is related to the following:

[0067]

[0068] Where f2 is the friction coefficient of the smaller diameter (D2) portion of the pipe.

[0069] The reflected tube wave can manifest as a pressure increase at 44, after which, for the same reasons explained in Figures 2 and 3, the pressure can continue to increase at 45.

[0070] Figure 5A illustrates another example where the pipe's inner diameter may be reduced, for example, from the nominal inner diameter D1 to a smaller diameter D2 due to scaling, but this is an intermediate section located between the two ends of the pipe. As shown in Figure 5, the fluid pressure measured in the pipe can include responses at 51, 52, 54, and 55, which are due to the change in flow rate from Q1 to Q2, corresponding to the pressure responses explained with reference to 41, 42, 44, and 45 in Figure 4.

[0071] In Figure 5, the time interval between the pressure drop at 52 caused by the change in flow rate and the reflected pipe wave response (i.e., pressure decay) at 54 can have several different characteristics related to the diameter change shown in Figure 5A. At 53A, the pressure continues to decrease at a rate corresponding to the friction in the larger diameter section (D1) of the pipe. The rate of pressure decrease is related to the following:

[0072]

[0073] The reason is the same as explained in Figure 4. Accordingly, at 53C1, a sudden pressure drop may occur as the pipe wave effect diameter decreases to the beginning of D2. The magnitude of the pressure drop is essentially the same as explained with reference to Figure 4:

[0074]

[0075] At point 53D, due to increased fluid friction in the smaller diameter section of the pipe, the fluid pressure inside the pipe decreases at a greater rate, similar to the situation explained with reference to Figure 4:

[0076]

[0077] At point 53C2, the pipe diameter may return to its nominal value (or another intermediate diameter), for example, due to the end of scaling. This diameter change may be accompanied by a sudden increase in pressure, which is essentially the opposite of the pressure drop at point 53C1. After such a period of time, at point 53B, the fluid pressure will decrease, but at a slower rate. If the pipe diameter returns to its nominal value and the surface roughness does not increase, i.e., the coefficient of friction is the same as that of the portion of the pipe before the diameter reduction, the pressure drop will return to the rate before scaling at point 53A.

[0078] Figures 6 and 7 provide examples of pressure response to changes in flow rate in a subsurface well, where the diameter decreases due to scaling, resulting in a reduction in the inner diameter. While this example illustrates a well and the discussion focuses on wells, pipelines or other conduits or pipes with similar characteristics will exhibit essentially the same pressure behavior. The illustrated example represents a well with a casing (the inserted pipe) extending from the surface to a depth of 6,900 feet (2,103 meters). The nominal inner diameter of the casing is 6.1 inches (15.5 centimeters). From 6,900 feet to a total well depth of 21,000 feet (6,401 meters), the well inner diameter decreases to 4.67 inches (11.9 centimeters). This simulates the effect of a sudden buildup of scale below 6,900 feet, approximately 0.7 inches thick, well within the range of the examples explained with reference to Figures 4 and 5.

[0079] For the illustrated example, Figure 6 shows a graph of the fluid flow rate at 61 and the measured pressure at 62 as a function of time. In this example, the flow rate changes from a first flow rate Q1 to a lower flow rate Q2 at 63. The sampling rate of the measured pressure at 62 is less than the timescale of some pressure responses caused by characteristics in the well. This pressure response can be observed in more detail in Figure 7, which shows the measured pressure sampled at a higher rate in the well, where this pressure response is detectable. Therefore, for the purposes of this disclosure, it is important to sample pressure measurements at a sufficiently high rate to detect certain responses in the pressure measurements that would be masked if the pressure measurements were sampled at an insufficient rate. If flow rates are measured, these measurements only need to be sampled at a rate sufficient to characterize the change in flow rate from a first flow rate Q1 to a second lower flow rate Q2.

[0080] At point 71, the measured pressure remains stable at the first fluid flow rate Q1. At point 72, the fluid flow changes from Q1 to Q2. At point 73, the pressure change (decrease) can be attributed to the change in flow rate from Q1 to Q2. Point 74 indicates the time it takes for the fluid flow rate to reach Q2. Point 75 shows the pressure decay, i.e., the period during which the pressure continues to decrease as water hammer propagates downwards through the nominal diameter section of the well due to pipe friction.

[0081] Point 76 represents the time it takes for the pressure pulse (tube wave) to reach the measurement point due to reflection from the proximal end (top) of the diameter-reducing section; the propagation time of the reflected tube wave is equal to the time at point 76 minus the time at point 72. This propagation time can be used to determine the axial location along the diameter reduction of the well or pipe. This location can be calculated as follows: C T The velocity is the tube wave velocity.

[0082] Reference numeral 77 indicates that after scaling begins, the reflected pressure continues to decrease due to the change in diameter.

[0083] Figure 78 indicates the time it takes for the pressure drop endpoint (corresponding to point 74) to reach the pressure measurement point in the form of a reflected pipe wave. This is in accordance with the time difference T of pulse propagation caused by fluid-pipe friction effects. 77 –T 76 Then, the ratio (T) 77 –T 76 ) / (T 74 –T 72 It contains information about the reflector (abrupt diameter changes and distributed diameter changes).

[0084] The attached figure, labeled 79, indicates the period of time during which the pressure in the well section below the reflector drops due to friction.

[0085] The reference numeral 80 in the attached figure indicates a pressure drop that begins to be reflected from the "end" of the well.

[0086] Reference numeral 81 indicates the time when the endpoint of the reflected tube wave reaches the pressure sensor. The characteristics of the pressure signal at 78, 79, and 80 can be used to provide detailed information about the characteristics of the bottom hole tube wave reflector; however, these characteristics are not necessary for performing the methods of this disclosure.

[0087] The above method can be repeated at different times to characterize the changes in pipeline flow characteristics over time, such as the accumulation of scale or the increase in surface roughness.

[0088] Referring to Figure 8, in an exemplary implementation of the method disclosed herein, an inversion process can be used to determine the length and friction coefficient of one or more pipe segments, each with a different inner diameter and friction coefficient. The inversion process can use forward modeling to simulate pressure changes over time at selected locations on the pipe (e.g., measurement points), referencing changes in the flow rate or pressure of the fluid within the pipe. Forward modeling can be performed, for example, using the simulation methods described in the following paper: Dunham, EM, J. Zhang, D. Moos (2023), Constraints on pipe friction and perforationcluster efficiency from water hammer analysis, SPE-212337-MS, published at the SPE Hydraulic Fracturing Technology Conference and Exhibition in Woodlands, Texas, USA, doi 10.2118 / 212337-MS.

[0089] Pressure can be measured at selected locations along the pipe, as shown at 800. At 802, the flow rate of the fluid can be changed by closing or opening a valve, thereby generating a pressure change in the pipe of sufficient magnitude and duration to produce a pipe wave.

[0090] At point 804, pressure measurement can continue until no reflected wave events in the pipe can be detected in the measured pressure. This can be determined, for example, by setting a pressure change (amplitude) threshold; any pressure changes below this threshold will not be used.

[0091] An initial model of the pipeline can be generated at point 806. The initial model may contain one or more pipeline segments, each with a length, inner diameter, and coefficient of friction. The initial model should include at least the pipeline segment closest to the measurement point. The initial model can be used as input to a forward model. The output of the forward model includes a representation of the expected pressure within the pipeline at the measurement point over time. Parameters in the initial model may include the length of at least one pipeline segment, an estimate of the inner diameter of at least one pipeline segment, and an estimate of the coefficient of friction of at least one pipeline segment. In some embodiments, the initial model may be constrained, for example, by prior knowledge of the nominal inner diameter of the pipeline near the measurement point.

[0092] At point 808, the initial model is input into the forward model, and at point 810, the expected pressure over time is calculated. The calculated pressure is compared with the measured pressure. At point 812, the initial model is adjusted by changing the inner diameter and the coefficient of friction; at point 814, the adjusted initial model is input into the forward model, and the expected pressure over time is recalculated. At point 816, the initial model is adjusted as described above, the expected pressure over time is calculated, and the expected pressure and the measured pressure are repeatedly compared until the difference between the expected pressure and the measured pressure is minimized or falls below a selected threshold.

[0093] As mentioned above, during pressure measurement, it may be observed that there are other sections in the pipe further away from the measurement point with different flow characteristics (e.g., inner diameter and coefficient of friction). At 818, for each such additional section identified in the pressure measurement, the above-described inversion process from 806 to 816 in Figure 8 can be repeated until the measured pressure matches the expected pressure in or along all identified sections in the pipe.

[0094] In some embodiments, the pressure time derivative (dp / dt) can be modeled instead of the pressure itself. Alternatively, the time derivative of the measured pressure can be calculated to perform the inversion process described with reference to Figure 8. Utilizing the pressure time derivative can help determine the timing and magnitude of specific events in the pressure data; for example, pipe waves might occur at points in time caused by changes in flow rate and the resulting pressure. Referring to Figure 9A, the measured pressure in the pipe before and after a change in flow rate is shown at 900. The expected pressure calculated using the forward model is shown at 901. An initial value for the friction coefficient (which can remain constant over the entire pipe length or a relevant pipe segment) is input into the forward model. 904 in Figure 9C shows the initial value of the pipe inner diameter input into the forward model. Figure 9B shows the pressure measurement from Figure 9A converted to the time derivative form at 902. The point in time when a change in flow rate might produce a pipe wave is shown as the trough at 903. Figure 905 shows the pressure-time derivative after the pressure stops decreasing due to the change in flow rate, where the sustained pressure change (represented by a slightly negative dp / dt value) indicates the presence of frictional pressure loss in the reflected pipe wave event. When the pipe diameter and friction coefficient values ​​for the first segment are correct, the dp / dt curve calculated by the forward model will match the dp / dt curve calculated based on the measured pressure, at least at the end of the first pipe segment.

[0095] Figure 10A shows the measured pressure 1014 and the model pressure 1012, where at least the second pipe segment can be identified in the pressure measurement because the fluid flow characteristics of the second segment are different from those of the first segment. Figure 10B shows the corresponding dp / dt curves, where the timing of the second pipe event is correct, but the amplitude of the second event is incorrect. Figure 10C shows the model pipe characteristics (e.g., inner diameter) and the actual pipe diameter at 1020 and 1022, respectively. The model pipe friction coefficient and the actual pipe friction coefficient are also shown in the figure. In the first segment, the diameter and friction coefficient of the model pipe and the actual pipe are the same, but in the second segment, the friction coefficient and diameter values ​​of the model pipe and the actual pipe are different. The connection position between the segments is correct (Figure 10C), and the timing of the reflection from the end of the first segment is correct (Figures 10A and 10B). Figure 11A shows similar pipe pressure data at 1126 and 1124, where the differences between the pipe characteristics (e.g., inner diameter) shown in Figure 11C are different from those shown in Figure 10C. Figure 11B shows the timing and amplitude of events in the dp / dt data matching between the forward model and the measured pressure, from which it can be inferred that the pipe characteristics (diameter and coefficient of friction) have been correctly determined.

[0096] In some embodiments, known values ​​of the initial flow rate, the final flow rate after the flow rate change, fluid characteristics, pipe diameter range, and friction coefficient range can be used as inputs to pre-calculate a lookup table of characteristics that can be measured in the pipe.

[0097] Figure 12A shows a graph (nomial plot) of such pre-calculated values. For Figure 12A, the pipe diameter can range from 2 to 5 inches (50 mm to 125 mm), and the f value ranges from 0.0005 to 0.05. The initial flow rate is 10 bbls / min. A flow rate variation of 2 bbls / min is applied to the flowing fluid. The contour lines in Figure 12A define the values ​​of pressure decay, see, for example, 905 in Figure 9B, which is the initial pressure drop due to the flow rate variation; the pressure decay is in psi / s. The values ​​in Figure 12A can be calculated using known input values ​​of the initial flow rate, flow rate variation, and fluid properties. The above parameters can be input into the forward model as described above, and using a series of values ​​for the pipe diameter D and the friction coefficient f, the pressure decay rates corresponding to these values ​​can be calculated and stored in a lookup table.

[0098] To use lookup tables, flow rate, flow rate variation, pressure drop, and pressure decay can be measured in the analyzed pipeline. Pressure decay can be determined by pressure measurements taken in the pipeline after the pressure drop has stabilized following a flow rate variation. If the pipeline diameter is known or determined, the intersection of the pipeline diameter and the pressure decay contour lines will provide the friction coefficient f on the noctilinear plot coordinate scale. It should be understood that the values ​​of pressure drop and pressure decay measured within the pipeline can be used to perform machine or computer calculations of f.

[0099] Figure 12B generally shows that the pipe diameter calculated based on the pressure drop caused by the change in flow rate is largely unaffected by the coefficient of friction. Therefore, the value of the pipe diameter D can be determined using only the change in flow rate and the pressure drop. The contour lines in Figure 12B are scaled to the pressure drop caused by the change in flow rate (e.g., 2 bbls / min). The determined value of D can be substituted into the graph in Figure 12A to determine the coefficient of friction based on the determined pressure decay.

[0100] It should be understood that the values ​​of pressure decay and pressure drop may be uncertain; that is, the measured values ​​may differ from the actual values ​​to some extent, depending on factors such as the placement and accuracy of the pressure measuring device. Referring to Figure 13A, the uncertainty in pressure decay is graphically represented at 1302 as a "band" between the pressure decay contour lines shown in Figure 12A. In Figure 13B, the uncertainty in pressure drop (at 1301) introduces uncertainty into the determination of the pipe diameter, which is represented by a band. At 1303 in Figure 13C, the intersection of the pressure decay band (at 1302 in Figure 13A) and the diameter band (at 1301 in Figure 13B) forms region 1303, which defines the possible boundaries of the pipe diameter and the coefficient of friction. Although the technical solutions are graphically shown in Figures 13A, 13B, and 13C, it should be understood that the above can be implemented by machine in the form of a lookup table.

[0101] For measurements of pressure drop, flow rate, flow rate change, and pressure decay, if these values ​​fall between explicitly calculated values ​​in a lookup table, the final values ​​of pipe diameter and friction coefficient can be generated using any suitable form of interpolation between the closest explicitly calculated values.

[0102] Figures 14A to 14D show the maximum value of dp / dt(max) of the time derivative of the measured pressure during a flow rate change and the subsequent pressure decay. If the flow characteristics (D, f) of the preceding pipe segment are known, the characteristics of subsequent pipe segments can be determined using the same method. Figure 14A shows the pressure change event of the reflected wave after a flow rate change. The maximum (or minimum) value of dp / dt corresponds to the amplitude of the reflected wave event, as shown at 1402. The pressure decay is represented by the non-zero value of dp / dt after the reflected wave event at 1404.

[0103] Nodal plots or lookup table procedures can be used to determine the characteristics of flow changes at the junction between two sections of a pipe. Since the results depend on the characteristics of other sections of the pipe, which differ from those of the section whose characteristics are being determined, calculating the nodal plot before determining these characteristics may not be practical. However, it remains advantageous to use the uncertainties in the measurement to estimate the uncertainties in the determined characteristics.

[0104] The technique in this application uses dp / dt(max) instead of the pressure drop at the junction and the pressure decay of the next segment after that junction. Although using pressure drop as described above avoids the need to know the pattern of rate decay, using dp / dt(max) can provide more accurate values ​​and has potentially lower uncertainty.

[0105] In an exemplary embodiment, dp / dt is first used to determine the pipe wave reflections from the junctions between segments with different characteristics; the maximum value during the reflection event and the value that subsequently results from frictional pressure loss (pressure decay); see 1402 and 1404 in FIG. 14A.

[0106] As graphically shown in FIGS. 14B and 14C, a lookup table can be calculated where the values of dp / dt during the pressure decay process correspond to various combinations of f and D, and the values of the maximum slope of the pressure drop (dp / dt(max)) also correspond to known values of f and D within the same range. FIGS. 14B and 14C show the pre-calculated predicted values of dp / dt and dp / dt(max), as well as the contour lines of constant dp / dt and dp / dt(max). It should be noted that dp / dt(max) is independent of f, and a change in f requires a change in D to produce the same dp / dt. Thus, the intersection of the lines corresponding to the measured dp / dt(max) and dp / dt is the unique point in the (D,f) space and can be determined graphically or from a lookup table through a series of simulations. The contour lines in the lower figure represent the values of constant dp / dt(max). A reasonable range of values for f is from 1E - 3 to 1E - 2; in this example, a set of uniformly spaced log(f) is selected, i.e., -3 < log(f) < -2, with an interval of 0.05. The contour lines in the upper figure represent the values of constant dp / dt (in psi / second) within the same range of f values.

[0107] FIG. 14C shows the ranges of dp / dt and dp / dt(max) for the changes in the pipe flow characteristics consistent with those shown in FIG. 14A, where the measured dp / dt is -5.3 psi / second and the measured dp / dt(max) varies by -36. For the sake of illustration, the uncertainty is set at ±10% of the measured value. FIG. 14D shows the intersection of these ranges, corresponding to the range of values of f and D for which the measurement results can be obtained given the uncertainty. The actual values are within the range of 3.8 < D < 4.2 and 0.002 < f < 0.005. A method for detecting changes in the pipe fluid flow characteristics, for example, detecting changes in the fluid flow characteristics caused by fouling or an increase in surface roughness in a pipe (such as an underground well or pipeline), can be carried out without stopping production or the flow of the fluid along the pipe, and without installing dedicated equipment other than one or more pressure sensors. In many cases, equipment for changing the fluid flow rate is already installed in the well or pipeline and can be used in accordance with the present disclosure.

[0108] Figure 15 illustrates an example computing system 1500 that can be used to implement the methods of this disclosure according to certain embodiments. The computing system 1500 may be a single computer system 1501A or a collection of distributed computer systems. The single computer system 1501A may include one or more analysis modules 1502, which may be configured, according to some embodiments, to perform various tasks, such as those explained with reference to Figure 15. To perform these different tasks, the analysis modules 1502 may operate independently or in coordination with one or more processors 1504, which may be connected to one or more storage media 1506. A display device 1505, such as any known type of graphical user interface, may signal to the processors 1504 to enable the user to input commands and / or data and display the execution results of the instruction set according to this disclosure.

[0109] Processor 1504 may also be connected to network interface 1508 to enable a single computer system 1501A to communicate with one or more other single computer systems and / or computing systems (e.g., 1501B, 1501C, and / or 1501D) via data network 1510. It should be noted that computer systems 1501B, 1501C, and / or 1501D may or may not have the same architecture as computer system 1501A, and may be located in different physical locations. For example, computer systems 1501A and 1501B may be located at a drilling site while communicating with one or more computer systems (e.g., 1501C and / or 1501D) in one or more data centers that may be located on shore, on a ship, and / or in different countries on different continents.

[0110] The processor may include, but is not limited to, a microprocessor, a microcontroller, a processor module or subsystem, a programmable integrated circuit, a programmable gate array, or other control or computing device.

[0111] Storage medium 1506 may be implemented as one or more computer-readable or machine-readable storage media. Note that while in the example embodiment of FIG. 15, storage medium 1506 is shown as residing within a single computer system 1501A, in some embodiments, storage medium 1506 may be distributed within and / or across multiple internal and / or external chassis of a single computer system 1501A and / or other computer systems (e.g., 1501B, 1501C, 1501D). Storage medium 1506 may include, but is not limited to, one or more different forms of memory, including semiconductor storage devices (such as dynamic or static random access memory (DRAM or SRAM), erasable and programmable read-only memory (EPROM), electrically erasable and programmable read-only memory (EEPROM), and flash memory); magnetic disks (such as fixed disks, floppy disks, and removable disks); other magnetic media, including magnetic tape; optical media (such as optical discs (CDs) or digital video discs (DVDs)); or other types of storage devices. Please note that computer instructions for causing any single computer system or computing system to perform the tasks described above may be provided on a single computer-readable or machine-readable storage medium, or may be provided on multiple computer-readable or machine-readable storage media distributed across a multi-component computing system having one or more nodes. Such computer-readable or machine-readable storage media may be considered part of an article of manufacture (or article of creation). An article of manufacture may refer to any single or multiple manufactured components. The storage medium may be located in a machine that executes the machine-readable instructions, or it may be located at a remote site from which the machine-readable instructions can be downloaded via a network for execution.

[0112] It should be understood that computing system 1500 is merely an example of a computing system, and any other embodiment of the computing system may have more or fewer components than shown, may combine other components not shown in the exemplary embodiment of FIG. 15, and / or computing system 1500 may have different configurations or arrangements of the components shown in FIG. 15. The various components shown in FIG. 15 may be implemented in hardware, software, or a combination of hardware and software, including one or more signal processing and / or application-specific integrated circuits.

[0113] Furthermore, the actions of the above processing method can be implemented by running one or more functional modules in an information processing device (e.g., a general-purpose processor or a dedicated chip such as an ASIC, FPGA, PLD, or other suitable device). These modules, combinations of these modules, and / or their combinations with general-purpose hardware are all included within the scope of this disclosure.

[0114] Based on the principles and exemplary embodiments described and illustrated herein, it should be understood that modifications can be made to the arrangement and details of the exemplary embodiments without departing from these principles. The above discussion focuses primarily on specific implementations, but other configurations are also considered. In particular, it should be noted that although terms such as “embodiment” or similar expressions are used herein, these phrases are intended to generally refer to the possibilities of embodiments and are not intended to limit this disclosure to specific embodiment configurations. These terms used herein may refer to the same or different embodiments, which may be combined to form other embodiments. Generally, any embodiment mentioned herein can be freely combined with one or more other embodiments mentioned herein, and any number of features of different embodiments can be combined with each other unless otherwise stated. While only a few examples have been described in detail above, it will be readily understood by those skilled in the art that many modifications can be made within the scope of the described examples. Therefore, all such modifications are intended to be included within the scope of this disclosure as defined by the following claims. Claims (as amended under Article 19 of the Treaty) 1. A method for characterizing the flow characteristics of fluid in a pipe, comprising: To measure the pressure of the fluid flowing inside a pipe; The pressure of the fluid in the pipe is changed from a first pressure to a second pressure, thereby changing the pressure to generate pipe waves in the pipe. Determine the location along the pipe and at least one of the following: (i) the magnitude of the change in the pipe's inner diameter, or (ii) the fluid flow friction coefficient of the pipe; The location is determined by measuring the time between the change in the applied pressure and the detection of the pipe wave reflection caused by the change in the inner diameter; The amplitude or coefficient of friction is determined based on the rate of change of the measured pressure over time, where time is the time between the change of the pressure and the responsive pressure change caused by reflection of pipe waves in the pipe. 2. The method according to claim 1, wherein the pressure change is caused by a change in the flow rate of the fluid in the pipe from a first flow rate to a second flow rate. 3. The method according to claim 1, wherein the rate of change of the measured pressure is determined based on the value of the time derivative of the measured pressure. 4. The method of claim 1, wherein the time between the change in applied pressure and the detection of tube wave reflection caused by the change in inner diameter is determined by determining the elapsed time between consecutive peaks or troughs in the time derivative of the measured pressure. 5. The method of claim 1, further comprising, at at least one selected time, repeatedly measuring the pressure of the flowing fluid, repeatedly changing the pressure from the first pressure to the second pressure, and determining the position and amplitude along the pipe to characterize the change of the position and amplitude over time. 6. The method of claim 1, wherein determining the location of at least one of the following along the pipe based on the pipe wave generation event and at least one of the following includes inverting the measured pressure: (i) the magnitude of the pipe inner diameter change, or (ii) the pipe fluid flow friction coefficient. 7. The method of claim 6, wherein the inversion process is performed relative to the time derivative of the measured pressure. 8. The method of claim 1, wherein the pipe diameter and friction coefficient are determined according to a pre-calculated lookup table, said lookup table being generated using known values ​​of flow rate, flow rate variation, pressure variation, and pressure decay after a pressure drop. 9. The method of claim 8, wherein the pre-calculated lookup table includes parameter strips related to determining the uncertainty of pressure decay and pressure change. 10. A non-transient computer-readable medium having logic stored thereon, the logic being operable to cause a programmable computer to perform operations including: It accepts measurements of the pressure of the fluid flowing in the pipe as input to the computer; After changing the pressure of the fluid in the pipe from the first pressure to the second pressure, the pressure in the pipe continues to be measured, and the pressure is changed to generate pipe waves in the pipe. Determine the location along the pipe and at least one of the following: (i) the magnitude of the change in the pipe's inner diameter, or (ii) the fluid flow friction coefficient of the pipe; The location is determined by measuring the time between the change in the applied pressure and the detection of the pipe wave reflection caused by the change in the inner diameter; The amplitude or coefficient of friction is determined based on the rate of change of the measured pressure over time, where time is the time between the change of the pressure and the responsive pressure change caused by reflection of pipe waves in the pipe. 11. The computer-readable medium of claim 10, wherein changing the pressure comprises changing the flow rate of the fluid in the pipe from a first flow rate to a second flow rate. 12. The computer-readable medium of claim 10, wherein the rate of change of the measured pressure is determined based on the value of the time derivative of the measured pressure. 13. The computer-readable medium of claim 12, wherein the time between performing a pressure change and detecting tube wave reflections caused by the change in inner diameter is determined by determining the elapsed time between consecutive peaks or valleys in the time derivative of the measured pressure. 14. The computer-readable medium of claim 10, further comprising logic operable to cause the computer to repeatedly receive a measured pressure of the flowing fluid as input at at least one selected time, repeatedly change the pressure from a first pressure to a second pressure, and determine the position and amplitude along the pipe to characterize the change of said position and amplitude over time. 15. The computer-readable medium of claim 10, wherein determining the location along the pipe at least one of the following based on the pipe wave generation event and at least one of the following includes inverting the measured pressure: (i) the magnitude of the pipe inner diameter change, or (ii) the pipe fluid flow friction coefficient. 16. The computer-readable medium of claim 15, wherein the inversion process is performed relative to the time derivative of the measured pressure. 17. The computer-readable medium of claim 10, wherein the pipe diameter and the coefficient of friction are determined according to a pre-calculated lookup table generated using known values ​​of flow rate, flow rate variation, pressure variation, and pressure decay after a pressure drop. 18. The computer-readable medium of claim 10, wherein the pre-computed lookup table includes parameter strips related to determining the uncertainty of pressure decay and pressure change.

Claims

1. A method for characterizing the flow characteristics of fluid in a pipe, comprising: To measure the pressure of the fluid flowing inside a pipe; The pressure of the fluid in the pipe is changed from a first pressure to a second pressure, thereby changing the pressure to generate pipe waves in the pipe. The location along the pipe and at least one of the following, and at least one of the following, are determined based on the pipe wave generation event in the measured pressure: (i) the magnitude of the change in the pipe's inner diameter, or (ii) the fluid flow friction coefficient of the pipe.

2. The method according to claim 1, wherein, The pressure change is caused by the fluid flow rate in the pipe changing from a first flow rate to a second flow rate.

3. The method according to claim 1, wherein, The amplitude is determined based on the rate of change of the measured pressure over time, which is the time between the changing pressure and the responsive pressure change caused by reflection of pipe waves in the pipe.

4. The method according to claim 3, wherein, The rate of change of the measured pressure is determined based on the value of the time derivative of the measured pressure.

5. The method according to claim 1, wherein, The position is determined by measuring the time between the change in the applied pressure and the detection of pipe wave reflections caused by the change in the inner diameter.

6. The method according to claim 5, wherein, The time between the change in applied pressure and the detection of pipe wave reflection caused by the change in inner diameter is determined by determining the elapsed time between consecutive peaks or troughs in the time derivative of the measured pressure.

7. The method of claim 1, further comprising, at at least one selected time, repeatedly measuring the pressure of the flowing fluid, repeatedly changing the pressure from the first pressure to the second pressure, and determining the position and amplitude along the pipe to characterize the change of said position and amplitude over time.

8. The method according to claim 1, wherein, Determining the location along the pipe at least one of the following based on the pipe wave generation event, and at least one of the following including inversion processing of the measured pressure: (i) the magnitude of the pipe inner diameter change, or (ii) the pipe fluid flow friction coefficient.

9. The method according to claim 8, wherein, The inversion process is performed relative to the time derivative of the measured pressure.

10. The method according to claim 1, wherein, The pipe diameter and friction coefficient are determined based on a pre-calculated lookup table, which is generated using known values ​​of flow rate, flow rate variation, pressure variation, and pressure decay after a pressure drop.

11. The method according to claim 10, wherein, The pre-calculated lookup table includes parameter strips related to determining the uncertainty of pressure decay and pressure change.

12. A non-transient computer-readable medium having logic stored thereon, the logic being operable to cause a programmable computer to perform operations including: It accepts measurements of the pressure of the fluid flowing in the pipe as input to the computer; After changing the pressure of the fluid in the pipe from the first pressure to the second pressure, the pressure in the pipe continues to be measured, and the pressure is changed to generate pipe waves in the pipe. The location along the pipe and at least one of the following, and at least one of the following, are determined based on the pipe wave generation event in the measured pressure: (i) the magnitude of the pipe inner diameter change, or (ii) the fluid flow friction coefficient of the pipe.

13. The computer-readable medium according to claim 12, wherein, Changing the pressure involves changing the flow rate of the fluid in the pipe from a first flow rate to a second flow rate.

14. The computer-readable medium of claim 12, wherein, The amplitude is determined based on the rate of change of the measured pressure over time, which is the time between the changing pressure and the response pressure change caused by reflection of pipe waves in the pipe.

15. The computer-readable medium according to claim 14, wherein, The rate of change of the measured pressure is determined based on the value of the time derivative of the measured pressure.

16. The computer-readable medium of claim 12, wherein, The position is determined by measuring the time between the change in the applied pressure and the detection of pipe wave reflections caused by the change in the inner diameter.

17. The computer-readable medium of claim 16, wherein, The time between the change in operating pressure and the detection of pipe wave reflection caused by the change in inner diameter is determined by determining the elapsed time between consecutive peaks or valleys in the time derivative of the measured pressure.

18. The computer-readable medium of claim 12, further comprising logic operable to cause the computer to repeatedly receive a measured pressure of the flowing fluid as input at at least one selected time, repeatedly change the pressure from a first pressure to a second pressure, and determine the position and amplitude along the pipe to characterize the change of said position and amplitude over time.

19. The computer-readable medium according to claim 12, wherein, Determining the location along the pipe at least one of the following based on the pipe wave generation event, and at least one of the following including inversion processing of the measured pressure: (i) the magnitude of the pipe inner diameter change, or (ii) the pipe fluid flow friction coefficient.

20. The computer-readable medium of claim 19, wherein, The inversion process is performed relative to the time derivative of the measured pressure.

21. The computer-readable medium according to claim 12, wherein, The pipe diameter and friction coefficient are determined based on a pre-calculated lookup table generated using known values ​​of flow rate, flow rate variation, pressure variation, and pressure decay after a pressure drop.

22. The computer-readable medium of claim 21, wherein, The pre-calculated lookup table includes parameter strips related to determining the uncertainty of pressure decay and pressure change.

Images