Flow Rate Determination in the Wellbore

(adsbygoogle = window.adsbygoogle || []).push({}); https://youtu.be/Zao4VZQMMQE Flow rate determination in the wellbore is a crucial aspect of oil and gas drilling and production operations. Accurately measuring the flow rate of fluids such as oil, gas, and drilling mud is necessary for monitoring the performance of the well and making informed decisions about production optimization and well control. The tools used to quantitatively evaluate flow volumes downhole are the radioactive tracer/gamma ray and the flowmeter. The radioactive techniques are used mostly in injection wells, since they are relatively easy and inexpensive and there is no danger of radioactive material coming to the surface. The flowmeter is most often used in producing wells, where use of the radioactive tracer is rare. For evaluations to be made when multiphase flow is present, flowmeter and fluid identification surveys are required. There are two basic types of flowmeters. Continuous flow-meters, which are logged across the producing interval, include the small-diameter and the folding full-bore flowmeters. The other basic type is the diverter flowmeter, which diverts the flow through a narrow test section, and is most effective in deviated multiphase flow conditions. Horizontal wells pose unique problems for mechanical flowmeters, which have questionable usefulness in these operations. Fluid Behavior (adsbygoogle = window.adsbygoogle || []).push({}); In producing wells, volumetric flowrates downhole generally do not match those at the surface. This difference is caused by two factors. First, the reduction of pressure in a liquid as it is produced to the surface may cause it to expand slightly. This expansion effect is very minor, however, and is not usually considered. The second and far more important cause is the dissolution of gases present in the liquid phases at downhole conditions. This occurs in both water and oil, although gas is far more soluble in oil than in water, and thus the changes in oil volume from downhole to surface are more dramatic. Figure 1 is a phase diagram. FIGURE 1 Phase diagram At reservoir conditions, a liquid flowing from the formation to the wellbore undergoes a drop in pressure without a change in temperature. As the oil is produced to the surface, both pressure and temperature are reduced, causing the oil to give up a large amount of gas and decrease in volume. The point at which gas begins to break out of solution is called the bubble point. Gas that comes from the oil in this manner is called solution gas. If gas-cap gas (which is not and was not in solution with the oil) is produced, it is called free gas. This free gas also changes dramatically in volume from downhole to surface. Such volume changes are a function of the gas gravity, and of reservoir pressure and temperature. Figure 2 shows the change in fluids as they move from down-hole to the surface. As pressure begins to decrease, a slight expansion of the liquid takes place. FIGURE 2 Change in fluids as they move from down-hole to the surface At the bubble point, gas begins to break out of solution, and as the pressure is further reduced, vast volumes of gas come from the oil. A similar effect is noted with water, although the volume of available gas is much less. The relation between the downhole and surface volumes is called the formation volume factor, and is defined as Oil: [latex]B_o=\dfrac{\textrm{oil volume at reservoir conditions}}{\textrm{oil volume at standard conditions}}[/latex] [latex]\quad[/latex] (1) Gas: [latex]B_o=\dfrac{\textrm{gas volume at reservoir conditions}}{\textrm{gas volume at standard conditions}}[/latex] [latex]\quad[/latex] (2) Bo is typically greater than one and Bg is is typically much less than one. For gas, the reciprocal, 1/Bg, is usually used and is a number in the hundreds. These relationships are determined from PVT data on the produced fluids or may be approximated from correlation charts available in the technical literature. (adsbygoogle = window.adsbygoogle || []).push({}); Injection Well Profiling Using Radioactive Tracers (adsbygoogle = window.adsbygoogle || []).push({}); Although many of the methods available for radioactive tracer logging can be made quantitative, two basic techniques are most often used. These are referred to as the velocity shot technique and the area under the curve technique. It is common for results from either of these techniques to be presented in the form of a flow or injection profile on the tail of the log. In the velocity shot technique, the tool is held stationary and a small cloud of radioactive material is ejected into the flow. As this cloud passes two gamma ray detectors on the tool below the ejector, a measurement is made of the time of transit between those detectors. This measurement is made by recording the response at the detectors while the film is scrolling at a constant rate; i.e., the recorder is on time drive. Figure 1 illustrates this technique. FIGURE 1 Injection Well Profiling Using Radioactive Tracers In this figure, a velocity measurement is being made between the upper and lower set of perforations. By performing a number of tests at various points in the wellbore, a flow profile as shown on the right may be produced. The differences between the constant values measured between, above, and below the perforations represent the loss of fluid to the formation in this injection well. The volumetric flow rate may be computed using the following equation: [latex]Q=\left ( \dfrac{1}{t} \right ) \cdot \left [ 84\cdot F\cdot DS\cdot \left ( D ^2-d^2 \right ) \right ][/latex] or, in SI units, [latex]Q=\left ( \dfrac{1}{t} \right ) \cdot \left [ 6.79\cdot F\cdot DS'\cdot \left ( D'^2-d'^2 \right ) \right ][/latex] where: Q= flow rate, B/D (Q′ is in m3/D) F= flow profile correction factor, typically less than 1.0 DS= distance between detectors, ft (DS′ is in meters) D= pipe internal diameter (ID), in. (D′ is in centimeters) d= tool diameter, in. (d′ is in centimeters) t= time between detections, seconds (adsbygoogle = window.adsbygoogle || []).push({}); The profile-correcting factor (F) may be computed to match surface and downhole injection rates above the top perforations. Once the term in the right-hand brackets is computed, and assuming that F is constant, the term does not change and only 1/t need be calculated thereafter. If fraction or percent of flow only is to be calculated, then the flow varies directly with 1/t. In the area under the curve technique, it is assumed that the area is directly related to the amount of radioactive material ejected by the tool into the flow. As the initial area is reduced, the fluid remaining is reduced proportionally. Figure 2 shows a series of passes with a gamma ray after a large cloud of radioactive material has been ejected above the interval to be evaluated. FIGURE 2 Series of passes with a gamma ray The initial run, designated R-1, is at the far left. To determine the amount remaining at the location of the cloud in run eight (R-8), the areas under R-1 and R-8 must be measured and [latex]\textrm{fraction flow rem airing at R-8}=\dfrac{\textrm{area under R-8}}{\textrm{area under R-1}}[/latex] [latex]\quad[/latex] (1) The difference between the flow remaining at two successive runs is the fraction of the flow lost to the formation between those runs. Computation of the fraction of flow remaining at each run may then be used to determine an injection profile across the interval. Of the two techniques presented in this section, the velocity shot technique is better for quantitative answers, although the area technique often agrees quite well with it. In some international locations, radioactive tracers are difficult to obtain. This situation has led to the evolution of non-radioactive tracers having high-capture cross sections, and the application of systems such as Schlumberger’s "Flagship Tool String," which employs RST measurements. (adsbygoogle = window.adsbygoogle || []).push({}); Flowmeters (Turbine Type) https://youtu.be/xXupgmSjgOM Flowmeters (Turbine Type) (adsbygoogle = window.adsbygoogle || []).push({}); The two types of turbine flowmeters are the small-diameter and the full-bore. These tools are run continuously over the interval of interest, making a number of logging passes, usually in both the up and down directions, all at different logging speeds. These tools respond to the bulk flow rate, even in multiphase flow. They are best suited for use in vertical wells, but also may be used effectively in deviated wells, especially at higher flow rates. The typical response to flow is shown in Figure 1. FIGURE 1 The typical response to flow The dashed curve is the typical turbine spinner response to a static fluid in the wellbore. The response, in terms of spinner rotational speed in revolutions per second (RPS) against logging speed, shows that the relationship is linear. The response curves, however, do not go through the origin, but instead intercept the horizontal axis on each side of the origin. This offset is due to the viscosity of the fluid; greater viscosity tends to cause a greater offset. The intercept is sometimes called the "threshold" of the spinner, although the actual tool velocity in static fluid at which the spinner begins to rotate may be larger. When the spinner encounters an upflow, as would be expected in a producing well, the effect is to shift the response curve of the tool to the left; that is, the new response lines of the tool when it encounters the upflow are similar to the static response, except that the new response is shifted to the left by an amount equal to the upflow velocity. Figure 1 shows such response curves to an upflow, VF. If a downflow is encountered, it causes the response curve of the spinner to be shifted to the right by an amount equal to the flow velocity downhole. If the intercepts or thresholds are not symmetrically located about the margin, the same relative position is maintained to determine the flow velocity. Interpretation of Continuous Flowmeters (adsbygoogle = window.adsbygoogle || []).push({}); The schematic in Figure 2 shows a well with two sets of perforations, each producing. The flowmeter measurements are taken in the intervals between the entries, i.e., intervals A, B, and C. FIGURE 2 Well with two sets of perforations, each producing To the right of the well sketch is a minimum flowmeter logging suite consisting of three up and three down log runs, all run continuously over the intervals, and each at a different but constant logging speed. The rotational speed of the spinner flowmeter is recorded in revolutions per second (RPS). At the right is a series of plots of the spinner response curves for each of the intervals. In interval A, which should be static, the values of RPS and cable speed are plotted using values from points 1 through 6 on the log. This is the static response. A similar plot is constructed for intervals B and C, and the displacement of the B and C response curves from the static is a measure of the flow velocity upward downhole. The velocities VF and V′F are the velocities of the flow detected in intervals B and C, respectively. If a well is producing at a high flow rate, the up runs may not be usable, because the flow velocity may be faster than the tool speed in most of the well. As a result, the spinner rotates as if the flow is up, relative to the tool. When this occurs, the technique of Figure 3 may be used. Tool-velocity-versus-spinner-speed The intercept of the response curve with the vertical axis is first located. From this point a line is drawn to the static response curve, and then down to the horizontal velocity axis. The intercept of the horizontal velocity axis is the velocity of flow in the interval being computed. Where both up and down runs are available over the whole logged interval, the two-pass overlay technique may be used. This technique is especially useful where there are many entries over the logged interval. The first step of this technique is to plot the spinner response curve in the lowest interval. This response curve should indicate that the flow is likely zero, i.e., the intercepts fall on each side of the origin. This does not ensure zero flow, but if coupled with a fluid identification device that shows water, completion fluid, or debris in the rathole, it is certainly static. The slope of the response curves in both the up and down logging direction must also be determined. Note that these are not usually the same. Then, as shown in Figure 4, the most representative or average or composite up and down runs are overlain in the lowest interval. FIGURE 4 The most representative or average or composite up and down runs are overlain in the lowest interval The separation relative to this lowest interval, labeled ΔRPSB and ΔRPSC, may then be used to calculate the flow in each upper interval using the equations shown in the figure. Both the up and the down runs must be presented at the same RPS and depth scales for this technique to be used. The measured flow velocities are those seen by the spinner turbine blades. If the spinner is centralized, and it should be for best results, it has sampled the flow in the center of the wellbore, which is too large. As a result, a flow profile correction factor must be used to correct the data to an accurate average velocity. For this computation, service companies may have available corrections based on Reynolds number of the flow, although a correction of 0.83 is commonly used in hand calculations. If Vi is the velocity detected by the spinner in interval i, the average velocity in interval i is [latex]\overline {V}_i=0.83\cdot V_i[/latex] To compute the bulk flow rate in barrels per day (Q), the following equation is used: [latex]Q_i=1.4\cdot \overline {V}_i\cdot (ID)^2[/latex] or, in SI units, [latex]Q'_i=0.113\cdot V'_i\cdot (ID')^2[/latex] where: [latex]Q_i[/latex]= bulk flowrate in interval i, B/D (Q′i is in m3/D) [latex]\overline {V}_i[/latex]= average flow velocity in interval i, ft/min (V′i is in m/min ) [latex]ID[/latex]=wellbore inside diameter open to flow, in. (ID′ is in centimeters) The presentation of the final computation may take the form shown in Figure 5. FIGURE 5 Three entry points and four intervals for flowmeter evaluation In this figure, the well sketch shows three entry points and four intervals for flowmeter evaluation. The cumulative bulk flow illustrates the volume flowrates calculated by the flowmeter. The entry profile is determined from the changes in the bulk flowrate at the entry points. (adsbygoogle = window.adsbygoogle || []).push({}); Multiphase Vertical Flow https://youtu.be/yqOuimP80sg (adsbygoogle = window.adsbygoogle || []).push({}); Many different flow regimes may exist in multiphase flow. In an oil well, two or three phases of fluid may be present in the producing interval. If the flow is water and oil, bubble and emulsion flows are most common, while slugs and more complex patterns are relatively rare. If the slug pattern exists downhole, it appears as a square wave pattern on the flowmeter log, since the oil slugs are moving up at a higher velocity than the water phase. When gas and liquid are present, the flow is much more complex. Bubble flow probably exists up to about 10% gas by volume at downhole conditions. A transition quickly occurs to the slug or more complex flow pattern. Unlike oil-water flow, gas-liquid flow is turbulent and violent, and produces a very ratty response on the flowmeter. This messy situation continues until the gas flow rate and volume fraction is so large that it carries the liquid uphole as a mist. As a result, flows containing gas and liquid may be difficult to compute accurately. The terms "holdup" and "cut" are often misunderstood. "Cut" refers to the amount of a particular phase that is being produced. For example, if 1000 B/D (159 m3/D) of liquid is produced, of which 350 B/D (55.6 m3/D) is water, the liquid is said to have a 35% water cut and a 65% oil cut. "Holdup," on the other hand, refers to the fraction of the bulk volume occupied by one of the phases. Figure 1 helps illustrate this concept. FIGURE 1 Multiphase Vertical Flow Holdup At the left, there is a standing water column in the pipe, above which the pipe is filled with oil. The valve at the bottom is then opened and oil only is pumped in. Flowing out at the top is 100% oil cut with no water cut. The oil simply bubbles up through the water and joins the other oil at the oil/water interface. No water is produced. Across the bubbly interval, the bubbles occupy about 30% of the volume (determined from the new position of the interface) , and hence that interval is said to have an oil holdup of 30% and a water holdup of 70%. The cut and holdup in this case are clearly different. Because of this difference, water is likely to accumulate downhole in all wells, even though the water cut is small. The chart of Figure 2 shows how the difference between holdup and cut can be quite dramatic, especially at low flow rates. FIGURE 2 Difference between holdup and cut (adsbygoogle = window.adsbygoogle || []).push({}); Note that at 300 B/D (47.7 m3/D), a 1% water cut at the surface means a 50% water holdup downhole. If two phases are present (a heavy and a light phase), then YH+YL=1.0 (1) where Y is the symbol for holdup and the subscripts refer to the heavy (H) and light (L) phases. If water and oil are flowing downhole, water is the heavy phase, and if gas and liquid are flowing, the liquid is the heavy phase. If the three phases water, oil, and gas are present, then Ywater+Yoil+Ygas=1.0 (2) Measurement of Phase Holdup Measurement of phase holdup in two-phase flow is made indirectly by measuring the fluid bulk density. Schlumberger's gradiomanometer and PTS sonde measure bulk density by determining the pressure differential over about a 2-ft (0.61-m) interval. This measurement is made with mechanical sensing bellows on the gradiomanometer, or by a quartz differential pressure gauge measurement over about a 2-ft interval. A schematic of the gradiomanometer is shown on the left side of Figure 3. FIGURE 3 Nuclear fluid density meter on the right and gradiomanometer on the left side Note that these tool responses must be corrected for well-deviation angle. Bulk density is also measured using the nuclear fluid density meter, as pictured on the right of Figure 3. The tool contains a gamma ray source and a detector, and the counts received at the detector may be related to the density of the fluid between the two. This measurement of the bulk density does not have to be corrected for the well-deviation angle. To determine the holdup from the bulk fluid density, the following equation is used: [latex]Y_H = \dfrac{\rho _{measured} - \rho _L}{\rho _ H - \rho _ L}[/latex] and YH+YL=1.0 In the above equations, ρ symbolizes the fluid density, gm/cc. Capacitance devices for fluid identification are also available. Their best measuring range is from about 0 to 40% water holdup. These tools are designed to measure annular capacitance between the tool housing and a core within the housing. Fluid turbulence downhole is the mechanism that pushes the multiphase fluid into the tool. There is some question about whether the fluid mixture within the tool is representative of the fluid mixture in the main flow. The capacitance tool is mainly responsive to water. Computation of the Two-Phase Flow Profile Once the bulk flow rate and the holdup of the two phases are measured, the slippage velocity must then be determined. This slippage velocity is the velocity of the light phase relative to the heavy phase, and is the cause of the difference between cut and holdup. To determine the slippage velocity between oil and water, use the chart in Figure 4. FIGURE 4 Computation of the Two-Phase Flow Profile The horizontal axis is the density difference between the water and the oil phases (note that this chart is not used for gas/liquid mixtures). The holdup of the water phase is also needed for the use of this chart. For example, if the water density is 1.0 gm/cc and the oil density is 0.70 gm/cc, the density difference on the chart is 0.30 gm/cc. If the water holdup is 0.70, then the slippage velocity of the oil with respect to the water is about 19 ft/min (5.8 m/min). When dealing with a gas/liquid system, a slip velocity of 60 ft/min (18.3 m/min) is assumed. Better estimates of the gas slip velocity may be available from the service companies. (adsbygoogle = window.adsbygoogle || []).push({}); To compute the flow rates for each interval, in two-phase flow, the following equations are used: [latex]Q _{H_{i}} = Y_{ H_{i}} [Q_i - 1.4(ID_{casing}^2 - D_{tool}^{2} )(V_{slip_{i}})(1 - Y_i)][/latex] or, in SI units, [latex]Q'_{H_{i}} = Y_{H_{i}} [Q_{i} - 0.113({ID'}_{casing}^{2} - {D'}_{tool}^{2})(V'_{slip_{i}})(1 - Y_{i})][/latex] and [latex]Q_{L _{i}}= Q_i - Q_{H _{i}}[/latex] or, in SI units, [latex]Q'_L = Q'_{L _{i}} = Q'_i - Q'_{H _{i}}[/latex] where: Q= bulk flow rate from the flowmeter, BD (Q′ is in m3/D) QH= heavy phase flow rate, B/D (Q′H is in m3/D) QL= light phase flow rate, B/D (Q′L is in m3/D) YH= heavy phase holdup Vslip= slip velocity of light phase, ft/min (V′slip is in mmin) IDcasing= internal diameter of the casing, in. (ID′ is in centimeters) Dtool= tool diameter, in. (D′tool is in centimeters) i= subscript denoting interval under analysis Individual entries are determined by the differences between the flow rates measured above and below an entry. (adsbygoogle = window.adsbygoogle || []).push({}); Multiphase Flow in Deviated Wells https://youtu.be/dteUNyVF7s0 (adsbygoogle = window.adsbygoogle || []).push({}); Deviated wells with multiphase production present a unique problem to flow evaluation. In the schematic in Figure 1 and Figure 2, FIGURE 1 Three sets of perforations there are three sets of perforations, each producing oil with little or no water cut. FIGURE 2 Bulk flow profile (adsbygoogle = window.adsbygoogle || []).push({}); The actual bulk flow profile is shown on the left. When the oil enters the wellbore, it gravitates to the high side of the pipe and moves uphole along the pipe's high side, carrying some water with it. If there is little or no water production, the water must fall back along the low side of the pipe, resulting in the flow profile shown in each interval. The flowmeter responds to the flow it sees, which is downflow in the lowest interval, upflow in the upper interval and somewhere in-between in the middle interval. This problem is minimized by centralizing the tool. Even with the tool centralized, this is a serious interpretation problem at lower flow rates and at deviation angles greater than 15º. If a small-diameter spinner is run noncentralized, interpretation problems occur at deviations of about 2º. The detection of a downflow in the lower parts of a deviated well should always be questioned. This problem may be alleviated by using diverter-type flowmeters, which are available from major service companies. The Schlumberger inflatable diverter tool (Figure 3) is a typical example. FIGURE 3 Inflatable diverter tool This tool utilizes a fabric diverting element and an inflatable tauroidal ring to divert the flow through the funnel-shaped test section. Other versions use metal petals attached to the centralizer arms to make a funnel element. These tools are much more effective than conventional flowmeters in deviated wells, but are limited to flow rates may impose limitations on their use, depending on the tool size and the service company. The response of diverter flowmeters is precalibrated, and each tool and spinner combination has a unique calibration curve. Figure 4 shows the response of a typical diverting tool. FIGURE 4 The response of a typical diverting-tool Responses of individual tools must be obtained from the service companies. For multiphase flow, some tools contain a fluid-identification device, upstream from the spinner element. In a case where all of the fluid passing through the tool also passes through the fluid-identification device inside of it, the flow is very turbulent, and the holdup and cut are nearly equal. Either a nuclear densimeter or a capacitance device may be accurate under these conditions. Another alternative used by some service companies is to locate the fluid-identification devices directly above the exit ports of the diverter-type flowmeter. In flow loops, the holdup measured directly above the exit ports of a diverter tool closely matches the actual cut of fluids passing through the tool. (adsbygoogle = window.adsbygoogle || []).push({}); Oxygen Activation Measurement https://youtu.be/-DF7kQz-JEo (adsbygoogle = window.adsbygoogle || []).push({}); A schematic showing the oxygen-activation measurement is illustrated in Figure 1. FIGURE 1 The oxygen activation measurement The neutron generator emits a burst of neutrons which causes oxygen (present in water molecules) in the borehole to become activated. If the water is moving up past the tool, a population of activated water is formed. This activated water has a half-life of about seven seconds, and as the oxygen atoms return to their normal state, gamma rays are emitted. These gamma rays are counted by the detectors and are shown as an increase in the background counts. Oxygen activation has particular application in production logging, where it is used to identify water flow in wellbores or behind casing strings. Tools such as Western Atlas’ Hydrolog or Schlumberger’s Water Flow Log (WFL) are used for this purpose. (adsbygoogle = window.adsbygoogle || []).push({}); Assessment (adsbygoogle = window.adsbygoogle || []).push({}); 1. The rotational speed of the spinner flowmeter is recorded in feet/seconds. A .TrueB .False ✔ 2. In typical wells, unlike oil-water flow, gas-liquid flow is: A .Steady-stateB .TransientC .Turbulent and violent ✔D .Laminar 3. The slippage velocity is defined as: A .The velocity of the light phase relative to the heavy phase ✔B .The velocity of the heavy phase relative to the light phaseC .The velocity of the total liquid phase relative to the gasD .The true vertical velocity of the gas phase in the wellbore 4. In an oxygen activation measurement, a neutron generator emits a burst of neutrons which causes oxygen (present in water molecules) in the borehole to become activated. What type of radiation is emitted as the oxygen atoms return to their normal state? A .Alpha raysB .Beta raysC .Gamma rays ✔D .Positron particlesE .A, B, C and D (adsbygoogle = window.adsbygoogle || []).push({}); 5. Which of the following techniques is used to estimate the velocity in an injection well using radioactive tracers? A .CaliperB .Velocity-shot ✔C .Capillary tubeD .Downhole rotor 6. When the oil enters a deviated wellbore, it gravitates to the low side of the pipe and moves uphole along the pipe's low side, carrying some water with it. A .TrueB .False ✔ 7. In producing wells, volumetric flowrates downhole generally do not match those at the surface because of: A .Reduction of pressureB .Reduction of temperatureC .Gas present in the solutionD .A and C ✔E .A, B and C Recommended for You Basic Concepts in Reservoir Engineering Reservoir Fluid Flow and Natural Drive Mechanisms Production Logging of Multiphase Flow in Horizontal Wells Introduction to Acidizing (adsbygoogle = window.adsbygoogle || []).push({});