STID 92250744

Velocity Tools in Production Logging.A. Nasirisavadkouhi, International Campus of Sharif University of Technology

Winter 2015

This paper was prepared for the advanced well-log course held by Dr Saeed Shad at SUT_international Campus. The template of the paper is based on the latest SPE standards therefore the pictures can be found at the end of the paper.

AbstractProduction logs are a record of one or more in-situ measurements that describe the nature andbehavior of fluids in or around the borehole during production or injection. The instrument''spinner'' which is a device for measuring in situ the velocity of fluid flow in a production orinjection well based on the speed of rotation of an impeller, was introduced in this paper. Its historyand its types were mentioned. Then I discussed some concepts of its working and the reasonsbehind it. Eventually a method of graphical spinner log interpretation was explained.

Fundamentals of Production LoggingThe aim of production logging is to determine where the oil and gas and water are coming from in aproducing well or to determine where the gas or water is going to in an injection well. Because theradial influx (or outflux) of these phases into the borehole cannot be directly measured, productionlogging looks for intervals of stable or unchanging flow rate (q) and then calculates the differencesbetween adjacent stable intervals. From a few basic sensors, production logging tools have evolvedto a family of tools each with sensors designed to make measurements that, once interpretedtogether, provide accurate flow rates for multiple phases and determine precisely where the variousfluids are entering (or exiting) the borehole. This development and application of new productionlogging technologies is much needed, as well trajectories continue to grow in complexity,progressing from vertical to deviated and horizontal and posing new challenges in completiondesign and flow assurance. Downhole separators and positive displacement meters are not used tomeasure the stable downhole flow rates; instead, velocities, areas, void fractions, and other indirectattributes of the flow rate must be measured. Most of the measurements available have limitedranges within which a calibrated response can be expected. It would be fair to say that the task ofconverting downhole measurements into a multiphase flow rate and then accurately determiningwhere the various fluids are entering the borehole presents a challenge, a nontrivial task, or to useplain, noneuphemistic language, a problem. The objective of this paper is to familiarize readers withthis tool and moreover to help them address the difficulties production logging faces in this area.Therefore, this paper reviews the concepts with regards to the function of the Spinner.

The History and Evolution of the SpinnerAs described in Bonet (Pat. US3,630,078) one of the most successful techniques presentlyemployed for determining the flow rate of fluids flowing in a well bore is to successively pass a so-

called "spinner-type" flowmeter tool at selected constant speeds through the fluid-filled well bore.By successively recording the resulting rotational speeds of the flowmeter spinner at thecorresponding depth locations of the tool, a continuous flow survey or fluid-velocity log will beobtained from which the flow rates of the well bore fluids at different depth intervals of the wellbore can be readily determined. Thus, where the well being surveyed is a production well havingtwo or more producing intervals, the resulting log will clearly indicate the respective velocities orflow rates of the connate fluids which are being produced from each of the several producingintervals. On the other hand, where the well is an injection well in which fluids are being injectedsimultaneously into two or more formation intervals, the resulting flow survey will show whatportion of the injection fluid is entering each formation interval. Those skilled in the art will, ofcourse, appreciate that the rotational speed of the spinner in a flowmeter of this nature is simply alinear function of the apparent or relative velocity of the well bore fluids in relation to the tool.Thus, at low flow rates, the spinner will inherently turn at correspondingly-low speeds so long asthe well bore fluids are moving at a sufficient velocity to still turn the spinner. It is apparent,therefore, that for a given spinner, the minimum "operating threshold" for such a flowmeter isdirectly related to the amount of rotational friction which must be overcome before the spinner canturn. Accordingly, as fully explained in the Bonnet, it was found that the unique magneticsuspension arrangement shown there significantly reduced the static and dynamic friction affectingthe rotation of the flowmeter spinner. Although flowmeters arranged in accordance with the Bonnetpatent have met with considerable success, it has been found nevertheless that their loose-fittingmagnetically-suspended spinners become unreliable, if not ineffective, in substantially deviated ornon-vertical well bore interval. Attempts to use bushings or bearings of different types formaintaining these spinner shafts coaxially centered in the tool have not been too successful,however, in view of the additional friction. Moreover, fluid-borner debris such as sand grains orother solid particles will often enter the clearance spaces around or in such bearings and impair, ifnot totally disrupt, the operation of these bearings as well as other closely fitted movable elementsof the flow meter. Eventually innovations were introduced by (Anderson et al. US3,954,006) thefirst results are shown in (Fig 2) . Nowadays turbine, or spinner, flowmeters are used extensivelywithin industry with small to negligible errors, the situation is very different in oilfield applications.The fullbore spinner does not, as its name suggests, cover the entire pipe cross section (Fig. 3).Typically a fullbore spinner sweeps only about 40% of the casings cross-sectional area. In addition,the blades do not have a progressive pitch (as on a ship's propellers and in gas turbines) because therequirement to collapse down to a diameter of 1 11/16 in precludes anything more complicated than aflat spinner blade. The continuous, or tubing, spinner has a progressive-pitch spinner, which is moreeffective at extracting energy from the well fluids (and therefore reducing the spinner threshold,which is the minimum velocity needed to start the spinner turning) (Fig.4). Unfortunately, the muchreduced spinner diameter more than negates the effect of the improved blade profile, and thethreshold velocity of a standard tubing spinner is about 3 times higher than that of a fullborespinner.The Flow Scanner mini spinner (Fig.5) is used in an array of five mini-spinners recording velocitieson the vertical axis of the pipe, from the bottom to the top. This arrangement is discussed in detailfor the Flow Scanner horizontal and deviated well production logging system (see the"Fundamantals of production logging'' Ch.12.Flow Scanner Interpretation, Schlumberger). A changeof bearing technology together with the progressive pitch of a tubing spinner delivers a spinnerthreshold comparable to that of a fullbore spinner.

Theoretical spinner response modelConsider the response of an ideal spinner flowmeter (Fig.6). The spinner speed in revolutions persecond (rps) is directly proportional to the fluid velocity passing through the spinner. The slope ofthe response curve, measured in rps/ft/min [rps/m/min],comes directly from the spinner pitchmeasured in inches [centimeters].Once friction in the bearings is included, the response becomes a little more complicated, with two

response lines, one for positive spinner readings and a second for negative spinner readings. Thereis now a range of low fluid velocities where the spinner does not turn because the spinner torque issmaller than the bearing friction. Close inspection of the response lines in Fig.6 shows a small curveat low spinner speeds owing to the action of static friction (stiction), viscosity effects, or both. Toavoid the complications arising from nonlinear spinner response, near-zero spinner readings arediscarded if they look at all suspicious. Increasing the viscosity of the fluid passing through thespinner produces some unusual results. The threshold first increases and then decreases while thespinner slope changes by about a factor of 5 or more. Figures.7 and .8 show the results ofpreviously unpublished experimental data from the Schlumberger Gould Research Center.Changing the density of the fluid passing through the spinner (e.g., from liquid to gas) alsoincreases the size of the low-velocity region where the spinner does not turn but should notsignificantly change the spinner response slope (Fig. 9). However, changing the fluid from liquid to gas causes a big change in the pseudo-Reynolds number(created using the tool velocity) and makes the creation of turbulence and vortices much easier, thusleading to the situation of (Fig. 10).

Nℜ pseudo=

ρ . v . dμ

where: v: tool velocity, m/s ρ=gasdensity , kg /m3

d=hydraulic diameter ,m μ=dynamic viscosity ,Pa . s

On the left of (Fig. 10) is an upward-moving tool (equivalent to a negative fluid velocity)generating vortices that travel down and confuse the spinner. Behavior like this creates asymmetricspinner slopes and thresholds. The effect can be expected to be bigger in gas wells, but it is stillpresent in water and the lighter oils. In the middle and on the right of (Fig. 10) is the effect of thespinner cage stirring up the flow. To a first-order approximation the effects seem to be equal forflow from above and flow from below.

Practical spinner response modelThe theoretical spinner response model described in the previous section is too complicated foreveryday use. Instead, some approximations are introduced until the model of (Fig. 11) is reached.This shows a spinner in an unknown fluid as having a positive and negative spinner slope and apositive and negative spinner threshold. Because these four parameters can change with velocity,fluid density, fluid viscosity, casing diameter, and other conditions, the model needs judiciousupdating over an interpretation interval.

Spinner interpretation —Initial laboratory characterizationThe first approach (Meunier et ah, 1971) to calibrating the spinner involved laboratorycharacterization and the creation of interpretation nomograms (Fig. 12).The laboratory-determined spinner threshold and spinner pitch were combined with a stationaryspinner reading, velocity profile viscosity model, and the pipe internal diameter to deliver adownhole flow rate. Unfortunately, the log analyst did not often have reliable downhole viscosityinformation, so measurements of the spinner threshold in the laboratory were rarely representativeof the field, and logs versus depth could not easily be processed. Since tool speed cannot bemeasured downhole, as a proxy the cable velocity at surface is used. Typically cable speeds of 30,60, and 90 ft/min [10, 20, and 30 m/min] are used, but for unstable wells additional speeds areadded to average out the variations. For high-velocity gas wells, top speeds of 120-150 ft/min [40-50 m/min] are used to better define the positive spinner intercept.

In situ spinner calibrationBecause it is impractical to vary the downhole fluid velocity while measuring the spinner rps, theproblem of spinner characterization (usually known as calibration) is approached from a differentdirection. Instead of varying the fluid velocity, the tool is moved up and down at different speeds

and the spinner rps plotted versus tool speed.In the absence of any kind of downhole velocity or downhole depth measurement, the tool velocityis inferred from the cable velocity as it leaves the drum at surface. Fortunately, under steady-stateconditions the velocity at surface is very close to the downhole tool velocity. However, undertransient conditions as the tool accelerates from rest or slows to a halt, the tool velocity cannot beexpected to accurately match the cable velocity at surface. As a rule of thumb, traversing a 30-ft[10-m] interval above the top perforation and below the deepest perforation allows the tool toachieve a steady velocity before logging the zone of interest.In a zero-flow environment it is possible to determine the positive and negative spinner slopes andthe positive and negative spinner thresholds (Fig. 13). But where does a zero-flow environmentexist? Shutting in the well at surface does not guarantee zero flow because there may be cross flowbetween zones. Above the top perforation, after the well has been shut in for many hours, thereshould be no flow, but in the time available for production logging there may be wellbore storage(unlikely) or liquid fallback from the tubing that extends to surface. Although it is safer to assumethat there is no flow below the deepest perforation (in the absence of casing plugs isolating deeperzones), the fluid density and viscosity below the deepest perforation are often unrepresentative ofthe fluid density and viscosity flowing in the well (the fluid for which the spinner calibration isintended). Usually the best way to identify a zero-flow region is to refer to the temperature log andidentify what appears to be a geothermal gradient because geothermal gradients are incompatiblewith fluid movement. The spinner calibration in (Fig. 14) corresponds to a small positive velocity(down flow) but this analysis can be delivered with confidence only after inspecting the temperaturelog in (Fig. 15).The log in (Fig. 15) shows cable velocity, depth, spinner rps, the extent of the perforated intervals inred, spinner calibration zone in yellow, rate calibration zones in gray, pressure, temperature, anddensity (indicating a water-filled borehole). The steep change in temperature at about 3,900 ftshows where the cooler cross flowing water is lost into a perforation (indicated in red) and thegeothermal gradient is recovered.

Recirculation and the spinnerIn anywhere from 5° to 75° deviation, a low mixture velocity combined with a high slip velocityproduces gravity segregation of the phases, giving rise to large high-side velocities, significantshear between light and heavy phases in the pipe, and finally a downflow of the heavy phase on thelow side of the pipe (Fig. 16 ). A centered spinner tries to average the mixture of velocities passingthrough the swept area of the blades but generally returns a velocity that is too low if not actuallynegative. A poorly centralized spinner, lying closer to the low side of the pipe, returns an answerstill more heavily weighted for heavy-phase recirculation.Increasing the diameter of the spinner blades reduces the size of the errors and is the simplest wayof improving data quality under these conditions. While recirculation normally occurs with gas oroil bubbling up through water, the inverse situation, of water falling back through oil or gas, is oftenseen when a well has just been shut in. In these cases the spinner sees an erroneous uphole flowrate.

Diverter flowmetersAnother approach to handling the problems of recirculation is use of the diverter flowmeter.Because recirculation requires a low mixture velocity, the diverter, or petal basket (Fig. 17),flowmeter funnels the flow of the well through a 1- to 1 ½ in diameter tube in which a spinnervelocity is recorded. If run in a 7-in completion the diverter flowmeter increases the velocity byabout 20 times and therefore reduces the poorly defined threshold for recirculation effects to onetwentieth. However, once the diverter is deployed the diverter flowmeter tool can only be used tomake stationary measurements. This means that the accelerated flow passing through the divertermust exceed the spinner threshold (which is of the order of 15 ft/min for the small spinner used). Inaddition, the in situ spinner calibration of the slope and threshold must be made with the flowmeter

closed and in a different flow regime from that being used for the station measurements.Nevertheless, the diverter flowmeter is currently the least bad approach to measuring velocity in thepresence of recirculation.

Graphical interpretation techniquesIn the past, graphical techniques for interpreting spinner data were very popular. One elegantapproach is still seen in production log interpretation manuals. In (Fig.18), after the various stableinterval responses are plotted together with a zero-flow response, the reading line for the zero toolvelocity spinner is projected right, across to the zero-flow line, from which a vertical line is droppeddown to the horizontal axis, which delivers the fluid velocity. Increasing the slope of the zero-flowline by the reciprocal of the velocity profile correction factor automatically corrects for the velocityprofile across the pipe. This technique assumes that the zero-flow spinner response slope andthreshold are applicable to all the stable intervals above. In practice this is true only for well-behaved monophasic wells with a clean, uncontaminated zero-flow region at the bottom. Thisplotting technique is no longer used commercially.

References

Colin Whittaker ''Fundamantals of production logging'' ,2012, Schlumberger Technology Corporation.

Jean-Loup Bonnet, ''MAGNETIC SUSPENSION FLOWMETER'' Verrieres-le-Buisson, France, SchlumbergerTechnology Corporation, Oct. 31, 1969, United States Patent Nu.3,630,078

Meunier, D., Tixier, M.P., and Bonnet, J.L.: "The Production Combination Tool, A New System for ProductionMonitoring," Journal of Petroleum Technology (May 1971), 603-613.

Ronald A. Anderson; James J. Smolen, both of Houston, Tex. ''methods for determining velocities and flow rates offluids flowing in well bore'', Schlumberger Technology Corporation, May 4, 1976,United States Patent Nu.3,954,006.

Figures.

Figure 1. The principle of production logging Figure 2. The first result of Spinner log

i. shows a typical flowmeter as it, will appearduring the practice of the methods of the presentinvention in a. conventional multi-zoned productionwell;ii , iii. respectively depict typical flowmeasurement logs representative of what may heobtained during the practice of the present invention ina well bore such as shown in (I) with these measurements again being presented in (iii) as they mightappear when uniquely combined on a composite recordfor presenting a continuous flow profile of thewellbore;

i ii iii i

Figure.3 Fullbore spinner schematic Figure 4. Continuous, or tubing, spinner.

Figure 5. Flow Scanner minispinner. Figure 6. Spinner response with friction and stiction.

Figure 7. Spinner response to increasing viscosity.

Figure 9. Spinner response to decreasing density.

Figure 8. Spinner response to increasing viscosity, amplified scale

Figure 10. Fluid turbulence and the fullbore spinner. Figure 12. Spinner interpretation nomogram (Meunier et at, 1971)

Figure 11. Approximation to a spinner response. Figure 13. Zero-flow spinner calibration.

Figure 14. Ambiguous near-zero spinner calibration.

Figure 15. Near-zero spinner calibration plot data.In the absence of any kind of downhole velocity or downhole depth measurement, the tool velocity is inferred from the cable velocity as itleaves the drum at surface. Fortunately, under steady-state conditions the velocity at surface is very close to the downhole tool velocity.However, under transient conditions as the tool accelerates from rest or slows to a halt, the tool velocity cannot be expected to accuratelymatch the cable velocity at surface. As a rule of thumb, traversing a 30-ft [10-m] interval above the top perforation and below the deepestperforation allows the tool to achieve a steady velocity before logging the zone of interest.

Figure 16. Three-dimensional axial velocity distribution in recirculation. Figure 16. Diverter, or petal basket, flowmeter

Figure 17. Graphical techniques for computing the mixture velocity.