SPE SPE 10035 Society of Petroleum Engineers Production Logging by R.M. McKinley, * Exxon Production Research Co. *Member SPE-AIME Copyright 1982, Society of Petroleum This paper was presented at the International Petroleum Exhibition and Technical Symposium of the Society of Petroleum Engineers held in 8ejing, China, 18·26 March, 1982. The material is subject to correction by the author. Permission to copy is restricted to an abstract of not more than 300 words. Write SPE, 6200 North Central Expressway, Dallas, Texas, 75206 USA. Telex 730989 ABSTRACT Production logging denotes that area of well logging concerned with two general goals: (1) prob- lem well diagnosis, and (2) reservoir surveillance. The purpose of logging is to track fluid movement within or behind pipe or to monitor the movement of reservoir fluid contacts. The logs have been, traditionally, tools of the workover or subsurface engineer and the reservoir engineer. However, with the increasing hazards of drilling, the logs are becoming of vital importance to the drilling engineer. In many areas of the world, a suite of production logs are obtained before a particular well is even perforated for production. This is especially important for wells drilled within or near produc- ing fields. Successful completions through strata with unequal pressures are difficult. Because of the increasing importance of produc- tion logs, a survey of the subject is appropriate. In this paper, we review how the various logging tools work, what they measure, and how these measure- ments are related to flow. By example logs, we wish to illustrate three important points. First, production logs should be run in suites of comple- menting devices. Seldom does one log alone give satisfactory answers to a particular problem. Second, the subtle features, rather than the obvious anomalies, of a particular log often con- tain the desired information. Finally, production logging evolution has only recently turned in a direction of attempting to deal with multiphase flow of gases and liquids at low rates. As a result, the technology in this area is still insuf- ficient. INTRODUCTION Historically, the term "production log" was used to designate a well log run after a well had been placed on production. However, in modern usage, the term has come to mean any borehole Ref, md ill it It It ld ,f paper 563 survey used as an aid to either eliminating or assisting production. Traditionally, it has been the need to eliminate an unwanted flow that has spurred the growth of production logging. For a well being drilled, this flow is usually the result of premature entry into the wellbore of oil, gas, or water due to either mud pressure loss from frac- turing and flow into a weak formation or to abnormally high fluid pressure within the pore of a formation. With drill' pipe in the hole, logging device must be capable of detecting flow in the annular space between the pipe and the wellbore. For wells on production, the unwanted flow is most likely to be a water flow accompanying the hydrocarbon. This water may originate in the completed interval or it may channel behind pipe into the perforations from another formation or it may enter the wellbore through holes in the casing. The logging sonde should therefore respond to flow either within or behind pipe. Finally, for injec- tion wells, the unwanted flow would be that part of the injection which is lost by leaks to zones other than the designated injection zones. Again, the unwanted flow can be within or behind pipe. By the early 1940s, Ref. (1), downhole recording thermometers were in use to track the type of flows described above. During the 1940s, downhole recording pressure gauges and flow meters were added to thermometers as production logging devices. The disadvantage of not knowing the survey results until the device was retrieved from the well became quickly apparent. The late 1940s and early 1950s saw the development of surface indicating thermometers, flow meters, and pressure gauges, Refs. (2) and (3). Production logging subsequently became a part of the repertoire of service companies established in the field of open hole logging. Because of the difficulty and hazard of running an electric logging cable into a well against pressure, the downhole recording devices - run on small, solid wire lines - remained in wide- spread use. The introduction of grease injection control heads in the early 1960s resolved most of the pressure difficulties. We shall therefore discuss only those logging devices that are surface recording.
Transcript
SPE SPE 10035 Society of Petroleum Engineers
Production Logging
by R.M. McKinley, * Exxon Production Research Co.
*Member SPE-AIME
Copyright 1982, Society of Petroleum En~neers This paper was presented at the International Petroleum Exhibition and Technical Symposium of the Society of Petroleum Engineers held in 8ejing, China, 18·26 March, 1982. The material is subject to correction by the author. Permission to copy is restricted to an abstract of not more than 300 words. Write SPE, 6200 North Central Expressway, Dallas, Texas, 75206 USA. Telex 730989
ABSTRACT
Production logging denotes that area of well logging concerned with two general goals: (1) problem well diagnosis, and (2) reservoir surveillance. The purpose of logging is to track fluid movement within or behind pipe or to monitor the movement of reservoir fluid contacts. The logs have been, traditionally, tools of the workover or subsurface engineer and the reservoir engineer. However, with the increasing hazards of drilling, the logs are becoming of vital importance to the drilling engineer. In many areas of the world, a suite of production logs are obtained before a particular well is even perforated for production. This is especially important for wells drilled within or near produc-ing fields. Successful completions through strata with unequal pressures are difficult.
Because of the increasing importance of production logs, a survey of the subject is appropriate. In this paper, we review how the various logging tools work, what they measure, and how these measurements are related to flow. By example logs, we wish to illustrate three important points. First, production logs should be run in suites of complementing devices. Seldom does one log alone give satisfactory answers to a particular problem. Second, the subtle features, rather than the obvious anomalies, of a particular log often contain the desired information. Finally, production logging evolution has only recently turned in a direction of attempting to deal with multiphase flow of gases and liquids at low rates. As a result, the technology in this area is still insufficient.
INTRODUCTION
Historically, the term "production log" was used to designate a well log run after a well had been placed on production. However, in modern usage, the term has come to mean any borehole
Ref, md ill it It It ld ,f paper
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survey used as an aid to either eliminating or assisting production. Traditionally, it has been the need to eliminate an unwanted flow that has spurred the growth of production logging. For a well being drilled, this flow is usually the result of premature entry into the wellbore of oil, gas, or water due to either mud pressure loss from fracturing and flow into a weak formation or to abnormally high fluid pressure within the pore
of a formation. With drill' pipe in the hole, logging device must be capable of detecting
flow in the annular space between the pipe and the wellbore. For wells on production, the unwanted flow is most likely to be a water flow accompanying the hydrocarbon. This water may originate in the completed interval or it may channel behind pipe into the perforations from another formation or it may enter the wellbore through holes in the casing. The logging sonde should therefore respond to flow either within or behind pipe. Finally, for injection wells, the unwanted flow would be that part of the injection which is lost by leaks to zones other than the designated injection zones. Again, the unwanted flow can be within or behind pipe.
By the early 1940s, Ref. (1), downhole recording thermometers were in use to track the type of flows described above. During the 1940s, downhole recording pressure gauges and flow meters were added to thermometers as production logging devices. The disadvantage of not knowing the survey results until the device was retrieved from the well became quickly apparent. The late 1940s and early 1950s saw the development of surface indicating thermometers, flow meters, and pressure gauges, Refs. (2) and (3). Production logging subsequently became a part of the repertoire of service companies established in the field of open hole logging. Because of the difficulty and hazard of running an electric logging cable into a well against pressure, the downhole recording devices -run on small, solid wire lines - remained in widespread use. The introduction of grease injection control heads in the early 1960s resolved most of the pressure difficulties. We shall therefore discuss only those logging devices that are surface recording.
2 PRODUCTION LOGGING SPE 10035
Specifically, we will discuss temperature, noise, cement bond and radioactive tracer surveys along with flowmeter, fluid density, and fluid capacitance surveys. These are the surveys most widely used for problem diagnosis. Most of these have been the subject of earlier production logging discussions, Refs. (4) and (5), which the present paper hopes to update.
With the increasing value of oil and gas, those logs that assist in the economic production of a reservoir are becoming equally important. These are the cased hole nuclear logging devices that are useful in monitoring fluid contacts for the reservoir engineer and in locating new completion zones for the workover engineer. Details of these logs would lengthen the paper considerably. There is already an extensive literature on these devices, Refs. (6), (7), and (8), for example. Consequently, they are discussed only peripherally in this paper.
Another very important aspect of production logging is depth control. This will be discussed at this point and then assumed to be a part of all the other logs in the remainder of the paper. A new well is usually completed from a perforation depth control log, a PDC log, which is a cased hole nuclear log, such as a gamma ray or neutron log plus a collar log. The nuclear log is correlated to a similar log run before casing the well. In this manner, the collar depths are tied to the depth scale on the original open hole logs. The collars on this PDC log then serve as the depth reference for all subsequent production logs, each of which should have its own collar survey. Figure 1a shows that a collar locator section consists of a coil of wire, with many turns, placed between two cylindrical magnets whose poles are reversed. As the locator is pulled past a collar joining two sections of pipe, the increase in metal thickness distorts the magnetic fields cutting the coil. This induces opposite polarity voltages in the coil as each end passes through the collar. These voltages are recorded as Ittic lt marks at the surface. Such collar records are absolutely essential when logging deviated wells, where repeated reversals in the direction of cable travel are necessary to work the logging sonde into the well, or when repeated passes are to be taken. Although the counter wheels on modern production logging units are accurate to about 5 feet out of 5000 feet, any reversal of logging direction causes slippage between the cable and counter wheel. For the two situations mentioned, cumulative errors of 20 feet or more is not uncommon. Furthermore, even 5 feet may be too much error in a particular situation. Fig. 1b shows a collar record recorded on both the run into and the run out of a well completed with 2-7/8" pipe. A 3-foot "pup" joint appears at 6018-21 feet depth as a reference mark. On the run out, this joint appears about three feet too high. A noise log, which is discussed in detail later, appears on Fig. Ie. This log was taken coming out of the hole and shows flow at a liquid level at 7004 feet. A four foot shift upward would place this level at the bottom of existing perforations. Since this is a gas well, this is the depth at which the liquid level should be located. However, from the collar record, Ib, the depth at the level should be shifted downward about three feet.
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The flow is therefore associated with perforations that have earlier been closed by "squeeze cementing" to eliminate water production. These perforations are now leaking. For larger diameter pipe, the record from a small diameter collar locator may be of such poor quali.ty that a separate run with a nuclear logging tool is necessary. The logging cable can then be marked at selected depths for subsequent runs.
In what follows, any necessary depth corrections on logs will be made without further elaboration. The remaining discussion is divided into two major classes - those devices which are useful in detecting flow behind the pipe containing the logging tool and those useful for the detection of flow within the pipe.
Behind Pipe Flow: Temperature, Noise, Radioactive Tracer, and Cement Bond Surveys. Of the commercial devices, only the temperature and noise surveys are capable of giving positive indications of behind pipe flow in those situations where there is no fluid connection with the outside environment. These are complementary surveys that can be obtained with one logging run. The temperature log is obtained going into the well to prevent vertical mixing of wellbore fluid, while the noise log is obtained coming out.
Temperature Surveys - Although temperature surveys in a wellbore are the oldest production logging techniques, Refs. (1) and (9), they remain exceedingly useful for problem well diagnosis. A temperature log indicates the presence of flow by causing a departure of the borehole fluid temperature from its static or geothermal value. Under static conditions, temperature increases gradually with depth. Although quite variable with location, a geothermal gradient of 0.017 °F/ft is "typical" of sand-shale sequences. While the local gradient may not be known with great accuracy, an estimate is usually sufficient.
The type of disturbance that a particular flow situation produces, relative to geothermal temperature, can be classed as one of three cases: an injection gradient, a production gradient, or a circulation gradient. Each flow situation produces the type of temperature profile illustrated schematically in . 2. Injected fluid is usually cooler than ,rh~rm~l temperature at some depth, such as A in Fig. 2a. Below this depth, the flow cools the wellbore below geothermal to the deepest point of injection, the perforated zone C in the figure. Below this depth, the temperature returns to geotherm~l by vertical conduction which gives a profile that is concave toward geothermal. Once the injection is stopped, those portions of the borehole not coincident with injection zones will return to geothermal fairly rapidly, leaving a cold anomaly at an injection zone, location C on Fig. 2a. If the injection has continued for several days, then the injection cold anomaly will appear to "grow" in size on sequential shut-in logs as the rest of the borehole returns to geothermal. The behavior of the cold spot at B in Fig. 2a shows sustained injection at this location as well. This is the way in which an injection problem shows up. If gas is injected,
SPE 10035 R. M. McKinley 3
then some expansion cooling may occur whenever the gas pressure drops, such as at the injection zone C of Fig. 2a.
1f a well is on production, then the flow heats the borehole above the point of fluid entry, zone A on Fig. 2b. Once the production ceases, the borehole will return to geothermal from the hot side. Figure 2b shows that flow continues at a lower rate up to depth B after the well is shut-in. Gas production can show cooling at the productive zone, due to its expansion, as indicated on Fig. 2b. Finally, a circulation profile is shown on Fig. 2c. The two previous profiles have been either parallel to or concave towards the geothermal gradient; however, the ci~culation profile is concave away in the cooled portions of the wellbore.
Before actual logs are illustrated, a brief description of how a moderrr, surface recording thermometer operates is given. A sketch in Fig. 3 shows that the resistive sensing element, usually a wire coil, is in a cage at the bottom of the device. The element is part of either a bridge circuit or a constant current circuit such that a voltage proportional to temperature can operate a voltage controlled oscillator that transmits a frequency modulated Signal (FM signal) to the surface. This eliminates the attenuation influence of varying cable lengths. At the surface, the FM signal is reconverted to a voltage for recording as a temperature. A continuous record of temperature is obtained as the device is run into the well at logging speeds of 20-30 feet per minute. This record is called a "gradient" curve. Some form of amplification is usually available on either the temperature or its rate of change (differential curve). The absolute accuracy of the device is usually only about ±5°F due to a combination of logging speed and infrequent calibration. The resolution is, however, quite good. Changes of the order of O.l°F are easily detectable. The customary depth scale of either one inch or five inches of log per 100 feet of depth is not all that satisfactory. From such a long strip of paper, it is difficult to recognize the subtle trends indicated on Fig. 2. Consequently, the depth scale is greatly reduced on the examples that follow. The diameter of these type of thermometers range from 7/B-inch to 1-11/16-inches.
Our Fig. 4 shows a sequence of temperature logs run to determine the source of water in a gas well. A total of 200 barrels of field salt water was injected into the well at a rate of about 600 BPD. On the log obtained while injecting, the temperature begins its "conductive" return to geothermal temperature just below the perforations. There is a slight disruption in this return about 20 feet below the perforations at depth A on Fig. 4. The shut-in curves after 1 and 2 hours show that a small amount of injection has occurred at this depth. Since there is a water sand here, this is the most likely source of water during production. The effect of injection at A has practically disappeared from the 17-hr shut-in log. This is a good illustration of the sequential or "time-lapse" logging procedure where time is obviously critical to successful interpretation. Note also that the logs do not give the path taken by the water in reaching depth A. The flow may leave through a casing hole at this depth or travel behind pipe from the perforations.
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A recent evolution of the thermometer which will help in determining the flow path is the radial differential thermometer (RDT). In addition to the section shown on Fig. 3, the RDT device has a section which can be anchored by bow springs at a given depth. Two arms containing the temperature sensing elements are then extended to contact the casing wall. The difference in the output of these sensors is then recorded as they are rotated around the circumference of the casing. If this device were anchored about 10 feet below the perforations in the example of Fig. 4, it should show one side of the pipe preferentially cooler if the injected water is flowing in a channel behind pipe. A most promising feature of this device is its potential to orient a perforating gun to shoot into the channel. A prototype of this thermometer has been demonstrated for field use, Ref. (10), and it is ~Ull11UCLLi avail-able on a limited scale.
Other logging devices that would be useful for determining the flow path are the radioactive tracer and the noise logging tools. These are discussed later.
Considerable effort has also gone into making quantitative rate determinations (injection profiles) from temperature logs such as those of Fig. 4. That this is very difficult for the shut-in anomalies is well illustrated by the model study of Ref. (11). It is much easier to relate the rate to displacement of the flowing curve from geothermal, Refs. (9) and (12). The last reference summarizes the details of rate estimation excellently.
The next example illustrates a typical production profile. The temperature log in Fig. 5 was run after a flowing oil well had been shut in for 24 hours. This particular well had pressure on both the 2-3/8" - 5-1/2" annulus and the 5-1/2" - 9-5/8" annulus. The log shows a return to geothermal temperature only over the top 400 feet. Below this depth, there is a large crossflow originating at the perforations; there is an underground blowout in progress. Several features of the log are worth exam1n1ng. Above depth A, the CUrve shifts slightly to lower temperatures. This can be looked upon as a "shielding" effect that the tubing provides for the thermometer once the flow shifts from inside to outside the tubing as illustrated in Fig. 5. Actually, the shift occurs because the thermometer, traveling downward, does not equilibrate with its surroundings as rapidly in stagnant fluid as it does in moving fluid. Proceeding up the hole, we see that the production profile is altered above depth B. Yet the temperature does not begin a conductive type decay until above 600 feet, depth C on the figure. These observations suggest the indicated circulation between 1000 and 600 feet. Above 600 feet, the temperature log shows some "anomalies" due to lithology.
Lithology can have a pronounced effect on a temperature log. In Table 1, various earth materials and fluids are listed in Column A according to decreasing thermal conductivity, k. This will also be the order of increasing static geothermal gradient. Groups of materials have similar conductivities. Gpnpr~ll , an increasing water content accounts for the decreasing conductivities. The dramatic difference between the static in
4 PRODUCTION LOGGING SPE 10035
shale and salt is illustrated in Fig. 6a for a well drilled into a salt dome. The large heat flux upward through the salt causes a high gradient in the poorer conducting shales above. Figure 6b shows that a shale-sand sequence also produces a non-linear gradient, which in fact somewhat resembles an injection flow profile.
Most wells, however, are not at static conditions when first logged. Lithology also plays a role in the manner in which temperature returns to geothermal. The larger the thermal diffusivity
k ' pc- , whe:e p is the density and c the heat p capaclty, the more rapid is th~ return to geo
thermal temperature. In column B of Table 1 materials are listed in order of decreasing ~hermal diffusivity, which is the same as the order of increasing lag time to get back to geothermal. While a well is flowing, convective heat transfer produces a profile nearly free of lithological detail. When the flow is stopped, those portions of the wellbore traversing high thermal diffusivity beds change toward geothermal temperture most rapidly. The lithological detail due to this radial heat flow grows during the early stages of shut-in. This creates high vertical temperature gradients which oppose the radial heat flow. Consequently, the lithological distortions die out with increased shut-in times. This is illustrated in Fig. 7a which shows a 6-hr shut-in log dominated by lithology and a 24-hr shut-in log on which the lithology effects are much more subdued. The "cold" spikes are water sands that can be correlated with a self potential or gamma ray log. Had this been an injection well, the "anomolies" would reverse. Water sands would show up as "hot" spikes.
The nature of the well completion also influences the manner in which temperature returns to its geothermal value. Fig. 7b is a montage of illustrations from Ref. (13). After circulation is stopped, the hole enlargement at depth A looks like an injection zone with the exception that the anomaly will first grow and then die out as shut-in ~ime increases. The cemented casing, starting at B, lnsulates the formation and prevents its cooling as far away from the well as does the open hole. On shut-in, the insulated portion therefore returns to geothermal faster than the part below the casing. The same insulating effect is provided by the washout at C which is filled with cement. The direction of these shielding anomalies assume that the wellbore fluid temperature equalizes over the cross section more rapidly than in the formation. This may not be the case either for very short shut-in times or for short flow periods. Referring back to Fig. 4, we see that the shielding effect of the tubing on the I-hr shut-in curve is the reverse of that shown in Fig. 7b at depth B. Initially, the tubing-annulus insulation slows the transfer of heat to the fluid inside the tubing relative to that in the casing below. By 2 hours shut-in this reverse shielding anomaly has disappeared, while on the 17-hr profile the anomaly is in the proper direction as shown on Fig. 7b. For very short flow periods, the anomaly may remain reversed as it appears on the 1-hr profile of Fig. 4. In any case, the transient distortions due to either lithology or completion first grow and then die out on sequentially run temperature logs. This contrasts to long-time flow anomalies which continue to grow. In fact, zones
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may continue to show temperature anomalies for years after injection has ceased.
Finally, a standing liquid level produces a shift similar to that illustrated at depth A in Fig. 5 as the thermometer enters liquid from gas.
Our next example illustrates lithological influences. Fig. 8a shows injection logs run 3 weeks after a massive hydraulic fracturing treatment on the perforated interval indicated on the figure. Before injection, the log on the right, labeled as 3 weeks, was obtained. It shows a residual from fracturing that indicates fluid injection or fluid redistribution over the entire interval. After this log, 240 barrels of water was injected over a onehour period at 4 bbl/min rate. The profile during injection is the leftmost curve on Fig. 8a. It shows that the shallowest injection point is at the top of the perforations. A second major injection is at a depth of about 9160 feet. The 1-hr shut-in is already beginning to show lithological influence in the sand-shale sequence above the perforations. The anomalies at 8750 and 8840 feet appear as growing "cold" spots during the first 6 hours and then begin to be subdued at later times. These spots are at depths where the gamma ray log shows shales between massive sands. According to column B in Table 1, shales should not return to geothermal temperature as rapidly as do sands. This accounts for the "cold" spots. By contrast, the injection anomalies at 9000 and 9160 feet continue to "grow" at least during the first 12 hours of shut-in. These logs were run to determine if any flow behind pipe was going into the sands above the perforations. There is no indication of such flow. The temperature logs immediately after are also interesting. Two of these are shown on 8b where we see the same cold injection interval between 9100 and 9200 feet that appears on Fig. 8a. By contrast, the 9000-ft injection zone at the top of the perforations is showing up as a "hot" spot. One would tend to say that no injection occurred here. However, this behavior has been observed before, Ref. (14), where it was speculated to be the result of flow from one wing of the fracture through the wellbore into the second wing as earth stresses redistribute after fracturing. This flow, originating away from the wellbore, would be warmer.
As a final example of some of the subtle features of temperature logs, there appears on Fig. 9 a sequence of logs run on a new gas well that was drilled as an infill well in an old gas field. The log of Fig. 9a was run 20 days after the well was cased to 5800 feet with 5-1/2" casing. Consequently, the temperature should be near geothermal values. There are two features to the log: a "cold" anomaly at 5475 feet, and a "cold" interval from 5560 to 5675 feet. The latter behavior in the 5500-5700 foot interval resembles the lithology pattern of a shale-sand sequence as illustrated in Fig. 6b, and is probably not indicative of crossflow between sands Band C. The "cold spike" at 5475, however, is not characteristic of a static geothermal profile, being instead suggestive of gas expansion cooling. This, in turn, suggests gas flow from the higher pressured A-sand past a constriction at 5475 to the lower pressured M-sands. This is, however, undesirable since gas is being injected
SPE 10035 R. M. McKinley 5
into the A-sand for pressure maintenance. The size of the "cold spot," :::: 1°F, is related to the size of the pressure drop at that location rather than to the amount of flow. For methane, the adiabatic (Joule-Thompson) cooling coefficient is typically one Fahrenheit degree per 40 psi pressure drop. Actually there is at least a 200-psi pressure difference between the A-sand and the M-sands. The flow is not adiabatic and is, in fact, at a low rate. This low rate is evident from the fact that the cooling is not carried downstream from 5475 toward the M-sands. Figure 9b shows the two higher frequency measurements on a noise log from this well. This log, discussed more fully in the next section, also shows crossflow in the 5400-5500 foot interval, but does not indicate any flow between the B- and C-sands below 5550 feet. The well was then perforated and flowed for 28 hours for clean up. Subsequent shut-in temperature logs are shown on Fig. 9c. These logs show that all the gas production came from the completed interval. The growth of the small flow anomaly at 5475 feet depth is evident.
The above examples illustrate the various factors that influence a temperature survey. However, a temperature log alone seldom gives enough information to completely diagnose a particular problem. Therefore, it is prudent to run the tool in combination with other devices such as the noise log discussed next.
Borehole Sound Surveys - The detection of sound generated by the turbulence associated with behind-pipe flow was described early in the history of production logging, Ref. (15). A more complete discussion appeared in 1973, Ref. (16), shortly after which the service became available commercially, Ref. (17). Specialized applications are described in Ref. (18). The logging device is a hydrophone which is positioned at a particular depth to record the sound level in the wellbore at that depth. Commercial tools range in diameter from 1 inch to 1-11/16 inches, and are capable of re~glving pressu~e oscillations as small as 10 psi in amplitude, Ref. (16). As indicated on Fig. lOa, the device transmits an amplitude modulated voltage to the surface where it is passed through a sequence of high-pass filters that span the frequency range from 200 Hz to 2000 Hz. Two optional filters at 4000 and 6000 Hz are also available. As discussed in Ref. (16), the audible frequencies will usually be most sensitive to fluid turbulence generated behind pipe. At each stop, at least four readings are taken to give four curves of noise amplitude versus depth on the completed log. The way each of these curves should look is illustrated in Fig. lab for the hypothetical situation shown. Fluid accelerating from the source sand at depth A produces a peak in the noise record whose amplitude is proportional to the cube of the velocity, Ref. (18), at that point. A second peak in the record appears at depth B where the fluid accelerates past a tight spot in the cement. The peak amplitude will again reflect localized velocity at depth B. If the fluid speeds up to leave the channel at depth C, a third peak will appear on the sound record at that depth. Three points are illustrated in Fig. lOb. First, the velocity of most leaks behind pipes will be sufficiently large that there will be an increase
567
in noise level above ambient throughout the crossflow interval, A-C in the figure. Second, the record will show peak noise levels at those depths where the fluid accelerates. This may occur at fluid sources, sinks, or at constrictions to flow. Hence, the log's character reveals information about the flow path. Finally, on either side of a peak, there is a conductive carry-away of sound. In contrast to the temperature log, several thousand feet may be required for the lower frequency curves to reach ambient noise level which is usually in the range 0.1 - 4 millivolts. Because of the randomly changing phases, this carry-away can hide smaller peaks on the record. For example, any peak in the interval between depths A and B on Fig. lOb would need an amplitude exceeding the carry-away amplitude at the peak location if it is to be detected by the survey.
Four readings are taken at each stop to identify the frequency character of the sound source. This, in turn, helps identify the type of leak. If the flow in the confined environment behind pipe consists of a single phase (gas or liquid) or a mixture of liquids, then the turbulence generated by the accelerating flow will have a relatively high frequency, 1000 Hz or above. The individual filter readings at the peak will be close together, at least through the 1000-Hz cut, as illustrated in Fig. 10c. If the flow consists, however, of gas having to bubble or head through liquid, all the peak readings will spread out as in Fig. lad. In fact, the difference in amplitudes between the 200-and 600-Hz readings will generally exceed the amplitude of the 1000-Hz This type of flow generates considerable sound in the 200-Hz range. For a given flow rate, the amplitude is much greater than for single-phase flow. These concepts are illustrated by the following examples which discuss the combination temperature-noise survey.
Figure lla shows a temperature log run in the drill pipe of a well shut in after a pressure surge (kick) occurred at the surface six hours earlier. The log shows a crossflow from the greatest depth reached up to 15,600 feet. The log, however, does not tell how the flow gets to the shallower depth. The flow may take place inside the casing to a split at 15,600 feet. Alternately, the flow may be behind the casing if the pressure surge destroyed the cement bonding. The remedial action required is different in the two cases. The noise log, Fig. lIb, helps decide the issue. The number of peaks, starting at the casing shoe, on the log indicates a very torturous flow path, i.e., a flow behind pipe to the 15,600-foot sink sand. Furthermore, the crowding together of the three lowest frequency curves shows a single-phase type of flow. Since the well contained drilling mud, this single phase requirement eliminates gas as a source fluid for the underground blowout. Note from Fig. lIb that ambient or dead well noise levels are reached only above 13,000 feet which is some 2600 feet above the sink sand. Also note that the highest frequency curve, the 2000-Hz curve, attenuates most rapidly to ambient level. Consequently, the optional 4000-Hz and 6000-Hz measurements can often be used for better vertical resolution.
6 PRODUCTION LOGGING SPE 10035
The noise log of Fig. 12 should be contrasted with that of Fig. lIb. The Fig. 12 log also shows crossflow from 4800 feet to the 800-1000 foot level. However, the lack of peaks other than statistical in the intervening interval means that the flow is inside pipe or above cement tops outside pipe. According to the well completion sketch, the flow is apparently entering the 9-5/8"-7" annulus at 4800 feet.
A noise log is particularly useful in detecting small gas leaks into liquid. This is illustrated by the logs on Fig. 13 from a well that developed annulus gas pressure before completion. Fig. 13a shows a temperature log obtained while venting about 50,000 scf/D of gas from the 13-3/8"-20" annulus. This log is dominated by the heat generated by curing cement as evidenced by the hot interval from the bottom of the 20" casing at 560 feet to the cement top in the annulus at about 170 feet. The gas source is not evident on the log. By contrast, the noise log of Fig. 13b shows a gas entry into liquid at 2450 feet. This is the deepest gas source. There is flow upward behind pipe from this depth. It is not possible to determine from the log whether the large peak at 1400 feet is an additional gas source, a constriction, or a water sand being charged by gas. In any case,the deepest source should be eliminated first. This well was perforated at 2100 feet after which cement was pumped behind the 13-3/8" pipe and allowed to set. The well annulus would still flow gas but at a greatly reduced rate. A second noise log, Fig. 13c, shows that this gas source is in the vicinity of 1500 feet. It is most likely the sand at 1400 feet in the log of Fig. 13b. A charged water sand is now discharging. The pressure drop associated with charging intermediate sands can cause shut-in gas pressure at the surface to be a deceptive indicator of the depth of a gas source.
Flow rates within a factor of two to three can be estimated from peak noise levels. Details appear in Refs. (16) and (18). Briefly, for single-phase flow, the noise amplitude is proportional to the pump work creating the peak, i.e.,
where q and ~p are the flow rate and pressure drop creating the sound peak, C1 is a calibration constant, and Ninoo is the peak ~oise value from the 1000-Hz curve. TfilS latter read1ng must be corrected for cable attenuation, tool gain, and well completion. For example, if the reader will refer back to Figs. 9a and 9b, he will recall that these logs indicated a small gas flow from the A-sand to the M-sands which were some 200 psi lower in pressure. Using the methods outlined in Ref. 16 and the 1000-Hz noise level at 5475 feet depth, we estimate the loss from the A-sand to be about 100 cu. ft/day at bottomhole conditions or about 20,000 cu. ft/day at standard conditions.
For small gas flow rates through liquid, the flow rate is proportional to the noise in the 200-600 Hz band, Ref. (16)
where C2 is a calibration constant.
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Rates estimated from noise logs in the above fashion are crude, but can be satisfactory in deciding the seriousness of a particular problem.
Extraneous sOUrces of sound are the greatest impediment to noise log quality control. These extraneous SOurces may be surface equipment noise or inadvertant flow past the sonde or continued movement of the logging tool during measurement, as, for example, happens when logging in heavy mud or from floating vessels. Fig. 14a shows a noise log run from a floating drill ship. The combined motion of the ship and the telescoping of the pipe sections attached to the ship have created a high noise level throughout the section of free pipe above the cement top at 5200 feet. Even below this depth, the noise levels are high and erratic. As a second example, Fig. 14b is a noise log obtained from a supposedly shut-in oil well. There is actually a leak at the wellhead which allows a small flow of gas through liquid originating at the perforations below 5550 feet. This flow does not create much of a problem until it enters the smaller diameter tubing. Here, the clearance between the pipe wall and the sonde is so small that the flow velocity becomes significant. The problem becomes worse at shallow depths where additional gas evolution occurs.
Another aspect of the noise log should also be illustrated. If flow is occurring, then a standing liquid level will show up dramatically on a noise log since sound attenuation away from a source in a liquid is much less than in a gas. The log on an earlier figure, Fig. lc, shows a liquid level at about 7005 feet depth. Because of the better sound transmission away from the source at 7005 feet, the part of the borehole below the liquid level is much noisier than is a comparable section above the level. Also, the character of the noise below the liquid level is not due to flow behind pipe at these depths, but results from variations in the source strength at 7005 feet.
The combination temperature-noise survey is the primary detection procedure for flow purely behind pipe. If the flow can be tagged with a radioactive tracer in the wellbore and then pumped out perforations, then the radioactive tracer device is a very effective tool for observing the flow of the tagged fluid behind pipe.
Radioactive Tracer Surveys - The radioactive tracer tool assembly is seen in Fig. 15a* to consist of a casing collar locator (eCL) , a reservoirejector assembly, and two gamma ray detectors. The spacing between the detectors can be varied - up to, typically, ten feet - to accommodate a range of fluid velocities. The relative positioning of detectors to ejector can also be changed. As positioned in Fig. 15a, the detectors will time the passage of a slug of tagged fluid flowing downward, as illustrated in Fig. I5b, where the times of maximum (peak) activity are used for timing. Since the slugs can become dispersed, the times at onehalf peak value are sometimes employed. Usually, a few seconds error is present in the timing. This error determines the high velocity limitation of the device. The device is excellent at low flow rates
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SPE 10035 R. M. McKinley 7
if the density of the tagged fluid is closely matched to that of the we1lbore fluid. The low flow rate resolution is far better than any of the mechanical flowmeters available.
A variety of tracers are available including water soluble, oil. soluble, oil/water soluble, and gaseous. Produced gas, however, will tend to strip tracer from a liquid. Common fluid tracers are Iodine-13I, with an 8-day half life, and Iridium-192, with a 74-day half life. Both emit gamma rays at roughly 0.4-0.5 Mev level.
To track flow behind pipe, the device is used as illustrated in Fig. 16. The wellbore interval is first logged with a detector sensitivity sufficient to give a base log comparable to a cased hole gamma ray log. The ejector is then located opposite the perforations and a slug of tracer ejected with the well shut in. A small amount of injection at the surface is then used to displace the t:gged fluid into the perforations. The interval is re10gged to give the solid curve on Fig. 16 with peak activity at the perforations. Additional injection is then made from the surface to push the tracer into the formation or into any channel communicating with the perforations. A subsequent log, the dashed curve of Fig. 16, shows that some tagged fluid has moved up outside the pipe to the 9000 foot level indicating communication with gas sands at this depth.
Proper timing, acquired by experience, is obviously important in the type of surveys illustrated in Fig. 16. Also, the pressure differences may be such that all the injection enters the completed interval. Crossf1ow because of pressure imbalance should appear on temperature-noise surveys with the well shut in.
Most tracer devices eject the slug perpendicular to the axis of the sonde. This is not satisfactory in a borehole which contains fluid that exhibits plastic or yield behavior, such as heavy drilling muds or certain fluid emulsions. Most of the ejected tracer remains in the stagnant zone at the pipe wall. The device should be modified to concentrate the tracer near the pipe center.
For flow surveys inside pipe, the device should always be calibrated at a depth receiving 100% of the total flow. This eliminates the question of what velocity the device measures.
It is also common practice to coat with a tracer the solid propants used in hydraulic fracturing, Ref. (19), to help estimate vertical fracture extension. It is good policy to tag the entire batch of solids rather than a portion, because most detectable radiation will come from within a foot of the wellbore. Since these tagged solids are introduced into the well at the surface, collection within the tubing-casing can be quite a problem, particularly at collars or at the ends of tubing strings. After fracturing, a short fluid injection or a short flow period will help flush out the collected solids.
The success of the above procedures is predicated on tagging the fluid or solid inside the pipe. A prototype device to create a tracer in
569
water beind pipe has also been demonstrated, Ref. (20). This device uses a 14 Mev neutron generator to activate oxygen to nitrogen-16 whose decay gamma radiation can then be detected. This method has the potential to detect very low water flow rates. However, the device is not available commercially at this time. Water flow behind casing is also known to precipitate radioactive salts leached from shales. A sequence of gamma ray logs can sometimes be used to detect such flow, Ref. (21).
In addition to the primary devices discussed above, a properly run cement bond log can give information on the quality of a completion.
Cement Bond Logs - A cement bond log evaluates the quality of a cementing operation by the fact, amply illustrated in our earlier Fig. 14a, that sound travels along free pipe much better than along pipe to which cement is bonded. The logging device is similar in operation to an open-hole velocity logger, consisting of a pulsed transmitter and two receivers. The log is presented in a format that indicates the amplitude of the 20-30 KHz signal that travels along the pipe from the transmitter to the first receiver. This is an indicator of the lack of bonding of cement to pipe. To identify signals traveling through the formation - and hence, cement bond to formation -some form of wavetrain display, such as the variable density displays of Refs. (22) and (23), is also presented. Sound amplitudes are, of course, highly non-linear functions of the fraction of pipe circumference to which cement is bonded. Numerous other completion factors also influence these amplitudes, Ref. (24). It is still difficult to relate bond log characteristics to the presence of flow behind pipe with any more consistency than one can anticipate completion problems from, say, an open-hole caliper log. The author does not feel that at the present time the bond log is a primary production logging device. Opposing views are expressed in Refs. (25) and (26).
The primary logging devices discussed above will also respond to flow inside pipe. However, there are specialized logging tools more appropriate to this application. Modern practice is to run combination tools (Ref. 27) including those above and those to be discussed next.
making velOCity see if flow is occurring at a given depth along with fluid identification measurements to determine what is flowing. The use of the radioactive tracer device for velocity measurements has already been discussed. The other popular flowmeter is the spinner-type described next.
Spinner Flowmeter Surveys - The spinner flowmeter consists of a propeller mounted on a jewel supported shaft. The shaft has either magnetic keys or opaque keys so that its rate of rotation can be measured by pickup coils or by phototubes (optically) Some devices have eccentrically located keys to sense the direction of rotation. Early flowmeters were of the diverting type, such as the packer flowmenter of Fig. 17a, which diverted all the flow past the spinne
8 PRODUCTION LOGGING SPE.10035
These devices are stopped in a perforation-free section of casing, the packer element inflated, and a measurement taken. They are excellent in the flow range 15-2000 BPD. The interference of these tools with normal flow, their inability to measure high flow rates, or to profile in perforated intervals in addition to the operational inconvenience brought about the popularity of the non-diverting or continuous spinner illustrated in Fig. 17b. These devices log continuously at a constant logging speed. They are run centralized and obviously sample only a portion of the flow field. Two calibration curves* from a 6-inch flow loop appear on Fig. 18a for this type of spinner. For calibration, the tool is held stationary and fluid pumped past it. The calibration line for water has a slope close to the non-slippage slope for a propeller with a 4-inch pitch. However, the tendency of low pressure, low momentum gas to bypass the spinner without turning it causes the slope of the gas curve on Fig. 18a to be much less than that for the water curve. To improve this cross-sectional sampling, spinner flowmeters whose blades collapse while running through tubing and open in casing are also available, Ref. (28). This device is shown in Fig. 17c with the spinner vanes in both the collapsed and opened position. Calibration curves for this "fullbore" flowmeter in both water and gas are given in Fig. 18b'/('/( where the gas curve is seen to be similar in slope to the water curve.
The calibration response for all spinner-type flowmeters are non-linear at low fluid velocities (low spinner speeds); however, the extrapolations shown in Fig. 18 serve to establish frictional cutoff, or bypass, velocities, Vf' as indicated on the figure. In 5-1/2" casing, tfie liquid cutoff value, Vf = 3.5 ft/min, is equivalent to about 110 BPD flow cutoff. The tools are run continuously in an effort to improve on the low flow rate resolution by keeping the spinner turning. As a practical matter, however, the continuous spinners are high flow rate devices for which this 3 ft/min cutoff velocity is realistic for liquids. With the device moving at constant speed, VQ, the calibration equations relating spinner speed, S, to apparent fluid velocity, Vsf ' are
(a) Logging against flow
(1)
(b) Logging with flow: VQ > Vsf
(2)
(c) Logging with flow: VQ < Vsf
S (3)
where a is the calibration slo.pe, expressed here in RPS/(ft/min).
The spinner apparent v~locity is proportional to the average fluid velocity V, i.e.,
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g = C V A 1 sf (4)
Various companies list calibration constants Cl in the range 0.73 to 0.84.
The use of a continuous flowmeter to obtain a flow profile across a perforated interval in a water injection well is illustrated in Fig. 19a. The injection rate is 5000 BPD. There are two solid curves on the figure, the left one being a run down, in the direction of flow, at a logging speed of 200 ft/min. According to Eq. (2), the fluid velocity subtracts from the line speed to give the lowest spinner speed, 5 RPS, above the perforated intervals. The right curve is a run up, against the flow, at the same logging speed of 200 ft/min. In this case, the fluid velocity adds to the logging speed, Eq. (1), to give maximum speed above the perforations. The zero fluid velocity OCcurs where the two runs overlay, that is, where only logging speed is influencing spinner speed. This dynamic zero occurs at the bottom of the top set of perforations; within spinner resolution, all the injected fluid is leaving the wellbore at the top set of perforations. Note on Fig. 19a, that the two runs are not symmetrical about a vertical extension of the zero-flow line. This results from the combination of high logging speed and finite response time of the device. On the up run, the apparent zero is shifted about 6 feet up the hole while a similar shift downward occurs on the down run. This is illustrated by the dashed line on Fig. 19a which is the up-run shifted down by 12 feet to give a symmetrical opening. This total shift is determined by tracing one run, turning it over and moving it vertically until it overlays the other. The result is that the actual zero flow depth is about 6 feet from the bottom of the perforations.
The difference between the two depth adjusted traces, obviously, is free of the common logging speed and frictional cutoff velocity. This difference is therefore proportional to fluid velocity and can be divided by the difference at 100% flow to give the reasonably uniform injection profile of Fig. 19b. Successive differences in the percentages shown on Fig. 19b can be used to construct the percent injection profile of Fig. 19c. Such a presentation, however, amplifies noise in the survey.
Temperature logs from this well, Fig. 19d, show that some injected water is reaching the second set of perforations, although at a much reduced rate. This flow is either less than the flowmeter resolution or is taking place behind pipe. A noise log showed that the latter was the case.
If different fluids enter the wellbore at different depths, then a wide range of viscosities may be encountered. The two-pass profiling technique described above tends to compensate somewhat for this since both the up and down runs are influenced. It is good practice, however, to calibrate a continuous spinner by making a number of runs at various logging speeds, thereby constructing a response curve at various depths in the well, Ref. (28). This is crucial to quantitative interpretation and will be illustrated later.
SPE 10035 R. M. McKinley 9
Increasing demands to measure low rates of flow of mixtures of gas, oil, and water are causing the reappearance of spinners similar to the packer types of Fig. 17a. These newer devices have motorized vanes .or bonnets that can be extended to touch the casing wall. This diverts most of the flow through the tool throat past the spinner. These sondes are usually kept stationary for readings, but they can operate up to 4000 BPD and apparently give satisfactory profiles in perforated intervals. A calibration curve for such a flow meter over the high-rate range appears on Fig. 20.* The flow loop has a 6.S-inch diameter while the flowmeter diameter is 2-1/8-inches. The flowmeter to handle the higher flowrates without leakage around the diverting elements.
Wellbore turbulence, i.e., velocity components perpendicular to the wellbore axis, definitely interferes with the operation of the continuous spinner flowmeters. These velocity components also exert their momentum on the spinner. In high production rate wells, this turbulence may persist for a hundred or so feet above the perforations.
Wellbore turbulence becomes very intense in wells producing more than one phase. Because of buoyancy forces, the less dense phases rise faster than the heavy phase. The lighter phases flow as discontinuous bubbles or slugs so that their passage at a particular depth causes first an uplift of the heavy phase followed by a fall back. The heavy phase therefore sets up localized circulation cells. These circulation patterns maintain a holdup volume fraction of heavy in the wellbore that is much greater than the net fractional production rate of the heavy phase. In fact, the percentage holdup of a phase does not approach its percentage flow rate until the average flow velocity becomes several times greater than the buoyant or slip velocity for that phase. At about 10 times the slip velocity, the phases travel together. These slip velocities are large relative to typical flow rates. Gas, at typical downhole pressures, has a slip velocity through water of about 40 ft/min. At pressures near atmospheric, the apparent slip velocity can exceed 100 ft/min, Ref. (29). Typical slip velocity for gas in oil is 20 ft/min and for oil in water is 10-20 ft/min.
Such chaotic flow will, of course, cause considerable noise in a spinner record. Fig. 21 contains spinner surveys from a well flowing oil, water, and gas at the rates indicated. At bottomhole temperature and pressure, the total liquid rate is about 400 BPD while the gas rate is about 500 BPD. In 5-1/2" casing, the combined flow produces an average fluid velocity of about 30 ft/min, less than the gas-liquid slip velocity. The top figure in Fig. 21a shows an up and down pass, each at a logging speed of 26 ft/min. The noise above the perforations, relative to that below, is apparent. On the up-log, the relative velocity of the tool to the fluid is less than on the down-log; consequently, the noise level on the up-log is worse. Also, since on the up-run at 26 ft/min, the spinner does not go to zero speed or reverse direction, the apparent average fluid
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571
velocity does not exceed 26 ft/min. The two runs fi the zero velocity point at a depth below the top of the lower set of perforations, shown in black, which had been cemented to eliminate water production. An area of very strong turbulence is evident at the top of the cemented perforations, which indicates a high velocity entry at that depth. This turbulence is even more pronounced on the lower figure which is a logging run down at 4 ft/min. The survey gives at least qualitative information; namely, the cemented perforations are leaking. Figure 21b is a calibration curve obtained in 100% flow at 7100 feet depth. A plot of spinner speed versus logging speed for eight passes is given. The spinner speeds are visual averages from each pass. The response is reasonably linear with a s16pe near the liquid response slope shown on Fig. 18a. The response line on Fig. 21b extrapolates to a zero spinner speed at a logging speed upward of
Vi = 14.5 ft/min
This would be the speed necessary for the logging tool to keep up, within frictional velocity, with the flow stream. If S is set equal zero in our previous Eq. (3), then the resulting fluid velocity is
Vsf ~ V1 + Vf = 14.5 + 3.5 = 18 ft/min
If this value is taken equal to the average fluid velocity, V, then
0.131 x 18 2.36 cu. ft/min
q = 2.36 x = 605 BPD
while the actual flow is closer to 900 BPD. From the gas response curve of Fig. 18a, one would expect the gas flow to be underestimated. Another curve similar to that of Fig. 21b is at a depth between the two sets of perforations in order to estimate flow from the lower set. It is evident from Fig. 21a that such a curve is not available because of wellbore turbulence. This is often the si tua tion throughout the completed interval. In fact, flow loop data given in Ref. (29), Fig. 14, shows that for low pressure gas slugging through water, there is almost no correlation between a continuous spinner reading and the average flow velocity. If the tool is stopped and readings are time averaged, then a correlation does exist as shown on Fig. 20 of Ref. (29). This suggests that the practice of racing up and down the well with the device may be counterproductive.
Other possible solutions will be discussed after describing fluid identification devices, but we should point out that continuous flowmeter surveys are not meaningful in deviated or inclined wells where the lighter phases segregate and flow along the top of the well. On the other hand, the diverting meters, such as the basket flowmeter of Fig. 20, operate in inclined wells with little or no error due to deviation angle.
Borehole Fluid Density Surveys - Two types of density logging devices are available that give a continuous record of borehole fluid density with
10 PRODUCTION LOGGING SPE 10035
depth. The first is a pressure gradient tool, called a gradiomanometer, illustrated on Fig. 22a. With a sequence of three bellows, this device measures the pressure difference across a two-foot distance in the wellbore. For a vertical well without significant flowing frictional losses, the tool output is directly proportional to fluid density. It should also give a representative cross-sectional sample. The second type of density logger is a gamma ray absorption device that consists of an open cage through which wellbore fluid can flow. At the base of the cage there is a gamma ray source, typically Cesium-137, focused along the axis of the cage. Focused detectors at the top of the cage measure the activity of the radiation. As the calibration curve of Fig. 22b shows, the logarithm of the activity is inversely proportional to fluid density. Since this is a statistical measurement, stop readings are advisable. The device also samples near the pipe center which is where the lighter phases tend to flow. We also want to again emphasize that densities are indicative of wellbore fluid holdups, not flow rates, that is,
p (5 )
(6)
where p is the mixture density, p. and y. are the pure phase densities and phase holdups, the subscripts w, 0, and g meaning water, oil, and gas, respectively. Since the holdup is weighted towards the highest density phase, water, the mixture density will be even more heavily weighted towards water.
A gradiomanometer and fullbore spinner survey is illustrated in Fig. 23 for a well flowing 5000 BPD oil and 5000 BPD water. These rates correspond to an average fluid velocity of 190 ft/min; consequently, the oil and water should travel together. The spinner survey on the right shows that the perforations centered around 7150 feet are not contributing to production. In fact, most production is coming from the perforations below 7180 feet. The spinner survey shows strong turbulence in the bottom 5 feet of perforations as well as a large flow entry over this interval. The density log on the left has two traces. The solid trace goes with the gm/cc scale at the bottom while the dashed trace is a five-fold amplification. Above 7180 feet, the is constant indicating no additional fluid entry above this depth. The 1 gm/cc below the perforations indicates water as antiCipated. From the base of the perforations upward, the fluid density progressively decreases which implies a progressively larger accumulation of oil in the wellbore. Conversely, the water must enter at the bottom, probably within the same interval showing high wellbore turbulence on the spinner survey.
A density survey run with a gamma-ray device is shown on Fig. 24a. This well produces from the two intervals at a total of 2520 BPD of oil and water at 62% by volume of oil. In the 5-1/2" casing, this production causes an average fluid velocity of 75 ft/min while in the 2-1/2" tubing, the velocity is 350 ft/min. Therefore, the water holdup in the tubing should be lower than in the casing. This means that the mixture density should be less in the
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tubing string than in the casing. The flowing survey, the solid curve in Fig. 24a, does show a decrease in density as the flow enters the tubing. At a 350 ft/min velocity, the oil and water should b flowing together in the tubing. The flowing curve does indeed cross the shut-in oil-water contact at 8250 feet at about 60% of the total separation between oil and water. A short shut-in period following the flowing survey is good practice. The dashed curve on Fig. 24a was obtained after a two-hour shut-in period. This log checks tool operation and provides estimates of phase den~ities if the phases separate rapidly. It also prov~des a base against which the flowing run may be compared. Such a comparison in Fig. 24a shows that practically all of the oil is coming from the top set of perforations. It is difficult to tell whether the bottom perforations flow any oil.
The density contrast between oil and water is quite small for many heavy crude oils. Moreover, many wells produce only small amounts of one phase relative to the other phase. This gives small density contrasts. Another fluid identification tool that shows greater contrast between water and hydrocarbon is the capacitance logger. This device consists of a hollow insulated from the tool sheath surrounds the Holes in the sheath allow wellbore fluid to flow in the annular space between the cylinder and the sheath. The inner cylinder is part of an oscillating circuit whose frequency is a function of the capacitance of the fluid in the annular space. The dielectric constant for gas and oil is about 1 and 2 MRS units, respectively, while for water it is about 80 units. This contrast is not actually achieved since the device measures capacitance from an inner electrode to ground. However, as Fig. 24b shows, this device is apparently more sensitive to the presence of small amounts of one phase than is the density logger. 24b is a capacitance log from the previous well for both flowing and shut.in conditions. The lower perforations are produclng some oil which was not evident from the density survey of Fig: 24a. If the logger is linear, then.this pro~uction amounts to more than 16% of total o~l flow s~nce the oil rate percent would exceed the oil holdup. The position of the flowing trace on the oil/water contact indicates linear operation. Calibration of this device is apparently not yet complete. Also, heavy oils tend to form films on the in~er electrode which causes shifts in the water base l~ne. Its performance in viscous crudes is disappointing to date. In any case, the logger should be calibrated in-situ as is shown in Fig. 24b.
In stagnant gas the output response of the capacitance meter is about 10% greate: than in oil. This difference will be increased dur~ng flow due to center line sampling. The capacitance tool has the potential to give a value for wate: holdup, ~w, directly. This may then be used w~th a dens1ty reading in Eqs. (5) and (6) to obtain oil and gas holdups, y and y , respectively. o g
It is possible to derive flow equations for the individual phases since the total rate is the sum of the individual rates, i.e.,
(7)
SPE 10035 R. M. McKinley 11
or
where V. is the velocity of the i-phase in its portion~ y.A, of the pipe cross-section. Since each light phas~ velocity consists of the water velocity plus the buoyant or slip veocity for that phase,
v V + Vb 0 w 0
V + Vb w g
Eq. (8) can be solved for the flow rate of each phase, for example, the oil and gas rates are
- y V ] g b
g (9)
q ~ Y A [V + (l-y ) Vb - Yo Vb] (10) g g g g 0
If one assumes that a sp~nner survey gives the average fluid velocity, V, for the composite flow while fluid identification surveys give the holdups, y and y , then Eqs. (7), (9), and (10) establish the i&dividuBl rates, provided the necessary slip velocities are known.
One problem with this approach is that these slip velocities, not known with any great precision, are significant contributions to Eqs. (9) and (10). A second problem is that the continuous survey data quality is often poor. This last point is illustrated with the next suite of logs.
The gradiomanometer and fullbore spinner surveys on Fig. 25a are from a well flowing 1.2 x 10 6 cu. ft/D gas and 200 BPD water. At downhole conditions, the gas flow is about 1800 BPD, which with the water give an average flow velocity of 40 ft/min - much less than that required for the phases to travel together. The spinner survey on the right side of Fig. 25a places the zero flow point at 17,240 feet depth while the density log shows a little gas entry down to 17,250 feet, the base of the perforations. The spinner survey is asymmetric about the zero flow line. This implies problems with wellbore turbulence or foaming problems or flow instabilities. On the up-survey there are possibly significant entries at 17,210, 17,175, and 17,030 feet respectively. Taken literally, the down-survey shows an entry beginning in the unperforated casing at 17,080 feet, while the entry at 17,030 is not nearly as large as on the up-run. The density log shows that the first significant gas entry is at 17,210. Tangential velocities here are sufficient to create a turbulence spike. The next major gas entry is at 17,175 feet. These two entries agree with the spinner up-survey. However, the density log shows absolutely no indication of entry at 17,030 feet. If the up and down spinner readings at 16,950 are used with the calibration slope from Fig. 18b in the spinner Eqs. (1) and (2), one obtains fluid velocities of 140 and 190 ft/min, respectively. These are obviously gas heading velocities since the average flow velocity is about 40 ft/min. But where then is the
573
water entry? Since fluid density never increases from the base of the perforations upward, the water could be entering any place from the bottom perforations up to 17,210 feet where the first major gas entry occurs. High quality rate data are needed to proceed further with the analysis. A flow of 200 BPD would give an average fluid velocity of about 4 ft/min. According to Eqs. (1) and (2), this velocity would give an up-down spinner separation of
~s ~ 2aV ~ 2 sf X 0.043 x 4 0.34 RPS,
a value well within the noise level of the surveys of Fig. 25a.
Temperature surveys from this well appear on Fig. 2Sb. The shut-in log is strongly influenced by recent stimulation treatments. Particularly, the cooling below 17,300 feet does not signal gas flow behind pipe from this depth. If this were the case, the tracking of the shut-in and flowing temperatures up to 17,260 feet implies that this flow continues at the same rate after shut in, which is improbable and which noise logs show not to happen. The temperature logs show that the base of production is at the 17,260-foot depth where the flowing survey diverges as a production gradient from the shut-in survey. We had already surmised that the water might come from the lower perforations. The flowing temperature also shows shifts due to the mixing in the wellbore of fluid streams at different temperatures, i.e., fluid entry points, at 17,220, 17,175, and 17,040 feet respectively. These are the entry points recognized on the previous logs.
A flowing noise log from this well appears on 25c. There is what appears to be a standing
liquid level at 17,210 feet depth. This is a pseudo-level in the sense that there is not just gas above this depth. Whenever gas is dispersed in liquid, then the liquid becomes a poor conductor of sound. A pseudo-level will therefore appear at the first depth of a significant gas entry. Below this depth, there will be insignificant gas production. The log also shows production at two locations in the perforations from 17,150 to 17,180 feet as well as at three locations in the top perforated interval. Ref. (18) demonstrates that water entrained in a gas jet onto the logging tool raises the higher frequency content of the sound, which draws the 2000-Hz curve closer to the others. Peaks may be examined relative to each other for this crowding effect. On Fig. 2sc, the 2000-600 Hz spacing is reasonably uniform for all the jets above the pseudo-level, again indicating water production at or below the level.
After 3.5 hours shut in, this well was still 200 psi below static pressure. A noise log run at this time, Fig. 25d, shows a liquid level at the base of the perforations without any indication of channeling from below. All evidence implies a gaswater contact in the vicinity of the bottom perforations with water coning during production. Over 90% of the water was, in fact, eliminated by shutting off the perforations below 17,210 feet.
There is an obvious need for more quantitative surveys for the type of problem described above.
~rtUUULIIUN LU~~lN~ tin, lUUj)
This can most likely be achieved only through the utilization of the diverting-type devices with all sensors located in the throat of the tool. This will speed up and homogenize the flow. A flow of about 50 MCF/D gas and 10 BPD water through a I"-diameter pipe would give a velocity of about 60 ft/min at typical downhole conditions. Certainly one would expect emulsion and foaming problems, but these Can be duplicated in flow loop experiments.
There is even room for qualitative improvement. As we have seen, the flowmeter is probably the most deficient. It may be possible to better determine qualitatively which perforations are flowing by utilizing a horizontal spinner, Ref. 30, that responds only to tangential jets. An application of this device is illustrated in the next suite of logs.
The well in Fig. 26 has a top section of perforations that had been cemented to stop excessive gas production. After the workover, the well still produced at a gas/oil ratio of 17,000 m3 /m3 ,
Fig. 26a shows capacitance surveys from the well. On the shut-in run, the dashed curve, there is an oil/ water contact just below 1800 meters depth and a gas/oil contact at 1785 meters. The flowing run shows gas production beginning at about 1795 meters depth. Since this is in the interval of cemented perforations, the log indicates that the squeeze workover was unsuccessful. The horizontal spinner survey of Fig. 26b verifies this. Flow is coming from the entire bottom half of the cemented interval. Note that the device gives very good vertical resolution. At present, the logger gives only qualitative results in multiphase flow, but it could possibly be calibrated in a fashion similar to that discussed in Ref. (18). Also, the low velocity cut-off point has not been clearly established.
r.ONr.LlTS10NS
This review describes the commonly available production logging devices in use for problem well diagnosis. Individual log discussions have been primarily qualitative. However, the quality control on any log should be such that it can also be used quantitatively if necessary. Also, log headings should detail the sequence of events occurring during the logging operations along with pressure and rate data obtained at the surface. The purpose of logging should be stated. These logs become part of the file on a well and may be reviewed again years in the future.
The discussion has centered around how the various devices work, what they measure, and how this is, or is not, related to underground flow. There are numerous specialty tools that have not been discussed since these must be calibrated for each environment. The review has also demonstrated that logs run in suites are much more effective than any single log. Furthermore, it is shown that the subtle characteristics of a log are often as informative as are the obvious anomalies. Finally, the last several examples illustrate that additional technology is needed for multiphase flow problems.
574
NOMENCLATURE
a
A
c p
k
q
s
V
slope of spinner calibration line, RPS/(ft/min)
cross sectional area of pipe, sq ft
calibration constants
specific heat capacity at constant pressure, Btu/lb-oF
thermal conductivity, Btu/hr-ft 2
(OF/ft)
standardized noise log reading at frequency f, peak-to-peak millivolts
pressure drop, psi
flow rate, cu ft/D or cu ft/min
individual phase flow rates, cu ft/ min, for water, oil, or gas
spinner speed, rev. per sec.
9. A
average fluid velocity, ft/min
slip or buoyant velocity relative to water, ft/min, for oil or gas
spinner frictional cutoff or bypass speed, ft/min
~ logging or line speed, ft/min
yi(i::::.w,o,g) ::::
P
Pi(i=w,o,g)
ACKNOWLK'1Gm: NT::>
spinner indicated fluid velocity
volume fraction holdup in wellbore of water, oil or gas, dimensionless
mixture density, Ib/cu ft
pure phase density, lb/cu ft, for water, oil, or gas
I wish to thank the many individuals from various wireline service companies, from Exxon, U.S.A., and from our affiliates, especially Esso Resources Canada, who not only provided many of the logs for this paper but also gave valuable follow-up information. I also thank the management of Exxon Production Research Company for allowing publication of this paper.
SPE 10035 K. l."l. l."lcJ.\.lnley .LJ
REFERENCES
1. Millikan, C. V.: "Temperature Surveys in Oil Wells," Trans. AIME 142 (1941), 15-23.
2" Dale, C. R.; "Bottom Hole Flow Surveys for Determination of Fluid and Gas Movements in Wells," Trans. AIME 186 (1949), 205-210.
3. Riordan, M. B.: "Surface Indicating Pressure, Temperature and Flow Equipment," Trans. AIME 192 (1951), 257-262.
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" (February, 1965), 137-144.
5. Petovello, B. G.: "Evaluation of Well Performance through Produ<;tion Logging," presented at 5th Formation Evaluation Symposium of the Canadian Well Logging Society, Calgary, Canada, May 5-7, 1975.
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7. Hoyer, W. A., et al.: "Pulsed Neutron Logging, ff Soc. of Profession Well Log Analysts Reprint Volume (March, 1976).
8. Jameson, J. B., McGhee, B. F., Blackburn, J. S., and Leach, B. C.: IfDual-SpacingTDT Applications in Marginal Conditions,1I J. Pet. Tech. (September, 1977) 1067-1077.
9. Novak, T. J.: "The Estimation of Water Injection Profiles from Temperature Surveys," J. Pet. Tech. (August, 1953) 203-212.
10. Cooke, C. E., Jr.: "Radial Differential Temperature (RDT) Logging - A New Tool for Detecting and Treating Flow Behind Casing," J. Pet. Tech (June 1979), 676-682.
11. Smith, R. C., and Steffensen, R. J.: "Computer Study of Factors Affecting Temperature Profiles in Water Injection Wells," J. Pet. Tech. (November, 1970), 1447-1458.
12. Curtis, M. R., and Witterholt, E. J.: IIUse of the Temperature Log for Determining Flow Rates in Producing Wells," SPE 4637 presented at 48th Annual Fall Meeting of the SOCiety of Petroleum Engineers, Las Vegas, Nevada, Sept. 30-0ct. 3, 1973 .
13. Smith, R. C., and Steffensen, R. J.: "Interpretation of Temperature Profiles in Water Injection Wells," J. Pet. Tech. (June, 1975), 777-784.
14. Dobkin, T. A.: "Improved Methods to Determine Fracture Height," J. Pet. Tech. (April, 1981), 719-726.
15. Enright, R. J.: "Sleuth for Down-Hole Leaks, ff Oil and Gas J. (Feb. 38, 1955) 78-79.
575
16. McKinley, R. M., Bower, F. M., and Rumble, R. C.: "The Structure and Interpretation of Noise from Flow Behind Cemented Casing," J. Pet. Tech. (March, 1973), 329-338.
17. Robinson, W. S., "Field Results from the NoiseLogging Technique," J. Pet. Tech. (November, 1976), 1370-1376.
18. McKinley, R. M., and Bower, F. M.: "Specialized Applications of Noise Logging, fI J. Pet. Tech. (November, 1979), 1387-1395.
19. Moon, K. E.: "An Improved Radioactive Tagging System for Stimulation Evaluation," Presented at the Southwestern Petroleum Short Course, Texas Tech University, Lubbock, Texas, April 20-21, 1978.
20. Arnold, D. M., and Paap, H. J.,: "Quantitative Monitoring of Water Flow Behind and in Wellbore Casing," J. Pet. Tech. (January, 1979), 121-130.
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22. Brown, H. D., Grijalva, V. E., and Raymer, L. L.: "New Developments in Sonic Wavetrain Display and Analysis in Cased Holes," The Log Analyst (Jan.-Feb., 1971) 27-40.
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25. McNeely, W. E.: !fA Statistical Analysis of the Cement Bond Log," SPWLA Fourteenth Annual Logging Symposium, May 6-9, 1973.
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28. Leach, B. C., Jameson, J. B., Smolen, J. J., and Nicolas, Y.: "The Fullbore Flowmeter," SPE 5089 presented at Annual Fall Meeting held in Houston, Texas, Oct. 6-9, 1974.
29. Cmelik, H.; "A Controlled Environment for Measurements in Multiphase Vertical Flow," SPWLA Twentieth Annual Logging Symposium, June 3-6, 1979, Tulsa, Oklahoma.
30. Kading, H. W.: !fHorizontal-Spinner, A New Production Logging Technique," Southwestern Petroleum Short Course, Texas Tech University, Lubbock, Texas, April 17-18, 1975.
Materials in Order of Decreasing
Thermal Conductivity
Quartzite Salt Anhydrite
Dolomite
Limestone Sandstone
Shale Gypsum
Cement
Water
Oil
Gas
A
TABLE 1
LITHOLOGICAL EFFECTS ON TEMPERATURE LOGS
Increasing Static Geothermal Gradient
576
Materials in Order of Decreasing
Thermal Diffus
Quartzite Salt
Anhydrite Dolomite Limestone Sandstone
Shale Gypsum
Cement
Gas
Water
Oil
B
Increasing Lag Time
Fig. 1a - Collar locator section
6900
6940 ~~
~ ,~
~ .. ~
6980
I" r r t II I
J 1 I ~
< ti 2 7 /B" i=~7020
- c.... LoU o
,.,.~ Y iJl) ) »
7060
~ I ~ 21 ~
~V ~ f! II
7100
c::J c::J c::JN c::J c::J c::J::r c::J to c::J
c::J s= e-.J e-.J
714°10 100 1000 PEAK-PEAK MILLIVOLTS NOISE
Fig. 1c-Noise log from shut-in gas well that will produce excessive water
577
-A- COLLAR LOG RUN GOING INTO HOLE FOR TEMPERATURE LOG.
-6- COLLAR LOG RUN COMMING OUT OF HOLE FOR NOISE LOG.
