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Petroleum Engineering Handbook
Larry W. Lake, Editor-in-Chief
Volume V – Reservoir Engineering and Petrophysics
Edward D. Holstein, Editor
Copyright 2007, Society of Petroleum Engineers
Chapter 4 – Production Logging
- 1 Introduction
- 2 Misconceptions About Production Logging
- 3 Safety and Environmental Tips
- 4 Sinker Bar Weight
- 5 Depth Control
- 6 Pricing and Record Keeping
- 7 Operating Principles and Performance of Production-Logging Tools
- 7.1 Temperature-Logging Tool
- 7.2 Radioactive Tracer-Logging Tool
- 7.3 Noise-Logging Tool
- 7.4 Focused Gamma-Ray Density-Logging Tool
- 7.5 Fluid-Capacitance-Logging Tool
- 7.6 Unfocused Gamma Ray (Gravel-Pack) Density Logger
- 7.7 Special Logging Tools for Fluid Identification in High-Angle Wells
- 7.8 Diverting-Spinner Flowmeter
- 7.9 Continuous and Fullbore Spinner Flowmeters
- 8 Production-Logging Suite Examples
- 9 Summary
- 10 Nomenclature
- 11 Subscripts
- 12 Acknowlegments
- 13 References
- 14 General References
- 14.1 Books
- 14.2 Survey Papers
- 14.3 Operational Topics
- 14.4 Instrument Evolution
- 14.5 Papers Aimed at Computerized Interpretation
- 14.6 Temperature Logging
- 14.7 Noise Logging
- 14.8 Radioactive-Tracer Logging
- 14.9 Oxygen-Activation Logging
- 14.10 Flowmeter Logging
- 14.11 Fluid-Capacitance Logging
- 14.12 Multiphase Logging in Vertical Wellbores
- 14.13 Multiphase Logging in Deviated and Horizontal Wellbores
- 15 SI Metric Conversion Factors
- 16 Appendix-Production-Logging Application Tables: Tool Selection, Operating Procedures, and Interpretation Aids
This chapter consists of a general discussion of production logs, some misconceptions about what can be determined with these logs, and the requisite skills to obtain good results. Also included are discussions of practical matters such as required safety and environmental tips, sinker-bar weight, maximum tool length to pass through a bend, depth control, pricing, and record keeping. Attached as an Appendix is a set of tables prepared for readers that are consulting this text to find out quickly what type of production-logging tools are appropriate to a particular problem. These tables indicate what tools to use, how to use them, and what results (resolution) to expect. These tables were designed to be independent of the general discussion and can be used by themselves. The indexing scheme used in the tabulation is explained in the Appendix.
Production-logging tools find many applications from the time a well is drilled until abandonment and, occasionally, beyond . An appropriate categorization of production logs is by usage. This approach leads to the five distinct categories listed below that also represent a rough chronological order of tool evolution. Effective interpretation of the data from each type of log requires significant education and experience.
- Diagnose production problems and allocate production.
- Monitor cement placement.
- Monitor corrosion.
- Monitor reservoir fluid contacts.
- Select zones for recompletion.
These are discussed as categories below.
Includes tools used to track movement of fluid either inside or immediately outside the casing of a well. The logs frequently used for such flow diagnosis and allocation include temperature surveys, mechanical flowmeter surveys, and borehole fluid-density or fluid-capacitance surveys. Each of these tools responds to fluid velocity or fluid type. The logs are run to determine if a production problem, such as excessive water or gas production, is the result of a completion problem or a reservoir problem. Their value thus resides in the guidance they give for continued expenditure on a well that is performing poorly. This type of application is largely responsible for the growth and evolution of modern production logging. Also belonging in Category One are evaluations of the placement of acids or hydraulic-fracturing material and diagnoses of premature flow or lost circulation in a drilling well.
There are two different objectives of cement-placement monitoring: to determine where the cement went (cement top) and to determine whether the cement provides zonal isolation. The logs used to locate the cement top include the temperature log, which responds to hydration heating; the unfocused gamma ray log, which responds to behind-pipe density; and the regular bond log, which measures the acoustical deadening of pipe.
Zonal isolation should be addressed when pressure imbalance causes crossflow through poorly cemented sections, leading to excessive production of unwanted fluids. The tools most often used for this purpose include cement-bond logs, temperature, noise, radioactive tracer, and neutron-activation logs. The temperature log detects alterations caused by flow, the noise log measures turbulent sound caused by flow, and the tracer log tracks tagged fluid behind casing. The neutron-activation log creates tracer in behind-pipe water.
Corrosion-monitoring tools are specialized in nature and include mechanical caliper tools and electromagnetic casing-inspection tools. The mechanical caliper tools are used to assess corrosion internal to the casing and to measure the shape of casing as well as the amount of rod and drillpipe wear inside tubing or casing. The electromagnetic devices respond to changes in metal thickness either inside or outside the pipe containing the tool. These logging tools are either of the eddy-current type or of the flux-leakage type, or a combination of the two. The eddy-current devices measure the load on a coil resulting from eddy currents induced into the wall of the casing. This load increases with increases in wall thickness. The driven frequency of the coil determines the depth of penetration of the field into the casing wall. The flux-leakage devices measure, by means of pad-conveyed coils in contact with the pipe wall, the induced currents that result from magnetic field lines that escape at abrupt changes in metal-wall thickness. Both types of tools make indirect measurements that are then related to metal loss through calibration.
Categories Four and Five
The last two categories, monitoring of fluid contacts in formations and selection of recompletion zones, use the cased-hole nuclear logs such as the neutron, the pulsed-neutron, and the various spectral logs. Please refer to the chapter on nuclear logging in the Reservoir Engineering volume of this Handbook for information on these logs.
Misconceptions About Production Logging
There are three pervasive myths about production logging:
Anyone Can Run a Production Log
Quality control is paramount, and careful attention must be focused upon three parts of the logging operation: (1) procedure (this will usually determine the value of the resulting logs), (2) tool calibration, and (3) depth control.
Only One Logging Tool Is NeededJust like openhole-logging tools, production-logging tools should be run in complementing suites so that one log can be compared with another. Seldom does a single log identify a problem sufficiently to prescribe a remedial action.
Table 4.1 lists the more common tool combinations used to diagnose problems and allocate flow. The Class A tools respond to flow either inside or outside the pipe containing the sonde and are usually employed for initial evaluation of a production problem. Class B tools respond to flow past the sensor and are used for detailed flow allocation from multiple entries into or exits from the pipe containing the sonde. The resolution of some of the Class A tools is actually better than some of the Class B members.
The Answer (Anomaly) Will Jump Out From a Casual Scan of the Log
This myth is responsible almost entirely for the lack of adequate training in this area.
Production logs should be interpreted in a consistent fashion that first identifies normal or expected features. The abnormal portions can then be examined to determine which parts are pertinent to the problem and which parts are irrelevant. It is these irrelevant features that so often confound novices to the point that they delay or forego appropriate remedial action.
Once these three myths are set aside, the requisite skills, listed next, can be developed for use of production logs. In the authors’ experience, a collaborative effort by service provider and client is needed to yield the most meaningful results. The effective user must be able to
- Select the proper combination of tools.
- Establish operating procedure.
- Monitor data quality.
- Interpret results.
Origin of Flow ProblemsThe more common types of flow problems associated with production-logging efforts are summarized in Fig. 4.1. Side A shows a drilling well that has crossflow or an underground blowout. Such flow can start for two different reasons. First, the well may "take a kick"; that is, entry into an abnormally pressured zone may result in drilling mud being blown out of the hole. Even though the well may be successfully shut in at the surface, the culprit zone is still free to flow into lower-pressured strata. Second, the well may "lose returns"; that is, a zone may fracture and allow drilling mud to leave the wellbore faster than it is pumped down the drillpipe. The loss in mud pressure may allow hydrocarbon crossflow as shown. Such a flow must be stopped before drilling can be resumed to prevent an uncontrolled blowout with the potential for injuries and equipment loss, as illustrated in Fig. 4.2.
Side B of Fig. 4.1 illustrates why a well completed for production may flow excessive amounts of water or gas. Any combination of three reasons may account for the unwanted flow:
- Casing failure by stress or corrosion.
- Lack of cement integrity behind the casing.
- Mobile gas or water in the completed zone.
The first two situations result from completion failures that can usually be remedied. The third situation is caused by reservoir performance and typically remains as long as the zone is produced.
All the problems illustrated in Fig. 4.1 have a common feature, namely the presence of flow either inside or outside the pipe or both. Those devices listed under Class A tools in Table 4.1 were selected because of their ability to respond to whatever situation exists in a particular well. The Class B tools were then selected as discriminators or as quantifiers for known flow conditions. The structure of Table 4.1 is a direct consequence of the situations illustrated in Fig. 4.1.
Safety and Environmental Tips
The following safety and environmental tips should be considered on every production-logging job:
- All wireline units should be equipped with at least one 30-lbm dry chemical fire extinguisher.
- Engines should be equipped with emergency shutoff devices on air intake (butterfly valve) and with spark-arrester-type mufflers.
- Drip pans should be installed under all engines, pumps, oil reservoirs, and reels of skid-mounted units. Drip pans should be provided for trucks on barges.
- Oil from the lubricator control head and oil from the line should not be permitted to drip into canals and streams.
- Pieces of cut-off wireline or cable should be carried off by the wireline crew for disposal.
- Bleeding of gas and oil into metal buckets should not be done. Use of a plastic bucket rather than a metal one will minimize the danger of a static-electricity spark.
- Truck-mounted units should not be positioned over tall grass in such a way that mufflers or power-generator engines could ignite the grass.
When a potential risk is identified, the purchaser of the logging should make all required operational changes. Because service companies perform most of the production logging, it is also the purchaser’s responsibility to ensure that a system is in place for (1) contractor selection and evaluation; (2) defining, communicating, and stewarding performance requirements; (3) managing interfaces between the purchaser and the contractor; and (4) monitoring performance and correcting deficiencies.
Sinker Bar Weight
A dead weight (sinker bar) is necessary to overcome the force of the wellhead pressure acting on the cross-sectional area of the logging cable. Fig. 4.3 shows the required sinker bar weight in relation to the shut-in wellhead pressure. The weight shown is just enough to balance the force of the well pressure acting on the wireline.
Additional weight above that which is indicated on the graph is needed to realize downward movement of the logging string. As the inclination angle of the wellbore increases, it becomes especially important to increase the sinker bar weight over the value specified by the vertical axis of the figure. When an inclination angle requires unreasonably long sinker bars, roller centralizers are required.
Typical slickline diameters are represented by the group of lines at the bottom of Fig. 4.3. The low sinker-bar weight needed to carry out a slickline survey, even at high wellhead pressures, requires only a short lubricator. As a result, slickline services are enjoying a rebirth. New versions of these tools contain sufficient downhole memory to record what is essentially a continuous log.
Maximum Tool Length To Negotiate BendFig. 4.4a illustrates the maximum length of a tool that can pass a bend. The ends of the tool contact the bottom of the borehole, and its middle touches the top.
With the following equation, the maximum tool length that can pass through a bend can be calculated. While Fig. 4.4a shows a bend into a horizontal wellbore, the expression is valid for any bend and is independent of whether the final wellbore is horizontal.
The expression for Lt involves the hole and tool diameters, as well as the inside radius of the bend. The inside radius can be expressed in terms of the angle of the bend, and the distance to bend through the specified angle (see Fig. 4.4b):
An example of the use of the maximum-length equation:
Any 1.5-in. OD tool 7.61 ft in length can pass through the bend. If longer tools are required, then the tool string must be segmented with "knuckle" joints.
The counter wheels on a production-logging unit measure the length of cable in the well to an accuracy of 5 out of 15,000 ft, provided that a great deal of back and forth travel (yo-yoing) is not required to work the tool string down the well. Better depth control is obtained by placing a casing collar locator (CCL) sub at the top of any production-logging tool string. See logging chapters in the Reservoir Engineering volume of this Handbook for more on this tool. This sub generates a voltage spike as it moves past a change in metal thickness, particularly as it passes through the connection between joints of pipe. The resulting record of collars is the source of depth control.
Wells are perforated from a perforating depth control (PDC) log, a combination of a collar log and a cased-hole nuclear log such as a gamma ray log. The nuclear log is then depth correlated to a similar log run before the well was cased. This procedure ties the collar record into the depth scale on the openhole logs. Accuracy in this latter depth scale is maintained by means of magnetic flags placed at precise intervals—customarily, 100-ft intervals—along the openhole logging cable. The PDC log is a part of the file on a given well and provides the collar record that serves as the depth reference for subsequent production logging. A short joint of casing called a "pup" joint is often placed in the casing string as a depth marker. Otherwise, normal variations in length are used to correlate collar records.
Sometimes a radioactive collar that emits gamma rays is used as a marker for depth control. For flush-joint casing, collars are available that are strapped around the casing before it is run into the hole. Occasionally, radioactive bullets are fired into the formation before casing the well. Finally, it may become necessary to run a section of a nuclear log and to flag (mark) the logging cable on a particular operation to achieve the necessary depth control.
Pricing and Record Keeping
An understanding of the price structure to perform production logging can help optimize data-acquisition costs. The total cost of a job is the sum of four separate charges:
- Set-Up Charge. This is the amount the service company charges to bring their equipment to your well and "rig up" on it.
- Pressure Charge. This charge is based on the surface pressure on the well and represents a rental fee on the equipment necessary to safely log the well.
- Depth Charge. This is a charge based on the maximum depth reached in the well. It reflects the fact that at least three people are needed to rig up, to spool so much wireline off the drum of the logging unit, to reel this same amount of cable back onto the drum, and to rig down. It is the substitute for the familiar hourly charge.
- Logging Charge. This is a per-foot charge for each tool run that reflects the length of interval actually logged by the tool.
From this structure, one can immediately see the potential savings to be had from being present during the logging operation. On-site changes in procedure to ensure the desired diagnostic logs can prevent having to start another day, resulting in incurring the first three charges again.
The footage-logging charge is often cited as the reason for running only one tool. This, however, is false economics because this charge, even for a three-tool suite, is usually no more than 40% of the total.
Forward planning will ensure maximum long term use of log data. The log headings used by most service companies, while recording some specifics about the run itself, have little information on why and how the logs were run. Consequently, most professional loggers have their own forms to bridge this documentation gap. While the organization of these forms is a matter of personal preference, a good rule is to prepare a preliminary summary that specifies at least the following:
- Why the logging is undertaken.
- Previous production-logging summary.
- Current well-completion data with a wellbore sketch.
- Collars used for perforation.
- Depth reference point.
- Most recent well-test data.
- Anticipated total depth, bottomhole pressure, and temperature.
- A second form completed at the time of logging is a chronology that lists
- Logs run and their order.
- Run number.
- String logged and its status for each run.
- Status of other strings or annuli.
- Logging direction and speed.
- Tool calibration checks.
- Intervals relogged.
- A summary of conclusions.
Operating Principles and Performance of Production-Logging Tools
The following sections describe operating principles for each of the tools listed in Table 4.1. The text will indicate applications for which a tool is best suited, those for which it is only partially suited and, when possible, those for which a tool is not suitable.
Some interpretive principles and recommended logging procedures will be presented in examples. However, the reader should refer to the Appendix for detailed information of this type. Oxygen-activation, cement-bond, and casing-inspection tools are not treated. These tools are, however, included in the application tables of the Appendix.
Temperature-Logging ToolThe tool includes a cage, which is open to the wellbore fluid, at the tool’s bottom end. Inside the cage is a thermistor that senses the surrounding fluid temperature. The preferred sensor is a platinum element because the electrical resistance of the sensor varies linearly with temperature over a wide range and is stable over time. The circuitry of the tool is designed so that the voltage across the sensor is proportional to the sensor’s electrical resistance.
In analog recording, the transmitted spikes per minute are converted to a voltage by a counting circuit. This voltage is recorded on a pen-and-ink strip chart recorded as the temperature (or gradient) trace. This is Trace 1 of Fig. 4.5. The scale of this trace is in °F. A recording sensitivity of 1°F/in. across the chart is strongly recommended for production wells.
On the log, the temperature trace warms abruptly below Depth B. Because the tool is logging down and the temperature is increasing, the depth-rate-of-change of temperature is positive. Consequently the differential trace shows a strong positive excursion at B, highlighting the change of the slope of the temperature trace at this depth. The differential trace, when properly amplified as on Fig. 4.5, is easily worth the additional logging charge.
The flowing temperature Trace 1 in Fig. 4.5 also provides information on the production profile. Production commences at Depth A, where the flowing trace "stands up" to separate to the warm side of static. This location is at the bottom of the bottom set of perforations. The middle set of perforations, on the other hand, contributes nothing to the production. The largest contribution comes from near the bottom of the top set of perforations at Depth B, where a large mixing signature is evident. The volumetric rate of entry here is so large that the mixture temperature is "pulled" almost back to static temperature (i.e., to the entry temperature for the stream). There is one additional smaller entry at Depth C, whose mixing signature is hardly recognizable on the flowing Trace 1 but is clearly evident on the differential Trace 2. The location of this entry suggests that it is composed primarily of oil. The temperature traces therefore show that the top set of perforations is responsible for the majority of both water (the major stream) and oil (the minor stream). The use of these mixing signatures to profile both single-phase and multiphase flow is described in detail in the Appendix under production-well profiling. The important point is that the size of a mixing signature relative to static temperature is dependent upon the thermal content (product of density, specific heat, and volumetric rate) both of the entry stream and of the stream in the casing immediately below the entry.
In digital recording, the spikes-per-minute from the logging cable are counted digitally at the surface, and the resulting count rate is converted to a temperature trace by the computer’s program. Again, the temperature trace should be recorded at a sensitivity of 1°F across the chart. Digital recording degrades the sensitivity of the differential trace from that available with analog recording. Thus, the digitally determined differential trace is not as useful for highlighting important changes of the temperature curve’s slope.
Depending on how carefully (or recently) a particular temperature tool was calibrated, there may be several °F difference between the recorded temperature and the true downhole temperature. However, the difference does not degrade the sensitivity of the differential trace. Provided that the temperature curve is recorded at the recommended sensitivity of 1°F/in. across the chart, and that the temperature log is carefully depth-correlated, the resulting temperature curve has more vertical resolution than does a curve from any other production-logging tools.
The temperature tool is most effective when located at the bottom of a tool string. In a production well, the tool should always be logged downward so as to enter undisturbed fluid. The log should be recorded at a constant logging speed not to exceed 30 ft/min. With digital recording, the maximum logging speed should be reduced to 20 ft/min.
Fig. 4.6 shows temperature logs from an exploration well that was perforated and acidized before the flow test. During the flow test, the surface rates were 2 MMscf/D gas and 500 B/D spent acid and formation water. The formation is gas-saturated limestone.
At the time of the flow test, the near-wellbore temperature below the bottom perforation was still below static. The line labeled "cool temp" coincides with the flowing temperature profile below the bottom perforation and is parallel to the static temperature line determined subsequently. The cool temp line shows that, at the time of the flow test, the near-wellbore is below static throughout the perforated interval.
During the flow test, spent acid and formation water enter the wellbore at Depths 1, 2, 3, and 4. Each entry flow begins in the formation at static temperature. At Depth 1, the entry rate is small enough that the flow, after being cooled during passage through the cooler near-wellbore, enters the pipe at a flowing temperature that is considerably below static. Still, the entry causes an abrupt warming at Depth 1. Because the entry at this depth does not mix with a flow from below, the "entry temperature" (i.e., the temperature of the entry as it emerges into the wellbore) is the flowing temperature at the entry Location 1.
At Depth 2, additional liquid enters and mixes in the wellbore with the upward flow from Depth 1; the mixing of the two flows results in the abrupt warming at this depth. The flowing temperature at Location 2 is the final temperature after the mixing. The entry at Depth 2 comes into the wellbore at an entry temperature (before mixing) that exceeds the final temperature after mixing but is no greater than the static. Notice that the final temperature after mixing at Depth 2 is less reduced from static than is the entry temperature at Depth 1. Thus, the entry rate at Depth 2 exceeds that at Depth 1. The entry at 2 is cooled less by passage through the near-wellbore region than is the entry at 1, leaving the entry temperature at 2 higher than that at 1.
At Depth 3, liquid enters and mixes with the flow arriving from below. The mixing of the flows causes the abrupt warming at Depth 3. The flowing temperature at this depth is the final temperature after the mixing. The entry at Depth 3 comes into the wellbore at an entry temperature (before mixing) that exceeds the final temperature after mixing. However, this temperature is less reduced from static than is the final temperature at Depth 2. Thus, the entry rate at Depth 3 exceeds that at Depth 2. The entry at 3 is cooled less by the near-wellbore than the entry at 2, leaving the entry temperature at 3 higher than that at 2.
By similar reasoning, the entry rate at Depth 4 is greater than the entry rate at Depth 3. In a recently drilled well or in an old gas well, provided that the near-wellbore is below static, the deepest entry, if it is a liquid, results in a warming signature. The warming is caused by the liquid’s bringing of its warmer temperature into the wellbore itself. The contrast between the entry temperature and the cooler temperature of the wellbore below the entry is responsible for the warming signature. A common but mistaken view holds that the warming is caused by frictional heating of the liquid as it moves through the near-wellbore region and into the well. The fact that a water rate of only a few B/D is sufficient to produce a warm signature clearly refutes this "frictional" hypothesis. In a gas well, pressure loss in the near-wellbore and completion results in expansion of the gas during its passage into the wellbore. This expansion cools (or warms) the gas to a degree that depends on the flowing bottomhole pressure, temperature, and the amount of pressure loss. If the gas is cooled, it absorbs heat as it passes through the near-wellbore region before entry. Over time, the heat spreads up and down the near-wellbore, resulting in a below-static temperature in the near-wellbore region. Any subsequent liquid production produces the same warm signatures as described for a new well. In actual fact, the expanding gas warms at bottomhole pressures in excess of approximately 10,000 psi and cools at pressures lower than 5,000 or 6,000 psi. At intermediate pressures, the amount of cooling or warming is generally not significant.
In reference to the example of Fig. 4.6, the flowing bottomhole pressure and temperature are 1,325 psia and 200°F, respectively. The well flows at a drawdown in excess of 3,000 psia. At Depths 5 and 6, each temperature mixing signature is caused by expansion of a dry gas as it passes through the near-wellbore and completion. At Depth 5, the colder gas mixes in the wellbore with the warmer liquid arriving from below, giving the cooling signature at this depth. At Depth 6, the colder gas mixes with the warmer flow of gas and liquid arriving from below, giving the cooling signature at this depth. The next calculations focus again on the water entries.
Certain conventions apply to the volumetric rates qi in the relationships to be discussed next. If water is produced, then the rates for all other phases are "water equivalent" rates that represent the multiplication of each actual rate by a ratio. The numerator in this ratio is the product of density and specific heat for the particular phase, whereas the denominator is the same product for water. If only gas and oil are produced, then the gas rate is presumed to be an "equivalent oil" rate obtained with a similar ratio for gas/oil. Once profiling is done by the following expressions, then the equivalent rates are converted to phase rates according to the equivalence ratios. Typically, 3 volumes of oil are the equivalent of 1 volume of water, whereas ~ 10 volumes of gas are the same equivalent.
The entry rates of the four liquid entries can be determined quantitatively from two relationships, a warming relationship where qi (i ≥ 2) refers to a given stream entering the wellbore at temperature Ti to mix with the total stream from below at temperature Ti–1 and produce a mixture with temperature Tmix.
and a warming relationship,
and qi (i ≥ 2) denotes any stream entering the bottom stream – 1. In the ratio for Ri, the temperature Ti refers to the temperature at which stream-i arrives at the wellbore, whereas Tgeo indicates normal geothermal temperature at the depth of the entry, and Tcool is the cooler temperature of the stream coming from below entry-i. Usually, the entry temperature Ti for a given liquid stream will be the same as geothermal temperature Tgeo and only the mixing relationship (Eq. 4.3) is required to determine the relative size of the rates. The warming relationship (Eq. 4.4) is required when the wellbore has been cooled below geothermal, and liquid entries arrive at the wellbore at some unknown temperature cooler than geothermal. In this situation, a succession of liquid entries moves the flowing temperature profile successively closer to the geothermal temperature line without bringing the two into coincidence. This is the temperature behavior at Depths 1 through 4 of Fig. 4.6. The left side of the relationship in Eq. 4.5 is the ratio qi/q1 (i = 1 to 4 in the present example), which is the ratio of the entry rate qi to the entry rate at Depth 1. The right side of the relationship in Eq. 4.5 incorporates numerical values that are available from the "cool temp" and "static" lines in the figure. The remaining variable is Ti, which is the temperature of the ith entry as it emerges into the wellbore, before mixing with the flow from below. This is the same as the "entry temperature" used in the text above. T1 is the temperature at the warming signature at Depth 1, because there is no flow below this depth. The value of Ti at higher depths must be determined along with the rate ratios.
On the left side of the mixing equation appears the ratio qi/q1; on the right side all numerical values are available from the temperature profiles of Fig. 4.6 with the exception of Ti. Thus, there are two unknowns: qi/q1 and Ti. Various trial values of Ti are entered into the warming and mixing relationships to give two values for qi/q1. A solution for Ti is the trial value for which the two values of qi/q1 are substantially in agreement. A trial value for Tini should exceed the final temperature after mixing at Depth i, but should be less than the static temperature at Depth i.
The process of using trial values is shown by Table 4.2, which relates to finding the value of q2/q1 and T2. As can be seen, the two values of the rate ratio are in close agreement at a trial temperature of 201.54°F.
From the same technique illustrated previously, the ratio of the third entry rate to the first is 4.65, and the ratio of the fourth entry rate to the first is 14.85. These ratios, along with a ratio of 1.00 for Entry 1, sum to 23.0 and provide the fractional value of each entry in the total liquid stream of 500 RB/D. Thus, Entry 1 amounts to 500 × (1/23) = 22 RB/D. Likewise, the entry rate at Depth 2 is 54 RB/D, at Depth 3, 101 RB/D, and at Depth 4, 323 RB/D. In Fig. 4.6, notice that the entry at Depth 4, with by far the largest rate, moves the temperature after mixing much closer to static than does any other entry, as expected. The density log of Fig. 4.6 shows that all four streams are composed primarily of water so that no phase conversion is needed.
Radioactive Tracer-Logging ToolThe tool has a reservoir to hold radioactive material and a pump section at the top. For injection-well logging, two gamma ray detectors below the reservoir and pump are preferable. Some tools employ only one detector, but this is less desirable. The tool includes the circuitry to amplify and transmit the detector counts to the surface, for recording.
Most natural radioactivity underground is from the decay of isotopes of potassium, thorium, and uranium. These materials concentrate in the shales, where they register approximately 100 API units on the gamma-ray log. Once downhole, a "slug" of tracer is ejected by the pump, under surface control. The activity owing to the ejected slug is much greater than the natural background activity. By tracking the progress of the slug down the wellbore, the exits of injected flow from the wellbore can be determined, as well as whether any of the injection, after exiting, passes through a channel close to the pipe.
There are two modes of logging: slug tracking and velocity shot. For slug tracking, the logging operator ejects a slug of tracer from the tool. After ejection, the tool is run up and down through the slug to ensure that the slug is uniformly mixed across the wellbore cross section. Then, the tool is lowered quickly and an upward logging pass is made at constant logging speed until the slug is detected. The time of detection of the peak and the depth of the peak are recorded. Then the tool is quickly lowered again, and another upward logging pass is made at the constant logging speed until the slug is detected again. Again, the time of detection of the peak and the depth of the peak are recorded. This process is repeated several times, resulting in a succession of detections of the same slug (see Fig. 4.7). As long as the peak progresses downward, there is flow in or near the wellbore. Once the peak stops, there is no flow in or near the wellbore below the stopping depth. For each detection, the area under the trace and above the common baseline of the traces is proportional to the percentage of injection still in or near the wellbore.
Generally, only one gamma-ray detector is used for slug tracking. Slug tracking gives the best overview of where injection leaves the wellbore and whether, after exiting, any injection travels in a channel close to the pipe. The upward logging passes are made at high line speed. A constant logging speed should be used, and the same speed should be used for all passes.
Provided the ejected slug is uniformly mixed in the flow by movement of the tool up and down through the slug after ejection, the vertical distance (ft) between two successive peaks in total flow divided by the time (minutes) between detection of the peaks provides an accurate estimate of the average flow velocity of total injection. Such velocities are listed on the left of Fig. 4.7. The most frequently used tagging material for water is an aqueous solution of sodium iodide, which contains the isotope of iodine, I-131. The 8-day half-life is ideal. In solution, the iodine does not stick to rock surfaces; instead, with continued injection, the iodine is washed from the rock surfaces and carried away from the near-wellbore, beyond detection by the logging tool.
From inspection of slug spacing in Fig. 4.7, it is evident that slug tracking has limited vertical resolution. Furthermore, because 90% of the detected gamma rays originate within 1 ft of the detector, the tracer tool’s depth of investigation is also limited and is much less than that of the temperature tool. Because of the limited depth of investigation, tracer that is channeling after exiting the wellbore must be close to the pipe to be detectable. Not all channels can be detected by the tracer tool. The same is true for fractures.
A velocity-shot survey is used in intervals where greater vertical resolution is desired. To perform a velocity shot, the logging operator stations the tool so that the detectors are at chosen locations. Then, with the tool stationary, a slug of tracer is ejected into the injection flow. As it passes downward, the slug is first detected by the top detector and then by the bottom detector, resulting in two traces on the log (see Fig. 4.8). On the chart, time increases from the bottom upward. Thus, the top detector gives the lower trace. The time interval between the two peaks (travel time) is inversely related to the velocity of the injection flow. The chart speed should be such that there are 5 to 10 vertical chart divisions between the peaks in total flow, although such is not the case in the figure.
The ratio of the travel time in total flow to the travel time at a selected position is the fraction of injection still in the wellbore at the selected position. However, dividing the separation between the detectors (ft) by the travel time (minutes) does not produce the average velocity of flow, as the slug cannot be uniformly mixed in the flow before it passes the detectors.
Two detectors are preferred for velocity shots. If there is only a single detector, there can be timing errors between initiating ejection of a slug and actual ejection downhole. These timing errors contaminate the measured travel times.
For detection of flow behind pipe, many logging operators prefer velocity shots. One detector is stationed within the perforations, while the other is stationed above or below the perforations to see if any flow channels up or down after exiting the wellbore. One difficulty with velocity shots is that they investigate only a very limited part of the total injection interval. In some circumstances, the results from velocity shots indicate the presence of a channel when in fact there is none. Whenever the results from velocity shots indicate an integrity problem, it is better to switch over to slug tracking, which investigates the overall injection interval as well as the wellbore above the interval.
Fewer applications of tracer logging occur in production wells. In a true single-phase flow, there is an appropriate tracer, whether the flow is water, oil, or gas. Because a slug is tracked for a while and then disappears uphole, multiple slugs are used, one for each producing interval under investigation. Usually, a well is logged from a bottom, no-flow interval up to an interval of total flow. Because of the unusual circulation patterns that can occur in multiphase flows, tracer results in these flows can be misleading.
Noise-Logging ToolThis tool "listens" passively to downhole noise, for example, from gas bubbling up through liquid in the wellbore. Behind pipe, a channeling flow often passes through cramped spaces and constrictions. These "tight spots" cause high velocities, sudden pressure reductions, and significant flow turbulence. The noise tool listens to the noise associated with the turbulence. Consequently, noise logging is an inexpensive way to investigate whether there is channeling in injection or production wells.
The tool includes piezoelectric crystals (transducers) which convert the oscillating pressure of wellbore sound to a corresponding oscillating voltage. At the surface, the oscillating voltage is applied to a speaker, permitting the logging operator to hear the downhole sound. The oscillating voltage also is applied to each of four high pass filters. A high pass filter is unresponsive to frequency components of the oscillating voltage that are below the filter’s "cutoff" frequency, while it generates an oscillating output signal whose amplitude represents the content of the oscillating voltage of frequencies in excess of the cutoff. The cutoff frequencies most often used are 200, 600, 1,000, and 2,000 Hz.
For quality measurements, the operator stops the tool at a selected depth and waits for extraneous noise, such as the noise generated by tool and logging-cable movement, to subside. Hurrying contaminates the measurements with extraneous noise. Then, a recording system averages and records the amplitude of each filter’s oscillating output signal. Subsequently, the tool is moved to a new measurement depth; after waiting for the extraneous noise to subside, the operator initiates the averaging and recording of the amplitudes at the new depth. Thus, four values are recorded for each measurement depth. These are plotted in millivolts across the chart at a measurement depth. The amplitude of the 200-Hz filter output is the greatest; as the cutoff frequency increases, the amplitude correspondingly decreases, with the amplitude of the 2,000-Hz filter output being the least. To form a log, the plotted 200-Hz amplitudes are joined by line segments between successive measurement depths, as are the amplitudes for 600, 1000, and 2,000 Hz.
Because a filter’s output signal is oscillatory, it consists of positive excursions from neutral alternating with negative excursions. There are two ways of measuring the amplitude of the output. One measures the amplitude from the peak of a positive excursion to the trough of the following negative excursion. The resulting amplitude is known as "peak to peak," and the recording is characterized as "standard gain" or "standard sensitivity." The other amplitude measurement is from the peak of a positive excursion to neutral, with the amplitude being characterized as "peak" and the recording sensitivity as "one-half standard gain." Other measures are sometimes used.
A single-station measurement typically lasts 3 to 4 minutes. Relocating the tool usually requires 1 minute. Thus, the logging rate is approximately 15 stations per hour. A 4-hour logging run accommodates 60 measurements. Thirty of these are used for a coarse-measurement grid, with successive measurements separated by one-thirtieth of the total survey interval. The remaining 30 measurements are used for detailing areas of interest, such as a noise peak identified by the coarse grid, a gas/liquid interface in the wellbore, a plug, or a packer. For detailing, the separation between successive measurements can be as little as 1 to 3 ft.
Fig. 4.9 shows the "dead-well" response recorded at one-half standard gain in a shut-in injection well. As expected, the 200-Hz amplitude is greatest, and the amplitudes progressively decrease as the frequency increases. Notice that the trace for one frequency never crosses the trace for another frequency. If such crossings occur, the log is faulty. If a dead-well response does not appear at all, the log is suspect. The figure is illustrative, and the amplitudes of the dead-well response in other wells may vary from those shown.
One service company uses software processing that implements four different high-cutoff frequencies with the same low-frequency cutoff of 100 Hz in all four instances. Thus, the computed amplitudes pertain to the frequency "bands" between 100 Hz and each of the high-cutoff frequencies. One difficulty is that the lower-frequency components of the sound, whatever their origin, have amplitudes more variable with time than those of the higher frequencies. Also, extraneous noise sources tend to be more intense at the lower frequencies. The result is that each of the bandpass amplitudes can be contaminated by the variable amplitudes and the extraneous sources.
Noise can travel appreciable distances to the noise tool, both vertically and horizontally. The user must be sure that all extraneous noise from surface operations (with the exception of logging-truck vibrations) and flow in nearby wells is eliminated, so that the only noise recorded is that associated with the suspected well problem.
Fig. 4.10 pertains to a 20-B/D water flow behind pipe into a depleted gas zone. Only one noise peak occurs, corresponding to a single "tight spot" between the water sand and the gas sand. Almost 30 measurement stations were used. Farthest away from the peak, the spacing between measurements was greatest. Closer to the peak, the spacing was reduced. The measurements were densest in the locality of the peak for best detailing of the peak itself. The single-phase nature of the behind-pipe flow is evident from the "bunching" of the 200-, 600-, and 1,000-Hz traces at the peak. Gas-through-liquid flow would separate the 200- and 600-Hz traces, in addition to the separation of the 1,000- and 2,000-Hz traces.
Because there is no noise peak at the water or gas sand, the entry and exit of flow to and from the channel occur in absence of a tight spot at either sand. With the known 250-psi pressure drop between the sands confined to a single constriction, it is possible to estimate the flow rate of the channeling water from the pressure drop and the level of the 1,000-Hz trace at the peak (twice the level shown on the log, which was recorded at half-standard gain), yielding the 20-B/D rate. The rate equations are discussed in the appendix. If there were multiple tight spots, the estimate could still be made based upon total pressure drop and upon the sum of all the peak 1,000-Hz noise levels.
Above the gas/water interface in the wellbore, all four traces in Fig. 4.10 decline rapidly to dead-well response because of two attenuating factors. First, much of the sound reflects downward at the interface itself. Second, the tool sensor is constructed for coupling to liquid rather than to gas. In the water below the interface, only the 2,000-Hz trace, which attenuates the most rapidly with distance, reaches dead-well level. Because the water transmits sound at much less attenuation with distance than the gas, the 2,000-Hz trace requires almost 700 ft to reach the dead-well level in the water. In the gas, the dead-well level is reached in considerably less distance. In the water, the other traces show typical noise behavior; the attenuation with distance is least for the 200-Hz trace and increases with increasing frequency. In a production or injection well, it is not unusual to find a gas/liquid interface.
Focused Gamma-Ray Density-Logging Tool
The tool incorporates a compacted slug of Cesium-137 at the bottom of an open cage. The Cesium emits gamma rays, and a lead lens focuses gamma rays in a narrow beam parallel to the axis of the cage. Because the cage is open, wellbore fluid is present inside the cage, and the fluid is in the path of the focused beam. The gamma rays have an energy level low enough that the rays are deflected by the electron cloud surrounding the nucleus of any atom. Furthermore, the amount of backscatter (or absorption) is directly related to the density of the electron cloud and, therefore, to the density of the wellbore fluid. Those gamma rays that are backscattered or absorbed do not emerge from the wellbore fluid at the top of the cage.
At the upper end of the tool cage, a gamma detector responds to the gamma rays that still remain when the beam emerges from the wellbore fluid. A counter determines the counts/min (intensity) of the gamma rays; this information is transmitted through the logging cable to the surface.
The preferred gamma-ray detector is a scintillation crystal because of its high sensitivity and short dead time (the interval required between detection of different gamma rays). Many tools use Geiger tubes as the gamma-ray detector. A Geiger tube has a much longer dead time than a scintillation crystal. It is necessary to use multiple Geiger tubes to ensure detection of all the gamma rays. Preferably, there are eight tubes, but tools of lesser quality may have as few as three.
Count rate is inversely related to the density of the fluid in the wellbore and is recorded in g/cm3 vs. depth. The count-rate/density relationship is calibrated first with air in the open cage, yielding a count rate corresponding to a density of 0 g/cm3 and then with tap water in the open cage, yielding a count rate corresponding to a density of 1 g/cm3. For some tools, there is an aluminum block of known density that can be placed in the open cage. There is enough nonlinearity in the relationship to justify a calibration with three known density values, but typical practice is to use only two. Often, the recording system is adjusted so that the range from 0 to 1 g/cm3 spans the right-side track of a typical log. With 20 chart divisions in this track, the recorded log is shown at a sensitivity of 0.05 g/cm3. Attempts to increase the recording sensitivity appreciably over that used for the typical display result in a trace with many irregularities because of the statistical nature of nuclear events. The irregularities can make log interpretation difficult.
The advantage of the focused tool is that it measures only the density of the wellbore fluid. If an unfocused (gravel-pack) tool is used, the gamma rays investigate not only the density of the wellbore fluid, but also that of the pipe wall as well as the material and fluids that are close to the outside wall. The gamma tool can distinguish between the phases in a two-phase mixture, but it cannot distinguish among the phases of a three-phase mixture.
The tool should be logged downward at logging speeds between 15 and 30 ft/min in a flowing production well. A constant logging speed should be used, and the same speed should be used for all runs. It is best to log downward from a starting depth above all the perforations, and to log all the way to the deepest depth that can be surveyed. In a slugging or churning multiphase flow, the log may show variable behavior even in intervals that are not perforated. In that case, another logging run is advisable to establish the degree of repeatability. If the result is less than desirable, a stationary measurement can be time-averaged for each selected location. Usually a logging run is also made with the well shut-in. This log should be run after at least two or three hours of shut-in, to be sure that the fluid distribution is stable. If the well has been shut in overnight, a shut-in log can be recorded, but the well must flow for 2 or 3 hours before the first flowing log is recorded. If the tool is centralized, there is a tendency for the recorded density to be somewhat low in a multiphase flow relative to the average density across the wellbore cross section. This is because the lighter phase tends to rise through the center of the cross section, leaving the remainder of the cross section for the heavier phase.
Although the health, safety, and environmental risks are generally low, radiation safety procedures should be strictly followed when calibrating or running a gamma-ray density logger. Needless exposure to the radiation from the tool when it is at the surface should be avoided. Logging-company personnel should have current radiation training and certification. Because of the long half-life of Cesium-137, the legal restrictions on the use of the tool vary from state to state and country to country. If the tool is dropped in the well or becomes stuck, it must be retrieved or cemented over.
Another common density tool is the pressure-gradient instrument. As the name implies, this device determines density from a differential; pressure measurement across a spacing of a few feet along the wellbore. These instruments are often called "gradiomanometers" or "differential manometers." Owing to their linearity, a two-point, air/water calibration is sufficient for such instruments. Furthermore, the resolution of the tools is higher than that of the gamma-ray densiometers. However, at high fluid velocities, the apparent density provided by these tools is corrupted by frictional losses in pressure and requires correction. Likewise, in wellbore intervals containing intense fluid turbulence, the apparent values are again corrupted and are uncorrectable. Finally, the apparent density must be corrected for deviation of the wellbore from the vertical.
A pressure-gradient density log is shown in Fig. 4.6. Near the top of the figure, about halfway across the chart, is a trace labeled "Density." This trace is scaled from 0 to 1.5 g/cm3. Below the perforations, there is a stagnant mud column in the wellbore; the mud’s density is somewhat in excess of 1.5 g/cm3.
Spent acid and formation water enter the wellbore at the bottom perforation, Depth 1, where a density of approximately 1.2 g/cm3 is measured. This density continues to the perforations at Depth 2. At Depth 2, spent acid, water, and a small amount of gas enter the wellbore and mix with the flow from below. After mixing, the gas contributed at Depth 2 causes a density decrease from approximately 1.2 g/cm3 to approximately 1.1 g/cm3. The density remains at that level to Depth 3.
Additional entries of spent acid and gas at Depths 3 and 4 result in further, slight reductions in density.
Major gas entries at Depths 5 and 6 reduce the density to less than 0.3 g/cm3.
Redistribution of phases occurring in the 20 ft above 9,300 ft results in a density averaging approximately 0.4 g/cm3 below and within the tubing. The actual density of the gas/liquid mixture decreases significantly in the tubing stream relative to the mixture density in the casing just below the end of tubing. This happens because the gas holdup in the stream in the tubing increases in response to the increase in fluid velocity. This significant decrease is hidden on the density trace by the increased frictional loss associated with the increased velocity.
The four liquid entries and the two major gas entries correlate with the temperature behavior. Please refer to the discussion of the temperature-logging tool for a detailed interpretation of the temperature data.
Fluid-Capacitance-Logging ToolThe tool includes an inside dielectric probe located on the tool’s axis. The probe is surrounded by an outside housing that is open to the wellbore fluid. Together, the probe, the housing, and the fluid constitute an electrical capacitor, the capacitance level of which depends on the particular fluid, or fluids, within the capacitor.
Circuitry within the tool is connected to the electrical capacitor, with the result that the circuitry generates an oscillating signal that varies inversely with the capacitance level. Water has the greatest capacitive effect, resulting in the lowest frequency. Gas has the least capacitive effect, resulting in the highest frequency. The frequency with oil is intermediate to those of water and gas. However, the oil frequency is much closer to the gas frequency than to the water frequency. Consequently, the tool distinguishes principally between water and hydrocarbons.
Preferably, the tool is calibrated at the surface in produced water from the well, establishing the trace for water. Normally, the recording system is adjusted so that the water trace is at the left edge of the track. Air customarily establishes the trace for gas. Normally, the recording system is adjusted so that the air trace is at the right edge of the track. If the well produces any oil, the tool can be calibrated in produced oil, establishing the trace for oil. Sometimes tap water is used to establish the water trace.
Obviously, the tool poses no hazard to personnel who are exposed to it at the surface. If the tool is dropped into the well and it must be left there, it is not necessary to cement it over, as with a nuclear tool. Furthermore, the recording sensitivity can be greatly increased above normal sensitivity because the tool produces a signal that is "clean" (free of statistical events), unlike a nuclear tool. At such an increased sensitivity, the tool can detect the slightest "whiff" of hydrocarbon that passes close enough to its sensor. With the sensitivity increased, the tool also can detect very small amounts of water dispersed in oil.
A small gas entry into water looks to the fluid-capacitance tool just about the same as a small oil entry. Whereas the small oil entry, because of its low density contrast with water, changes the fluid density only slightly, the small gas entry, because of its low density relative to water, changes the density log significantly. Thus, by a comparison of the two log types, an analyst can fathom the nature of a hydrocarbon entry.
From the prior discussion, it is obvious that the fluid-capacitance tool can distinguish between water and the two hydrocarbons, but it cannot distinguish one hydrocarbon from the other. Also, the tool has a very nonlinear response over the range from water to hydrocarbon. During use downhole, there can be a calibration drift because of filming of the housing or the dielectric probe, or both. If the drift is severe, the film possibly can be removed with the tool pulled into the tubing, where the velocity of flow may be high enough to remove the film.
In a production well, the tool should be logged down at a logging speed between 20 and 30 ft/min. Maintain a constant logging speed, and use the same speed for all passes. The log should begin at a location above the perforations and end at the deepest depth that can be reached. In a slugging or churning multiphase flow, the log may show variable behavior, even in intervals that are not perforated. In that case, another logging run is advisable to establish the degree of repeatability. If results are less than desirable, a stationary measurement can be time-averaged at each selected location. Usually, a log is run with the well shut-in after flow. If the well has been shut in before logging, a shut-in log can be recorded, but the well must flow for 2 or 3 hours before the first flowing log.
Fig. 4.11 pertains to a well producing 3,520 RB/D at 68% oil and 32% water. Notice the shut-in log (left trace); at the bottom, below the perforations, the water response is near the left edge of the track. At 8,250 ft, the log shows a water/oil interface in the wellbore. In the oil above the interface, the response appears near the right edge of the track. In gas, the response would be approximately 2,350 Hz.
Below the perforations, the flowing log shows a water response indicating stagnant water. Across the bottom perforations, the log shifts somewhat to the right, indicating some contribution to the oil production.
At 8,420 ft, there is a spike in the oil direction caused by perforations which jet oil directly at the tool’s sensor. Just above the spike, the log is somewhat farther in the oil direction than it is just below, identifying the additional oil in the wellbore.
Near the top of the upper perforations (8,400 ft), there is a major shift in the oil direction. Moreover, the log response persists from this location to the end of tubing. This means that the major contribution to the oil production is from the top part of the upper perforations. Above 8,350 ft, the elevated fluid velocity within the tubing results in the oil being more effective at sweeping the water out of the pipe’s cross section than it is in the casing. The reduced presence of water across the tubing cross section results in a shift of the log in the oil direction. The presence of the water production is indicated because the log never shifts as far right as the oil response identified by the shut-in log.
Note that in Fig. 4.11, the flowing trace in the tubing crosses the oil/water contact on the shut-in trace at approximately 62% of the total deflection from water to oil. If the tool’s response was completely linear in holdup, then the flowing trace would cross at 68% of the total deflection (i.e., at a point slightly closer to the oil frequency). Unfortunately, the "calibration" for these instruments depends upon the viscosity of the oil owing to the filming of oil on the electrode. The smaller the diameter of the electrode, the larger this effect. In gas/water flows, water tends to film the electrode instead, which biases the "calibration" toward water.
Unfocused Gamma Ray (Gravel-Pack) Density LoggerThe tool incorporates a compacted slug of Cesium-137 near the bottom of the device. A gamma-ray detector, located approximately 20 in. above the slug, responds to incident gamma radiation. A counter determines the counts/min (intensity) of the gamma rays; this information is transmitted through the logging cable to the surface, where the count rate is plotted against depth.
From the Cesium-137 source, some of the gamma rays are transmitted to the detector through the tool body ("direct" transmission), some by the wellbore fluid between the tool and the casing ("indirect" transmission), and some through the material outside the casing (also "indirect" transmission). Not all of the gamma rays from the source reach the detector because of backscattering by the wellbore fluid, but the majority of the detector’s response is attributable to this transmission.
As in the focused detectors, a scintillation crystal is preferable, but Geiger tubes are used in many tools. Preferably there are eight tubes, but tools of lesser quality may have as few as three.
When the tool is at the surface, radiation safety procedures should be strictly followed. Needless exposure to the radiation from the tool should be avoided. Logging-company personnel should have current radiation training and certification. Because of the long half-life of Cesium-137, the legal restrictions on the use of the tool vary from state to state and country to country. If the tool is dropped in the well or becomes stuck, it must be retrieved or cemented over.
Logging-speed and shut-in times for a shut-in survey are the same as recommended for the focused tools.
An example of an unfocused gamma log appears in Fig. 4.12. A gradiomanometer (pressure-gradient) density log also is shown. Logs were recorded with the well flowing and shut-in.
During shut-in, both tools identify an oil/water interface at Depth 6. The gradio shows that the density of water in the screen below the interface is approximately 1.1 g/cm3. Although the gradio responds only to fluid inside the screen, 1.1 g/cm3 is also the density of the fluid in the porosity of the pack below the interface, because this porosity is water-filled during shut-in. Above the interface, the oil density in the screen is approximately 0.6 g/cm3; although the gradio surveys only within the screen, the density of the fluid in the porosity of the pack is also 0.6 g/cm3, because this porosity is oil-filled during shut-in.
Because gamma-ray count rate is inversely related to density, the count rate on the shut-in unfocused log is lowest in the water below the interface. Whether the transmission is direct or indirect, the transmission is lower and the count rate is lower when the density of the fluid in the transmission path is higher.
Above the interface, the unfocused gamma ray shows its greatest count rate in the oil in the screen and pack.
During flow, the gradio shows essentially water in the screen below Depth 1. Farther down, at Depth 5, however, the unfocused gamma ray shows a much higher count rate than during shut-in. Because the screen at this depth is water-filled, as during shut-in, the increased response implies more transmission of gamma rays through the pack than during shut-in. More transmission through the pack is attributable to a lower density fluid in the pack. Thus, oil is present in the pack on the high side of the casing at Depth 5, but it is not in the screen. From Depths 1 to 2, the gradio shows decreasing density in the screen. This means that oil enters the stagnant water in the screen between Depths 1 and 2. Consequently, the oil in the pack at Depth 5 flows up the pack and enters the screen between Depths 1 and 2.
There is an oil-jet entry in the screen at Depth 2. Correspondingly, the gradio shows a slight spike toward lower density. The unfocused gamma ray shows a spike toward higher count rate because the oil jet lowers the density around the tool, causing more transmission of gamma rays to the detector.
At Depths 6, 7, 8, and 9, the unfocused gamma ray shifts somewhat toward higher count rate. From Depths 6 to 7, the gradio, however, shows no change of the density of the fluid in the screen. The same is true for Depths 10 to 9. Consequently, the shifts toward higher count rate of the unfocused log are attributable to increased transmission of gamma rays through the pack. Each shift, then, implies an increased presence of oil in the pack, and thus, an entry of oil to the pack at each of the four depths. At Depth 4, a slight decrease of the gradio response indicates that oil from the four entries flows up the pack and enters the screen over the 10 ft immediately above this depth.
Both logs show little or no contribution from the top, short interval at 8,600 ft. The gradio shows no change of the density of the fluid in the screen, and the unfocused gamma ray also shows no change, implying that no change occurs in the pack.
At Depth 10 (8,670 ft), the unfocused gamma ray response decreases on both the flowing and shut-in logs. During shut-in, the screen and the pack are both oil-filled above and below Depth 10; thus, the decrease during shut-in cannot be explained by a change of the density of the fluid, whether in the screen or in the pack. Also, the flowing gradio response is unchanged at Depth 10; thus, the decrease during flow cannot be attributed to a change of the density of the fluid within the screen. Instead, the decrease is attributable to a change in the porosity of the pack, with the porosity decreasing at Depth 10, resulting in an increased density of the pack above Depth 10, relative to the pack density below this depth. Above Depth 10, the increased pack density results in lower transmission of gamma rays through the pack and, thus, a lower count rate. Consequently, the decrease appears on both the flowing and shut-in logs.
In this example, it is important to note that the unfocused gamma ray, by itself, cannot distinguish between entries to the screen and entries to the pack. In addition to the unfocused gamma ray, this distinction requires a gradio log, as in this case, or a focused gamma-ray log.
The comparison of the two density logs has shown that, at least in the lower parts of the hole, oil moves upward as a separate layer on the high side of the hole. The discussion in the Appendix shows that in such situations, the count rate from the unfocused density tool is linear in the fraction of water occupying the casing’s cross-sectional area. If this concept is applied to the data in Fig. 4.12, then the two unfocused-density trace shows a constant water holdup of 28% below Depth 6 during flow. This quantitative feature of the tool can be exploited in the high-angle holes discussed in the next section of the text.
Special Logging Tools for Fluid Identification in High-Angle Wells
Layered flow often occurs in high-angle wells. (i.e., a water layer in the lower part of the wellbore cross-section, an oil layer above the water, and a gas layer at the upper part of the cross-section). While the tools used in vertical wells have proven effective in high-angle wells on most occasions, special tools have been developed for studying two- and three-phase flow. These tools make use of arms to position electrodes across the casing diameter. Consequently, they are "blind" to flow outside a screen or perforated liner. The brief descriptions of these tools that follow are based on the limited published information and personal discussions with suppliers.
Halliburton Gamma-Ray Backscatter Gas-Holdup Tool. * The purpose of this instrument is to distinguish liquid holdup (the percentage of the wellbore cross section occupied by liquid) from gas holdup (the percentage of the cross section occupied by gas) and provide a cross-sectional average for the mixture.
The gamma-ray source is the same Cesium-137 isotope used in the gamma-ray densiometers. A shielded scintillation crystal detector receives its signal from radiation backscattered by the density of material around the tool. The tool is used primarily to differentiate between gas and liquids. The contrast in density between gas and liquid causes a large change in signal level, while the small difference between oil and water densities causes a correspondingly small change in signal level. The value used for liquid density in the holdup calculation does not make much difference as long as it is in the range common to liquids. Thus, the corresponding error in holdup is at worst 10 to 15% and probably better because only backscattered radiation is involved. To compensate for pipe size, variable spacing between source and detector and/or shield should be used to eliminate backscatter from the formation outside the pipe.
For a limited range of gas-holdup values, flow-loop data for the backscatter tool show a linear response over the range of the data. Sensitivity to small gas concentrations is sufficient. These data do not shed any light on the matter of compensation for variable pipe size, however. If formation backscatter is high, then the gas point will show a much higher count rate and the small difference in liquid signal at zero gas holdup will become a relatively large difference. In-situ calibration in a shut-in well is therefore recommended for this tool if it is to function quantitatively.
Baker Atlas Multi-Capacitance Flowmeter. This centralized tool includes a spinner flowmeter at its bottom end. The wellbore cross section is considered as being divided into eight levels, and a positive orientation section of the tool ensures that the levels are perpendicular to true vertical.
Twenty-eight capacitance sensors are deployed on "wings" from the tool in such a way that there are capacitance sensors spanning each of the eight levels. An array of capacitance sensors spans levels at a first position along the tool’s axis. Another array of sensors spans levels at a second axial position.
During logging, the various capacitance measurements for each level are recorded and converted to values for the gas, oil, and water holdups. An across-the-wellbore, bidirectional velocity profile is constructed from transit-time measurements of the capacitance sensors on Levels 1 and 2 (bottom levels) and 7 and 8 (top levels). The construction involves cross-correlation of some of the sensor responses. The spinner flowmeter provides velocity information related to the wellbore centerline. Stationary measurements can be made as well.
The holdups, the velocity profile, and the cross-sectional area of the wellbore are combined to determine the flow rate of each fluid as a function of the axial position along the wellbore.
A possible limitation is that capacitance sensors sometimes film in heavier oils; in turn, an oil film biases the capacitance measurements toward oil and gas and away from water. Another possible limitation is that the distinction between oil and gas may not be nearly as great as the distinction between oil and water. Finally, the concept of velocity determination from two measurements at the same radius along the axis supposes perfectly layered flow free of circulatory velocities. This condition, however, is at odds with the assumption of capacitive-event creation for cross-correlation.
Schlumberger Flowview. In a horizontal well, five types of segregated flow are usually defined. These are: stratified with a flat interface, stratified with a wavy interface, stratified with a bubbly interface, lighter phase slugging over the heavy phase, and one phase existing as bubbles in the other phase.
Because of segregated flow, the new tool string consists of both traditional and nontraditional sensors. Some of these sensors average over the entire cross section of the casing, whereas others make measurements at different locations in the cross section. The various sensor sections are referred to as "items" in the description that follows. The tool string described next is for mainly oil/water flow. For three-phase flow, a larger tool string, called the Flagship (Schlumberger), is available.
Item 1 is a full-bore spinner. This item gives information about composite fluid velocity, which in multiphase flow is difficult to relate to fluid-flow rates even after an image of the layers in the well has been generated by an imaging sensor such as the Flowview Plus (Schlumberger).
Item 2 is the Flowview Plus. The main results from this tool are eight-electrode measurements of water holdup to provide an approximate image of how the fluids are segregated in the cross section. The fluid image greatly aids in the interpretation of the spinner response.
This item consists of two Flowview tools, combined so that one is rotated 45° to the other and separated from it by at least 3 ft. Each Flowview makes four independent measurements of borehole fluid holdup and bubble counts, distributed in different quadrants of the pipe cross section. The tool is self-centralized and uses matchstick-sized electrical probes to measure the resistivity of the wellbore fluid—high for hydrocarbons and low for water. The probes are located inside the tool’s four centralizer blades to protect them from damage. The opening of the blades positions each probe at midradius in the casing. The tool can run up to 9 5 / 8 -in. casing.
Each probe is sensitive to the resistivity of the fluid that impinges upon its sharp leading edge. If the fluids are distinct and not in a fine droplet emulsion form, and the bubble size is larger than the tip of the probe (less than 1 mm), then both water-holdup and bubble-count measurements may be obtained from the output of the probe. Local water holdup is equated to the fraction of the time that the probe is conductive, whereas bubble count comes from the average frequency of the output. The local water holdup from each of the eight probes is used to generate the water/hydrocarbon distribution in the well’s cross section.
Item 3 is the Reservoir Saturation Tool. This tool is a pulsed-neutron tool that can be operated in lifetime mode or spectral carbon/oxygen mode. Its main applications are for estimation of oil, gas, and water holdups and determination of water-phase velocity by oxygen activation.
Item 4 consists of pressure, temperature, and deviation sensors. In addition to the spinner, these are the sensors found on traditional production-logging tool strings. The new string, however, locates the temperature sensor nearly 15 ft from the end of the string, making the measurement subject to interferences from fluid mixing by tool movement.
From a combination of the holdups, the cross-sectional area of the wellbore, and the fluid velocities, the rates of the individual phases are estimated as a function of position along the wellbore’s axis.
The small resistivity probes tend to film with oil when in use in heavier oils and with water in gas/water flow. In these cases, the measurements of the affected probes are biased toward the filming phase.
Diverting-Spinner FlowmeterThese are the most accurate of the spinner devices when low total rates and multiphase flows occur. The stream is diverted through the tool’s barrel, thereby raising the velocity of flow and increasing the sensitivity to the point that diverting spinners can detect rates as low as 10 to 15 B/D. A typical 1 11/16-in. tool has a barrel ID of approximately 1.45 in. A flow of 10 B/D results in a velocity of 3.4 ft/min inside the barrel. Because of the limited clearance between the spinner and the barrel, this velocity is enough to overcome friction and turn the spinner.
Furthermore, a flow of 100 B/D passes through the barrel at 34 ft/min, which is sufficient to start the homogenization of the flow, which eventually eliminates phase influence. In casing, a rate of 2,000 B/D is needed to have the same effect around a continuous spinner. Another benefit to multiphase-flow application is that the tool can be calibrated directly for such flow. As long as the diversion is effective, casing size is not a parameter in the calibration, and the tool can be calibrated in the low-rate range where phase bias is still important even inside the tool.
One type of diverting flowmeter is the hem-packer. The lower end of the diverter contains a coated fabric "skirt" with a 1-in. hem at the bottom. The skirt is opened by the metal struts to which it is attached, so that the momentum of the stream can effect a reasonable seal. A downhole pump inflates the hem with oil contained in the tool body, resulting in a seal that diverts practically the full stream through the barrel and past the spinner. A downhole motor expands and retracts the struts. The response of the tool to single-phase flow is nearly linear. Two interchangeable spinner elements are available—one with a small pitch for high sensitivity at low rates and a second with a larger pitch for rates up to approximately 2,400 RB/D. Because of its fragility, the tool never found widespread use, but is still available at some locations.
Another type of diverting flowmeter is the basket (metal-petal) flowmeter. On the lower end, the basket is opened by motorized compression of its several struts, each of which is tack-welded on its underside to a corresponding petal cut from sheet metal. As the struts are compressed to open the basket, the petals slip over each other so as to maintain some overlap even when the basket is fully opened. As the basket opens more to accommodate larger casing diameters, overlap between the petals decreases and leakage through the basket increases. Strut travel is limited to prevent excessive opening and leakage. Standard 1 11/16-in. tools accommodate casings as large as 5.5 in. nominal. Some 1 11/16-in. tools can accommodate 7-in. casing. This is an operational feature that should be checked carefully when ordering this service. Also, it is prudent to inquire whether the tool has been calibrated in a section of pipe of diameter close to the intended application. If not, the service company may not know the effect of leakage on spinner response.
At the point where the outside of the struts meets the casing’s inside wall, the metal petals (which are attached to the inside of the struts) cannot deform enough to effect a complete seal. Because of leakage around the struts the low flow-rate response of the tool is nonlinear. Attaching the petals to the outside of the struts would improve the seal, but would wear the petals quickly during use, destroying the tool’s main advantage, its ruggedness.
There is very small clearance between the spinner and the ID of the barrel. This feature assures almost no diversion of flow around the spinner. On the other hand, small particles of debris can plug the tool.
As the spinner turns, it generates a specific number of voltage pulses per revolution. Thus, the pulse rate from the tool can be transmitted through the logging cable for surface recording and determination of the corresponding revolutions per second. The number of pulses per revolution varies considerably from manufacturer to manufacturer. When ordering the service, it is recommended to inquire as to the number of pulses per revolution (more is better).
Typical basket flowmeters are rated for temperatures in the range of 320 to 350°F and for pressures in the range of 15,000 to 20,000 psia. The 1.70-in. tool typically accommodates 3,000 B/D (maximum); the 2.25-in. tool, 5,000 B/D; and the 3-in. tool, 8,000 B/D. In each case, the tool length is approximately 60 in.
Measurements are made with the tool stationary. In a production well, the tool is lowered to the deepest measurement depth and then opened. After recording the measurement at this depth, the tool is pulled up (while open) to the next measurement depth, and so on. When opened in a production well, the tool can be damaged considerably by movement downwards. When considering a diverting flowmeter for an injection well, the user should inquire of the service company whether its tool is capable of such operation.
The chance of having a diverting flowmeter stick in the hole is greater than with a continuous flowmeter. In a sandy flow, for example, the basket recesses may plug, in which case the basket cannot close downhole. If the tool is stuck, the cable can almost always be pulled loose from the cable head and retrieved. If the flowmeter is stuck in the casing, the least expensive approach may be to jar the tool to the bottom of the hole and leave it. If stuck in the tubing, it may be necessary to pull the tubing. Horizontal wells typically have dirt along the bottom of the wellbore; the flow carries the dirt into the diverting flowmeter, which usually plugs.
Diverting flowmeters are easily calibrated in a flow loop, in both single- and multiphase flows. While continuous spinner flow-loop calibrations require many correction factors for their use, such is not the case for the diverting flowmeter.
Only a few companies have extensive flow-loop facilities. If flow loops are not used for calibration, the customary approach is to apply the same calibration to all types of flow or, even worse, to use the same sensitivity coefficient for all situations. Flow-loop facilities at various universities do offer an alternative source of equipment.
Flow loops generally cannot be pressurized or heated, so the calibrations they produce for diverting flowmeters are not exactly correct for multiphase flows, especially gas/liquid. The error, however, is much less than with a corresponding calibration for a continuous flowmeter. Further, some degree of correction is possible for a diverting flowmeter calibration, because diversion of flow around the spinner element is not a problem.
A single-phase calibration of a packer flowmeter in liquid flow is linear, showing constant sensitivity (slope), with no change of the response because of casing size. The corresponding calibration of a basket flowmeter is nonlinear because of leakage around the struts and through the basket. Moreover, the degree of leakage increases with the casing size. For a packer tool in water flow, the RPS-flow rate relation involves a threshold rate (below which the spinner does not turn); for rates above the threshold spin rate, the spin rate increases linearly with rate. For a basket tool in water flow, the initial response (at lower rates) is nonlinear because of leakage around the struts. The final response (at rates approaching maximum) is nonlinear because of leakage through the overlap between petals (i.e., flow through the basket itself). Because of leakage around the struts at lower rates, the basket also has a threshold. Unlike the packer calibration, there is no single sensitivity to the basket flowmeter calibration. The sensitivity is lower at lower rates, then increases with rate until it reaches a maximum at midrange, after which it decreases with increasing rate.
For a packer flowmeter in air at atmospheric pressure, the earlier portion of the tool’s response is nonlinear in gas rate. The lower the gas rate, the less the sensitivity because of the tendency of the gas to "spiral" through the spinner element rather than turn it. With increasing rate, the response becomes linear (constant sensitivity). The value of this sensitivity, however, is approximately one-half the sensitivity in water because of the presence of spiral-velocity components in the low-pressure stream. At normal wellbore pressure, gas density is sufficient to largely eliminate these distortions; however, tool sensitivity remains slightly lower than that for liquid.
In a multiphase flow, the diverting flowmeter should be calibrated at light-phase cuts of 0, 20, 40, 60, 80, and 100%. For each cut, the total flow rate should vary from the minimum the tool can sense up to the maximum the tool can accommodate. This process generates a family of calibration curves, with the total flow rate on the horizontal axis, the light-phase cut as the parameter of the curves, and the RPS response on the vertical axis. The total flow rate should begin at minimum and then include 100, 200, 300, 400, 500, 700, and 1,000 B/D. Above 1,000 B/D, the total flow rate should increase in 500-B/D increments until the maximum is reached. The calibrations should be performed in a pipe size close to the user’s intended application. The deviation angle is unimportant.
When requesting the diverting flowmeter, the user should verify that the service company has a calibration of the tool in the same phases as those that flow downhole in the user’s well, and in a pipe size close to that in the user’s intended application. Unfortunately, very few companies have such calibrations. If the calibration is at a different deviation angle than in the user’s well, this difference is not important.
An example of the use of a diverting flowmeter appears in Fig. 4.13, which also shows two temperature traces. A 24-hour shut-in temperature log, recorded before the flowing log, is dashed. A flowing temperature log, after 4 hours of flow, is solid. An open set of perforations is shown near the bottom of the figure. Six squeezed perforation sets are above the open set. The stationary measurements from the diverting flowmeter are shown at locations labeled A through D, top-to-bottom.
Above Depth F, the flowing temperature log is initially constant. A water flow of sufficient rate that the flow carries its temperature up with it originates at Depth F. At Depth D, the diverting flowmeter response is 7.1 RPS, showing that the water from F enters the pipe through the open perforations.
At Depth E, the flowing temperature log cools over a short interval, indicating that the water from F mixes with colder water entry at E. The size of the mixing signature at Depth E indicates that the entry accounts for 43% of the total flow, with the remaining 57% produced from the open perforations at Depth F. The flowmeter response at Depth C is 11.7 RPS, also showing that the colder water enters the pipe through squeezed perforations.
Above C, the flowmeter response is 11.5 RPS at Depth B and 11.6 RPS at Depth A. Thus, no more water enters the pipe above C. For a linear response from the diverting flowmeter, 7.1 RPS is 61% of 11.7 RPS; therefore, 61% of the water (approximately 610 BWPD) is from F, with the remaining 39% (approximately 390 BWPD) entering through the squeezed set. This is all the information the diverting flowmeter can yield, because the flowmeter responds only to flow in the pipe. On the basis of this information, one would assume that the 390 BWPD flow comes from the formation at E.
The flowing temperature log, which responds to flow within and behind the pipe, shows that the assumption just made is fallacious. Above depth G, the flowing temperature log is more constant (less slope) than it is below G. Above G the flowing temperature log responds to the full 1,000 B/D water flow inside the casing. At this rate, the stream cools slowly as it moves upward. Immediately below G, the temperature increases more rapidly with depth. This behavior is consistent with an "entry" at depth G that "pulls" the temperature toward its shut-in value. However, the spinner fails to show such an entry at this depth. Instead, the 390 B/D water flow channels down from G and enters the pipe through the squeezed set at Depth E, creating the mixing signature where it mixes with the flow from F. Therefore, the source of the colder water entering through the squeezed set is the formation at G, and not the formation at E. Between Depths E and G, water flows up inside the pipe at 1,000 B/D, while the 390 B/D water flow from G travels down behind the pipe. Because the net upward flow is less than 1,000 B/D and the temperature tool responds to the flow within and behind the pipe, the temperature trace between E and G cools more rapidly with decreasing depth than above G, where the net upward flow is 1,000 B/D.
Continuous and Fullbore Spinner FlowmetersThere is no generic difference between a "continuous" spinner and a "fullbore" spinner. In the case of the fullbore, the spinner element folds into a diameter no greater than that of the tool when in the tubing, but expands into a larger diameter for surveying in the casing. The continuous spinner does not have this capability. The difference between the two is too small to justify a separate discussion of each.
The continuous meter derives its name from the need to move the tool fast enough to overcome frictional torque and start the spinner element rotating. It also derives its name from the in-situ calibration procedure that uses logging runs at several different cable speeds with the well shut-in at the surface. Neither continuous nor fullbore, however, can provide a log that is quantitative whenever the fluid velocity is sporadic, that is, changing in the logged interval.
The continuous and fullbore tools share three features. First, the spinner element on each is at the very bottom of the tool string. If the temperature tool is run in combination with the spinner, then the thermometer’s sensor will usually be located in the tool string above the spinner. Thus, the sensor will be 4 to 6 ft above the bottom of the string. Moreover, this 4 to 6 ft will include at least one centralizer. The mixing caused by the passage of the centralizer in front of the temperature sensor will decrease the vertical resolution of the temperature log by a few ft. Even so, the vertical resolution of the temperature tool to localized entries is still far superior to that of the spinner tool, and the temperature tool should be included in the tool string.
The second common feature is the presence of at least two centralizers in any tool string containing the spinner flowmeter. The centralizers ensure that the spinner element samples the same location in the wellbore’s cross section at each depth. This consistency is necessary for the same tool calibration to apply at each depth and for the relative profile to be representative of flow rates.
The third shared feature is that both tools use a four-blade propeller-type (or turbine-type) spinner element. Although the design of the spinner element may vary, the four-blade feature is retained.
The spinner element can rotate either clockwise or counterclockwise (as viewed down the tool barrel). The direction of rotation depends upon the movement of the fluid relative to the barrel of the tool, that is, upon the direction of fluid movement as seen by "rider" on the tool. Usually, the pitch of the spinner is such that relative movement of fluid up the barrel causes the spinner to turn clockwise, whereas relative movement of fluid down the barrel causes a counterclockwise rotation of the spinner. Consequently, movement of the tool downward in stagnant fluid causes relative movement of fluid up the barrel and rotates the spinner clockwise. Movement upward in a stagnant fluid causes relative fluid movement down the tool barrel and spins the element in a counterclockwise direction. Movement of the tool in a direction opposite to the direction of flow causes the spinner to turn in the sam direction, clockwise or counterclockwise, throughout the logged interval including those intervals with stagnant fluid. Passes made downward in a production well therefore cause a clockwise rotation over the interval from 100% to 0% flow. Passes made upward in an injection well cause a counterclockwise rotation. On the other hand, movement of the tool in the direction of flow at a line speed less than full-steam velocity causes a reversal in the direction of spinner rotation at some depth within the flow interval. The spinner first loses speed as flow velocity approaches tool speed. It then stops when fluid velocity reaches tool speed less the frictional threshold speed for the tool. The spinner remains stopped until fluid velocity changes by an amount that equals two threshold values, at which point the spinner begins to turn again, but in a direction opposite the previous one. As fluid velocity changes further, the spinner maintains its opposite rotational direction. Such a pass should not be used for percentage flow profiling, because two threshold values are "lost" in the record of spin rate.
Many spinners, however, do not record the direction of rotation. Even worse, some spinners have lower sensitivities when rotating counterclockwise. In event the direction of rotation changes and the spinner does not record it, the change can be recognized from its signature: a drop of the RPS to zero, followed by a resumption of the RPS to above-zero values.
Both continuous and fullbore tools are intended for quantitative use only in flow streams having a single component of velocity directed along the axis of the tool. Furthermore, the stream should be a single-phase or a high-rate multiphase (10,000 B/D or more). In the multiphase case, the well should have low deviation angle. The meters are designed to function quantitatively in environments such as that indicated in Fig. 4.14. This spinner pass downward is from a cased, vertical well producing single-phase gas from three isolated perforation sets, the deepest of which is a short interval at 11,700 ft. In the left track, the cable speed trace shows a logging speed of 56 ft/min. This speed produces the 1.2-RPS rate of spin below the deepest perforations. This part of the RPS trace is labeled "zero-flow reference" because the RPS response is caused by moving the tool downward through the stagnant fluid below the deepest set.
The survey of the figure appears to show simple and direct a spinner record is to interpret. The validity of the interpretation, however, cannot be judged on the basis of the spinner log itself. Most wells that produce only oil or gas will have a stagnant column of mud or workover fluid standing to some depth in the wellbore unless the deepest entry is at a high rate. A wellbore-fluid density log for the present example could show a stagnant water column standing in the wellbore, at least to the bottom of the middle perforation set. If that is the case, then the spinner record above the bottom set is in response to lifting of water by the buoyant rise of gas through it and not a response to the single-phase velocity of gas flow upward. Then, if the response is assumed to be from single-phase gas flow, the contribution from the bottom set will be greatly exaggerated.
Furthermore, the type of completion in Fig. 4.14 is seldom encountered. The type of completion more likely to be associated with spinner logs is shown in Fig. 4.15. Here, there is a long bottom interval perforated over 65 ft and a short perforated interval only 5 ft above the bottom one. The figure shows a fullbore-spinner log on the right track and a wellbore-fluid density log on the left track. Both logs were run downward at a cable speed of 200 ft/min with the well producing at a combined rate of 10,000 B/D of oil and water at a 50% water cut. The objective of the logs was to profile the relative oil and water production within the long interval and to determine the relative contributions of each from the short interval.
Below D, the RPS trace in the 7-in. casing is ever-changing. The trace never attains a stable RPS value, which is necessary for quantitative analysis of the flow velocity. This fact alone means that the production from the long part of the bottom interval cannot be profiled in the straightforward manner of Fig. 4.14. Possibly, the absence of a stable RPS response is because of the high logging speed, which raises the rotational inertia of the spinner element. Quantitative analysis also requires that the flow velocity be entirely axial. But such is not the case in this example. At Depth A, there is a jetting entry, the tangential velocity of which causes a spiked increase in the RPS response. The fluid-density log at this depth decreases for a short interval, identifying oil. At Depth C, the fluid-density trace spikes in response to a fluid jet that appears to put water between the sensor ports spaced 2 ft apart. If this is the case, then the rate is insignificant because the density is the same on either side of the spike. At D, there is a spiked increase in the RPS response resulting from the tangential velocity of a jet entry. This is not to say that all perforation jets cause an increase of the RPS response. In other cases, a jet entry may have a tangential velocity that decreases the RPS trace. This happens at 7,211 ft, for example.
The density trace shows that essentially all the oil has entered the wellbore by a depth of 7,180 ft. The spinner shows that essentially all the flow is in the wellbore by this depth. Consequently, both oil and water enter below this depth. The reader can apply similar reasoning to conclude that approximately 70% of the flow enters below 7,200 ft, bringing with it a major part of the oil and water production.
Above D, the RPS trace slowly diminishes. This means that the flow at D has a swirling (tangential) component that dies away as the flow moves up. Swirls can require several hundred feet of travel to decay completely. At D, the swirl is contributing to the RPS response; as the swirl dies away, the contribution diminishes and the RPS decreases. In other cases, the swirl may detract from the RPS response; as the swirl decays, the RPS increases. Even if the RPS trace were to show some evidence of production from the short interval, the presence of the swirl would preclude a quantitative analysis of the flow velocity.
The logging operator used the high logging speed in this example to minimize the distortion of the RPS trace by jet entries, as at Depth A. Actually, this procedure maximizes the distortion by biasing all fluctuations to the high side of their excursions rather than to their average.
The previous two examples should remind the reader that an apparently simple record from a direct measurement can have subtle meanings and may fail to present a complete accounting of the situation.
Continuous tools are available in a wide range of configurations, more so than the fullbore tools. The diameters range from 1 3/8-in. to 2 1/8-in. The 1 3/8-in. versions, with centralizers, should pass through 2-in. tubing. If the tubing includes landing nipples, such as the 1.82-in. size, it is difficult to force the centralizers through the nipples. Safety considerations preclude even an attempt.
The centralizers also come in a variety of configurations. Powered centralizers offer the least problem to entry through tubing. These are closed by strong springs when in the tubing. In the casing, a downhole motor opens the centralizer against the spring force. In event of a failure of the motor downhole, the powered centralizer has a shearing mechanism so that the constriction at the tubing’s end can be used to close the centralizer when re-entering the tubing. The chance of sticking a centralized string is greater than that for an uncentralized one.
Some continuous tools have the spinner element inside a bow-spring cage with no additional protection from damage. In others, the element is inside a rigid cage having the same diameter as the tool. Still others place the element inside a short section of tubing having the same diameter as the barrel. The latter are immune to the tangential velocity of a jet-entry; they are not immune to swirl, which has both axial and tangential components. If the flow is multiphase, the trace from such a tool is noisier because of the light phase’s tendency to pass through the "chimney."
To measure the RPS of the spinner element, the most common means is a magnet and pickup coil. A narrow magnet is attached lengthwise to a section of the spinner shaft. The magnet rotates under the pickup coil, which is divided into independent segments so that the coil generates a number of inductive current spikes per revolution of the shaft. The resolution, however, does not approach that from tools utilizing an optical sensing assembly, which also detects the direction of rotation. Another variation uses a single sector of pickup coil with three bar magnets embedded in the rotor at unequal azimuth angles. While reducing the tool’s resolution, this approach does detect the direction of rotation.
Magnets should be located inside the tool barrel so that iron particles in the wellbore fluid attach themselves to the outside of the tool and do not interfere with rotation of the spinner. Magnets located on the spinner shaft before it enters the barrel can attract iron particles and eventually make rotation impossible.
Most continuous spinners are rated for pressures in the range of 15,000 to 20,000 psi and temperatures of 350 to 400°F. Some tools can accommodate 500°F, but they employ vacuum flasks and thus have a diameter of at least 2.5 in.
Practically all fullbore spinners are copies of the original Schlumberger version with slight modifications here and there. Fullbore tool diameters range from 1½ to 1∕1611 in.
These tools use specific diameter spinner elements to accommodate specific casing sizes. Typically, three different diameters are used to cover casings in the range of 4 to 9 5 / 8 in. Pressure and temperature ratings are the same as for the continuous spinners, which were stated previously.
The difference in resolution between continuous and fullbore spinners is small; the following comments apply to both types. Neither is very effective for quantitative resolution of low-rate, multiphase production. In the U.S., the spinners’ greatest quantitative application is injection profiling. Table 4.3 summarizes typical rate resolution under different flow conditions in vertical wellbores, although actual resolutions are quite dependent on flow conditions.
Refer to Fig. 4.16, which pertains to the record of a high-quality, high-resolution continuous tool that detects the spinner element’s direction of rotation. The well, with three perforation sets, produces 1,800 B/D at 28% oil, 72% water, and no gas. The survey shows two logging runs, one up and one down, with each at 22 ft/min cable speed (left track). There are two respective RPS records (right track). Zero RPS is at the fifth chart division from the left, and 1 RPS is spread over four chart divisions (a sensitivity of 0.25 RPS per chart division), showing the tool’s high resolution.
On the up run (dashed trace) in the stagnant fluid below the bottom perforation set, an imaginary observer riding on the tool would perceive the fluid velocity as down the barrel so that this trace records counterclockwise rotation (CCW) below the bottom set. On the down run through the stagnant fluid below the bottom set, the imaginary observer would perceive the fluid velocity as up the barrel; therefore, the rotation is clockwise (CW). Below the bottom set, the RPS of the up run is more irregular than on the down run, because the tool, when jerked off the bottom, requires some distance to reach a steady speed. Thus, the comments below pertain to the down run.
On the down run in the stagnant fluid (which is single-phase formation brine or workover fluid) below the bottom set of perforations, the RPS shows a very steady value of three chart divisions; that is, 0.75 RPS. The tool used for this survey has a threshold velocity of 5 ft/min. This amount of line speed in the stagnant fluid is required to overcome frictional torque and start the spinner rotating. Therefore, the velocity driving the spinner on the down run through the stagnant fluid is 22 – 5 = 17 ft/min. The sensitivity of the tool is 17/0.75 = 22.67 ft/min/RPS. In the stagnant fluid, a sustained defelection of 0.2 chart division would be recognizable on the RPS trace. The single-phase sensitivity of this tool is
0.2(chart div) × 0.25(RPS / chart div) × 22.67 ft / min / RPS = 1.13ft / min.
The 7-in., 23-lbm/ft casing has a capacity of .0393 bbl/ft; thus, this velocity corresponds to a flow rate of
1.13(ft / min) × 0.0393(bbl / ft) × 1,440(min / D) = 64 B / D.
This value is at the low end of the range listed in Table 4.3 because the flowmeter in this case has very high resolution. On the down run, the flow from the bottom two sets causes an average deflection of 0.8 chart divisions to the right of the steady response in the stagnant fluid below the bottom set (the no-flow reference). In full flow, the average deflection is 6.5 chart divisions to the right of reference. Thus, the relative contribution of the bottom two sets is (0.8/6.5) × 1,800 = 222 B/D. A flowing temperature survey in the same well (not shown), analyzed separately, establishes a more reliable estimate of the contribution of the bottom two sets: 430 B/D. The flowmeter lost 200 B/D, which is consistent with the resolution stated for oil and water flows (see Table 4.3). As oil, because of its buoyancy, rises through water in the wellbore interval defined by the bottom two sets, the oil churns and circulates the water even if the water is flowing; in turn, this action in the heavy phase can either slow down or speed up the spinner element, depending upon what component of circulation in the heavy phase most affects the tool. On the down run, the spinner is slowed, diminishing the spinner-estimated relative contribution of these sets. On the other hand, the spinner element speeds up slightly on the up run in response to a circulation downward.
The calculation immediately preceding is an example of relative profiling; that is, using the flowmeter log to establish relative contributions, with the total flow rate known independently. When an absolute flow rate is needed, the method of downhole calibration can be used. Downhole calibration is appropriate for injection flows or single-phase production except for, perhaps, the deepest entry, which may be submerged in captive completion fluid.
To perform a downhole calibration, the well is shut in at the surface. Both up and down runs are made through the static fluid at various cable speeds. On the calibration plot, cable velocities appear on the horizontal axis, with downward logging speeds as positive velocities and upward speeds as negative velocities. Values of RPS appear on the vertical axis, with values positive for down runs and negative for up runs. For each run, a point is plotted that corresponds to the cable velocity and its respective RPS value. A "best-fit" straight line is constructed for the plotted points of the down runs; this line corresponds to clockwise rotation and is located in the first quadrant of the plot. A second best-fit straight line is constructed for the plotted points of the up runs; this line corresponds to counterclockwise rotation and appears in the third quadrant.
The line for the down runs intersects the cable velocity axis to the right of the origin, and the velocity value at this intersection is the ideal or extrapolated threshold velocity for down runs. This value is slightly less than the actual speed needed to overcome frictional torque and start the spinner element rotating. The slope of this line is the sensitivity of the tool during down runs. The line for the up runs intersects the cable velocity axis to the left of the origin, and the absolute velocity value at the intersection is the threshold velocity for up runs. The value of the slope of the line is the sensitivity of the tool during up runs. For a quality tool, the two threshold velocities are nearly the same, as are the two sensitivities.
As an example of the use of the downhole calibration, consider a down run with the well producing. The RPS value at a depth of interest is taken from the log and on the plot is projected horizontally onto the straight line for the down runs. The corresponding value on the velocity axis is the velocity that drives the spinner element at this location. From this velocity, subtract the cable speed to obtain the net velocity. This velocity value is the apparent flow velocity. Multiplication of the net velocity (ft/min) by the pipe capacity (bbl/ft), by 1,440 (min/D) and by an independently determined calibration factor yields the desired flow rate. The calibration factor is needed because the apparent velocity as measured by a spinner is larger than the average or superficial velocity of the stream.
As another example, consider an up run with the well producing and with the spinner turning counterclockwise. The RPS value at a depth of interest is taken from the log and projected onto the line for the up runs. The corresponding value on the velocity axis is the velocity that drives the spinner element. From the absolute value of this velocity, subtract the positive value of the cable speed to obtain the net velocity. The rate is calculated from this net velocity in the same way. Had the spinner reversed to spin clockwise, the speed would be projected onto the calibration line for down runs and the cable speed added to the result to obtain the net velocity. An algebraic formulation of spinner speed as a function of cable and fluid velocities is given in the Appendix under the category of injection profiling.
Some additional comments are in order relative to the spinner traces in Fig. 4.16. Note first the pass upward at a line speed of 22 ft/min (the dashed-line trace). This line speed is close to the value of the upward superficial velocity for the full-flow stream (18 ft/min). Consequently, the spinner deflection is small approximately 0.25 rps counterclockwise above 6,050 ft. Below this depth, this low speed accentuates the fluid turbulence associated with the lifting and fallback of water as oil moves through it. This churning and circulatory action causes the spinner speed to flip-flop across the zero-rps axis with a reversal in the direction of spin on each crossing. On the downward pass at 22 ft/min (the solid-line trace), the higher-frequency oscillations are much smaller than on the upward pass. With the relative sped of the fluid to the tool being approximately 10 times larger than on the up pass, the sample time is too small for the spinner response to mirror the full extent of the high-frequency fluctuations seen on the up pass. As a result, one sees on the downward pass primarily the occasional lower-frequency events associated with gross slugging or "heading" in the flow.
The reduced effect of turbulence on the pass downward illustrates an adage that one still finds repeated in the literature to the effect that a high logging speed should be used to "minimize" the effect of turbulence. Although the claim is true, the implication that the response is more accurate is not. The reduced sample time caused by high relative speed between fluid and tool introduces a "hidden" bias toward higher spinner speed in flows affected by multiphase turbulence. The positive bias results from the greater influence of the life surges relative to the fallback flow along the casing wall. Such a bias is evident on the record from the upward pass, the dashed line in Fig. 4.16. An average value for the spinner speeds on the section of record in the interval of 6,090 to 6,130 ft is clearly to the clockwise side of the zero axis by approximately 0.25 rps, whereas the value above 6,050 ft is approximately 0.25 rps counterclockwise. The gross bias of approximately 0.5 rps represents a flow of 160 B/D in this example. The bias increases as the relative speed increases. Some spinner tools rectify the output pulses before conversions to rps values. On records from such tools, turbulence of any type produces a bias to higher speeds, owing to the interaction between sample time and spinner inertia.
Production-Logging Suite Examples
The earlier discussion emphasized the importance of using suites of production logs, rather than relying on a single log. In addition, the discussion indicated the applicability of production logs at various stages of a well’s life, from drilling to abandonment, and even beyond. To further emphasize these points, four examples of production-logging suites (during drilling, during primary recovery, during tertiary recovery, and after abandonment) are described. These discussions include the objective of running a particular production-logging suite, stating why each log was used, and indicating what each log contributed toward achieving the objective of an understanding of the subject well’s behavior.
Gas Kick While DrillingIn this development well, 10 3/4-in. pipe is set to 3,500 ft, and 7 5/8-in. casing is set to slightly below 14,000 ft. Behind the 7 5/8-in. casing, the top of the cement is just below 6,000 ft. During the coring of a gas sand at 15,000 ft, a pressure kick occurred, gas pressure was then lost at the surface, and mud was added periodically to keep the drillpipe full.
On the day after the gas kick, noise and temperature logs were recorded during the same run inside the drillpipe with the well static. These logs were run to identify the flow path of a likely underground blowout. The temperature log is basic to understanding a well’s behavior, and the noise log is particularly responsive to the movement of gas through liquid.
At 15,000 ft, the noise log (Fig. 4.17a) exhibits a nearly "dead-well" noise level, indicating no activity (i.e., no fluid movement). Above 15,000 ft, however, the noise log departs from dead-well response. This departure shows that the gas, which enters the wellbore just above 15,000 ft, moves uphole. Above 14,000 ft, the noise log decreases very rapidly to dead-well response, showing that the gas moving uphole enters a formation at 14,000 ft, approximately 100 ft above the 7 5/8-in. casing shoe. The log thus shows a crossflow of gas (single-phase) from approximately 14,800 to 14,000 ft. The absence of gas pressure at the surface on the annulus between the drillpipe and the 7.625-in. casing means that the annulus is plugged by a bridge at some unknown depth above 14,000 ft.
A temperature log is quite sensitive to liquid flow and will reveal details regarding the flow path of any mud returns, which should move uphole in the annulus between the drillpipe and the 7 5/8-in. casing, owing to the periodic addition of mud to the drillpipe at the surface. Each time mud is added at the surface, some hotter mud is pushed upward in the annulus. For a given length of wellbore, the volume of hotter mud in the annulus greatly exceeds the volume of cooler mud in the drillpipe. During the time between additions, the two volumes equate in temperature to a value warmer than static. The periodic addition of mud at the surface should therefore produce what appears to be a "production" profile on a temperature survey. The temperature log in Fig. 4.17b does indeed show such a profile below Depth C. From this depth downward to 14,000 ft, the temperature is warmer than static, indicating displacement of annular mud upward to Depth C. This depth happens to be the location of a zone that was fractured and used during drilling for disposal of sour mud from the mud pit. The log therefore shows the movement of mud from deep in the well upward and into the disposal zone at Depth C. Above Depth C, the temperature trace lies to the cool side of static, reflecting the addition of cool mud to the drillpipe without displacement of warmer mud upward in the annulus.
For this flow path to exist, the 7.625-in. casing must also have failed at some depth. The temperature trace shows the location of this failure at Depth A just below 5,000 ft. Above this depth, the displaced mud moves behind the casing and loses heat to the formation at an increased rate. The corresponding mud temperature, although still warmer than static, is not as warm as the mud still in the annulus below Depth A. A mud path is therefore established as shown by the dashed line on the wellbore schematic on the left side of Fig. 4.17b. The only remaining task is the location of the depth of the failure in the drillpipe.
To investigate the mechanical integrity of the drillpipe, a radioactive tracer log was run, with the tracer tool stationary in the drillpipe at various depths while mud was pumped into the drillpipe continuously. The tracer traveled down the drillpipe with the mud flow, and the time lapse between its ejection and its subsequent detection by a detector below the ejector was measured. Time-lapse measurements made at various depths indicated a significant mud leak from the drillpipe in the interval between 12,800 and 12,900 ft. As further confirmation of the mud leak, tracer was ejected at 12,800 ft, and the tracer tool was quickly repositioned to 12,500 ft. While the logging tool was at 12,500 ft, the detector responded to the ejected tracer as it moved upward in the drillpipe-casing annulus. As a result of this survey, one can further conclude that the annulus is plugged to gas flow at some depth below the leaking joint of drillpipe at approximately 12,800 ft. The location of this bridge was determined from a free-point survey (see appendix), allowing a joint of split drillpipe to be replaced. The underground gas crossflow was then "killed" with mud.
Once the underground blowout was eliminated, the drillpipe was removed and the 7 5/8-in. casing string was examined with a casing collar locator to complete the investigation of mechanical integrity. The collar-locator log showed a 4-ft vertical separation in the casing string at Depth A because of a casing joint that was unscrewed from the collar above.
In this example, a careful analysis of a suite of inexpensive production logs yields definitive information of a diagnostic nature. Please note that the first suggestion of mechanical integrity problems resulted from a thorough examination of the temperature profile. Because the temperature profile was analyzed during the logging, the tracer and collar-locator logs were run while at the wellsite, avoiding the additional setup, pressure, and depth charges that would occur if the service company were to return for the tracer and collar-locator logs at a later date.
Profiling Commingled-Gas ProductionThis well produces gas from four perforated intervals; however, the bottom two intervals are in such close proximity that they are considered as one perforation set. Therefore, the perforations are referred to as the "top set" (A), the "middle set" (B), and the "bottom set" (C). The well produces 175 to 320 Mscf/D, with negligible water production. The objective of the production logs was to determine the fraction of total production contributed by each perforation set. With the well flowing, fluid density, temperature, and continuous-spinner flowmeter profiles were recorded. With the well flowing, a diverting flowmeter log was also recorded with the flowmeter stationary below and above each perforation set.
Viewed upward from the bottom, the fluid-density profile (Fig. 4.18) responds to a column of water below the bottom perforation set. Then it decreases above each of the three perforation sets, indicating that each set produces gas. Above the top perforation set, the measured density still exceeds the density of the gas, showing that water is present in the wellbore throughout the survey interval. Even though the water production is negligible, the gas rate is insufficient to lift water out of the wellbore.
Although there are two phases present in the wellbore (the produced gas and the captive water), the diverting flowmeter can respond to the gas flow rate at each measurement depth. This flowmeter was calibrated in a flow loop by measuring its response to a variety of air flows as they were passed through a column of stationary water. A "percolation calibration" was generated by plotting the diverting flowmeter’s responses to the various air-flow rates. With this percolation calibration, the flowmeter’s downhole measurements, shown in the depth track, were interpreted to yield the profile in Table 4.4, which shows the fraction of total gas production from each perforation set.
The fractional contributions of the three sets also were determined by a linear analysis of both the diverting-flowmeter log and the continuous-spinner-flowmeter log. With this approach, a perforation set’s fractional contribution to production is determined as the ratio of the change of the flowmeter’s response across the perforation set to the total change of response from below the bottom perforation set to above the top set. The linear analyses of the two flowmeter logs both erroneously indicate that only one-quarter of the total production is from the top set, as opposed to the correct contribution of nearly one-half. A linear analysis is appropriate when only one phase is present in the wellbore but not when there are two.
In this example, the production profiles based on the temperature log and a proper analysis of the diverting flowmeter log corroborate each other, showing the advantage of more than one log in the suite. Also, this example demonstrates that when reliable data are analyzed with an inappropriate method (the linear-flowmeter technique), appreciable errors can result.
Profiling Oil Production Under WAG Recovery
In this well, 5 1/2-in. casing is set to 4,463 ft. Below the casing, oil is produced in the open hole under WAG (water-alternating-gas) recovery.
The well produces 1381 RB/D of water, 119 RB/D of oil, and 245 RB/D of CO2. Carbon dioxide, CO2, dissolves primarily in the oil and secondarily in the water. Water is the continuous phase in the wellbore. The produced oil, with CO2 in solution, bubbles (or "percolates") up through the flowing water. The logs in this suite were run with the objective of identifying the following:
- Intervals in which water enters the wellbore.
- Whether CO2 is dissolved in the water.
- Intervals in which oil (with CO2 in solution) enters the wellbore.
The well was logged flowing, then shut in overnight. Shut-in logs were recorded the next morning. The following logs were run: fluid capacitance, fluid density, neutron, and temperature.
A comparison of flowing and shut-in temperature profiles (Fig. 4.19a) shows that the major production originates from a thin interval just above 4,575 ft (Depth G). Because the thermal content of the stream is essentially water, a thin interval at Depth G is therefore the source of water production. Injected water travels along a permeable streak known to exist at the based of the porous interval. This is not a good profile for oil recovery. The water is warm because warmer brine is being injected into a formation cooled by years of waterflooding.
The fluid-capacitance log (Fig. 4.19b) (well flowing) responds to the deepest oil entry at Depth C on an up run. However, fouling of the capacitance probe by the heavy oil renders the remainder of the up run useless for detecting additional oil entries. The probe was cleaned by stationing it in the tubing, where the elevated flow velocity removed the heavy oil film; however, it again fouled upon exit from the tubing. The shut-in capacitance profile, recorded later, reveals an additional oil entry at Depth E.
One usually depends on the response of the flowing fluid-capacitance log to determine whether an entering fluid is water or oil. In this example, the failure of the flowing capacitance log to respond to all oil entries with the exception of the deepest one (C) was anticipated in advance of logging and is not a problem because the water production is localized, and a comparison of flowing and shut-in neutron logs, which respond to a change of CO2 concentration in the wellbore, can detect oil entries above Depth C.
The comparison of the separations between flowing and shut-in neutron logs (Fig. 4.19c) reveals the following:
- CO2 is dissolved in the water entering at (A).
- CO2 is dissolved in the water entering below (B), but at higher concentration than in the entry below (A).
- CO2 is dissolved in the oil entry at (C), which is the deepest oil entry according to the flowing capacitance log.
- Oil with dissolved CO2 enters just below (D).
- CO2 is dissolved in the fluid entering at (E), which is oil according to the shut-in capacitance log.
- There is a fluid entry at (F), but with no CO2 dissolved in the entering fluid. Because the water is produced below (C), the entering fluid is probably oil. The injected CO2 is not reaching as far up the formation as Depth F. Still, the gravity migration of carbon dioxide upward in the formation above the bottom permeability streak is much better than one might suspect from the water production profile alone.
In this example, none of the three log types (temperature, fluid capacitance, and neutron) is capable of accomplishing the logging objective by itself. Moreover, no combination of two of the logs is capable of fulfilling the objective. Only a thorough analysis of the three logs taken together can accomplish the objective, showing the importance of a carefully selected, comprehensive suite of logs.
Gas Blowout After AbandonmentA well was drilled through two gas zones on the way to test a deeper oil zone. The well was abandoned and the wellhead cut at the seafloor.
Six months after abandonment, there was a gas blowout to the surface, causing the sea to churn. A relief well was drilled in order to flood the blowing zone. A magnetometer survey (Fig. 4.20a) shows the distance of the relief well from the original wellbore. The separation of the two wellbores "corkscrews" between approximately 5 and 25 ft, an effect caused by changes in the direction of the original wellbore. The two gas-zone locations are marked on the figure.
A noise log (Fig. 4.20b) was run in the relief well to identify which of the two gas zones was the source of the gas blowout. The noise log is applicable for this purpose because of its ability to "listen" to the sound in the original wellbore.
The dead-well noise levels in the interval of the relief well at the location of Gas Zone (2) shows it is not the source of the blowout. The noise-log response is elevated above the dead-well level in an interval of the relief well corresponding to the location of Gas Zone (1) showing that this gas zone is the source of the blowout. Above this location, the noise log exhibits several peak responses, two of which are larger than the response at the source of the gas blowout. The location of the largest corresponds to the location of least separation above Zone (1) in Fig. 4.20a. The other spikes are likely at locations of tight spots in the flow path.
It is also possible to estimate the distance between a blowing well and a relief well a point source of noise in the blowing well. This is done from the rate at which the noise level attenuates with distance along the relief wellbore from the peak noise location, and is possible because the noise level is inversely proportional to distance from the source. For example, the 200-Hz noise level at the location of zone (1) in Fig. 4.20b is 17 millivolts. By 3,500 ft, a distance of 140 ft in the relief well, this level has dropped to 2.0 millivolts. The separation between the wells at zone (1) is therefore estimated by the expression:
This value compares to the 13–14 distance indicated by the magnetometer survey. Likewise, the separation at the large peak at 3,150 ft is estimated from the decay at a value of 6.5 ft, which is the same distance as that shown on the magnetometer survey.
In this example, only two production logs were used. In considering this point, it is important to remember that the logging objective is quite limited: to determine which of the two known gas zones is the source of the blowout. Given that the logging is in the relief well, the noise log is better suited to this purpose than any other production log.
In aggregate, the previous four examples give the reader an appreciation of what can be accomplished with production logs during the entire life of a well.
This chapter describes the various tools used in production logging and provides insight on how to interpret results. In addition, the Appendix provides a "road map" of what logs to use for specific circumstances and what analysis methods apply. In particular, logging tools for making temperature surveys, several types of gamma-ray measurements, and spinner surveys are described. Examples are included for each tool and for four examples that illustrate why logging suites are needed to pinpoint what is happening in a well. Specific information is included on logging suites and skills needed to make successful surveys and meaningful interpretations. There are two specific recommendations that merit repeating: logging suites can be used to reduce ambiguous interpretations, and careful planning and documentation will ensure the current and future usability of production-logging results.
|A||=||coefficient; also area, L2|
|C||=||casing capacity, bbl/ft|
|C||=||count rate, counts/sec|
|Dh||=||casing or hole diameter, ft|
|Dt||=||tool diameter, ft|
|Lt||=||maximum tool length to pass through bend, ft|
|Lturn||=||distance to bend, ft|
|Np||=||number of pipe strings|
|q||=||flow rate, B/D–scf/D|
|Ri||=||inside bend radius (or turning radius), ft|
|S||=||spinner turn rate, RPS|
|y||=||holdup of a given phase|
|z||=||distance in z vertical direction|
|α||=||angle of bend, degrees|
|Δ||=||difference in two values|
|1||=||referemce to bottom set of perforations|
|cool||=||area cooled below geothermal gradient|
|in||=||property of fluid flowing into wellbore from a set of perforations|
|mix||=||mixture of flowing fluids|
The authors wish to express their appreciation to the ExxonMobil Co. for permission to use the information contained in this chapter. The information was extracted largely from an internal document that required many hours of preparation by the authors.
- Polaris-Production Optimization Log and Reservoir Information Solutions. 1999. Houston: Baker-Hughes Brochure.
- Hupp, D. and Schnorr, D.R. 1999. Evaluating High-Angle Wells With Advanced Production-Logging Technology. Presented at the SPE Annual Technical Conference and Exhibition, Houston, Texas, 3-6 October 1999. SPE-57690-MS. http://dx.doi.org/10.2118/57690-MS.
The following brief collection of references to production-logging technology is definitely not intended to be comprehensive. Instead, the entries are chosen as being representative of the available literature within the constraint that each reference contains information of general interest. The reader should be warned that some of the articles are strongly biased toward the tools offered by a particular company to the exclusion of other equally effective but usually older devices. The inclusion of such articles does not constitute an endorsement by us. Furthermore, the reader should know that log interpretations offered in some of the papers differ from those that would follow from the application of the interpretative guidelines presented in the Appendix to this chapter.
The references are organized into categories for ease of use. Within each category, articles are listed in alphabetical order according to the surname of the lead author without regard to the relative significance of the article.
Bateman, R.M. 1985. Cased-Hole Log Analysis and Reservoir Performance Monitoring. Boston, Massachusetts: Intl. Human Resources Development Corp.
Carlson, N.R. 1982. Interpretative Methods for Production Well Logs, Publication 9411. Houston, Texas: Dresser Atlas (Baker Hughes) Co.
Hill, A.D. 1990. Production Logging—Theoretical and Interpretative Elements, Vol. 14. Richardson, Texas: Monograph Series, SPE.
McKinley, R.M. 1994. Temperature, Radioactive Tracer and Noise Logging for Injection Well Integrity. U.S. Environmental Protection Agency, Publication EPA/600/R-94/124, R.S. Kerr Research Laboratory, Ada, Oklahoma.
Smolen, J.J. 1973. Production Log Interpretation. Publication C-11811. Houston, Texas: Schlumberger Ltd.
Smolen, J.J. 1985. Production Logging. Richardson, Texas: Reprint Series No. 19, SPE.
Smolen, J.J. 1996. Cased Hole and Production Log Evaluation. Tulsa, Oklahoma: PennWell Publishing Co.
Connolly, E.T. 1965. Resume and Current Status of the Use of Logs in Production. Paper presented at the 1965 SPWLA Annual Well Logging Symposium, Dallas, 4–7 May.
Hill, A.D. and Oolman, T. 1982. Production Logging Tool Behavior in Two-Phase Inclined Flow. J Pet Technol 34 (10): 2432-2440. SPE-10208-PA. http://dx.doi.org/10.2118/10208-PA.
McKinley, R.M. 1982. Production Logging. Presented at the International Petroleum Exhibition and Technical Symposium, Beijing, China, 17-24 March 1982. SPE-10035-MS. http://dx.doi.org/10.2118/10035-MS.
Petevello, B.G. 1975. Evaluation of Well Performance Through Production Logging. Paper presented at the 1975 Formation Evaluation Symposium, Calgary, 5–7 May.
Wade, R.T., Cantrell, R.C., Poupon, A. et al. 1965. Production Logging-The Key to Optimum Well Performance. J Pet Technol 17 (2): 137-144. SPE-944-PA. http://dx.doi.org/10.2118/944-PA.
Garwood, G.L. 1974. Equipment Selection for Sour Gas Condensate Wells. The Drilling Contractor (March–April): 40.
Hammack, G.W., Myers, B.D., and Barcenas, G.H. 1976. Production Logging through the Annulus of Rod-Pumped Wells to Obtain Flow Profiles. Presented at the SPE Annual Fall Technical Conference and Exhibition, New Orleans, Louisiana, 3-6 October 1976. SPE-6042-MS. http://dx.doi.org/10.2118/6042-MS.
Howell, E.P., Smith, L.J., and Blount, C.G. 1988. Coiled-Tubing Logging System. SPE Form Eval 3 (1): 37-39. SPE-15489-PA. http://dx.doi.org/10.2118/15489-PA.
Anderson, R.A., Smolen, J.J., Laverdiere, L. et al. 1980. A Production Logging Tool With Simultaneous Measurements. J Pet Technol 32 (2): 191-198. SPE-7447-PA. http://dx.doi.org/10.2118/7447-PA.
Brown, G.A., Kennedy, B., and Meling, T. 2000. Using Fibre-Optic Distributed Temperature Measurements to Provide Real-Time Reservoir Surveillance Data on Wytch Farm Field Horizontal Extended-Reach Wells. Presented at the SPE Annual Technical Conference and Exhibition, Dallas, 1-4 October. SPE 62952. http://dx.doi.org/10.2118/62952-MS.
Dennis, B.R. et al. 1985. High-Temperature Borehole Instrumentation, Report LA-10558-HDR. Los Alamos, New Mexico: Los Alamos Natl. Laboratory.
Hupp, D. et al. 1999. Polaris—Production Optimization Log and Reservoir Information Solutions, Brochure A 99118. Houston, Texas: Baker-Atlas Div. of Baker Hughes.
Hupp, D. and Schnorr, D.R. 1999. Evaluating High-Angle Wells With Advanced Production-Logging Technology. Presented at the SPE Annual Technical Conference and Exhibition, Houston, Texas, 3-6 October 1999. SPE-57690-MS. http://dx.doi.org/10.2118/57690-MS.
Hupp, D. et al. Memory Pressure and Production Logging Tools, Brochure. Bramshill, UK: Sondex Ltd.
Tello, L.N., Blankinship, T.J., Roberts, E.K. et al. 1999. A Dipole Array Sonic Tool for Vertical and Deviated Wells. Presented at the SPE Annual Technical Conference and Exhibition, Houston, Texas, 3-6 October 1999. SPE-56790-MS. http://dx.doi.org/10.2118/56790-MS.
Papers Aimed at Computerized Interpretation
Catala, G.N., Torre, A.J., and Theron, B.E. 1993. An Integrated Approach to Production Log Interpretation. Presented at the Middle East Oil Show, Bahrain, 3-6 April 1993. SPE-25654-MS. http://dx.doi.org/10.2118/25654-MS.
Holm, W.H. et al. 1983. A Cased Hole Well Log Computer System. Paper presented at the 1983 SPWLA Annual Well Logging Symposium, Calgary, 27–30 June.
Nerby, G. 1989. A New Approach to Production Log Analysis. Graham and Trotman’s Proceedings, 1989 North Sea Oil and Gas Reservoirs Conference II, Trondheim, Norway, May.
Nerby, G. 2000. Plato—The Answer to Your Production Logging Analysis, Brochure. Houston, Texas: IPS Interpretative Software Products Co.
Agnew, B.G. 1966. Evaluation of Fracture Treatments With Temperature Surveys. J Pet Technol 18 (7): 892-898. SPE-1287-PA. http://dx.doi.org/10.2118/1287-PA.
Carlson, N.R. et al. 1986. The Significance of the Temperature Log in Multiphase Flow. Paper presented at the 1986 SPWLA Annual Well Logging Symposium, Houston, 9–13 June.
Cooke Jr., C.E. 1979. Radial Differential Temperature (RDT) Logging - A New Tool for Detecting and Treating Flow Behind Casing. J Pet Technol 31 (6): 676-682. SPE-7558-PA. http://dx.doi.org/10.2118/7558-PA.
Dobkins, T.A. 1981. Improved Methods To Determine Hydraulic Fracture Height. J Pet Technol 33 (4): 719-726. SPE-8403-PA. http://dx.doi.org/10.2118/8403-PA.
Jameson, L.R. 1967. Some Applications of Differential Temperature Logging. Presented at the SPE Regional Secondary Recovery Symposium, Pampa, Texas, 26-27 October. SPE-1977-MS. http://dx.doi.org/10.2118/1977-MS.
Millikan, C.V. 1941. Temperature Surveys in Oil Wells. Trans. of AIME 142 (1): 15-23. SPE-941015-G. http://dx.doi.org/10.2118/941015-G.
Pierce, A.E. et al. 1966. Temperature surveys spot well ills, solve operating problems. Oil & Gas J. (June): 96.
Ramey, H.J.J. 1962. Wellbore Heat Transmission. J Pet Technol 14 (4): 427–435. SPE-96-PA. http://dx.doi.org/10.2118/96-PA.
Smith, R.C. Temperature Log Interpretation. Publication L-36, The Welex (Halliburton) Co.
Smith, R.C. and Steffensen, R.J. 1975. Interpretation of Temperature Profiles in Water-Injection Wells. J Pet Technol 27 (6): 777-784. SPE-4649-PA. http://dx.doi.org/10.2118/4649-PA.
Enright, R.J. Sleuth for Down-Hole Leaks. Oil & Gas J. 38: 78.
Koerner Jr., H.B. and Carroll, J.C. 1979. Use of the Noise Log as a Downhole Diagnostic Tool. Presented at the Middle East Technical Conference and Exhibition, Bahrain, 25-28 February 1979. SPE-7774-MS. http://dx.doi.org/10.2118/7774-MS.
Korotaev, Y.P. 1970. Acoustic Method of Delineating Operating Intervals in Gas-Bearing Formations. Gazovaya Prom. (11): 14.
McKinley, R.M., Bower, F.M., and Rumble, R.C. 1973. The Structure and Interpretation of Noise From Flow Behind Cemented Casing. J Pet Technol 25 (3): 329-338. SPE-3999-PA. http://dx.doi.org/10.2118/3999-PA.
Myung, J.L. 1976. Fracture Investigation of the Devonian Shale Using Geophysical Well Logging Techniques. Presented at the SPE Eastern Regional Meeting, Columbus, Ohio, 18-19 November 1976. SPE-6366-MS. http://dx.doi.org/10.2118/6366-MS.
Pennebaker Jr., E.S. and Woody, R.T. 1977. The Temperature-Sound Log and Borehole Channel Scans for Problem Wells. Presented at the SPE Annual Fall Technical Conference and Exhibition, Denver, Colorado, 9-12 October 1977. SPE-6782-MS. http://dx.doi.org/10.2118/6782-MS.
Rambow, F.H.K. 1991. Active Listening: An Alternative Method for Detecting Flow and Measuring Flow Velocity Behind Casing. The Log Analyst (November–December): 645.
Robinson, W.S. 1976. Recent Application of the Noise Log. Paper presented at the 1976 SPWLA Annual Well Logging Symposium, Dallas, June 9–12.
Shuck, L.V. et al. 1974. Noise Characteristics of Oil Wells and Reservoirs. Paper SPE 5147-B presented at the 1974 SPE Annual Meeting, Houston, 6–9 October. http://www.onepetro.org/mslib/app/Preview.do?paperNumber=SPE-005147-B&societyCode=SPE.
Stein, N., Kelly, J., Baldwin, W.F. et al. 1972. Sand Production Determined from Noise Measurements. J Pet Technol 24 (7): 803-806. SPE-3498-PA. http://dx.doi.org/10.2118/3498-PA.
Akers, T.J. et al. 1985. Radioactive Tracer Logging in Laminar Flow. Paper presented at the 1985 CWLS Formation Evaluation Symposium, Calgary, 29 September–2 October.
Anthony, J.L. and Hill, A.D. 1986. An Extended Analysis Method for Two-Pulse Tracer Logging. SPE Prod Eng 1 (2): 117-124. SPE-13396-PA. http://dx.doi.org/10.2118/13396-PA.
Bearden, W.G., Cocanower, R.D., Currans, D. et al. 1970. Interpretation of Injectivity Profiles in Irregular Boreholes. J Pet Technol 22 (9): 1089-1097. SPE-2685-PA. http://dx.doi.org/10.2118/2685-PA.
Gadeken, L.L. 1991. The Interpretation of Radioactive-Tracer Logs Using Gamma-Ray Spectroscopy Measurements. The Log Analyst (January–February): 24.
Hill, A.D. and Solares, J.R. 1985. Improved Analysis Methods for Radioactive Tracer Injection Logging. J Pet Technol 37 (3): 511-520. SPE-12140-PA. http://dx.doi.org/10.2118/12140-PA.
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Kelldorf, W.F.N. 1970. Radioactive Tracer Surveying--A Comprehensive Report. J Pet Technol 22 (6): 661-669. SPE--2413-PA. http://dx.doi.org/10.2118/2413-PA.
Killian, H.W. 1966. Fluid Migration Behind Casing Revealed by Gamma Ray Logs. The Log Analyst (January–March): 46.
Lichtenberger, G.J. 1981. A Primer on Radioactive Tracer Injection Profiling. Southwestern Petroleum Short Course, Lubbock, Texas, 251–263.
Roesner, R.E. et al. 1983. New Logging Instruments for Polymer and Water Injection Wells. Paper presented at the 1983 SPWLA Annual Well Logging Symposium, Calgary, 27–30 June.
Self, C. and Dillingham, M. 1967. A New Fluid Flow Analysis Technique for Determining Bore Hole Conditions. Presented at the SPE Mechanical Engineering Aspects of Drilling and Production Symposium, Fort Worth, Texas, 5-7 March. SPE-1752-MS. http://dx.doi.org/10.2118/1752-MS.
Simpson, G.A. and Gadeken, L.L. 1993. Interpretation of Directional Gamma Ray Logging Data for Hydraulic Fracture Orientation. Presented at the Low Permeability Reservoirs Symposium, Denver, Colorado, 26-28 April 1993. SPE-25851-MS. http://dx.doi.org/10.2118/25851-MS.
Small, G.P. 1986. Steam-injection Profile Control Using Limited-Entry Perforations. SPE Prod Eng 1 (5): 388-394. SPE-13607-PA. http://dx.doi.org/10.2118/13607-PA.
Wiley, R. and Cocanower, R.D. 1975. A Quantitative Technique for Determining Injectivity Profiles Using Radioactive Tracers. Presented at the Fall Meeting of the Society of Petroleum Engineers of AIME, Dallas, Texas, 28 September-1 October 1975. SPE-5513-MS. http://dx.doi.org/10.2118/5513-MS.
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Hill, F.L. et al. 1989. New Instrumentation and Interpretive Methods for Identifying Shielded Water Flow Using Pulsed Neutron Technology. Paper presented at the 1989 CWLS Formation Evaluation Symposium, Calgary, September.
Ierubino, J.V. and Ginest, N.H. 1989. Use of Pulsed Neutron Logging Techniques To Prove Protection of Underground Sources of Drinking Water. Presented at the SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 8-11 October 1989. SPE-19616-MS. http://dx.doi.org/10.2118/19616-MS.
Lamb, G. et al. 1983. Measurement of Water Flow in Deviated Production Wells by Oxygen Activation Logging. Paper presented at the 1983 SPWLA Annual Well Logging Symposium, Calgary, 27–30 June.
Scott, H.D., Pearson, C.M., Renke, S.M. et al. 1993. Applications of Oxygen Activation for Injection and Production Profiling in the Kuparuk River Field. SPE Form Eval 8 (2): 103-111. SPE-22130-PA. http://dx.doi.org/10.2118/22130-PA.
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Maher, T. and Trcka, D. 1999. Inflow Fluid Typing in Screened Horizontal Completions Using aPulsed Neutron Holdup Imager. Presented at the SPE Annual Technical Conference and Exhibition, Houston, Texas, 3-6 October 1999. SPE-56646-MS. http://dx.doi.org/10.2118/56646-MS.
Nice, S.B. 1992. Production Logging in Horizontal Wellbores. Paper presented at the 1992 World Oil Horizontal Well Conference, Houston, 9–11 November.
Roscoe, B.A. 1996. Three-Phase Holdup Determination in Horizontal Wells Using a Pulsed-Neutron Source. Presented at the International Conference on Horizontal Well Technology, Calgary, Alberta, Canada, 18-20 November 1996. SPE-37147-MS. http://dx.doi.org/10.2118/37147-MS.
SI Metric Conversion Factors
|bbl||×||1.589 873||E − 01||=||m3|
|ft||×||3.048*||E − 01||=||m|
|°F||(°F − 32)/1.8||=||°C|
|psi||×||6.894 757||E + 00||=||kPa|
Conversion factor is exact.
Appendix-Production-Logging Application Tables: Tool Selection, Operating Procedures, and Interpretation Aids
Introduction. This section of the chapter provides an extensive set of tables intended to aid in the practical application of production-logging technology. For a given problem, the reader is guided first in the selection of the set of logging tools most appropriate. Next, suggestions are given on the proper procedure for each tool’s use. This is an important part of the guidance, because the way logging records are obtained is often the most important part of the operation. Finally, the user is provided with comments regarding what the records should show relative to the problem. Recognition of expected results is equally important because irrelevant features on a log can easily prevent its proper interpretation. The tables are independent of the preceding body of the text and presume that the user lacks detailed knowledge of the subject.
The tables are unique to the literature in their ability to provide the user with detailed guidance without the investment of extensive search time. This feature is a consequence of the indexing approach to the information in the tables. The first level in the classification system is the nature of the well and the type of completion in which the tools are to be run. This environmental factor is called the Well Category. The tools that are best for one type of completion may be completely inappropriate for another type. For a given Well Category, the second level is the type of problem of interest to the user. This level is called Problem Type. Its identification leads to the final or third level in the classification—namely, to a table of tools appropriate to the specific well category and problem type. This final table provides the information listed above. Such an approach leads to much duplication of material, but is the one most beneficial to the user. Available publications attempt the classification on the basis of problem type alone, but this approach leads to so many disclaimers "for this situation and for that situation" that the result is confusion rather than guidance.To make use of the application tables, one therefore enters the compilation sequentially through two indexing tables, identified as Table 4.A1: Well Category and Table 4.A2: Problem Type. Having selected a category number from Table 4.A1 (Level 1), the user than locates this number in Table 4.A2 (Level 2), where a listing of general problem types is associated with each category number. Each problem type is identified by its index number, made up of a category number followed by a capital letter. For example, the designation 1A identifies a well still being drilled (well category) but experiencing problems of pipe sticking (pipe manipulation) or cross-sectional constriction (problem type). Having selected an index number from Table 4.A2, the reader next locates the third-level table having this number/letter designation. This final table subdivides the general problem into more specific problems (where appropriate) and provides a listing of recommended logging tools along with suggestions concerning their proper use and comments on what one should expect to see in the records from each tool. The tools are listed in the order of their likelihood to resolve the reasons for a particular problem; consequently, tool exclusion for a particular job should start at the bottom of the list and work upward.
The well category, Table 4.A1, cannot include all possible combinations of tubing placement relative to casing. The user may therefore not find a single category that describes completely an unusual completion. Instead, the completion may have at certain locations features common to one particular listing, whereas, at other locations, the features may coincide with a different listing. In such a case, the user will need to digest the contents of several tool-selection tables to devise a tool string appropriate to the completion.
A general comment is in order relative to tool selection. Slickline or downhole-memory logging tools have evolved to the point that multiple traces can be recorded on a single pass. This gives the ability to record traces from depth-control sensors, such as a collar locator and a gamma-ray tool, simultaneously with traces from production-logging sensors. The previously limited quality in depth control has therefore been eliminated. Furthermore, sample rates can be set sufficiently high (up to 5 samples per second) so that the tools produce traces with a quality equal to that from electric-line surveys. In fact, the newer sensors on slickline strings often provide better traces. A corresponding improvement in surface interrogation and processing hardware now makes it possible to prepare a log from a slickline string within a few hours after tool retrieval. Memory tools now have practically all the advantages of electric-line tools with the added potential for safer and less-expensive operation.
Despite the extensive nature of the tables, their primary function is to provide realistic information on the selection of logging tools for a particular environment and a specific problem. The tables cannot make the user proficient in the very important task of interpretation. Moreover, computer software cannot do this either; intervention by an expert analyst is still required to ensure correct interpretation. The user should not hesitate to seek such intervention, preferably from experts other than employees of the logging company involved.
Classification Tables. The two classification Tables 4.A1 and 4.A2 are provided here. These tables are used sequentially to navigate the extensive set of tables devoted to tool selection. Table 4.A1 is used to select a category number best describing the type of well to be logged. This numeral is then entered in Table 4.A2 and associated with the capital letter best describing the type of problem to be resolved. The resulting Index Number identifies one of the Tool-Selection Tables . This final table provides the user with the information necessary to plan and conduct the logging operation.Tool-Selection Tables. These guidance tables list recommended logging tools in order of general effectiveness, giving comments regarding procedures for tool use and indicating the normal features that should appear on the log traces. Each table is identified by an index code made up of a number and a capital letter, such as 2C. A specific index code is obtained through the use of Tables 4.A1 and 4.A2. Each tool-selection table deals with a particular problem area for a particular well configuration.