Cased Hole Logging

Cased Hole Logging OverviewLogging Operations

We may divide cased-hole logging operations into two groups: those in which the tools are run through tubing and those in which they are run in casing. Through-tubing tools include those designed to evaluate flow conditions downhole, along with certain nuclear tools. Most other tools are larger in diameter and are used before placing tubing into the well (such as for cement-bond surveys), or after pulling the existing string.

Figure   1 illustrates a typical setup for through-tubing operations, as might be used for flow evaluation surveys such as flowmeters in producing wells. The following items are numbered to correspond to the figure.

Figure 1

1. Logging truck

2. Mast truck—The mast hydraulically folds up and down for easy transport to and from location. The mast may be part of the logging truck, especially when logging pumping wells.

3. Wellhead with valves on top

4. Lubricator, or riser pipe—The logging tool is placed in the lubricator; the pressure in the lubricator is equalized to that of the wellhead pressure, the wellhead valves are opened, and the logging tool is lowered into the well. At the completion of logging, the tool is raised into the lubricator; the wellhead valves are closed, and pressure is bled down before the tool is removed. Note that a number of riser pipe sections may be connected to accommodate longer tool strings.

5. Cable—This is usually a single-conductor armored cable (monocable). This cable is wound onto the winch of the logging truck for storage.

6. Pressure bleed-off hose to relieve pressure from the lubricator after the job

7. Grease line to maintain the grease seal

8. Grease pump and reservoir for the grease seal

9. Grease seal—Grease is injected into the small annulus between the cable and the seal tubes to effect a pressure seal around the cable.

10. Instrument truck—This unit may or may not be required, depending on the instruments run.

11. Prssure bleed-off hose—This is where pressure is released from the lubricator.

12. Upper and lower sheave wheels—Note the lower sheave wheel chained to the wellhead.

13. Flare line—Gas may be flared, or produced into the flowlines. Liquids may be produced into stock tanks or flowlines.

On through-tubing surveys, it is sometimes preferable (subject to safety considerations) to run the logging tool down through the tubing with the well flowing. This ensures that the interval being evaluated is stable in terms of production and fluid saturation.

Certain small-diameter logging tools may be run in rod-pumped wells. This requires a special wellhead that has an access for a wireline tool to be run in the tubing/casing annulus. The tubing anchor must be removed so that the tool can easily fit into the completed interval. The pump should be placed 50 to 100 ft (15.2 to 30.5 m) above the top producing interval, and the well should be stabilized prior to logging.

Depth control in a cased hole is achieved by running a gamma ray and collar locator, typically at the time of perforating. The cased-hole gamma ray log, which responds to formations’ natural radioactivities is similar to an openhole gamma ray log.

Correlation of these two logs enables easy location of the collars with respect to down-hole zones. A short joint of pipe at or near the zone of interest is very helpful in accurate depth control.

Figure   2 shows a typical gamma ray and collar locator survey.

Figure 2

Note that the collars are shifted up to compensate for the distance between the collar locator and gamma ray sensors on the tool string.

The Logging Environment

A typical cased-hole logging environment is illustrated in Figure   1 .

Figure 1

Zones A, B, C and D are porous, permeable zones containing fluid; these are separated by impermeable shales. Casing is cemented into the borehole across the entire interval; each zone should be hydraulically isolated. Zones A, B, and D have been perforated to establish communication with the formations. (When a number of zones are perforated in the same wellbore, as shown in the figure, the zones are said to be commingled.)

The completion results shown in this figure indicate some problems with this well. Zone A is producing, whereas zone B is not. Zone B is "stealing" fluid production which would otherwise be produced to the surface, and thus is said to be a thief zone. From the inside of the wellbore, it would appear that zone D is producing properly, although examination of the figure indicates that this is not the case. A defect in the cement job has allowed communication between zones C and D, and the result is a "channel" in the cement through which zone C is produced. From the schematic, it is not clear whether zone C is just producing or is also flooding zone D. These problems—the sources and losses of production, the presence of channels, and the possibility of zone C flooding zone D—are the types of issues addressed by cased-hole logging techniques.

Cased-hole operations present special problems not seen in openhole logging, especially especiallly with respect to formation evaluation. Again, it is clear from

Figure   1 that the logging tool is not adjacent to the formation, but instead is inside the pipe which, in turn, is separated from the formation by cement or by a channel. The channel may be filled with mud, water, oil, or gas, and cement of unknown thickness may be present. Certain tools are serious1y affected by wellbore fluids. The region below the lowest perforations (the rathole) may be filled with water, while the wellbore immediately above the perforations across zone D is filled with oil. Apparent gas entry from zone D has caused the wellbore fluid above this zone to become gas-cut. There are clearly many variables in the wellbore environment that affect the response of cased-hole logging tools.

One way to classify cased-hole logs is by their Primary area of investigation. Moving from the center of the wellbore in Figure   1 , four regions are encountered: the inside of the well-bore, the casing wall, the annulus between the casing and the formation, and the formation itself (labeled by Roman numerals I, II, III, and IV, respectively). A cased-hole logging tool is generally designed to investigate one of these four regions. Flow evaluation devices measure fluid movement inside the well-bore; casing inspection surveys examine the pipe itself; cement-bond logs scan for cement annular fill; and formation evaluation sensors measure the shaliness, porosity, water saturation, and other formation properties. Each sensor, while having a primary region of investigation, may be secondarily or adversely affected by the other regions.

Formation Evaluation in Cased HolesCASED HOLE RESISTIVITY TOOL

The capability to record formation resistivity in cased holes has been long sought -nearly since the first openhole resistivity log was run in 1927. However, it was not until nearly 2001 that advances in electronics and contact design made such resistivity measurements possible. By mid-2001, Schlumberger was able to offer a handful of commercial models of their Cased Hole Formation Resistivity tool, while Baker Atlas had a cased hole resistivity tool in the development stages.

Applications Cased hole resistivity tools provide deep-reading resistivity measurements through steel casing. These tools have a much greater depth of investigation than that of nuclear logging tools previously used for through-casing evaluation. Such resistivity measurements can be used for:

detecting and evaluating bypassed hydrocarbons,

monitoring the reservoir to track fluid movement,

making accurate saturation calculations in formations with deep invasion,

optimizing sweep efficiency for improved production, making better decisions for placement of sidetrack wells, and

contingency logging

Furthermore, cased hole resistivity and nuclear measurements can be combined to provide saturation estimates similar to openhole evaluations.

Tool Operation

The Schlumberger tool uses four levels of three voltage electrodes. The electrodes on each level are spaced 120 degrees apart, as shown in Figure   1    Schlumberger’s CHFR tool.

This 12-electrode configuration allows faster operations while providing redundant measurements. Because good tool-casing contact is essential to the CHFR measurement, each electrode on the sonde is designed to push through small amounts of casing scale and corrosion for better contact. The electrode-casing contact is measured at each station as a quality control check.

After establishing good contact with the casing, the tool will transmit an electrical current. Most of the current will remain in the casing, where it flows both upward and downward before returning to the surface. However, a very small portion of the current will escape into the formation, and the casing will tend to act as a focusing electrode to force the current deep into the formation.

Typical formations have resistivity values that are about 1 billion times that of steel casing. While logging, the currents that escape to the formation cause a voltage drop in the casing segment. Electrodes on the tool measure the difference in electrical potential that is created by this leaked current. Since casing has a resistance of a few tens of micro-ohms, and the leaked current is typically on the order of several milliamperes, the difference in potential that is detected by the CHFR tool is measured in nanovolts.

The difference in potential is proportional to the conductivity of the formation.

Tool Limitations

The noise created by tool movement is about 10,000 times greater than the measured signal, so the tool has to make stationary measurements. With a 4-foot vertical resolution, the 2-minute station time (which includes a downhole calibration) translates into a logging speed of 120 feet per hour. At this logging rate, the tool is most often used to measure specific zones of interest, rather than measuring the entire length of the cased wellbore.

Formations with resistivities from 1 to 100 ohm-m can be measured with +     10% accuracy, and longer station times improve the accuracy and extend the range of measurable resistivities. Low-resistivity cements typically found in oil wells do not degrade the CHFR measurement, but measurements made through cements with unusually high resistivities call for environmental corrections.

Case Study

In this Middle East field study, a Schlumberger Cased Hole Formation Resistivity tool was run immediately after the well was cased. This log established a baseline resistivity measurement to study fluid movement across the reservoir. The tool was later run after three months, and then again at five months after casing was set. Data from each log run showed good correlation with deep laterolog resistivity openhole data, which had been obtained before the hole was cased. See Figure   2     CHFR log correlated and openhole laterolog (log reprinted from SPWLA, 41st Annual Logging Symposium Transactions: Beguin, D.

Benimeli, A. Boyd, I. Dubourg, A. Ferreira, A. McDougall, G. Rouault and vander Wal, 2000, Recent progress on formation resistivity measurement through casing. Paper CC, 1-14). This log clearly shows a change in formation resistivity with each successive log run. The log helped to show that a high-permeability zone in this well was affected by a nearby injection well, where injected water was pushing an oil front past the wellbore.

Pulsed Neutron Capture Logging

The pulsed neutron capture tool is used to determine water saturation in formations having high water salinity. The range of applicability for determining water saturation is generally a minimum of about 15% porosity, with a formation water equivalent sodium chloride salinity of at least 50,000 ppm. New tools and repeat runs can reduce the statistical error inherent in a nuclear tool, correspondingly reducing these limits. For purposes of comparison with earlier logging to detect changes in saturation, these limits may be reduced even further, since such comparisons are not intensely quantitative. Be sure to consult with the wire-line service company prior to running any pulsed neutron capture logs if conditions are at or below these limits.

Some of the more recently developed tools (e.g., Schlumberger’s Reservoir Saturation Tool, or RST) can be run through tubing. Schlumberger’s RST also has carbon-oxygen (C/O) measurement capabilities, and so can be used in environments of low or unknown water salinity.

Pulsed Neutron Capture Hardware

Pulsed neutron capture logging tools are typically small-diameter through-tubing tools, 1 11/16 in. (4.29 cm) diameter or less. These tools include an electronically activated neutron generator, which periodically emits bursts of 14 MEV neutrons, at rates ranging from 800 µs to 5000 µs between bursts. The burst rate varies with the service company and tool model. All modern tools have a near (short-spaced) and a far (long-spaced) detector that count gamma rays associated with neutron interactions with the formation. Figure 1 shows a schematic of this tool.

Figure 1

The detectors are typically sodium iodide crystal scintillation detectors and do not discriminate with regard to gamma ray energies. As a result, the tools also measure a background count rate to distinguish natural from induced gamma rays.

At present, the main industry versions of the pulsed neutron capture log are the following:

Schlumberger Wireline & Testing: thermal decay time log (TDT-K, TDT-M, TDT-P); as noted above, Schlumberger has incorporated pulsed neutron capture and carbon-oxygen measurements into the reservoir saturation tool (RST).

Halliburton Energy Services: thermal multigate decay time tool (TMD-L).

Western Atlas: reservoir monitoring system (RMS).

Other types of pulsed-neutron capture tools are available, and may be obtained from smaller independent service companies.

Capture Cross Section

When the pulsed neutron capture tool emits a burst of high-energy neutrons, these neutrons move into the wellbore and formation, quickly (within tens of microseconds) losing most of their energy and moving about at their thermal energy. They are then captured by the molecules and atoms present in the formation. Each time a neutron is captured, a gamma ray is released and is detected by the tool. Monitoring these gamma ray emissions provides a means of determining the rate at which the neutron cloud is captured by the formation.

As it turns out, each of the molecules and atoms in the formation has a different propensity to capture these thermal neutrons and emit a gamma ray. The measure of their ability to capture these neutrons is called the capture cross section, and is symbolized by (sigma). The higher the capture cross section, the greater the tendency for the atom or molecule to capture the neutrons. Hence, a formation having a high bulk capture cross section is likely to cause the neutron cloud to disappear more rapidly than a formation having a low capture cross section.

Capture Cross Section Values  Water (200 oF)*Fresh (0ppm) 22.2 c.u. 150,000ppm 77.0 c.u.50,000ppm 38.0 c.u. 200,000ppm 98.0 c.u.100,000ppm 58.0 c.u. 250,000ppm 120.0 c.u.

HydrocarbonsCrude Oil (Stock tank)  22.2 c.u. Reservoir Oil  ~21.0 c.u. Gas at reservoir conditions <10.0 c.u.

Formation-Matrix**Sandstone 7-13 c.u.Dolomite 7-12 c.u. Limestone 7-14 c.u.Anhydrite 18-21 c.u. Shale 30-50 c.u.

Some ElementsChlorine 570 c.u. Calcium 6.6 c.u.Hydrogen 200 c.u. Aluminum 5.4 c.u.Nitrogen 83 c.u. Phosphorous 3.9 c.u.Potassium 32 c.u. Silicon 3.4 c.u.Iron  28 c.u. Magnesium 1.7 c.u.Sodium 14 c.u. Carbon 0.16 c.u.Sulfur 9.8 c.u. Oxygen 0.01 c.u.

Rare ElementsBoron 45000 c.u. Mercury 1100 c.u.Cadmium 18000 c.u. Manganese 150 c.u.Lithium 6200 c.u. 

  * Salinity reported as equivalent ppm NaCl.

** Approximate range of reported values. Actual value is dependent upon impurities and trace elements in formation.

The table above lists capture cross section values for a number of materials commonly found in formations. Fresh water, for example, has a capture cross section of about 22.2 capture units (c.u.). Stock tank oil also has a capture cross section of about 22.2. The fact that water and oil have the same capture cross section creates a dilemma, because the pulsed neutron capture technique is capable of distinguishing water from oil and computing the water saturation. However, the table shows that chlorine has a sigma value of 570 c.u. and hydrogen has a value of 200 c.u. Compare this with the carbon and oxygen values, which are very small. This indicates that the tool is primarily responding to the hydrogen content of the water and oil. Chlorine is commonly found as a salt (NaCl) in solution with downhole waters, and therefore salt waters can be easily distinguished from oil or gas (gas has a capture cross section generally less than about 10 c.u., depending on the gas gravity, pressure, and temperature). Values for the capture cross section of salt water are also presented. The minimum salinity for quantitative computations, as a general rule, is about 50,000 ppm sodium chloride salinity, which corresponds to about 38.0 c.u.

The capture cross sections of formation matrix materials may vary somewhat, but are generally around 10 c.u., with limestone slightly higher than sandstone. This value of ten is typical of the matrix value indicated by most tools, although the actual value may be somewhat smaller. Even when present in trace amounts, the rare elements may increase the apparent salinity of the water.

When the neutron generator emits a burst of neutrons, the cloud of neutrons is captured by the formation, and the neutron population decays exponentially according to the equation (decay of thermal neutrons at a point in the formation)

where: N = thermal neutron density

No= initial thermal neutron density at time to

t = time since to

= formation thermal decay time—this is the time it takes for a 63.2% drop in the neutron density, and is a characteristic of the formation

If the gamma ray count rate is plotted against time after the neutron burst on a semilog graph paper, the result is as shown in Figure 2 .

Figure 2

Immediately after the burst, the count rate is quite high as a result of the large number of neutrons in or near the casing, and (if the casing is filled with salt water) the relatively fast decay of the neutrons therein. After a short time, the wellbore signal dies away and the remaining counts come essentially from the formation. This portion plots linearly on the semilog graph paper. If the pore space is filled with a high-capture cross-section fluid, such as high-salinity water, the formation signal dies away rapidly. If the pore space is filled with oil or gas, the formation signal dies away more slowly. The measure of the decay rate is the thermal decay time,  , which corresponds to about a 63% loss of neutron population.

Pulsed neutron capture tools measure the thermal decay time by setting appropriate electronic gates to measure the gamma rays that reach the detectors during the formation part of the decay period. Initially, this was done with a linear fit to the formation portion of the decay on the semilog plot. Modern tools are designed to compensate for the background and wellbore effects that may still be present in the formation portion of the decay. The determination of the capture cross section of the formation, LOG is done automatically, using the equation LOG = 4550/ (µsec). This value of LOG is presented on the log and scaled in capture units.

Evaluation of Water Saturation, Sw

The simplest model of the formation for purposes of pulsed neutron capture logging is shown in Figure 3 .

Figure 3

This formation is composed of four constituents: the formation matrix with capture cross section MA, the shale with capture cross section SH, and the pore volume, which is filled with water and hydrocarbons. This porosity is called the effective porosity, e. Water has a capture cross section W, dependent upon its salinity. Hydrocarbons have a capture cross section H — about 21 c.u. for liquid hydrocarbons. More accurate H values may be found in the chart books available from the service companies.

The bulk capture cross section of the formation is linearly related to the contributions of each constituent, according to the following equation:

Matrix                         Hydrocarbon         Water             Shale(1)

where:

(1-VSH-e) = matrix rock volume e(1-SW) = hydrocarbon volume

= water volume VSH = shale volume

The above volumes are fractional, and equal one when added together.

To illustrate the use of the above equation and to appreciate the tool's response, consider the above equation simplified for a shale-free zone, VSH = 0. The equation reduces to

(2)Using the above equation, compare the response of a water zone and an oil zone where e = 0.30, MA = 10 c.u., H = 21 c.u., and W = 60 c.u. (about 105,000 ppm NaCl). For the water zone, SW = 1.0 and

        Matrix         Hydrocarbon         WaterConsidering an oil zone with SW = 0.25, the above equation yields an oil zone formation cross section (as seen by the logging tool) of 16.2 c.u. With a range of 8.8 c.u. between the oil and the water responses, it is apparent that distinguishing water from oil is easy under these conditions. If the tool response repeatability is ±0.5 c.u., quantitative determinations of water saturation will be accurate and useful.

If similar computations are made with marginal values of porosity and salinity, the response range is reduced quite significantly. Consider = 0.15, SW = 0.25 for the oil zone, and W = 38 c.u. (50,000 ppm NaCl in water); the water zone response is 14.2 c.u. and the hydrocarbon (oil) zone is 12.3 c.u. With this degree (or less) of contrast between a water zone and a liquid hydrocarbon zone, the saturation measurement is no longer a reliable quantitative measurement, although it still may have qualitative value.

Equation 2.1 may be rearranged and, if the parameters MA, H,W, SH, VSH, and e are known, may be used to determine the water saturation.

(3)

For clean, shale-free formations, the above equation simplifies to the form

(4)For example, if the log reads 15.8 c.u. in a clean interval having a porosity of 24%, where is MA 11 c.u., the water salinity is 100,000 ppm NaCl, and the hydrocarbon present (if any) is liquid, then

and the zone is an oil-bearing zone.

The foregoing equations, or equations similar to them, are used for wellsite computations. If the fluid and formation parameters are not known, then crossplot techniques and/or sampling techniques must be used to define the values of the various capture cross sections involved. Porosity is usually known, although it can be

computed using pulsed neutron capture log information. Shale volume is often determined from the gamma ray log.

Log Presentation

A typical pulsed neutron capture log presentation (in this case a Schlumberger TDT-K) is shown in Figure   1 .

Figure 1

On the left track is shown a spontaneous potential (SP) log, which is an openhole log traced onto the TDT-K log. The SP is not run in cased hole. The usual log in the left track is the gamma ray, which commonly serves the same purpose as the SP. In this case, the left-most response of the SP indicates a clean zone. The F3 curve is the background count rate measurement and is taken at the far detector after the formation signal has died away.

The main measurements of the pulsed neutron capture log are shown to the right of the depth track. The primary measurement, LOG is indicated as the neutron capture cross section and is scaled from 0 to 60 c.u. The ratio curve is the ratio of the count rates of the near to the far detector. This ratio is sometimes background-corrected. In general, the ratio is the primary porosity indicator, and may be viewed as an

uncalibrated porosity curve with porosity increasing with ratio. This curve closely resembles the CNL porosity response and shows a similar decline in porosity in the presence of tight or gas-filled formations. While the sigma curve is shown over two tracks, the ratio curve is confined to the center track. The right track shows the overlay of the near (N1) and far (F1) count rates. When these count rates are overlaid in a water-bearing zone, the F1 curve moves to the left of the N1 curve in a gas-bearing zone. The degree to which this effect occurs depends upon the logging tool used. The TDT-K shows one of the stronger gas effects among the pulsed neutron capture tools.

In this figure, the oil-water and gas-oil contacts are clearly indicated. Note that the sigma response of the formation shows the largest response in the water zone, a somewhat lesser response in the oil zone, and the least response in the gas zone. The ratio, the main porosity indicator, shows a relatively uniform porosity across the water and oil zones, and a sudden drop in porosity in the gas zone. This effect is common in neutron logs and indicates not a porosity change, but a decline in the formation's hydrogen content. The N1 to Fl overlay shows the gas, indicating separation from about 4495 ft (1370 m) up to about 4550 ft (1387 m).

While Figure   1 is a Schlumberger TDT-K, other service companies show essentially the same curves in the same tracks. The curves of one service company generally cannot be directly compared to those of another. The spacing between the tool detectors is likely to be different, as is the way the electronic measuring gates are arranged. Therefore, count rates, ratios, and even sigma may vary among service companies. If a pulsed neutron capture log is run for purposes of comparison with earlier logs, it is best to use the same tool model that was used initially. It is also desirable to record a number of passes and compute a weighted average sigma response to minimize variations inherent in the nuclear measurement.

This TDT-K example shows the basic measurements obtained from a pulsed neutron capture tool. Newer tools have become available, which incorporate spectral measurements to show elements present in formation lithology and which, as is the case for Schlumberger’s RST tool, include carbon-oxygen measurement capabilties for environments of lower or unknown salinity.

Applications of Pulsed Neutron Capture Logs

The applications of pulsed neutron capture logging may be conveniently categorized into four groups:

Evaluation of Water Saturation Through Casing—These measurements are used for initial evaluation when openhole data are not available, or to serve as a baseline for later comparison—to check for bypassed production in the producing interval, or to locate other zones for possible completion.

Time-Lapse Logging—This technique is used to monitor changes in saturation. Movements of gas-oil or water-oil contacts can be predictive of breakthrough or depletion. The log in Figure   1 ,

Figure 1

Figure   2 ,

Figure 2

Figure   3

Figure 3

and Figure   4 show an initial TDT-K run and a monitor run about two years later.

Figure 4

The third track on this log indicates Porosity and Fluids Analysis by Volume. The black coding indicates hydrocarbon and white indicates water, while their envelope defines the porosity. Comparison of the initial and later monitor runs indicates a movement of the hydrocarbon/water contact in both zones A and B. The shaded area corresponds to the moved hydrocarbons.

Residual Oil Saturation—One method for determining residual oil saturation (ROS) after a reservoir waters out is the log-inject-log technique. This basically involves injecting relatively fresh water of known salinity into the formation to be tested, thereby displaceing the native formation waters and all movable hydrocarbons, and then running a pulsed neutron capture log. This is followed by a second injection with high-salinity water, and a second log run. The residual oil saturation is then given by the equation

(1)

Residual oil saturation may also be determined from time-lapse logging techniques.

Secondary Measurements—Secondary measurements include the wellbore capture cross-section measurement and the inelastic count rate mentioned earlier, as well as lithology and spectral data, and the various quality-control curves offered by the service companies.

Oxygen-Activation—A schematic showing the oxygen-activation measurement is illustrated in Figure 5 .

Figure 5

The neutron generator emits a burst of neutrons which causes oxygen (present in water molecules) in the borehole to become activated. If the water is moving up past the tool, a population of activated water is formed. This activated water has a half-life of about seven seconds, and as the oxygen atoms return to their normal state, gamma rays are emitted. These gamma rays are counted by the detectors and are shown as an increase in the background counts. Oxygen activation has particular application in production logging, where it is used to identify water flow in wellbores or behind casing strings. Tools such as Western Atlas’ Hydrolog or Schlumberger’s Water Flow Log (WFL) are used for this purpose.

The log in Figure   6 shows a Halliburton TMD log.

Figure 6

The primary presentation is virtually identical to the Schlumberger TDT-K, although a wellbore sigma measurement is usually shown. The quality presentation is shown in part on the right and includes the long-spaced (LS) and short-spaced (SS) background count rates. The perforated intervals are indicated between the presentations. The increase in background above the lowest and middle set of perforations indicates water entry from those perforations.

Carbon/Oxygen Measurement Principles

Carbon/Oxygen (C/O) tools measure the gamma rays emitted by the nuclei of formation elements when they are bombarded by high-energy neutrons. Because elements produce characteristic gamma rays of specific energies, C/O measurements can be used to determine the types and amounts of elements present in the formation, and thus provide information regarding fluid type and saturation. Unlike pulsed neutron devices, C/O tools can be used in formations containing water of low or unknown salinity.

The interactions between emitted neutrons and formation nuclei are of three basic types (Adolph et al., 1994):

· Inelastic neutron scattering, where the neutron bounces off the nucleus and causes it to emit inelastic gamma rays. Measurement of the resulting gamma

ray spectra indicates the relative concentrations of carbon and oxygen in the formation. Inelastic neutron scattering is of primary interest in C/O logging, in that the measured relative concentrations of carbon and oxygen can be used to determine the presence of oil and gas. With all other variables equal, a high C/O ratio indicates an oil-bearing formation, while a low C/O ratio indicates a water- or gas-bearing zone.

· Elastic neutron scattering, where the neutron "bounces" off the nucleus without exciting or destabilizing it. The neutron loses energy (i.e., slows down) with each elastic interaction. Because its mass is equal to that of a neutron, a hydrogen nucleus is particularly effective at slowing down neutrons. Thus, the efficiency with which a formation slows down neutrons isa measure of how much hydrogen it contains. Because hydrogen is most abundant in pore fluids, a high degree of neutron slowdown indictes high porosity.

· Neutron absorption or neutron capture, where the neutron absorbs the nucleus and emits capture gamma rays. This commonly occurs after neutrons have been slowed down by elastic and inelastic scattering. Measurement of the capture gamma rays indicates the presence of such elements as silicon, calcium, chlorine, hydrogen, sulfur and iron. Neutron capture measurements are important because carbon and oxygen counts alone are not enough to determine water saturation. Figure   1 , which shows the C/O ratio as a function of porosity, illustrates this point; note that at about 30 percent porosity, a water zone in limestone looks like an oil zone in sandstone.

Figure 1

Since capture measurements can differentiate between calcium (Ca) and silicon (Si), it is possible to determine saturation as well as lithology.

Development of C/O Logging Techniques

C/O logging, first developed in the 1970s, has historically had limited application due to large tool diameters, slow logging speeds and sensitivity to wellbore fluid type. These limitations were largely overcome during the 1990s with the introduction of such tools as Schlumberger’s RST (Reservoir Saturation Tool). The RST combines C/O and TDT pulsed neutron measurement capabilities, and can be run through tubing. The RST-A tool, with a diameter of 1 11/16 inches, has a logging speed up to four times greater than that of the GST tool, while the RST-B tool, with a diameter of 2 1/2 inches, is capable of logging flowing wells.

The RST tool has three operating modes, which can be changed in real time while logging:

· In the inelastic-capture mode, the tool obtains C/O measurements and neutron capture gamma ray spectra to provide saturation, lithology, porosity and apparent water salinity information (logging speed 60 to 100 ft/hr).

· In the capture-sigma mode, the tool records capture gamma ray spectra and total capture gamma ray count rates in one logging pass (logging speed 600 ft/hr). This provides lithology, porosity and apparent water salinity information, and enables the analyst to determine the formation capture cross-section.

· In the sigma mode, the tool provides capture cross-section data in a fast logging pass (up to 1800 ft/hr). The sigma mode can be used when the formation water salinity is high enough for TDT logging.

This type of tool thus provides operators with the flexibility of recording pulsed neutron capture data, C/O data, or both on the same logging run.

Applications of the Carbon-Oxygen Measurement

The numerous elemental yields available from C/O logs are helpful in

· evaluating water saturation through casing independently of formation water salinity (usable in fresh or mixed salinity solutions)

· determining the bulk fluid salinity (and hence water salinity) when it is unknown

· lithology and shale identification; shale characterization is much more accurate when run with the natural gamma ray spectroscopy tool

· identifying minerals

Porosity Measurement

Through-casing porosity measurements are made with a neutron tool that carries an americium beryllium or similar neutron source downhole. Modern tools are configured with two detectors in much the same manner as the pulsed neutron capture tools. These dual detector tools are wellbore-compensated and are generally called compensated neutron logs or CNLs. CNLs are larger-diameter tools and are not available in through tubing sizes. A schematic of a CNL tool is shown in Figure   1 .

Figure 1

CNLs are typically run noncentralized, to ensure better sampling of the formation count rates by minimizing the wellbore influence.

The compensated neutron logging tool is available from most service companies. The calibration standard for this tool is the API test pit in Houston. Most service company tools are calibrated to conform to this standard. Service companies should be consulted about compensations for the wellbore environment so that the measurements properly agree with the API standard even when run in nonstandard conditions.

Fundamentals of the CNL Measurement

Figure   2 is a tool schematic showing the neutron source and detectors.

Figure 2

Unlike the pulsed neutron capture tools, the CNL measures the slowing-down length of the neutrons by counting the neutrons or gamma rays from neutron interactions at the detectors. The neutron flux at the detectors is a function of the number of hydrogen atoms in the formation. For fluid-filled pore space in a clean formation, the number of hydrogen atoms is directly proportional to the porosity. The main effect of the fluid is determined by the fluid's hydrogen index, which is a measure of the density of hydrogen atoms in the fluid. The hydrogen index is approximately the same for water and oil, while it is markedly reduced for hydrocarbon gases.

The ratio of the near and far detectors is calculated as part of the measurement, and the response of this ratio to formations of varying porosities is shown in Figure   2 . This response is nearly linear for limestone and sandstone formations over normal reservoir porosity ranges. As a result, the ratio is not presented on the log. Instead, porosity is presented directly on the log, typically on a limestone scale but occasionally on a sandstone scale. If the formation lithology is different from the scale used, corrections for lithology must be made. Corrections must also be made for the environmental effects of the borehole. Correctable environmental factors include the openhole diameter, casing thickness, cement thickness, wellbore fluid

weight, wellbore fluid salinity, formation water salinity, and wellbore temperature. Correction charts for these factors are available from the service companies.

Figure   3 shows a cased-hole CNL overlying an openhole porosity log.

Figure 3

Note that the presentation is porosity and that the log is recorded on the limestone scale. In this case, the cased-hole and openhole porosities compare quite well.

The response of the CNL is very similar to the pulsed neutron capture tool ratio curve. The presence of gas in the pore space causes the tool to indicate an erroneously low porosity due to the lack of hydrogen atoms. In shaly zones, hydrogen atoms (in the form of water molecules attached to the shale matrix) cause an erroneously high porosity reading. This uncorrected porosity is sometimes referred to as total porosity. The porosity that we typically use is called effective porosity, which is the pore space available for fluid storage.

Natural Gamma Ray Measurements

Devices such as the gamma ray and natural gamma ray spectrometry tools do not carry any nuclear material. Rather, they measure the occurrence of natural gamma rays downhole. The natural gamma ray spectrometry tool is run under the following service company trade names:

Schlumberger Wireline and Testing: natural gamma ray spectrometry tool (NGS or NGT)

Halliburton Energy Services: compensated spectral natural gamma tool (CSNG)

Western Atlas: spectralog

Natural gamma rays can be traced mainly to three elements in formations: Th232, U238, and K40. As these decay to other stable elements, each gives off gamma rays of ceratin characteristic energies. The gamma ray emission spectra for thorium, uranium, and potassium is shown in Figure 1 .

Figure 1

Natural gamma ray spectral tools measure the amounts of gamma radiation within energy ranges or windows to determine the relative contribution from each of the three elements. Conventional gamma ray tools simply count all gamma rays regardless of energy level.

The importance of conventional gamma ray logging arises from the fact that most radioactive materials tend to accumulate in shales. As a result, the gamma ray tool has long been a shale indicator. Under certain circumstances, however, it may incorrectly indicate shale. Thorium and potassium tend to accumulate in shales. Uranium tends to form salts and may be carried by water over great distances. As the water migrates, whether through a porous formation or along natural fractures, uranium salts are left behind and deposited within these formations or fractures. As a result, the conventional gamma ray log may give an erroneous shale indication where such salts are present.

Shale Volume Computations

If the gamma ray log is run in an area where the shale volume correlation to gamma ray response is known, then the shale volume may be calculated from the conventional gamma ray log. The shale volume curve of Figure 2 is typical in character.

Figure 2

The horizontal axis is a measure of relative gamma ray deflection between the clean (shale-free) reading, GRMIN, and the shale point, GRMAX, and is given by the equation

where GRLOG is the measurement at the depth of interest. Figure 2 shows how relative gamma ray deflection is used to compute the shale volume, VSH. The computation of VSH is carried out for two points on the gamma ray log.

In certain nonshaly formations containing large amounts of uranium salts (which may cause false shale indications), the spectral gamma ray may be employed by using a shale volume curve similar to that of Figure 2 which correlates to the K, Th, or K+Th logs. The relative deflection of the appropriate log is computed and the shale volume determined from the correlation curve. An example of a Western Atlas Spectralog in Figure 3 shows the individual K, U, and Th curves and the total counts as measured by the conventional gamma ray (the sum of the K, U, and Th counts) .

Figure 3

Sometimes the total counts minus the uranium counts are presented along with the total counts. Note that the total count curve appears to indicate a very shaly interval from about 5445 to 5513 ft (1660 to 1680 m). It is clear from the potassium and uranium curves on the log that this zone is not very shaly, and that the total count reading is primarily due to uranium counts.

Specialized Applications of the Natural Gamma Ray Spectral Tools

Some of the other applications of natural gamma ray spectral tools are as follows:

Natural Fracture Evaluation—Over geologic time, water containing radioactive uranium salts migrates through formations and deposits these salts along natural fractures. As a result, the uranium count rate on the log may show increased count rate spikes at the fractures.

Mineral and Clay Identification—Mineral and clay identification may be accomplished by monitoring the amounts of thorium, potassium, and the Th/K ratio. Charts are available from service companies and computations may be made in this regard. Better identification of clay and shales also leads to better tie-in and improved well-to-well correlations.

Water Movement—Water movement through perforations, channels, and even through formations may be detected by the salt it leaves. Deposition of uranium salts is easy to detect either by comparing a present-day gamma ray with a base gamma ray log, or by using a spectral gamma ray to detect the higher uranium counts associated with the water movement.

Multiple Tracer Monitoring—For most spectral gamma ray tools, output may be adjusted to focus on selected gamma ray energy levels. As a result, fluid or gravel pumped downhole may be tagged with selected radioactive elements and their location detected by use of the spectral gamma ray tool. This technique is widely used to distinguish gross fracture height (tagged fluid) and propped height (tagged proppant) in hydraulically fractured zones.

Exercise1

Gamma ray logs are useful in

a. depth control

b. shale evaluation

c. detection of flow in channels, when used with radioactive materials in injection wells

d. all of the above

2.The primary sources in earth formations of naturally occurring gamma radiation are uranium, potassium, and thorium. The following is/are generally associated with shales:

a. uranium

b. potassium

c. thorium

d. more than one of the above

3. Neutron logs are used primarily to

a. evaluate porosity

b. determine lithology, based on natural downhole radiation

c. compute shale volume

d. all of the above

4Pulsed neutron capture logs are used for

a. bulk-density evaluation of fluids

b. detection of hydrocarbon flow behind pipe

c. evaluation of water saturation in formations where water salinity is high

d. fuel in nuclear furnace

5. The following has the highest neutron capture cross section:

a. oil

b. sand

c. fresh water

d. salt water

6. If a well producing water and oil is shut in and a pulsed neutron capture log is run shortly thereafter,

a. the separation of phases will cause oil to migrate up through tubing and impede movement of the tool downhole

b. computed water saturations will be too high due to borehole water invading the producing zone

c. computed water saturations will be too low due to borehole water invading the producing zone

d. the formation capture cross section is masked by water in the borehole

7. The carbon-oxygen log

a. locates previously oxidized hydrocarbons by detecting such compounds as CO and CO2

b. is useful to evaluate formations where water salinity is low and other pulsed neutron logs are not effective

c. detects and measures the fraction of water and oil production in a borehole

d. is best used to hunt alligators

tests

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Self Assessment 1.

The pulsed neutron capture tool in cased holes is mainly used to determine:

  (A) Porosity

  (B) Permeability

  (C) Mud cake thickness

  (D) Water saturation

  (E) Formation resistivity

  2.

When the generator of a pulsed neutron capture tool emits a burst of neutrons, the cloud of neutrons is captured by the formation, and the neutron population decays:

  (A) Linearly

  (B) Exponentially

  3.

(TRUE or FALSE) In a typical pulsed neutron capture log presentation, the response of the tool is normalized with respect to the natural gamma ray reading and shown to the right of the depth track.

  (A) True

  (B) False

  4.

One the application of the pulsed neutron capture logging may be:

  (A) Casing wall evaluation

  (B) Sonic reflection

  (C) Oxygen activation

  5.

What is the main principle behind the Carbon/Oxygen measurement?

  (A) Elastic proton collisions

  (B) Inelastic electron scattering

  (C) Inelastic neutron scattering

  (D) Elastic neutron collisions

  6.

(TRUE or FALSE) Carbon/Oxygen logs are also useful in identifying minerals.

  (A) True

  (B) False

  7.

In order to conduct a through-casing porosity measurement a neutron tool needs to have a source of:

  (A) Americium beryllium

  (B) Neutrino

  (C) Wilson cloud

  (D) Potassium sulfate

  8.

What element emits gamma rays at one energy level?

  (A) K40

  (B) U238

  (C) Th232

 Submit Your Answers

Note: Your answers CANNOT be changed after they have been submitted. Check your answers thoroughly BEFORE you submit them.

 

Cement Bond Evaluation

Cement Bond Log (CBL)Cement-Bond Log (CBL)

The CBL is an acoustic device used to detect the presence of cement. The tool includes an omnidirectional acoustic transmitter and usually two receivers located 3 and 5 ft (0.91 and 1.52 m), respectively, from the transmitter. The tool emits an acoustic signal, which is detected by these receivers. Figure   1 shows a schematic of the CBL tool with possible acoustic paths from the transmitter to receiver.

Figure 1

Figure   1 shows that, excluding the path through the tool, there are four possible acoustic paths for the acoustic signal to get to the receiver. The tools are designed to suppress the signal traveling through the tool. Of the remaining four paths, the one through the casing is likely to be the fastest, since an acoustic signal is known to travel relatively quickly through steel pipe. Thus, if the casing signal is fastest, it is the first of the four to arrive at the receiver. The next signal to arrive at the receiver is the one passing through the formation. The other signals either arrive later or are greatly weakened by the time they get to the receiver. Figure   2 shows the makeup of

the received acoustic signal.

Figure 2

The acoustic signal is affected by cement contacting the pipe in that the cement, which is coupled to the pipe in shear, tends to dissipate the signal energy as the signal propagates down through the pipe. The greater the cement annular fill contacting the pipe, the weaker the signal at the receiver.

The effect of a good cement job on the received signal is to weaken the pipe portion of the signal while strengthening the formation portion. The formation signal is strong because there is no fluid gap for the signal to cross behind pipe, leaving a solid, unbroken acoustic path. Hence the signal passes freely through the casing to the formation and returns. When no cement is present, the condition is called free pipe and the pipe simply "rings" rather loudly as the pipe signal reverberates. Figure   3 illustrates the wavetrains associated with the various conditions of cement behind pipe.

Figure 3

It is important that this wavetrain response be well understood, since all other of the logs of the CBL are based on this wavetrain.

The amplitude curve is universally presented on CBLs. The amplitude is measured by setting an electronic window to evaluate the amplitude of the pipe portion of the received signal. Typically, the window or gate is set to measure the amplitude of the first arrival, although the gate may be set for second, third, or over the first few wave arrivals. Since the amplitude curve measures the amplitude of the pipe portion of the signal, a low amplitude indicates good annular fill of cement, while a high amplitude indicates poor annular fill. Figure   3 shows typical responses of the amplitude curve for various cemented conditions.

The variable-density log (VDL) is also derived directly from the wavetrain. Referring to Figure   2 , the VDL is made up of numerous closely spaced exposures of the film by the positive wavetrain amplitudes. The result is a contour map of the history of the wavetrain over the logged interval. Notice in Figure   2 that the pipe portion of the received acoustic signal appears as strong straight lines. If the tool is centralized, the acoustic path of the pipe signal does not change during the logging operation, and hence the signal always arrives at the same time and at the same frequency. The formation signal, on the other hand, comes in at all different times, since the cement thickness may vary and the acoustic properties of the formation change from one point to the next in a well. While the VDL theoretically is shaded for degrees of amplitude, it almost always appears as a black and white set of lines. Notice in Figure   3 that in a very good bond, the pipe portion of the VDL does not show up

because the amplitude of the wavetrain is too low to expose the film. The formation signal, however, comes in quite strongly. With poorer bonds, both the pipe and the formation signals may be present. The VDL response is summarized in Figure   3 .

Microannulus, Centralization, and Quality Control

If cement is allowed to cure at wellbore pressures greater than existed at the time the log is run, a microannulus is likely to form. The reduction in wellbore pressure from the time the cement cures to the time of the logging run causes the casing to shrink without a similar shrinking of the cement sheath; as a result, a tiny annulus around the casing is formed. Even with this tiny crack, effective hydraulic isolation may be maintained; however, the cement cannot maintain the shear coupling to the pipe that is required to attenuate the acoustic signal propagating through the Pipe. As a result, the recorded amplitude is high and indicative of poor bonding. However, if the pipe pressure is greater than the pressure maintained during curing, the microannulus may be closed and the shear coupling restored. Therefore, an appropriate pressure should be maintained during all CBL logging runs to eliminate the microannulus and achieve interpretable results. Approximately 90% of all cemented wells have a microannulus problem.

If the CBL tool is run without proper centralization, the received signal is reduced in amplitude. This happens because the signal energy reaches the receiver over a longer period of time when the tool is noncentralized. The effect of this lack of centralization on amplitude is shown in Figure   1 .

Figure 1

Note that an off-center shift of only 1/4 in. (0.635 cm) causes a 50% reduction of the received pipe amplitude. This effect may lead to an erroneous interpretation of adequate cement fill. This effect may be detected by the use of the travel-time curve supplied by most service companies.

The travel-time curve is the primary quality-control curve on a CBL. The travel time is measured from the initiation of the acoustic signal at the transmitter to the first signal at the receiver reaching a minimum threshold or bias. When the signal is reduced due to a good bond, the travel-time signal may stretch, since the threshold or bias is not reached until a somewhat later time. If the pipe signal is very low, the first arrival may not reach the threshold, but instead may stop the travel time clock at the second or later positive arrival. The first effect is known as travel-time stretch, and the second is known as travel-time cycle skipping. These effects are shown in Figure   2 and Figure   3 .

Figure 2

Neither of these effects causing an increase in travel time should be of much concern, since they are caused by better bonding.

Figure 3

Shortening the travel time, however, is cause for concern. If the tool is noncentralized, one side of the tool is closer to the pipe wall than the other, and as a result the acoustic signal travels to the receiver faster through the short path on the side close to the wall. With most wellbore fluids, a 4 s shortening of the travel-time curve corresponds to an off-center shift of about 1/8 in. (0.32 cm) and about a 30% reduction in the amplitude signal. Any greater degree of off-center shift is considered unacceptable by most companies.

Travel-time shortening may be caused by another factor. Even if the tool is centralized, certain limestone or dolomite formations have faster travel times for an acoustic signal than does steel pipe. The travel time in steel is 57 s/ft (187 s/m), while a dense limestone or dolomite may have travel times as low as 45 s/ft (147.6 s/m). As a result, the formation signal beats the pipe signal to the receiver, and a shorter travel time is recorded. This effect is often visible on the VDL or wavetrain display. Unlike the case of an off-center tool, the amplitude is usually increased and

the pipe signal amplitude is now unknown. Therefore, the bond cannot be measured in a fast formation.

Computing Annular Fill of Cement

The measure of annular fill is termed the bond index or percent annular fill. Bond index is defined as

If the bond index is 0.8 or better over an interval of pipe, a "reasonable assurance" of isolation is possible. Figure   1 shows the length of such 0.8 or better bond index required for isolation for a variety of pipe sizes.

Figure 1

The 0.8 bond index level corresponds to 80% annular fill of cement around the pipe.

The equation for the bond index is expressed in units of dB/ft, while most amplitude curves are presented in millivolts or percent free pipe (maximum) amplitude. Most

service companies have charts to convert from millivolts to dB/ft and vice versa. However, these are related logarithmically, and there is a much simpler method to determine the 0.8 bond index level ( Figure   2 ).

Figure 2

After looking at the log, select an interval that appears to have 100% bond and note the amplitude. Find the free pipe amplitude from either the log or service company information. Plot these points on a semilog piece of graph paper, as shown in Figure   2 . Determine the amplitude level corresponding to a 0.8 bond index and mark that value on the CBL amplitude curve. For intervals satisfying the required length of Figure   1 , isolation can be reasonably expected. Notice in this example that errors in the estimate of free pipe amplitude (points B and C) have little effect on the 0.8 bond index log response.

A typical CBL is shown in Figure   3 .

Figure 3

This log includes an amplitude curve and a VDL, as well as the travel-time curve. The log shows a clear transition from free pipe to a wellbonded section at the lower part of the logged interval. Note the presence of the collars on the amplitude and the VDL curves in the free pipe interval.

Strictly speaking, the bond index computation is not the percent annular fill. Bond index is, in fact, a function of cement annular fill, cement compressive strength, and casing size and weight. Under most conditions, casing size and weight do not change over the logged interval. If this is the case, an interpretation performed as suggested indicates annular fill only if the cement compressive strength does not change. By selecting the best observed bond, however, the point in the well with a bond index equaling 1.0 generally corresponds to the point with the best annular fill and highest compressive strength. Lower bond index indications may then result from reduced annular fill and/or reduced cement compressive strength.

Wellbore-Compensated Cement-Bond Log

Figure   1 illustrates the configuration of a wellbore-compensated tool.

Figure 1

The tool has certain advantages over the conventional CBLs in that it is less sensitive to centralization problems and, due to the two-transmitter and two-receiver configuration, is less sensitive to calibration problems. By measuring attenuation of the acoustic signal between the receivers in both directions and by taking appropriate ratios, variations in transmitter and receiver operation may be normalized out of the measurement. The presentation of this type of tool is an amplitude curve recorded directly in dB/ft, although amplitudes recorded in millivolts are also available if desired.

This type of tool is available from the following service companies:

· Schlumberger Wireline and Testing cement bond tool (CBT)

· Western Atlas Bond Attenuation Log (BAL)

· Halliburton Energy Services compensated Cement Attenuation Tool (CCAT)

Interpretation of the data produced by this tool is very straightforward, since the apparent percent annular fill or bond index is related directly to the dB/ft amplitude. Figure   2 shows an amplitude curve presented on a 1 to 20 dB/ft (0 to 65.6 db/m)

scale.

Figure 2

Free pipe corresponds to a low level of attenuation. In this example, the bond index is linearly interpolated between the free pipe and good bond signal levels.

The VDL receiver on the tool may be used for evaluation of fast formations. For an acoustic signal originating at the lower transmitter, the acoustic path through the pipe will always be faster than the formation signal, and the pipe signal will always arrive at the VDL receiver before the formation signal. This is useful since the degree of attenuation may be monitored over this short-spaced (about one-foot) interval and apparent cement fill or bond index may be evaluated over the fast-formation interval.

Pad-Type Cement-Bond Logs

Western Atlas has developed a pad-type acoustic logging device called the segmented bond tool, or SBT (Bigelow et al., 1990). As shown in Figure   1 , the tool is a pad-type device which investigates six sectors or segments of the casing along the acoustic paths shown in the upper right of the figure.

Figure 1

The measurement is similar to the CBL in that the tool is responsive to shear support from cement contacting the outside of the pipe. Each pad contains a transmitter and a receiver and the sector being investigated is that between the receivers. The presentation shows either the attenuation in each sector, or a cement density or fill display (lower right in the figure). The cement fill display is shaded black for good fill, unshaded for no fill, and has shades of gray for partial fill. This measurement is microannulus sensitive to the same extent as the conventional CBL.

Pulse-Echo Cement Evaluation

Pulse-echo CBLs, like other cement bond tools, are acoustic devices, although their mode of operation is quite different. The main tools of this type include the following:

· Schlumberger Wireline and Testing cement evaluation tool (CET)

· Halliburton Energy Services pulse echo tool (PET)

Figure   1 shows the configuration of this type of tool.

Figure 1

The tool is equipped with eight helically placed transducers, each examining an approximately 1-in. (2.54-cm) diameter area in each 45° sector of the wellbore. A ninth transducer is used to evaluate the velocity of the wellbore fluid. Each transducer emits an ultrasonic pulse and monitors the echo. On the basis of this echo, the pipe dimensions and the compressive strength of the medium behind the casing can be determined.

Figure   2 shows the signal and gate location for the Schlumberger CET.

Figure 2

Gate W1 is used to monitor the strength of the reflection. Weakening of this signal is due to either surface rugosity (roughness) or the oblique incidence of the signal to the pipe wall. The reflected series of signals (shown 10 size) are monitored by gates W2 and W3. These gates monitor the numerous reflections that occur within the pipe itself and are returned to the transducer. Gate W2 monitors the energy of the signal resulting from acoustic oscillations within the casing wall. Gate W3 measures only the first of these reflections. The strength of the W2 and W3 signals may be used to compute the compressive strength of cement behind pipe. If there is no cement behind pipe, the tool recognizes and distinguishes liquid or gas behind the pipe.

The computation of the cement compressive strength is based on the appropriately normalized responses of W2 or W3. These are each normalized to read 1.0 in intervals with water on the outside of the pipe. A chart such as that shown in Figure   3 ,

Figure 3

Figure   4 ,

Figure 4

and Figure   5 is used to compute the compressive strength as seen by each transducer.

Figure 5

The plot of W2 against W3 is called a "banana" plot, and such a plot, with a cluster of data points going through the point (1,1), should be attached to the tail of the log to ensure that these gated measurements were properly normalized. Such computations of compressive strength for each transducer are done by computer and all of the data is depth-shifted to the same depth automatically.

Figure   6 illustrates an example of the CET.

Figure 6

This log shows the geometric parameters of ovality of the casing, mean casing diameter, and tool eccentralization on the left-hand track, as well as wellbore deviation angle and tool relative bearing. The middle track shows the minimum and maximum compressive strength computed at each transducer at that depth, along with the average normalized response seen in gate W2, known as WWM. This WWM should read significantly less than one for cement behind the casing, about one for water behind the casing, and significantly greater than one for gas behind pipe.

In the right-hand track of the log of Figure   6 is the cement map, which shows the pipe "unwrapped" and the positions of cement contacting it on the outside. Where the shading is black, the cement has a compressive strength over some minimum value, usually taken at about 1000 psi (6895 kPa). For lesser compressive strengths, either a small area is not shaded or the shading is partial in character. Channels are readily apparent with this type of presentation. At the far right, beside the cement map, are eight lines. If these lines are thick, they are interpreted as reflections from the formation/cement inter-face. If they are thin, they indicate gas behind pipe. These are generally called formation or gas flags. These flags may or may not be present, and their absence does not indicate a problem with the cement job.

Circumferential Imaging Tools

Circumferential imaging tools (e.g., Halliburton’s Circumferential Acoustic Scanning Tool (CAST-VTM) and Schlumberger’s Ultrasonic Imager (USITM)) employ single rotating head transducers to transmit and receive high-frequency ultrasonic pulses in the wellbore. These pulses are recorded and processed to obtain 360o profiles of casing and cement images in real time.

Schlumberger’s USI tool, for example, directly measures the acoustical impedance of the medium behind the casing string. These measurements can be processed into high-resolution cement impedance images, which accurately indicate cement placement and zones of hydraulic isolation. This tool can also provide information on casing condition, in the form of detailed images showing internal radius, thickness and both internal and external metal loss.

Casing InspectionCorrosion Investigation

Corrosion logs include mechanical, electromagnetic, acoustic, and electropotential measurements. These are used to

monitor pipe wear caused by continued drilling operations detect corrosion on the inside or the outside of the pipe locate holes and pits detect split or parted pipe detect collapsed pipe locate perforations determine where electrochemical corrosion is likely to occur

The tools for these logs are generally sized to match the casing to be inspected, and hence are not through-tubing devices.

Mechanical Calipers

Mechanical calipers are of two basic types. The bow-spring type caliper ( Figure   1 ) is typically run with a flowmeter, and is used to monitor the inside of the pipe.

Figure 1

Its use is critical when restrictions such as asphalt, paraffin, or scale buildup are likely. It is also routinely used in openhole completions where a flow profile with a flowmeter is required.

The other is the multifinger type, with anywhere from 40 to 80 individual fingers. As these fingers scrape the pipe wall, their maximum deflection is monitored. A single measurement of the maximum deflection among all of the fingers is most common, although some tools are capable of providing a maximum and minimum indication, or of examining individual angular sectors of the wellbore—e.g., a minimum and a maximum for each 120o (one-third) of the casing wall. Figure   2 shows a schematic of this type of tool, along with a typical log response.

Figure 2

This example is a Dialog Company multi finger caliper recorded with a pen recorder, and hence the deflections are arced in character. The multi finger calipers offer good detail of the inside of the casing and are accurate for measurement of percent wall penetration.

Electromagnetic Casing Inspection

The electromagnetic tools fall into two categories: those that saturate the casing with magnetic flux lines and measure the distortion of those lines by a defect, and those that measure the amount of metal remaining by measuring the phase shift between two coils. Both types of tool inspect both the inside and the outside of the pipe.

The tools that measure the distortion of flux lines by defects in the pipe wall are pad-type devices. The most modern of these devices record each pad directly. The service companies and their trade names for this service are as follows:

· Schlumberger Wireline and Testing Pipe Analysis Log (PAL or PAT)

· Western Atlas Vertilog

· Halliburton Energy Services Pipe Inspection Tool (PIT)

These devices are hereafter referred to as pad-type casing inspection tools.

The schematic of Figure   1 shows the pad tool.

Figure 1

Inside the tool is a coil, which generates a magnetic field whose flux lines are parallel to the casing axis. Inside each pad is a coil which generates a current as it passes over a point where the flux lines are distorted into the wellbore. This occurs at a pit or hole in the pipe, even if the pit is located on the outside of the pipe. Surface roughness has the same effect, appearing as a lot of pits. The pads are also equipped to highlight defects appearing on the inner surface. With this information, defects on the inner or outer surface of the pipe can be detected.

An example of a Western Atlas Vertilog is shown in Figure   2 .

Figure 2

The test, which responds to defects on either the inner or outer surface of the pipe (or within the metal), is sometimes called the flux leakage test. These tools have an upper and lower array of pads to ensure complete wall coverage. The flux leakage for the upper and lower pad arrays are labeled FL-1 and FL-2 on the log. The track labeled "discriminator" shows the measurement of the internal wall condition only. It is apparent that the interval from 4793 to 4870 ft (1401 to 1484 m) shows general external corrosion, since the inner wall is clear of defects except for the intervals noted. The track labeled "average" shows the average of all of the FL-l and FL-2 responses as seen by the pads. If the defect is large, it is detected by many or most of the pads and therefore shows a large average. A single-point defect shows a small average reading.

The phase-shift devices operate as schematically shown in Figure   3 .

Figure 3

The transmitter coil carries an alternating current which causes a magnetic field to be formed around it. These field lines cross through the casing and induce a current in the receiver coil. The current in the receiver coil will be out of phase by an amount that is proportional to the amount of metal the field lines cut. This measurement does not distinguish small defects very well, and is best suited to assess overall corrosion on the pipe. As with other electromagnetic devices, this tool responds similarly to corrosion on inner and outer surfaces of the pipe. An internal electronic caliper is often included with this measurement to distinguish inner from outer surface damage.

The log of Figure   4 illustrates the response of Atlas Wire-line's Magnelog, a phase-shift device.

Figure 4

Note that the phase shift generally increases with increased-weight casing, and that a collar (or defect) shows up as two distinct peaks. The two peaks result from the field lines passing over the collar or defect twice as the tool passes, and therefore detecting two distinct signals. The caliper shows whether the defect exists on the inner or outer surface. This type of tool is not very sensitive to small-point defects, but is best suited to assess gross overall conditions of the pipe. Unlike the pad-type device, this tool is responsive to the outer of two concentric strings of pipe.

Newer generations of electromagnetic tools are capable of multifrequency operation, and contain multiple receiver coils for varying depth of investigation.

Casing Potential Surveys

Casing potential surveys detect electrochemical corrosion as it occurs; hence, these tools indicate where damage from corrosion is imminent. The schematic of Figure   1 illustrates a well casing in which certain parts of the casing act like anodes relative to other sections of pipe, which act like cathodes.

Figure 1

Those sections that appear as anodes are undergoing electrochemical corrosion and metal loss. Casing potential surveys locate these intervals and assist in developing cathodic protection operations to protect these wells.

A log showing the casing voltage or potential profile is shown in Figure   2 .

Figure 2

A positive slope indicates a cathode, and a negative slope indicates an anode (interval of metal loss) Run 1 indicates that the intervals from 1495 to 1650 ft (456 to 503 m) and from 1700 to 1850 ft (518 to 564 m) are anodes, and hence are corroding. In Run 2, cathodic protection is being used by putting a current to the wellhead of five amps. Two areas are still found to remain anodes by the casing potential survey. At eight amps, Run 3 shows that the whole casing string is now a cathode, and therefore such electrochemical corrosion is minimized or eliminated.

Acoustic Casing Inspection

Acoustic casing-inspection tools are basically modifications of the pulse-echo cement-bond tools. The geometrical parameters indicated in that section are presented, plus an analysis of the frequency response of the signal appearing in the gate W2. The frequency analysis is conducted to determine the wall thickness of the pipe. The kind of information available from these tools, (e.g.Schlumberger CET) includes measurements of ovality, minimum and maximum radius, internal diameter, and minimum and maximum wall thickness.

Newer-generation tools, such as Halliburton’s Circumferential Acoustic Scanning Tool (CAST-VTM ) and Schlumberger’s Ultrasonic Imager (USITM ), provide full 360o

coverage of the wellbore profile in a range of presentation formats. Cased hole applications include both ultrasonic cement evaluation and pipe inspection.

Qualitative Flow EvaluationTemperature and Differential-Temperature Surveys in Producing Wells

Deep formations are generally hotter than shallow ones; the temperature relationship describing this effect is called the geothermal gradient. This gradient varies from area to area, but normally ranges from about 0.5 to 2.0 oF (0.28 to 1.11 oC) per 100 ft (30.5 m). While it may vary somewhat with depth, for purposes of temperature log interpretation it is assumed to be linear.

Temperature surveys (sometimes called absolute-temperature surveys) are often used to locate fluid entries into producing wells and fluid exits in injection wells. The differential temperature is the gradient of the temperature with respect to depth. This differential temperature survey is useful in highlighting changes of slope in absolute-temperature surveys and is not usually used by itself. Temperature surveys are run in both up and down directions.

The detection of liquid entries by temperature logs is shown in Figure 1 .

Figure 1

Looking at the log from the bottom, the temperature indicated is the geothermal gradient. Liquid flowing into the wellbore from the formation enters the wellbore at essentially the same temperature as the formation. As the liquid moves uphole, the temperature gradually begins to decrease as it loses heat to the surrounding cooler formations. As the cooling and the fluid movement come into balance, the log approaches an asymptote to the geothermal gradient. In general, the displacement of this asymptote to the right of the geothermal gradient increases with flow rate.

In certain cases, a heating anomaly may be apparent at the entry of a liquid. This may occur at a tight or skin-damaged formation with a high drawdown, which heats the fluid by friction. It may also occur if fluids are circulated prior to the logging job. Such circulation may cool the static region below the entry, and the geothermal gradient may then appear unusually cool. The result is the appearance of a heating anomaly when it is, in fact, a transient effect: the static fluid is gradually returning to the geothermal gradient but has not reached it at the time of the log run.

Figure 2 shows the effect on the temperature log of a gas entry for the same completion geometry as the previous figure, i.e., a point entry.

Figure 2

In this case, the gas entry is a cooling anomaly because of the expansion of the gas. As the gas moves uphole, it heats up until it reaches the geothermal gradient in temperature and cools above that point. The magnitude of the cooling anomaly depends on the pressure drawdown, which in turn depends on the gas flow rate and the formation permeability.

The temperature log, when run with other surveys such as the flowmeter and fluid identification device, may be effective at detecting channels behind pipe. In the example of Figure 3 , the actual produced fluid is supplied from below the perforation, through a channel.

Figure 3

The static fluid below the perforation is in thermal equilibrium with the produced fluid in the channel, so the temperature survey shows the actual entry depth. The flowmeter shows that the flow enters the wellbore at the perforation. While these two give differing indications of the entry point, each investigates a different region around the wellbore. The flowmeter sees only inside the casing, while the temperature survey is affected by the nearby environment. A channel is a reasonable explanation for this conflicting information.

Figure 4 shows a channel from above.

Figure 4

In this case, the flow-meter shows the entry point into the wellbore. The temperature survey indicates that it is a gas entry, when in fact it is a liquid. A fluid identification device (not shown) may confirm that the entry is a liquid; therefore, the explanation is a channel from above.

Notice in the example of Figure 4 that the cooling anomaly is a liquid. Indeed, if the flowing temperature in the wellbore is above the geothermal gradient, every entry uphole, whether a gas or a liquid, would be a cooling anomaly. The use of combination tools, including at least a flowmeter, temperature survey, and fluid identification device, is necessary to examine multiphase flow downhole.

Temperature Surveys in Injection Wells

Temperature surveys are frequently used to locate the formations taking fluid in injection wells. The technique involves injecting fluids and running a base temperature while injecting, then shutting in the well and making a number of temperature-log passes during shut-in. Except for the wellbore fluid adjacent to the large volume held by the zone of injection (which returns to geothermal temperature

much more slowly) , the injection fluid stranded in the wellbore generally returns rapidly to geothermal temperature. As a result, the shut-in temperature surveys are observed to develop a "bump" at the injection zone. This effect is illustrated in Figure 5 .

Figure 5

Shut-in temperature surveys, in order to be effective, should have a base log run prior to shut-in. For water injection, at least 10o F (5.6 oC) difference between the injected fluid at the sand face and the geothermal temperature is required for good development on a 48-hr shut-in survey. If a 20 oF (11.1 oC) difference exists, then the bump will develop as quickly as 12 hours after shut-in. This technique is effective regardless of how the injected fluid gets to the zone, i.e., through the pipe or a channel. Once the well is shut in, the fluid movement downhole should be stopped completely to ensure accurate results.

Fracture-Height and Acid-Placement Detection

The same principle involved in using temperature logs to locate zones of injection is used to determine fracture height. A base-temperature log is run prior to fracturing. Immediately following the fracture operation, temperature surveys are run to locate

the interval that has taken fluid. (Of course, the well is shut in during these post-fracture surveys.) It is assumed that the fracture is in contact with the wellbore over its entire height. If it is oblique to the wellbore, the measured height will be less than the actual height.

Acid placement is treated similarly to injection or fracturing. The main difference in technique is a result of the acid reaction with the formation, which generates heat. Depending on depth and other factors, the reaction zone is usually at a different temperature from the geothermal and from the static fluid in the wellbore above the interval of injection.

Borehole Noise Surveys

Noise surveys detect fluid movement downhole by the sound it generates. Both fluid movement and pressure drop are required for noise to be generated. Noise-logging tools detect noise generated either inside or outside of the wellbore. Quantitative techniques have been developed, but they may not be accurate and are beyond the scope of this discussion.

Noise-logging tools are run in a stationary mode (i.e., the tool is stopped and the noise level is recorded). Continuous noise-logging tools exist, but are seldom used. Continuous noise logs are recorded at high frequencies to avoid the clutter of road noise associated with the tools' movement; however, it is the noise spectrum at the low frequencies that is of primary interest.

Amplitude of Downhole Noise

A single-phase entry has both flow and pressure differential, and hence may generate noise detectable with a noise-logging tool. Figure 1 shows a schematic of the noise-log amplitude detected by a tool making a number of stops within the wellbore.

Figure 1

In this example, noise amplitude is greatest at the point of entry into the channel from the formation and at the point of restriction of the flow in the channel. Entry back into the upper formation also generates some noise, but less than the other two, since the pressure drop is small. The typical noise log is recorded on a logarithmic scale in units of millivolts. The millivolt level may be expressed as either peak to peak, RMS, or half-wave values. The scale is only important for quantitative evaluation and is irrelevant to qualitative evaluation of flow.

Noise Frequency Spectrum Log

Analysis of the noise spectrum has shown that different flow conditions downhole often have a unique spectral character. For example, the spectrum of Figure 2 is typical of a single-phase entry.

Figure 2

As a general proposition, single-phase entries tend toward the higher frequencies. Below this frequency spectrum is the log that would be recorded across the interval having this entry. From the amplitude of the log data, the entry depth is associated with the highest or peak amplitude. Each recording on the log corresponds to the energy of the noise detected at frequencies greater than that indicated on the log. The log records show, in fact, what is recorded by filters allowing frequencies greater than 200, 600, 1000, and 2000 Hz. For the single-phase entry, the log curves are tightly packed at the entry point.

Bubbly two-phase flow ( Figure 3 ) shows a very different character.

Figure 3

The noise of bubbly flow tends to be confined to the lower frequency portion of the noise spectrum. The characteristic log response is shown at the bottom of Figure 3 . Two important factors are obvious. First, the 200-, 600-, 1000-, and 2000-Hz curves are spread out, indicating much energy in the lower-frequency bands. The second is that the noise remains high above the entry point. This is because the source of the noise is not the entry pressure drop and flow but the turbulence generated by passage of the bubbles.

The signal detected by the noise tool is strongest when the tool is in liquid. If the tool is brought up above the gas/ liquid interface in the casing, an acoustic decoupling occurs and the amplitude of the noise detected is considerably lower. Furthermore, the noise level for a point source or entry weakens as the tool is moved away from the source, with the higher frequencies weakening more rapidly than the lower frequencies.

Figure 4 illustrates an example of a noise log that was run to determine the sources of gas production among 29 single-hole perforations downhole.

Figure 4

Six entries are detected below the liquid level and one at the liquid level, and production is also indicated from at least four perforations uphole. Note that below the liquid level the 200-, 600-, 1000-, and 2000-Hz curves are spread out, indicating bubbly flow. Note also that the higher frequencies die out faster downhole from the liquid level. The sudden reduction in noise level above the liquid is due to the acoustic decoupling caused by raising the tool above the gas-liquid contact in the wellbore.

Gamma Ray Qualitative Techniques Using Radioactive Tracers

Qualitative radioactive tracer techniques are used primarily to monitor fluid movement downhole, typically in injection wells, and to locate the placement of certain materials, such as fracture proppant. The tracer may be injected at the surface, although it is more common for the tool to carry a radioactive fluid with it downhole. At selected intervals, the radioactive fluid is ejected by the tool into the flowing stream. Its movement is monitored by the tool's gamma ray detector. For fluid chasing, the most common radioactive isotope is sodium iodide (NaI) dissolved in water. The iodine is I131 and has a half-life of 8.04 days. Iridium-192 is often used for tagging sand or proppant for later detection.

The use of multiple radioactive materials has been developed in recent years. Typically, different radioactive materials are used to tag different materials—e.g., fracturing fluid, and lead-in and tail-in proppant—and their placement is evaluated later using a spectral natural gamma ray tool. These tools have recently become available in small through-tubing sizes.

Channel Detection Using Radioactive Tracers

To detect channels, radioactive tracers must be placed behind pipe. Therefore, this technique works only in wells that receive injection during the test. The schematic of Figure 1 shows the most common tracer technique, which detects the presence of channels.

Figure 1

Radioactive material is ejected into the flow above the perforations; the tool is lowered and then logged up. The location of the ejected cloud of material is easily detected by the gamma ray. The tool is again lowered and another up log is made. The cloud of ejected material is again detected by the gamma ray. With each up log, the movement of the cloud is monitored. If an upward channel exists, the cloud (or part of it) changes direction and begins to move up the hole.

An upward channel may later be confirmed by a channel check, in which a stationary tool is placed above the exit. When tracer is ejected, it moves down with the flow past the stationary tool and then up the channel again past the tool. With the recorder on time drive, two separate indications of the tracer cloud as seen by the tool's gamma ray detector confirm the existence of the channel. If a downward channel exists, tracer must be ejected above and below the exit and its movement must be monitored to confirm that the fluid movement is in the channel and not in the pipe.

Induced Fracture Height Determination Using Tracers

Fracture height determinations are made by tagging the proppant, typically with Iridium-192, and detecting its location. A pre-fracture and a post-fracture survey are run and significant differences are attributed to the concentration of the proppant in the fracture. The log in Figure 2 shows the base and post-fracture gamma rays, with the fractured interval highlighted.

Figure 2

Notice that a temperature log, with both a base and a post-fracture temperature survey, confirms the fracture location. The increase of radioactivity at the bottom of the well is attributed to the settling of proppant to the bottom, and not to a fracture.

The apparent discrepancy between the temperature and tracer techniques, especially at the bottom of the fractured interval, may be caused by the possible responsiveness of the temperature to the gross height through which the fluid moved and which remains unpropped. For these techniques to be accurate, the fracture must be coplanar with the wellbore.

Multiple Radioactive Tracer Techniques

Multiple radioactive isotope techniques are used to monitor complex downhole operations and their results. By using different isotopes, which emit gamma radiation of distinct energy levels, the placement of the individual tracers may be detected. Figure 3 shows the relative intensities and energy level spectra of elements commonly used for this purpose.

Figure 3

Natural gamma ray spectral tools are adjusted to focus their gates to detect certain peaks and thus locate the placement of individual isotopes. The multiple tracer technique is useful in monitoring induced fractures. The fracture fluid and proppant are each tagged with different fluids so they may be located downhole after the fracture operation. The gross height may be indicated by the tagged fracture fluid location, while the proppant indicates the propped height.

Flow Rate Determination in the WellboreFLOW RATE DETERMINATION IN THE WELLBORE

The tools used to quantitatively evaluate flow volumes downhole are the radioactive tracer/gamma ray and the flowmeter. The radioactive techniques are used mostly in injection wells, since they are relatively easy and inexpensive and there is no danger of radioactive material coming to the surface. The flowmeter is most often used in producing wells, where use of the radioactive tracer is rare. For evaluations to be made when multiphase flow is present, flowmeter and fluid identification surveys are required.

There are two basic types of flowmeters. Continuous flow-meters, which are logged across the producing interval, include the small-diameter and the folding full-bore flowmeters. The other basic type is the diverter flowmeter, which diverts the flow through a narrow test section, and is most effective in deviated multiphase flow conditions. Horizontal wells pose unique problems for mechanical flowmeters, which have questionable usefulness in these operations.

Fluid Behavior

In producing wells, volumetric flowrates downhole generally do not match those at the surface. This difference is caused by two factors. First, the reduction of pressure in a liquid as it is produced to the surface may cause it to expand slightly. This expansion effect is very minor, however, and is not usually considered. The second and far more important cause is the dissolution of gases present in the liquid phases at downhole conditions. This occurs in both water and oil, although gas is far more soluble in oil than in water, and thus the changes in oil volume from downhole to surface are more dramatic.

Figure 1 is a phase diagram.

Figure 1

At reservoir conditions, a liquid flowing from the formation to the wellbore undergoes a drop in pressure without a change in temperature. As the oil is produced to the surface, both pressure and temperature are reduced, causing the oil to give up a large amount of gas and decrease in volume. The point at which gas begins to break out of solution is called the bubble point. Gas that comes from the oil in this manner is called solution gas.

If gas-cap gas (which is not and was not in solution with the oil) is produced, it is called free gas. This free gas also changes dramatically in volume from downhole to surface. Such volume changes are a function of the gas gravity, and of reservoir pressure and temperature.

Figure 2 shows the change in fluids as they move from down-hole to the surface. As pressure begins to decrease, a slight expansion of the liquid takes place.

Figure 2

At the bubble point, gas begins to break out of solution, and as the pressure is further reduced, vast volumes of gas come from the oil. A similar effect is noted with water, although the volume of available gas is much less. The relation between the downhole and surface volumes is called the formation volume factor, and is defined as

(1)

(2)

Bo is typically greater than one and Bg is typically much less than one. For gas, the reciprocal, l/Bg, is usually used and is a number in the hundreds. These relationships are determined from PVT data on the produced fluids or may be approximated from correlation charts available in the technical literature.

Injection Well Profiling Using Radioactive Tracers

Although many of the methods available for radioactive tracer logging can be made quantitative, two basic techniques are most often used. These are referred to as the velocity shot technique and the area under the curve technique. It is common for results from either of these techniques to be presented in the form of a flow or injection profile on the tail of the log.

In the velocity shot technique, the tool is held stationary and a small cloud of radioactive material is ejected into the flow. As this cloud passes two gamma ray detectors on the tool below the ejector, a measurement is made of the time of transit between those detectors. This measurement is made by recording the response at the detectors while the film is scrolling at a constant rate; i.e., the recorder is on time drive. Figure 1 illustrates this technique.

Figure 1

In this figure, a velocity measurement is being made between the upper and lower set of perforations. By performing a number of tests at various points in the wellbore, a flow profile as shown on the right may be produced. The differences between the constant values measured between, above, and below the perforations represent the loss of fluid to the formation in this injection well.

The volumetric flow rate may be computed using the following equation:

Q = (l/t) (84  F  DS  [D2 - d2] )or, in SI units,

Q = (l/t) (6.79  F  DS'  [D'2 - d'2] )where:

Q = flow rate, B/D (Q' is in m3/D)

F = flow profile correction factor, typically less than 1.0

DS = distance between detectors, ft (DS' is in meters)

D = pipe internal diameter (ID), in. (D' is in centimeters)

d = tool diameter, in. (d' is in centimeters)

t = time between detections, seconds

The profile-correcting factor (F) may be computed to match surface and downhole injection rates above the top perforations. Once the term in the right-hand brackets is computed, and assuming that F is constant, the term does not change and only 1/ t need be calculated thereafter. If fraction or percent of flow only is to be calculated, then the flow varies directly with l/t.

In the area under the curve technique, it is assumed that the area is directly related to the amount of radioactive material ejected by the tool into the flow. As the initial area is reduced, the fluid remaining is reduced proportionally. Figure 2 shows a series of passes with a gamma ray after a large cloud of radioactive material has been ejected above the interval to be evaluated.

Figure 2

The initial run, designated R-l, is at the far left. To determine the amount remaining at the location of the cloud in run eight (R-8), the areas under R-l and R-8 must be measured and

(1)The difference between the flow remaining at two successive runs is the fraction of the flow lost to the formation between those runs. Computation of the fraction of flow remaining at each run may then be used to determine an injection profile across the interval.

Of the two techniques presented in this section, the velocity shot technique is better for quantitative answers, although the area technique often agrees quite well with it.

In some international locations, radioactive tracers are difficult to obtain. This situation has led to the evolution of non-radioactive tracers having high-capture cross sections, and the application of systems such as Schlumberger’s "Flagship Tool String," which employs RST measurements.

Types of Tools

The two types of turbine flowmeters are the small-diameter and the full-bore. These tools are run continuously over the interval of interest, making a number of logging passes, usually in both the up and down directions, all at different logging speeds. These tools respond to the bulk flow rate, even in multiphase flow. They are best suited for use in vertical wells, but also may be used effectively in deviated wells, especially at higher flow rates.

The typical response to flow is shown in Figure 1 .

Figure 1

The dashed curve is the typical turbine spinner response to a static fluid in the wellbore. The response, in terms of spinner rotational speed in revolutions per second (RPS) against logging speed, shows that the relationship is linear. The response curves, however, do not go through the origin, but instead intercept the horizontal axis on each side of the origin. This offset is due to the viscosity of the fluid; greater viscosity tends to cause a greater offset. The intercept is sometimes called the "threshold" of the spinner, although the actual tool velocity in static fluid at which the spinner begins to rotate may be larger.

When the spinner encounters an upflow, as would be expected in a producing well, the effect is to shift the response curve of the tool to the left; that is, the new response lines of the tool when it encounters the upflow are similar to the static response, except that the new response is shifted to the left by an amount equal to the upflow velocity. Figure 1 shows such response curves to an upflow, VF. If a downflow is encountered, it causes the response curve of the spinner to be shifted to the right by an amount equal to the flow velocity downhole. If the intercepts or thresholds are not symmetrically located about the margin, the same relative position is maintained to determine the flow velocity.

Interpretation of Continuous Flowmeters

The schematic in Figure 2 shows a well with two sets of perforations, each producing. The flowmeter measurements are taken in the intervals between the entries, i.e., intervals A, B, and C.

Figure 2

To the right of the well sketch is a minimum flowmeter logging suite consisting of three up and three down log runs, all run continuously over the intervals, and each at a different but constant logging speed. The rotational speed of the spinner flowmeter is recorded in revolutions per second (RPS). At the right is a series of plots of the spinner response curves for each of the intervals. In interval A, which should be static, the values of RPS and cable speed are plotted using values from points 1 through 6 on the log. This is the static response. A similar plot is constructed for intervals B and C, and the displacement of the B and C response curves from the static is a measure of the flow velocity upward downhole. The velocities VF and VF' are the velocities of the flow detected in intervals B and C, respectively.

If a well is producing at a high flow rate, the up runs may not be usable, because the flow velocity may be faster than the tool speed in most of the well. As a result, the spinner rotates as if the flow is up, relative to the tool. When this occurs, the technique of Figure 3 may be used.

Figure 3

The intercept of the response curve with the vertical axis is first located. From this point a line is drawn to the static response curve, and then down to the horizontal velocity axis. The intercept of the horizontal velocity axis is the velocity of flow in the interval being computed.

Where both up and down runs are available over the whole logged interval, the two-pass overlay technique may be used. This technique is especially useful where there are many entries over the logged interval. The first step of this technique is to plot the spinner response curve in the lowest interval. This response curve should indicate that the flow is likely zero, i.e., the intercepts fall on each side of the origin. This does not ensure zero flow, but if coupled with a fluid identification device that shows water, completion fluid, or debris in the rathole, it is certainly static. The slope of the response curves in both the up and down logging direction must also be determined. Note that these are not usually the same. Then, as shown in Figure 4 , the most representative or average or composite up and down runs are overlain in the lowest interval.

Figure 4

The separation relative to this lowest interval, labeled RPSB and RPSC, may then be used to calculate the flow in each upper interval using the equations shown in the figure. Both the up and the down runs must be presented at the same RPS and depth scales for this technique to be used.

The measured flow velocities are those seen by the spinner turbine blades. If the spinner is centralized, and it should be for best results, it has sampled the flow in the center of the wellbore, which is too large. As a result, a flow profile correction factor must be used to correct the data to an accurate average velocity. For this computation, service companies may have available corrections based on Reynolds number of the flow, although a correction of 0.83 is commonly used in hand calculations. If Vi is the velocity detected by the spinner in interval i, the average velocity in interval i is

= 0.83 (Vi)                             (1)To compute the bulk flow rate in barrels per day (Q), the following equation is used:

Qi = 1.4  (ID)2                 (2)or, in SI units,

Q'i = 0.113 (V'i) (ID')2

where:

Qi = bulk flowrate in interval i, B/D (Q'i is in m3/D)

= average flow velocity in interval i, ft/min (V'i is in m/min)

ID = wellbore inside diameter open to flow, in. (ID' is in centimeters)

The presentation of the final computation may take the form shown in Figure 5 .

Figure 5

In this figure, the well sketch shows three entry points and four intervals for flowmeter evaluation. The cumulative bulk flow illustrates the volume flowrates calculated by the flowmeter. The entry profile is determined from the changes in the bulk flowrate at the entry points.

Multiphase Vertical Flow

Many different flow regimes may exist in multiphase flow. In an oil well, two or three phases of fluid may be present in the producing interval. If the flow is water and oil, bubble and emulsion flows are most common, while slugs and more complex patterns are relatively rare. If the slug pattern exists downhole, it appears as a square wave pattern on the flowmeter log, since the oil slugs are moving up at a higher velocity than the water phase. When gas and liquid are present, the flow is much more complex. Bubble flow probably exists up to about 10% gas by volume at

downhole conditions. A transition quickly occurs to the slug or more complex flow pattern. Unlike oil-water flow, gas-liquid flow is turbulent and violent, and produces a very ratty response on the flowmeter. This messy situation continues until the gas flow rate and volume fraction is so large that it carries the liquid uphole as a mist. As a result, flows containing gas and liquid may be difficult to compute accurately.

The terms "holdup" and "cut" are often misunderstood. "Cut" refers to the amount of a particular phase that is being produced. For example, if 1000 B/D (159 m3/D) of liquid is produced, of which 350 bbl (55.6 m3/D) is water, the liquid is said to have a 35% water cut and a 65% oil cut. "Holdup," on the other hand, refers to the fraction of the bulk volume occupied by one of the phases. Figure 1 helps illustrate this concept.

Figure 1

At the left, there is a standing water column in the pipe, above which the pipe is filled with oil. The valve at the bottom is then opened and oil only is pumped in. Flowing out at the top is 100% oil cut with no water cut. The oil simply bubbles up through the water and joins the other oil at the oil/water interface. No water is produced. Across the bubbly interval, the bubbles occupy about 30% of the volume (determined from the new position of the interface) , and hence that interval is said to have an oil holdup of 30% and a water holdup of 70%. The cut and holdup in this case are clearly different.

Because of this difference, water is likely to accumulate downhole in all wells, even though the water cut is small. The chart of Figure 2 shows how the difference between holdup and cut can be quite dramatic, especially at low flow rates.

Figure 2

Note that at 300 B/D (47.7 m3/D), a 1% water cut at the surface means a 50% water holdup downhole.

If two phases are present (a heavy and a light phase), then

YH + YL = 1.0 (1)where Y is the symbol for holdup and the subscripts refer to the heavy (H) and light (L) phases. If water and oil are flowing downhole, water is the heavy phase, and if gas and liquid are flowing, the liquid is the heavy phase. If the three phases—water, oil, and gas—are present, then

Ywater + Yoil + Ygas = 1.0 (2)Measurement of Phase Holdup

Measurement of phase holdup in two-phase flow is made indirectly by measuring the fluid bulk density. Schlumberger's gradiomanometer and PTS sonde measure bulk density by determining the pressure differential over about a 2-ft (0.61-m) interval. This measurement is made with mechanical sensing bellows on the gradiomanometer, or by a quartz differential pressure gauge measurement over about a 2-ft interval. A schematic of the gradiomanometer is shown on the left side of Figure 3 .

Figure 3

Note that these tool responses must be corrected for well-deviation angle.

Bulk density is also measured using the nuclear fluid density meter, as pictured on the right of Figure 3 . The tool contains a gamma ray source and a detector, and the counts received at the detector may be related to the density of the fluid between the two. This measurement of the bulk density does not have to be corrected for the well-deviation angle.

To determine the holdup from the bulk fluid density, the following equation is used:

YH = (measured - L)/( H - L)             (3)and

YH + YL = 1.0                                         (1)In the above equations, symbolizes the fluid density, gm/cc.

Capacitance devices for fluid identification are also available. Their best measuring range is from about 0 to 40% water holdup. These tools are designed to measure annular capacitance between the tool housing and a core within the housing. Fluid turbulence downhole is the mechanism that pushes the multiphase fluid into the tool. There is some question about whether the fluid mixture within the tool is

representative of the fluid mixture in the main flow. The capacitance tool is mainly responsive to water.

Computation of the Two-Phase Flow Profile

Once the bulk flow rate and the holdup of the two phases are measured, the slippage velocity must then be determined. This slippage velocity is the velocity of the light phase relative to the heavy phase, and is the cause of the difference between cut and holdup. To determine the slippage velocity between oil and water, use the chart in Figure 4 .

Figure 4

The horizontal axis is the density difference between the water and the oil phases (note that this chart is not used for gas/liquid mixtures). The holdup of the water phase is also needed for the use of this chart. For example, if the water density is 1.0 gm/cc and the oil density is 0.70 gm/cc, the density difference on the chart is 0.30 gm/cc. If the water holdup is 0.70, then the slippage velocity of the oil with respect to the water is about 19 ft/min (5.8 m/min). When dealing with a gas/liquid system, a slip velocity of 60 ft/min (18.3 m/min) is assumed. Better estimates of the gas slip velocity may be available from the service companies.

To compute the flow rates for each interval, in two-phase flow, the following equations are used:

QHi = YHi[Qi - l.4(ID2casing - D2tool)(Vslipi)(l - Yi)]                 (4)or, in SI units,

Q'Hi = YHi [Qi - 0.1l3(ID'2casing - D'2tool) (V'slipi) (l - Yi)]and

QLi = Qi - QHi.                                                                                 (5)or, in SI units,

Q'Li= Q'Li = Q'i - Q'Hiwhere:

Q = bulk flow rate from the flowmeter, B/D (Q' is in m3/D)

QH = heavy phase flow rate, B/D (Q'H is in m3/D)

QL = light phase flow rate, B/D (Q'L is in m3/D)

YH = heavy phase holdup

Vslip = slip velocity of light phase, ft/min (V'slip is in m/min)

IDcasing = internal diameter of the casing, in. (ID' is in centimeters)

Dtool = tool diameter, in. (D'tool is in centimeters)

i = subscript denoting interval under analysis

Individual entries are determined by the differences between the flow rates measured above and below an entry.

Multiphase Flow in Deviated Wells

Deviated wells with multiphase production present a unique problem to flow evaluation. In the schematic in Figure 1 and Figure   2 ,

Figure 1

there are three sets of perforations, each producing oil with little or no water cut.

Figure 2

The actual bulk flow profile is shown on the left. When the oil enters the wellbore, it gravitates to the high side of the pipe and moves uphole along the pipe's high side, carrying some water with it. If there is little or no water production, the water must fall back along the low side of the pipe, resulting in the flow profile shown in each interval. The flowmeter responds to the flow it sees, which is downflow in the lowest interval, upflow in the upper interval and somewhere in-between in the middle interval. This problem is minimized by centralizing the tool. Even with the tool centralized, this is a serious interpretation problem at lower flow rates and at deviation angles greater than 15o. If a small-diameter spinner is run noncentralized, interpretation problems occur at deviations of about 2o. The detection of a downflow in the lower parts of a deviated well should always be questioned.

This problem may be alleviated by using diverter-type flowmeters, which are available from major service companies. The Schlumberger inflatable diverter tool ( Figure   3 ) is a typical example.

Figure 3

This tool utilizes a fabric diverting element and an inflatable tauroidal ring to divert the flow through the funnel-shaped test section. Other versions use metal petals attached to the centralizer arms to make a funnel element. These tools are much more effective than conventional flowmeters in deviated wells, but are limited to flow rates may impose limitations on their use, depending on the tool size and the service company.

The response of diverter flowmeters is precalibrated, and each tool and spinner combination has a unique calibration curve. Figure   4 shows the response of a typical diverting tool.

Figure 4

Responses of individual tools must be obtained from the service companies.

For multiphase flow, some tools contain a fluid-identification device, upstream from the spinner element. In a case where all of the fluid passing through the tool also passes through the fluid-identification device inside of it, the flow is very turbulent, and the holdup and cut are nearly equal. Either a nuclear densimeter or a capacitance device may be accurate under these conditions. Another alternative used by some service companies is to locate the fluid-identification devices directly above the exit ports of the diverter-type flowmeter. In flow loops, the holdup measured directly above the exit ports of a diverter tool closely matches the actual cut of fluids passing through the tool.

Oxygen Activation Measurement

A schematic showing the oxygen-activation measurement is illustrated in Figure   1 .

Figure 1

The neutron generator emits a burst of neutrons which causes oxygen (present in water molecules) in the borehole to become activated. If the water is moving up past the tool, a population of activated water is formed. This activated water has a half-life of about seven seconds, and as the oxygen atoms return to their normal state, gamma rays are emitted. These gamma rays are counted by the detectors and are shown as an increase in the background counts. Oxygen activation has particular application in production logging, where it is used to identify water flow in wellbores or behind casing strings. Tools such as Western Atlas’ Hydrolog or Schlumberger’s Water Flow Log (WFL) are used for this purpose.

Production Logging of Multiphase Flow in Horizontal Wells

PRODUCTION LOGGING OF MULTIPHASE FLOW

IN

HORIZONTAL WELLS

Overview

The advent of horizontal drilling brought new and unexpected challenges with respect to characterizing flow regimes in horizontal wells. New approaches to logging, fluid flow interpretation and evaluation, and wellbore configuration were developed in response to those challenges.

One obvious problem presented by the horizontal wellbore was that wireline tools could no longer be pulled to total depth by gravity. As borehole inclination approaches sixty degrees from vertical, friction increases to the point that wireline tools cannot freely fall to the bottom of the well. In this horizontal environment, gravity is no help at all. This unit will discuss some of the methods that were devised to overcome this problem.

As with vertical wells, it was necessary to identify commercially productive perforations, as well as to determine which intervals produced water. However, the results obtained by conventional production logging tools were generally not sufficient to characterize horizontal flow regimes. These conventional tools were designed to measure vertical flows, in which fluid phases are dispersed with near uniformity across the wellbore. With few exceptions, conventional production logging tools were not capable of characterizing horizontal flow in any detail. This experience prompted the study of horizontal flows in order to develop logging tools capable of discerning each phase within the flow.

The problems encountered in horizontal wells were not merely related to flow patterns and downhole tool designs. The broad application of slotted liners, gravel packs, and external casing packers pose problems in understanding and characterizing flow in horizontal wells.

Through such configurations, fluids can move both within the casing or liner, and through the annulus. As a result, the point at which a logging tool detects a sudden inflow into the borehole may not, in fact, mark the actual source of the fluid entry.

This unit focuses on current methods of measuring multiphase flow in horizontal wells. Though current technology has not addressed all of the problems associated with horizontal production logging, oil companies and logging companies continue to study the nature of multiphase flow downhole, and seek to develop more accurate tools to characterize flow in horizontal wells.

 

Horizontal Well Configurations

The term "horizontal well" is very loosely used in the industry, since no well is ever completely horizontal, except over the course of short intervals. In this discussion, the term "horizontal well" will encompass any well that is horizontal (90 degrees of deviation), near-horizontal (within 10 degrees of horizontal), or undulating (deviation fluctuates above and below 90 degrees). The important factor to recognize is that in a "horizontal well" a change of only a few degrees in inclination (e.g. changing from 88 to 90 or 92 degrees from vertical) can make a dramatic difference from a production logging perspective. The angle affects which fluid phase (heavy or light)

will be dominant within the cross section of the wellbore. A slight change in well angle can dramatically affect individual phase velocities.

To visualize this situation, consider the examples shown in Figure 1 (Horizontal well configurations; after Smollen, 1996).

Figure 1

Imagine a shut-in well, in which the fluids have segregated so that both the gas-oil interface and the oil-water interface are present. Well fluids segregate according to density where the deviation angle is less than 90 degrees, as illustrated in part a of Figure 1 . Water is shown at the bottom of the well, above which are oil and gas respectively. If the well is truly horizontal, multiple phases may be present along the horizontal section (see part b of Figure 1 ) and no particular phase will necessarily dominate. While only water and oil are present in the horizontal section shown in part b of Figure 1 , clearly all three phases could be present, given sufficient volumes of water, oil, and gas. If the well angle is greater than 90 degrees, as shown in part c of Figure 1 , then the water will accumulate at the lowest point, or heel, of the well. Moving away from the heel in either direction would first involve crossing a water-oil interface, then later crossing an oil-gas interface. Unlike the earlier example, the end of the horizontal section of the well is filled with gas.

In actuality, no wells are completely horizontal for any lengthy extent; instead, they are generally greater or less than 90 degrees, or may even "undulate" as shown in part d of Figure 1 . This example illustrates a shut-in well in which the phases have segregated in a more complex manner. The light phase, shown as gas, accumulates at the crest of the undulation, while water accumulates at the trough. The oil phase, if present, would accumulate between the water and gas phases. The ramification of this fluid segregation within a supposedly "horizontal" well is that segregation continues even during flowing conditions, unless flow velocities are extremely high.

Fluid identification logging tools are sometimes used to determine which fluid phases are present within the wellbore, and to measure each fraction at any point along the wellbore. Under ideal conditions, if such a tool provided excellent and reliable information within the horizontal environment, then the character of the logs would be much more affected by the well inclination than the entry profile. In vertical wellbores, the fluid identification tool provides an important indicator of fluid entry, but in horizontal wells, these indications could be misleading in the absence of other amplifying information; especially the directional survey.

 

Horizontal Well Completions

A variety of completion methods may be employed in horizontal wells. Figure 2 – Types of Completions; Smollen, (1996), shows some of the most typical configurations.

Figure 2

Each type of completion poses a different problem for the production logging tool.

The term "conventional" completion is used to describe a cemented and perforated cased hole completion, as well as an open-hole completion, as shown in the upper part of Figure 2 . These two completions are classified as conventional because, in both cases, all of the flow is confined to the segment of borehole through which the logging tool passes (assuming that a good cement bond in the cased hole was established). In the cased hole, however, fluid must enter through the perforations (assuming good casing integrity), while in the open hole, fluid may enter from anywhere. Furthermore, the segment of open hole may be rugose and is likely to accumulate more debris along the well than a cased completion.

Other wells fall outside the realm of conventional completions. The slotted liner and pre-packed gravel pack completions are shown in the middle part of Figure 2 . These completions are both characterized by an open annulus along which fluid can flow. As a result, any inflow detected at the liner or gravel pack screen is not necessarily representative of the actual source of the flow from the formation. The fluid may enter the annulus at one point, flow along the horizontal section, and suddenly be diverted into the liner or screen by a restriction or closure along the annulus. Such restriction or closure can occur, for example, when the formation collapses or swells.

Production logging tools designed for conventional wells may not be effective in this situation, and may provide misleading measurements.

A periodic external casing packer completion is shown in the lower part of Figure 2 . This completion is much like the slotted liner completion, and would appear to have the same problems. It does, however, provide features that are more conducive to effective production logging. This method typically uses a number of packers in the completion, so fluid entries to the casing are confined to those sections that are open to the annulus. This completion may exhibit flow characteristics similar to a "conventional" horizontal completion when measured adjacent to the packers because the flow is restricted to the same section of borehole that the logging tool occupies. When flow is measured between entry points in the casing and adjacent to packer sections, the flow contributed from each interval between packers can be determined without needing to account for flow in the annulus. If logging tools that are affected by annular flows are used to make measurements between packers, the log will resemble that seen in a slotted liner completion.

Flows In Horizontal And Near-Horizontal Wells

Flows within "conventional" completions are the most easily measured of horizontal flows. If the flow comprises only a single phase, then the response of most production logging tools (with the exception of the gradiomanometer or other pressure differential density tool) is essentially the same as that seen in a vertical well. If more than one phase is present, however, the flow segregates into a pattern as shown for two phases in Figure 3 – Flow patterns in a conventional completion; Smolen (1996).

Figure 3

While any of these patterns is possible, the stratified flow regime is most likely to be encountered under producing conditions. In this flow regime, the water, oil, and gas

phases are segregated by density, with oil on top of water, and gas on top of oil. The lighter phases generally move faster in an upward direction than the heavier phases. Minor changes in well deviation are capable of causing large changes in fluid velocity and holdup. Variations in fluid and gas velocity tend to generate different flow patterns which can complicate the log interpretation. Generally, stratified flow will dominate in horizontal wells unless flow rates are quite high. This is also the type of flow that the newer production logging equipment has been designed to measure.

The flow pattern map of Figure 4 – Flow regimes in the horizontal environment; Smolen,(1996),shows the nature of flow expected for two-phase gas/liquid flow under specified conditions.

Figure 4

The superficial velocities for a phase, Vs , is defined as the volumetric flow rate of that phase divided by the cross section area of the pipe:

where:

Vs = superficial phase velocity

Q = bulk flow rate of the phase

A = cross-sectional area of the pipe

To put this equation into perspective, for 7 5/8 inch, 29.7 lb/ft casing, a flow rate of 1000 B/D corresponds to a velocity of 15.1 ft/min. or .25 ft/s. Below a superficial liquid velocity of 10 ft/s, and for the conditions stated in Figure 4 , the flow will be either stratified or intermittent (essentially broken stratified flow). Dispersed bubble flow will not be produced until the liquid flow rate reaches nearly 40,000 barrels per day! Indeed, below a liquid flow of about 1000 barrels per day, the flow is almost always stratified over a very wide range of gas flows, given the conditions stated.

Non-conventional horizontal completions, such as slotted liner completions, exhibit flow properties that are much more difficult to evaluate. Figure 5 - Concurrent flows in liner, prepacked gravel packs, and external packer completions; Smolen (1996) shows the types of flows encountered.

Figure 5

Generally, there will be concurrent flows in both the liner and the annulus. These flows may exhibit varying degrees of independence relative to one another. Such independence implies that a measurement of flow in one region will not provide any information about flow in the other region. Any tools designed to measure concurrent flows must be able to discriminate the flow phase and its velocity - both inside and outside of the liner. Though nuclear tools currently provide the best capability to characterize flow within the annular region, the goal of obtaining concurrent flow measurements with any degree of confidence and consistency is yet to be fully realized.

PRODUCTION LOGGING IN HORIZONTAL WELLS

This section provides an overview of the equipment and techniques used to convey logging tools to total depth in high-angle wells.  

Logging Equipment and Techniques used in Horizontal Wells

Special equipment and techniques have been developed to run logging tools through horizontal or highly deviated boreholes. There are essentially three techniques currently available:

pump down technique,

coiled tubing technique, and

tractor technique

Each of the above techniques can be used to run logging tools in either of two modes: with a real-time surface readout of the wireline log, or

with a memory cartridge.

The real-time surface readout enables the operator to monitor the log at the surface as the sensors pass through the wellbore. Real-time monitoring is desirable because unexpected anomalies often occur, and real-time detection allows the operator to examine such anomalies more closely before pulling the tool out of the hole.

With a memory cartridge, the logging tools are pre-programmed to begin recording downhole at a specified time. Logging passes are made as required for any production logging job. However, the data is not available for analysis until the tool returns to the surface when the data is retrieved from the tool’s memory. Unexpected anomalies or tool failures will not be discovered until after the job is completed. On the other hand, memory equipment is considerably less expensive than surface readout equipment.

Pump-Down Technique

Pump-down equipment typically employs a special pump-down sub that is attached to the bottom of the logging tool. This assembly may employ swab cups to better enable the tool to be pumped down to the end of tubing or drillpipe. In some cases, the annulus between the tool and tubing is sufficiently small to pump the tool down into the hole without using swab cups or a pump-down sub; however, this technique is not commonly used in production logging. The tool must be pulled back into the tubing across the interval of interest. Spinners and other non-nuclear sensors may not provide adequate flow information along the horizontal section of the well. This technique is, however, useful for pulsed neutron formation evaluation carried out through stuck drillpipe, or where tubing has been run to TD.

An example of this application is shown in Figure 1 – Pumpdown logging technique with oxygen activation water flow measurements; courtesy of Schlumberger Oilfield Services.

Figure 1

Tubing was run to TD, and a pulsed neutron oxygen activation tool was pumped into the hole to evaluate water injection profiles through horizontal sections of the well. While water was being injected, stationary water flow measurements were made at six locations to detect flow outside of the tubing. The well crosses five major fracture systems, and measurements were taken between fracture systems or near the ends of the horizontal section. The velocities measured are shown in feet per minute on the figure. This test indicates that the velocity of the annular fluid remained constant across the first three fracture systems encountered. Only the last two fractures are taking injected water.

Coiled Tubing

Currently, the coiled tubing unit is the most common method used to run production logging tools in horizontal wells. A coiled tubing operation is shown in Figure 2 - Logging job performed with coiled tubing; Lohuis, et al, 1988. This technique uses continuously spooled steel tubing.

Figure 2

The logging tool is mechanically connected to the end of the coiled tubing, and the tool is moved across the horizontal interval as tubing is pushed through the injector head into the well. Measurements may be taken in both the "down" and "up" directions. Certain types of equipment utilize a special kind of coiled tubing that contains an internal electric wireline cable. This cable runs between the tool head and the surface unit to provide log data at the surface in real-time. Coiled tubing units that do not feature the internal electrical wireline cable are used to run production logging tools with memory cartridges. While less expensive than units that feature the internal cable, they are subject to the same shortcomings mentioned earlier in this section.

Downhole Tractors

The newest technique for logging horizontal wells utilizes a downhole tractor. Though tractors exist in a number of configurations, a typical example is shown in Figure 3 – Downhole Tractor for production logging; courtesy of Sondex.

Figure 3

This design employs folding arms equipped with drive wheels to propel it through the wellbore. When the arms are extended, the wheels engage the casing wall. The wheels are powered to push or pull the tool downhole. Most tractors are only capable of pushing the tool to TD, and only propel themselves in one direction (though a few now feature reverse capability). This limitation does not usually pose a problem, however, because the tractor is retrieved as the surface wireline unit pulls the tool out of the well. The logs are typically run when the tool is pulled back by the wireline unit. Most wireline equipment cannot record logs while the tractor is powered. While the tractor must be powered from the surface, the logs may be recorded with memory equipment.    

Conventional Production Logging Tools

A number of conventional logging tools have been used in an effort to characterize multiphase flow in horizontal wells. This discussion examines the applications and limitations of the sensors used in conventional production logging tools.

Spinner Flowmeters

To understand the effectiveness of production logging sensors used in the horizontal environment, it is necessary to consider the tool’s radius of investigation, as well as the flow profile to be measured. Figure   1 – Spinner response in horizontal wells; Smolen (1996) shows a schematic of both the full-bore and the small-diameter spinner.

Figure 1

To the right of the schematics are drawings of a casing centralized within the borehole. Inside the casing is a dashed circular area representing the logging tool’s radius of investigation. Notice that the small-diameter spinner is eccentralized and investigates the lower portion of the casing, while the full bore spinner is centralized, and investigates a larger area of the flow.

An undulating horizontal segment of a conventional cemented and perforated completion is shown below the tool schematics. Entries of gas and water occur along its length. If the spinner were responsive to the volumetric flow, it would detect the entries, and the flow volume would increase in steps to the left of each entry point. The log section at the bottom of Figure   1 shows how a spinner would actually respond. The small eccentralized spinner, with its high degree of log curve fluctuation, is easiest to understand in this regard.

Flow regime makes a significant impact on spinner performance. For example, spinners may not be effective in stratified flow. A spinner measuring stratified flow would tend to exhibit a response resembling downflow as the light phase moves up the high side of the pipe when the heavy (water) phase falls out and flows down the lower side of the pipe.

In Figure   1 , for example, we see, the spinner detects zero flow prior to gas entry. From the point where the gas entered, the gas will migrate to the top of the borehole and move to the high side of the pipe (toward the left in this example). However, water will also be carried to the left on the high side of the pipe, after which the water will tend to fall back to the low side, since there is no net water production. At some distance beyond the point of water entry, the water fallback will stop, and water will move to the left. This would certainly occur as the crest is approached. The downflow velocity would be high, but would slow down in the trough. In the uphill section, there may yet be some fallback at the low side, depending on the flow rates and angle of the hole. Clearly, the eccentralized small spinner would not be very useful in this environment; indeed, the full-bore spinner is not much better.

Stationary Flow Measurements

Stationary velocity flow measurements include both the diverter flowmeters (basket or packer types) and the tracer ejector. These tools and their responses to flow in the horizontal environment are shown in Figure   2 – Stationary flow measurements in horizontal wells; Smolen (1996).

Figure 2

Diverter-Type Flowmeters

The diverter type of flowmeter has been used effectively in horizontal wells. In an undulating section of a horizontal well, the flowmeter diverter basket can detect fluid entry through the well’s conventional completion and will provide a good quantitative indication of bulk flow rate.

However, if the diverter uses a metal petal basket, its performance will likely be degraded by leakage of the gas phase between the petals and leakage at the point where the petals contact the wall. Diverters also experience a pressure drop associated with flow through the tool. This pressure drop can change the flowing production profile, especially in horizontal wells where pressure drawdowns from formation pressure are not large. Furthermore, diverters may be plagued by debris, which may clog the spinner. This problem is especially prevalent in open-hole completions. Diverters are ineffective in slotted liner completions, since the diverter can force the fluids to simply flow back through the slots and out to the formation–liner annulus, to bypass the basket or packer, as shown in Figure   3 – Problem with basket flowmeters in slotted liner completions; Kessler, et al (1995).

Figure 3

Radioactive tracers

Radioactive tracer techniques use hydrocarbon and water soluble tracers. Some models of tracer equipment include dual tracer ejectors, in which tracers for one phase or the other may be ejected from the tool. The radioactive tracer is ejected and mixes with its compatible phase. One or more gamma ray detectors are then used to detect the tracer and determine the velocity of its associated phase. This tool has been effective in certain applications, and is the basis for the Phase Velocity Log used on Schlumberger’s FlagshipTM tool string, discussed later. Problems with mixing of the tracer and its compatible phase sometimes occur at the phase interface. Increasing the separation distances between the ejector and the detector, or the use of multiple detectors may mitigate these problems. Note that to make sense of this phase velocity data, accurate holdups of each phase must be known.

Fluid Identification Sensors

Fluid identification tools determine which phases are present in the well. Many estimate fluid bulk density, from which they determine the fractions of each of two phases present.

Pressure Differential Devices

The gradiomanometer uses differential pressure transducers to define fluid density. Downhole fluid density can be used for holdup calculations However, gradiomanometers become less effective as well deviations exceed 70. Increasing deviation affects the flow regime, phase segregation and velocity distribution. These can be severely affected by high turbulence – a phenomenon known as the ‘jet effect’. At higher flow rates, friction effects must also be corrected calculating for holdup. In addition, the hydrostatic head created by fluids disappears when two measure points are made at or near the same depth, as seen in horizontal wells.

Nuclear Fluid Density Devices

Nuclear fluid density devices ( Figure   4 – Fluid identification devices in horizontal wells; Smolen, 1996) have been used effectively in horizontal wells.

Figure 4

There are both focused and non-focused tool designs. The non-focused tool has a radius of investigation that fills the entire cross-section of the borehole. Theoretically, the source-to-detector spacing (denoted in Figure   4 as S and D respectively) could be adjusted to optimize the region of investigation for maximum effectiveness. This type of tool is commonly used for gravel pack evaluation. When used to obtain holdup values, uncertainties may be introduced by density anomalies outside of the casing (cement channels or gravel pack voids). These tools are not calibrated for holdup measurements.

Focused nuclear fluid density tools have a radius of investigation that is essentially the radius of the tool housing. The fluid must be in contact with the tool in order for it to be measured. In horizontal wellbores, it is common for such tools to indicate nearly 100% water.

Temperature and Noise Logs

Temperature and noise logs both employ a large region of investigation, extending even beyond the casing. Each of these tools can be useful in a conventional or a slotted liner completion. However, both of these tools are qualitative in their interpretation. Temperature and Noise logs are shown in Figure   5 – Temperature and noise logs in horizontal wells; Smolen (1996).

Figure 5

Temperature Log

The normal temperature gradient of a well tends to change as fluids enter or leave the wellbore. The temperature log can show gas entries by a cooling anomaly, and liquid entries may be detected by their effect upon mixing with the flow. Temperature logs are effective in vertical wells because of the presence of the geothermal gradient. However, in the horizontal environment, such gradients are non-existent and pressure drawdowns are low. As a result, anomalies are likely to be very small or non-existent. Indeed, it is common to record temperature logs on a scale of only one or two degrees across the logging track.

 

Noise Log

Noise logs can probably detect the bubbling gas entry without any trouble. However, low pressure drawdowns on the formation may cause liquid entries to be slow and spread over long intervals. Such entries would produce little noise and would probably be quite difficult to detect.

Oxygen Activation/Water Flow

The oxygen activation effect was first observed as an increase in background count rates from pulsed neutron capture logs. When the tool’s neutron generator produces a neutron burst, any nearby oxygen will be activated to produce an unstable nitrogen isotope with a half-life of slightly more than seven seconds. As the activated nitrogen returns to native oxygen, gamma rays will be given off. If water flows near the tool at a velocity greater than the speed of the logging tool, then the activated oxygen within the water will be carried past the near and far detectors, causing the measured gamma ray count rate at the near and far detectors to increase over the background reading.

The oxygen activation principle has been refined to make quantitative measurements of water velocity. In this application, the tool, which incorporates a pulsed neutron generator and an array of detectors, makes a stationary measurement. A schematic of a stationary velocity test, showing the location of the tool’s near (N) and far (F) detectors, is shown in Figure   6 – Oxygen activation water flow measured in horizontal completions; Smolen (1996).

Figure 6

Essentially, the pulsed neutron generator is used to activate the oxygen nuclei within the flowing water stream. The activated oxygen nuclei give off gamma rays at a known rate as the oxygen returns to its original state. These gamma rays are detected and counted by the tool. The gamma ray count rate can be calibrated against the known oxygen decay rate to ascertain the direction and velocity of the water flow. The count rate will be identical to the known half-life rate if the water is stationary. Count rates will increase if the water moves toward the tool, and will decrease if the water moves away from the tool.

Three detectors are typically spaced at varying distances from the neutron source to measure the fluid velocity before the signal dies away with the fading of the short half-life of the activated oxygen. This technique is very similar in principle to that of the radioactive tracer, except that only the water phase can be measured.

Useful Ancillary Information

An indication of wellbore trajectory is needed to make a reliable interpretation of production log data in horizontal wells, where fluids tend to segregate by phase density because undulations, crests, and troughs influence the behavior of the flows. Ideally, the production logging tool string should have an inclinometer to measure the borehole angle relative to true horizontal. Crests and troughs can then be readily

distinguished. If an inclinometer is not available, then directional data from earlier logging runs or drilling records must be consulted.

The gravel pack log is another important ancillary measurement that may be needed for slotted liner completions. The log may help to determine whether the formation has collapsed onto the liner. In areas where the formation has collapsed, annular flows will be diverted into the liner thus appearing as a fluid entry, while providing no true indication of the zone that the fluid was produced from. However, along the interval in which the formation collapsed, the completion essentially resembles a "conventional" completion, so the flow in this interval is more easily measured and understood.

A gamma ray tool and casing collar locator should be included in the toolstring to correlate the production log to open-hole data or earlier production log runs.

 

Production Logging Tools Designed For Horizontal Wells

A number of new production logging tools have been developed specifically for horizontal wells. Each service company has its own unique approach to evaluating horizontal multiphase flow; there are no generic measurements within this class of new tools. Some of the sensors described can be used in vertical or deviated holes, as well as in horizontal wells.

Most toolstrings employ a combination of conventional production logging sensors and special sensors designed for horizontal wells. This combination provides data redundancy and cross-referencing for assessing the quality of the interpretation. As well deviations vary, some sensors will work more effectively in one part of the wellbore than they will in another part of the well. When different sensors point to the same conclusion, they bolster the strength of the interpretation. When there is disparity between sensors, then the engineer can decide which sensor should be expected to provide the most reliable reading for any particular interval.

This discussion focuses on the approaches adopted by some of the leading innovators in petroleum technology, though other tools and technologies may have been developed by any of a wide number of smaller logging companies. To date, three of the leading service companies have directed their efforts toward measuring multiphase flow rates in horizontal wells having either conventional open hole or cased, cemented, and perforated completions. In this rapidly changing technology, new sensors are currently being developed by each of the major service companies. Contact your local service company representatives for the latest details. Internet listings for the three service companies discussed here are listed below:    

Baker Atlas:  http://www.bakeratlas.comHalliburton Energy Services:  http://www.halliburton.comSchlumberger Oilfield Services:  http://www.slb.com

Schlumberger

The first tool string designed to log horizontal flow was the Schlumberger PLFlagshipTM Production Logging Tool String. The tool was introduced in 1996 following collaboration between British Petroleum and Schlumberger to develop technology particularly suited for the horizontal well environment. This collaboration produced innovations that are featured in the Schlumberger PSPlatformTM, a new-generation production logging system which provides improved measurements through collocation of critical sensors. The tools are shown schematically in Figure 1 – Schlumberger Flagship production logging toolstring; courtesy Schlumberger Oilfield Services.

Figure 1

New measurements featured on the PL Flagship string include the PVLTM Phase Velocity Log using the RSTTM Reservoir Saturation Tool and the FloView PlusTM cross-sectional fluid hold-up imager. The RST is also used to generate the WFLTM Water Flow Log using the tool’s oxygen activation capability. Conventional sensors for flow evaluation include a full-bore flowmeter and a conventional pressure and temperature sonde. The response of the full-bore flowmeter and the temperature recorder is discussed under the heading entitled Conventional Production Logging Tools.

The RST is a pulsed-neutron tool capable of making both sigma and carbon/oxygen measurements. It is set up much like a conventional capture tool with both near and far gamma ray detectors. There is also a third gamma ray detector located further

downstream on the tool, with spacing between the three detectors set to obtain the optimal measure of water flow velocity.

The Water Flow Log (WFL) is based on the activated oxygen technique. A 14 MeV neutron burst activates the oxygen in water molecules as they flow past the tool’s neutron generator. Gamma rays are given off by the activated oxygen as it returns to the steady state. The gamma rays and travel time are measured as the water flows the known distance between the neutron generator and the gamma ray detector. This technique is used only for water velocity, and is not able to provide oil velocity measurements.

The Phase Velocity Log (PVL), measures the separate velocities of the oil phase and the water phase. The measurements depend on a technique borrowed from radioactive tracer velocity logging, discussed in the section entitled Stationary Flow Measurements (see Figure 2 – Stationary flow measurements in horizontal wells; Smolen, 1996).

Figure 2

The fluid marker ejector section (labeled E on the schematic) contains both water and oil tracer fluids. The fluids are laced with a soluble gadolinium compound that has a high capture cross-section, but which is not radioactive. When a tracer fluid is

ejected, the tracer fluid seeks its phase, travels with that phase, and is detected as it passes the RST. The RST detects the tracer fluid by monitoring the borehole capture cross section after the tracer is ejected. The RST measures the time of travel from the ejector to the RST.

If L is the distance between the ejector and the RST and t is the time of travel between those points, then the velocity of that phase is simply:

V = L/tThe FloView tool, shown in Figure 3 – FloView schematic; courtesy of Schlumberger Oilfield Services, is used to determine phase holdup.

Figure 3

The tool utilizes four centralizer arms; each with a tiny resistance probe positioned a short distance from the wall. In the vertical or moderately deviated environment, these probes detect bubbles and then average the resistivity readings from the four probes to calculate a holdup value. High and low resistivity values measured across a threshold band allow the tool to discriminate between water and hydrocarbon phases. Water holdup is calculated from the span of time during which the voltage measurement falls within a particular voltage threshold. Bubble count is determined from the number of voltage oscillations across the threshold. Water holdup and bubble counts are independently mapped from each probe.

To effectively log within the horizontal environment, two sets of centralizer arms (eight probes) are run in tandem, with one sonde rotated 45 degrees relative to the other. When run in this dual mode, the service is called FloView Plus. This configuration assures that a resistivity probe is positioned at 45-degree increments around the wellbore, providing eight independent, local holdups and bubble counts.

A relative bearing measurement tracks tool rotation and the positions of each probe relative to the high and low sides of the hole. This information is used to generate an oriented map of fluid segregation. In the horizontal environment, this dual sonde arrangement provides information on the water/hydrocarbon interface in stratified flow, as shown on Figure 4 – FloView Plus detects oil-water interface; courtesy of Schlumberger Oilfield Services. The probes can also detect intermittent hydrocarbon/water flows.

Figure 4

The holdup measurement is not affected by jet effect, friction, or extreme water cut values. Note that the tool cannot discriminate between oil and gas.

If only two phases are present downhole, there will be sufficient information to determine the volumetric flow rates of each of the two phases. Once the phase velocities and holdups are known, then the volumetric flow rates of each phase, , is given by the equation:

where:

Q = the volumetric flow rate,

V = the phase velocity,

A = the cross section of the pipe,

Y = the holdup, and

C = flow profile correction factor.

When three phases are present, the RST may be used as a three-phase holdup tool. The three-phase measurement is quite difficult and complex. Essentially, the RST emits neutrons from an electronically activated source. These neutrons interact with nuclei in the formation, which then give off gamma rays as the excited nuclei return to their original state. The gamma rays are counted by the near detector (spaced one foot from the neutron source), and the far detector (spaced two feet from the source). The gamma ray spectra measured by each detector is used to determine the carbon/oxygen ratio. This measurement is affected by the oil and water in the borehole, as well as by the formation itself. The near/far (N/F) count ratio is particularly sensitive to gas. The C/O measurements are used to determine the holdups of water, and oil, while the N/F ratio is used for gas holdups, assuming that the formation characteristics are known.

A brief review of tool functions is shown below:

Full Bore Spinner—Measures velocity, but is marginally useful

Phase Velocity Log—Measures the velocity of the water phase and the oil phase

FloView Plus—Locates the hydrocarbon/water interface or water holdup

WFL—Measures water velocity

Though capable of obtaining three-phase holdups, the Flagship is not capable of determining the velocity of the gas phase. Schlumberger is developing new production logging sensors to provide more direct measurements of those properties currently determined by calculation. In particular, the PS Platform is expected to evolve with the addition of new sensors to become easily configurable for all flow regime scenarios.    

Halliburton

The Halliburton tool configuration is shown in Figure 5 – Halliburton production logging tool configuration; courtesy of Halliburton Energy Services.

Figure 5

The main new production log sensors include the Gas Holdup ToolTM (GHTTM), and the Spectral Flow LogTM (SpFLTM), which will be discussed in more detail below. Other tools featured in this toolstring include:

Gamma Ray and Casing Collar Locator: provide correlation with other logs

Temperature Tool: identifies temperature changes which may indicate intervals of fluid entry or escape

Pressure Tool: for analyzing pressure drawdown or buildup

Fluid Density Tool: uses gamma ray absorption to measure density of the borehole fluid

Hydro Tool: uses dielectric measurements to distinguish water from hydrocarbons.

The GHT is shown schematically in Figure 6 – Gas Holdup Tool for vertical and horizontal flow; courtesy of Halliburton Energy Services.

Figure 6

Unlike center-sample tools, the GHT makes fullbore measurements which are not affected by the tool’s centralized position within the flowing stream. Centralization enables the tool to work at any angle of wellbore inclination – including horizontal.

The GHT uses a low-energy gamma ray source and relies on a combination of Compton scattering and photoelectric absorption of gamma ray energy to determine fluid holdup. A low-energy source emits gamma rays that are not capable of penetrating the casing, therefore, the measurement are not influenced by conditions outside the casing. Unlike the nuclear fluid density measurements, in which a decrease in counts implies a greater fluid density, the count rate increases with density when the back-scatter gamma rays are counted. The relationship between count rates and gas holdup depends on the casing size and the liquid component of the fluid, but is nearly linear.

After the gamma rays lose energy through Compton scattering, photoelectric absorption of gamma ray energy can take place. Because oil and water exhibit offsetting photoelectric and Compton sensitivities, very little difference in count rate is seen between either phase. Therefore, the gas holdup measurement is almost totally independent of the mixture or salinity or the oil and water phases.

Wellbore deviation will not affect the measurement of the gas holdup. When three phases are present, it measures the gas and liquid holdups. If no gas is present, the GHT is capable of discriminating oil holdup from water holdup.

The SpFL is actually a pulsed neutron tool that has been adapted for oxygen activation water flow measurements. This tool has the unique capability to determine an index related to the distance between gamma rays given off by activated oxygen and the detector. This index can be used to discriminate water flow inside the casing from that occurring outside the casing.

With the GHT and other conventional holdup sensors, the Halliburton tool string can be used to determine the holdup of each of the three phases. If the Reservoir Monitoring ToolTM (RMTTM) is on the tool string, it can be used to determine the carbon/oxygen ratio of borehole fluids and hence discriminate the oil and water phase fractions within the liquid phase holdup. The use of the diverter basket flowmeter coupled with the oxygen activation water flow measurement provides good answers in two-phase flow, but will not resolve volumetric flow rates of gas and oil in three-phase flow.

CASE STUDIES

This section discusses production logging examples obtained from three major logging companies. The first example shows how conventional logging tools obtain useful information in horizontal wellbores. The other case studies describe examples of logs obtained with tools developed especially for the horizontal logging environment.

Western Atlas - Conventional Production Logging Tools

Despite challenges imposed by horizontal wellbores, early log runs with conventional production logging tools proved useful in obtaining important diagnostic information. Though conventional tools were not able to provide the detail needed to analyze multiphase flow, they were quite capable of pinpointing water entry locations (for isolation to reduce water production), and they were also able to characterize flow to a limited extent. The paper presented by Nice at the 1992 World Oil Horizontal Well Conference describes how conventional logging tools were used to qualify fluid type and flow rates in an effort to optimize remediation efforts in a horizontal well.

A major operator drilled a horizontal well in the Gulf of Mexico with 1300 feet of horizontal displacement. The 8.5-inch wellbore was completed in an unconsolidated sand formation using a 7-inch uncemented liner and 721 feet of prepacked screen spaced over an interval of 831 feet. The production liner consisted of five prepacked screens, each separated by a 20 foot section of blank pipe ( Figure 1 – Schematic of horizontal well; courtesy Baker Atlas and World Oil Magazine).

Figure 1

The unconsolidated sand of the producing zone was expected to collapse around the liner. Because openhole logs indicated that the wellbore had penetrated a water sand, the operator installed two check valves below the screens when the liner was set 257 feet off bottom.

The well initially produced 1300 STB/D of oil, 300 B/D of water, and 800 MCF/D of gas. Within 6 months, however, production changed drastically. Oil production declined to 350 STB/D, while water production increased to 1700 B/D.

The operator ran a suite of conventional production logs to determine water entry points, production rates, and the extent to which the unconsolidated sand collapsed around the liner.

The operator selected Western Atlas to log the well, and the following tools were run on coiled tubing:

Radioactive isotope injector (Flolog): provided total flow profile

Oxygen activation (HydrologSM): provided water (only) profile

Surface readout pressure (SRP): provided flowing/shutin pressure

Gravel pack evaluation (Photon): provided borehole integrity evaluation

Log Measurements

The Flolog indicated fluid entry at screens 1, 2, 3, and 5 (numbered from the bottom up) ( Figure 2 – Results of log run; courtesy Baker Atlas and World Oil Magazine).

Figure 2

Screen 1 accounted for a total flow of 1700 B/D near its center. The upper quarter of screen 2 and all of screen 3 combined to contribute 3500 B/D. No additional flow was measured along screen 4. The upper two-thirds of screen 5 produced 2500 B/D, but no flow was measured in the lower portion of the screen. The total flow rate above the screened section was measured at 2200 B/D. Velocity measurements from the Flolog do not account for water fallback, holdup, or the wellbore space occupied by each phase as the rate is calculated.

The Hydrolog measured a similar profile to the Flolog, but three points produced at flow rates that exceeded the tool’s measurement capability. An entry of 1300 BWPD is indicated at the midpoint of screen 1. The upper end of screen 2 produced 2000 BWPD, just below the major influx indicated on the Flolog between screens 2 and 3. The water rate above this point averaged 1300 BWPD to the upper end of the screened section.

Pressure measurements from the SRP tool were used to compare downhole shut-in pressure and flowing pressure. This comparison revealed a pressure differential of 470 psi. Along lower points of the wellbore, a 5 to 7 psi increase in flowing pressure was attributed to additional water holdup.

The Photon log indicated that unconsolidated sand in the producing formation had indeed collapsed around the liner in all but two intervals, located along the upper part of the undulating wellbore. The collapse effectively restricted annular flow outside the screen. The voids found on the photon log correlated to zones of higher

shale content shown on openhole logs. Increased shale content may have contributed to formation strength and borehole stabilization along intervals that did not collapse around the screen.

Observations –

Total flow rates were greater than total production at several points within the wellbore. Rates at these points were measured several times for verification, and were measured again after a stabilizing flow period. The production profile was constant over a total monitoring period of about 8 hours. A directional survey was plotted on the log, which helped to show that these high velocities were found near higher elevations of the undulating wellbore. In these intervals, the water fallback, produced water, and oil all shared the available annular space. Under these flow conditions, the velocities of the oil and gas phase accelerate until the wellbore changes to a more neutral angle.

A comparison between the water (only) profile and the total flow profile showed a difference in flow rates that was attributed to oil production. This conclusion is supported by lower flowing pressure measured by the SRP, which would indicate lower water holdup. The total flow rate revealed major production entering at the upper end of screen 2 and the entire screen 3 interval. Additional production was indicated at the upper two-thirds of screen 5.

Recommendations

Based on these interpretations, the operator elected to isolate the water zone producing through screen 1. Coiled tubing was used to insert an inflatable bridge plug at the portion of liner between screen 1 and screen 2. After setting the bridge plug, water production decreased by 1200 B/D, while the oil rate increased by 500 STB/D.

Conclusion

This example shows that conventional tools were not used to measure flow rates for each phase, yet they still worked well in the presence of multiphase flow and undulating borehole conditions. These logs were used to identify the primary water entry point so that it could be isolated. By qualifying fluid type and flow rates, the operator was able to take appropriate remedial action to substantially improve well production.  

Schlumberger – Flagship Production Logging Service

Figure 3 – Comparing FloView Plus and RST three-phase holdup measurements; courtesy of Schlumberger Oilfield Services, shows a cased, cemented, and perforated completion, logged by Schlumberger Oilfield Services.

Figure 3

This newly drilled horizontal well was producing 95% water and had twice the gas oil ratio of neighboring wells. The operator suspected that the well was producing free gas through a fault connected to the gas cap.

Here, Schlumberger’s FloView Plus and the RST three-phase analysis package were run. The well contour is plotted on the vertical depth scale, and clearly shows an undulating wellbore. Both the RST and the FloView imaging show that water is the dominant phase in the uphill portion of the leftward-moving flow. As the water flows over the crest, the oil holdup increases dramatically, even though no perforations are present. This effect is, of course expected.

The FloView resistivity probes cannot differentiate between oil from water, but the RST can. The RST shows the presence of gas beginning suddenly at the perforations located at in the vicinity of 720 ft. Since it occurs midway along the down-slope and stays approximately constant, the data implies that this particular set of perforations is contributing the gas. The holdups are not usually sufficient to conclusively make an interpretation, and velocity data is typically also required.  

Halliburton – Gas Holdup Tool

Figure 4 – Flow regime and water fallback; courtesy of Halliburton Energy Services shows how bubbles and mist are detected.

Figure 4

The bottom of the log shows agreement between gas holdup curves derived from the center-sample fluid density tool (YG curve), and from the fullbore Gas Holdup Tool (YGHT curve). This data, combined with the fullbore flowmeter data indicate small bubbles dispersed throughout the fluid in a bubble flow regime.

At the perforation just below X230, we see separation between the YG curve and the YGHT curve, caused by water fallback. The fluid density tool, being a center-sample device, measures a higher gas holdup. The GHT shows a lower gas holdup as water falls back along the casing wall. This water is not being lifted to surface. Near the top of the log, the agreement between the YG curve and the YGHT curves, combined with the flowmeter data, indicate mist flow, with a high percentage of gas, and a very low amount of water, dispersed as mist.    

Exercises

1.Slotted liners can be very difficult to log in the horizontal environment since:

a. The flow may vary because there are no slots at the collars. b. Independent flows may occur in the annulus outside of the liner. c. The liner inclination and open borehole inclination may not coincide. d. The tools can hang up in the slots.

2. In a well that is deviated in excess of ninety degrees, which one of the following is not generally true if three phases are being produced?

a. The heel of the well will have a high water holdup. b. The toe (TD) of the well will have a high gas holdup. c. Debris will accumulate at the toe. d. Debris will accumulate at the heel.

 

3. Which of the following logging techniques would be best for a production logging job in a producing open hole horizontal completion?

a. Coiled tubing. b. Tractor. c. Conventional Wireline. d. Pump down.

4. The following Fluid Identification Device is not useful in a horizontal well:

a. FloView b. Nuclear Fluid Density c. Gradiomanometer

 

5. The Gas Holdup Tool, GHT, from Halliburton:

a. Will detect an increase in gamma ray counts in the presence of gas. b. Will detect a decrease in gamma ray counts in the presence of gas. c. Measures backscattered gamma rays. d. Works at any deviation angle.

6. The Phase Velocity Log, PVL, from Schlumberger does not:

a. Use the RST on the Flagship tool string. b. Eject radioactive tracers into the well for fluid flow measurement. c. Eject either water or oil containing a high capture cross section element. d. Measure the velocity of each phase.

7. Schlumberger’s FloView Plus does not:

a. Utilize four resistivity probes on each of its sondes. b. Locate the water –hydrocarbon contact. c. Discriminate water, oil, and gas. d. Stagger one sonde 45 degrees relative to the other to assure complete coverage.

8. Oxygen Activation tools

a. Use a chemical Cobalt radioactive source. b. Are used to measure hydrocarbon flow. c. Are used to measure water flow. d. Are frequently used for horizontal well holdup measurements.

9. Which of the following tools is most useful on a production logging string in a conventionally completed and clean horizontal well?

a. Focused Nuclear Fluid Density Tool b. Capacitance Holdup Meter c. Full Bore Spinner d. Diverter Flowmeter

10. Conventional production logging tools should never be used in horizontal wells.

a. True. b. False.