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Borehole imaging

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The term "borehole imaging" refers to those logging and data-processing methods that are used to produce centimeter-scale images of the borehole wall and the rocks that make it up. The context is, therefore, that of open hole, but some of the tools are closely related to their cased-hole equivalents. Borehole imaging has been one of the most rapidly advancing technologies in wireline well logging. The applications range from detailed reservoir description through reservoir performance to enhanced hydrocarbon recovery. Specific applications are fracture identification, analysis of small-scale sedimentological features, evaluation of net pay in thinly bedded formations, and the identification of breakouts (irregularities in the borehole wall that are aligned with the minimum horizontal stress and appear where stresses around the wellbore exceed the compressive strength of the rock).

The subject area can be classified into four parts:

  • Optical imaging
  • Acoustic imaging
  • Electrical imaging
  • Methods that draw on both acoustic and electrical imaging techniques using the same logging tool

Prensky[1] has provided an excellent review of this important subject.

Optical imaging

Downhole cameras were the first borehole-imaging devices. Today they furnish a true high-resolution color image of the wellbore. The principal drawback is that they require a transparent fluid in liquid-filled holes. Unless transparent fluid can be injected ahead of the lens, the method fails. This requirement has limited the application of downhole cameras. The other major historic limitation, the need to wait until the camera is recovered before the images can be seen, has fallen away with the introduction of digital systems.

The principal application of downhole video has been in air-filled holes in which acoustic and contact electrical images cannot be obtained. Most applications described in the literature are directed at fracture identification or casing inspection.

Acoustic imaging

Acoustic borehole-imaging devices are known as "borehole televiewers." They are mandrel tools and provide 100% coverage of the borehole wall. The first borehole televiewer, operating at a relatively high ultrasonic frequency of 1.35 MHz, was developed by Mobil Corp. in the late 1960s.[2][3] Since then, a succession of improvements have been made, principally through advances in digital instrumentation and computer-image enhancement. Modern tools contain a magnetometer to provide azimuthal information.

The borehole televiewer operates with pulsed acoustic energy so that it can image the borehole wall in the presence of opaque drilling muds. Short bursts of acoustic energy are emitted by a rotating transducer in pulse-echo mode. These travel through the drilling mud and undergo partial reflection at the borehole wall. Reflected pulses are received by the transducer. The amplitudes of the reflected pulses form the basis of the acoustic image of the borehole wall. These amplitudes are governed by several factors. The first is the shape of the borehole wall itself: irregularities cause the reflected energy to scatter so that a weaker reflected signal is received by the transducer. Examples of these irregularities are fractures, vugs, and breakouts. Moreover, the reflected signal is degraded in elliptical and oval wellbores because of non-normal incidence. The second factor is the contrast in acoustic impedance between the drilling mud and the material that makes up the borehole wall. Acoustic impedance provides an acoustic measure of the relative firmness of the formations penetrated by the wellbore material and, thus, it has the capability of discriminating between different lithologies, with high acoustic impedance giving rise to high reflected amplitudes. Borehole televiewers work best where the borehole walls are smooth and the contrast in acoustic impedance is high. The third factor is the scattering or absorption of acoustic energy by particles in the drilling mud. This problem is more serious in heavily weighted muds, which are the most opaque acoustically, and it gives rise to a loss of image resolution.

The borehole televiewer can provide a 360° image in open or cased holes. It can operate in all downhole environments other than gas-filled holes. The travel time for the acoustic pulse depends on the distance between the transducer and the borehole wall, as well as the mud velocity. Modern televiewers allow some independent method of measuring the mud velocity. Thus, the borehole televiewer also operates as an acoustic caliper log. For best results, the tool should be centered, although correction algorithms have been developed for eccentered surveys.

An example of a modern ultrasonic imaging tool is Schlumberger’s Ultrasonic Borehole Imager (UBI™), which is based on the cased-hole USI with two hardware modifications: a focused transducer was fitted for improved resolution, and an openhole centralizer was added.[4] The tool incorporates a rotating transducer within a subassembly. The size of the subassembly is selected on the basis of the diameter of the hole that is to be logged. The direction of rotation of the subassembly governs the orientation of the transducer. There are two positional modes:

  • The standard measurement mode with the transducer facing the borehole wall (Fig. 1)
  • The fluid-property mode with the transducer facing a target within the tool

In standard mode, the tool measures both amplitude and transit time at one of two frequencies, 250 or 500 kHz, with recommended logging speeds of 800 ft/hr [244 m/hr] and 400 ft/hr [122 m/hr], respectively, where logging speed is primarily determined by vertical sampling density and the rate of transducer rotation. The higher frequency allows a sharper image resolution of 0.2 in. [5 mm], but it is less effective in highly dispersive muds where the lower frequency should be used. The tool can also be used for investigating the geometry of the inner surface of casing where it is not desired to measure resonant ringing as an indicator of cement integrity.

  • Fig. 1 – Principle of the Ultrasonic Borehole Imager (UBI™). The UBI measures reflection amplitude and radial distance using a direct measurement of mud velocity.[4]

    Fig. 1 – Principle of the Ultrasonic Borehole Imager (UBI™). The UBI measures reflection amplitude and radial distance using a direct measurement of mud velocity.[4]

Baker Atlas’ Circumferential Borehole Imaging Log (CBIL™) has a similar range of capability but is rated to 20,000 psi [138 MPa] and 400°F [204°C]. Halliburton’s Circumferential Acoustic Scanning Tool (CAST™) additionally offers simultaneous casing inspection and cement evaluation. It is rated to 20,000 psi [138 MPa] and 350°F [177°C], as is Schlumberger’s UBI. Both of these tools predated the UBI.[5][6]

Data are usually presented as depth plots of enhanced images of amplitude and borehole radius. Applications include:

  • Fracture detection
  • Analysis of borehole stability
  • Identification of breakouts

Fig. 2 shows an example of breakout identification using an ultrasonic borehole televiewer.[7] The data presented are from the Cajon Pass scientific borehole in southeastern California. The aim was to investigate the orientation and magnitudes of in-situ stresses using borehole-image data. The televiewer has superseded multiarm dipmeter calipers for these applications. Although the caliper can reveal the orientation of breakouts, the tool provides little information about their size and, more generally, about the overall shape of the borehole wall. The ultrasonic televiewer can detect much smaller features than the multiarm caliper and can distinguish between features that are stress induced and those that are drilling artifacts.

  • Fig. 2 – Example of breakout detection using an ultrasonic borehole televiewer. Breakouts are indicated by the low acoustic amplitude of the reflected signal, shown here as darker areas. The breakouts are rotated because of a drilling-induced slippage of localized faults[7] (Courtesy of SPWLA.)

    Fig. 2 – Example of breakout detection using an ultrasonic borehole televiewer. Breakouts are indicated by the low acoustic amplitude of the reflected signal, shown here as darker areas. The breakouts are rotated because of a drilling-induced slippage of localized faults[7] (Courtesy of SPWLA.)

Electrical imaging

Microresistivity imaging devices were developed as an advancement on dipmeter technology, which they have mostly superseded. Traditionally, they have required a conductive borehole fluid, but it will be seen later that this requirement has been obviated by oil-based-mud imaging tools. Originally, in the mid-1980s, they comprised two high-resolution pads with 27 button electrodes distributed azimuthally on each. This arrangement provided a coverage of 20% of an 8.5-in. [216-mm] wellbore in a single pass.[8] This coverage was doubled by the development of a four-pad microresistivity imaging tool, each with 16 button electrodes arranged azimuthally in two rows of eight. The number of electrodes was limited by tool-transmission electronics.[9] Coverage was increased still further through the use of pads with flaps that opened to give a borehole-wall coverage of 80% in an 8-in. [203-mm] hole.[10] In another approach, the six-arm dipmeter evolved into a six-pad microresistivity imager,[11] Halliburton’s Electrical Micro-Imaging tool (EMI™). Each pad contained 25 button electrodes also arranged azimuthally in two rows. With this arrangement, a 60% coverage was achieved in an 8-in. [203-mm] hole.

The measurement principle of the microresistivity imaging devices is straightforward. The pads and flaps contain an array of button electrodes at constant potential (Fig. 3). An applied voltage causes an alternating current to flow from each electrode into the formation and then to be received at a return electrode on the upper part of the tool. The microelectrodes respond to current density, which is related to localized formation resistivity. The tool, therefore, has a high-resolution capability in measuring variations from button to button. The resistivity of the interval between the button-electrode array and the return electrode gives rise to a low-resolution capability in the form of a background signal. The tool does not provide an absolute measurement of formation resistivity but rather a record of changes in resistivity. The resolution of electrical microimaging tools is governed by the size of the buttons, usually a fraction of an inch. In theory, any feature that is as large as the buttons will be resolved. If it is smaller, it might still be detected. The tools can be run as dipmeters.

  • Fig. 3 – Measurement principle of microresistivity imaging devices illustrated by Schlumberger’s Formation MicroImager (FMI™). (Courtesy of Schlumberger.)

    Fig. 3 – Measurement principle of microresistivity imaging devices illustrated by Schlumberger’s Formation MicroImager (FMI™). (Courtesy of Schlumberger.)

Data are presented as orientated, juxtaposed pad outputs whereby the cylindrical surface of the borehole wall is flattened out. This has the effect of distorting quasiplanar features such as dipping layers or fractures, which appear as sinusoidal in the data display. Fig. 4 shows a typical data display and identifies some of the key features.

  • Fig. 4 – Recognition of sedimentary and structural features in microresistivity images. These Formation MicroImager (FMI™) images have been used to generate the dip information in Track 2. The combination of FMI images and dip data clearly differentiates the eolian and interdune sands in this 8.5-in. [216 mm] borehole. (Courtesy of Schlumberger.)

    Fig. 4 – Recognition of sedimentary and structural features in microresistivity images. These Formation MicroImager (FMI™) images have been used to generate the dip information in Track 2. The combination of FMI images and dip data clearly differentiates the eolian and interdune sands in this 8.5-in. [216 mm] borehole. (Courtesy of Schlumberger.)

Electrical microimaging tools have proved superior to the ultrasonic televiewers in the identification of sedimentary characteristics and some structural features such as natural fractures in sedimentary rocks. They are especially useful for net-sand definition in thinly laminated fluvial and turbidite depositional environments.

There are several microimaging tools available, each with similar capability. For example, Schlumberger’s fullbore FMI™ has two horizontally offset rows of 24 button electrodes on each pad and each flap, making a total of 192 electrodes (Fig. 5). The buttons have a diameter of 0.2 in. [5 mm], which determines the intrinsic spatial resolution of the tool. However, features as small as 50-μ fluid-filled fractures can be detected (but not fully resolved). Current is focused into the formation, where a depth of investigation of several tens of centimeters is claimed. However, the image probably relates to a depth of investigation of no more than 0.8 in. [20 mm]. The high-resolution image is normalized with respect to the low-resolution part of the signal or to another resistivity logging tool.

  • Fig. 5 – The Formation MicroImager (FMI™) pad and flap assembly with horizontally offset rows of electrode buttons. (Courtesy of Schlumberger.)

    Fig. 5 – The Formation MicroImager (FMI™) pad and flap assembly with horizontally offset rows of electrode buttons. (Courtesy of Schlumberger.)

The conventional microresistivity imaging devices require a conductive mud in which to function. However, drilling with oil-based or synthetic muds has increased because of the improved drilling efficiency and greater borehole stability relative to water-based muds. Rather than have to change out the mud specifically for a microresistivity imaging survey, two other approaches have been pursued. The first has been to develop a new synthetic mud that retains all the stabilizing characteristics of conventional synthetic muds but is sufficiently conductive to permit microresistivity imaging measurements.[12] The second has been to develop an electrical imaging device that operates in oil-based muds. This problem was addressed by the so-called oil-based mud dipmeters. These are conventional four-arm dipmeters for which the four microelectrodes are replaced by microinduction sensors.[13] More recently, contact resistivity methods have been applied in oil-based or synthetic muds.[14] Schlumberger’s Oil-Base MicroImager (OBMI™) uses four pads positioned at 90° to one another to achieve a 32% coverage of an 8-in. [203-mm] wellbore. Each pad contains two current electrodes and a set of five pairs of closely spaced potential electrodes positioned centrally between the current electrodes (Fig. 6). The arrangement is reminiscent of the Schlumberger electrode array that is still used for surface resistivity sounding in geoelectrical prospecting. However, in this downhole case, the aperture of the sensor gives an intrinsic spatial resolution of 0.4 in. [10 mm] with a nominal depth of investigation of 3.5 in. [90 mm]. Although the OBMI tool is sensitive to borehole rugosity, it has performed well in oil-based and synthetic muds for which water content lies between 1 and 30%. Examples of microresistivity image displays are shown in Figs. 7 and 8.

  • Fig. 6 – Principle of the Oil-Base MicroImager (OBMI™). A current, i, is applied between electrodes A and B. The potential difference, δV, is measured between electrodes C and D. An apparent formation resistivity, Rxo, is calculated using Ohm’s law and an array geometry factor.[14] (Courtesy of SPWLA.)

    Fig. 6 – Principle of the Oil-Base MicroImager (OBMI™). A current, i, is applied between electrodes A and B. The potential difference, δV, is measured between electrodes C and D. An apparent formation resistivity, Rxo, is calculated using Ohm’s law and an array geometry factor.[14] (Courtesy of SPWLA.)

  • Fig. 7 – Example of the Formation MicroImager (FMI™) run in highly laminated sediments. The FMI tool is able to detect laminations as thin as 0.2 in. [5 mm]. In contrast, note the undiagnostic smoothed form of the conventional array induction logs around depth XX30 ft in Track 2. Microresistivity tools are able to detect pay in places where conventional log analysis might overlook it. Note the more complete description of borehole geometry afforded by the X and Y calipers in Track 1. (Courtesy of Schlumberger.)

    Fig. 7 – Example of the Formation MicroImager (FMI™) run in highly laminated sediments. The FMI tool is able to detect laminations as thin as 0.2 in. [5 mm]. In contrast, note the undiagnostic smoothed form of the conventional array induction logs around depth XX30 ft in Track 2. Microresistivity tools are able to detect pay in places where conventional log analysis might overlook it. Note the more complete description of borehole geometry afforded by the X and Y calipers in Track 1. (Courtesy of Schlumberger.)

  • Fig. 8 – Example of an electrical microimage using the six-arm Electrical Micro-Imaging Tool (EMI™). Static (Track 2) and dynamic (Track 5) image enhancement has revealed a laminated sand/shale sequence and delivered computed dips (Track 4) of the sedimentary strata. The enhanced images also reveal drilling-induced fractures, which cut vertically across the bedding as sensed by Pads 2 and 5. (Courtesy of Halliburton.)

    Fig. 8 – Example of an electrical microimage using the six-arm Electrical Micro-Imaging Tool (EMI™). Static (Track 2) and dynamic (Track 5) image enhancement has revealed a laminated sand/shale sequence and delivered computed dips (Track 4) of the sedimentary strata. The enhanced images also reveal drilling-induced fractures, which cut vertically across the bedding as sensed by Pads 2 and 5. (Courtesy of Halliburton.)

Conjunctive acoustic and electrical imaging

To some extent, the ultrasonic and electrical images are complementary because the ultrasonic measurements are influenced more by rock properties, whereas the electrical measurements respond primarily to fluid properties. Another difference is that the ultrasonic image covers 360°, whereas the electrical image is somewhat less than 80% of the surface of an 8-in. [203-mm] wellbore. Ultrasonic measurements can be made using the same tool in all types of drilling mud, and this can facilitate interwell comparisons. On the other hand, most microresistivity imaging devices require a water-based mud; otherwise, an alternative tool, such as the OBMI, has to be used.

These differences can be accommodated through the combined use of electrical and acoustic imaging. As an example, Baker Atlas’ Simultaneous Acoustic and Resistivity Imager (STAR™) uses a combination of a CBIL and a six-pad resistivity imager with 12 electrodes per pad. The tool delivers a more complete data set than is achievable using either of the components separately. The combined tool is 86 ft [26.2 m] in length with a diameter of 5.70 in. [145 mm]. It is rated to 20,000 psi [138 MPa] and 350°F [177°C].

References

  1. ↑ Prensky, S. 1999. Advances in Borehole Imaging Technology and Applications. In Borehole Imaging: Applications and Case Histories, ed. M. Lovell, G. Williamson, and P. Harvey, 159, 1-43. London: Geological Soc. Special Publications.
  2. ↑ Zemanek, J., Caldwell, R.L., Glenn Jr., E.E. et al. 1969. The Borehole Televiewer--A New Logging Concept for Fracture Location and Other Types of Borehole Inspection. J Pet Technol 21 (6): 762-774. SPE-5402-PA. http://dx.doi.org/10.2118/2402-PA.
  3. ↑ Zemanek, J., Glenn, E.E., Norton, L.J. et al. 1970. Formation evaluation by inspection with the borehole televiewer. Geophysics 35 (2): 254–269. http://dx.doi.org/10.1190/1.1440089.
  4. ↑ 4.0 4.1 Hayman, A.J., Parent, P., Cheung, P. et al. 1998. Improved Borehole Imaging by Ultrasonics. SPE Prod & Oper 13 (1): 5-14. SPE-28440-PA. http://dx.doi.org/10.2118/28440-PA.
  5. ↑ Faraguna, J.K., Chance, D.M., and Schmidt, M.G. 1989. An Improved Borehole Televiewer System: Image Acquisition, Analysis and Integration. Presented at the SPWLA 30th Annual Logging Symposium, 1989. SPWLA-1989-UU.
  6. ↑ Seller, D., Torres, O., Goetz, J. et al. 1990. Field Performance of a New Borehole Televiewer Tool and Associated Image Processing Techniques. Presented at the SPWLA 31st Annual Logging Symposium, - 1990. SPWLA-1990-H.
  7. ↑ 7.0 7.1 Barton, C.A., Zoback, M.D., Moos, D. et al. 1997. Utilizing Wellbore Image Data To Determine The Complete Stress Tensor: Application To Permeability Anisotropy And Wellbore Stability. The Log Analyst 38 (6). SPWLA-1997-v38n6a1.
  8. ↑ Chen, M.Y., Ekstrom, M.P., Dahan, C.A. et al. 1987. Formation Imaging With Microelectrical Scanning Arrays. The Log Analyst 28 (3): 294. SPWLA-1987-v28n3a4.
  9. ↑ Boyeldieu, C. and Jeffreys, P. 1988. Formation Microscanner: New Developments. Trans., Soc. of Professional Well Log Analysts 11th European Formation Evaluation Symposium, Paris, paper X.
  10. ↑ Safinya, K.A., Le Lan, P., Villegas, M. et al. 1991. Improved Formation Imaging With Extended Microelectrical Arrays. Presented at the SPE Annual Technical Conference and Exhibition, Dallas, Texas, 6-9 October 1991. SPE-22726-MS. http://dx.doi.org/10.2118/22726-MS.
  11. ↑ Seller, D., Eubanks, D., and King, G. 1994. Field Test of a Six Arm Microresistivity Borehole Imaging Tool. Presented at the SPWLA 35th Annual Logging Symposium, 1994. SPWLA-1994-W.
  12. ↑ Laastad, H., Haukefaer, E., Young, S. et al. 2000. Water-Based Formation Imaging and Resistivity Logging in Oil-Based Drilling Fluids- Today's Reality. Presented at the SPE Annual Technical Conference and Exhibition, Dallas, Texas, 1-4 October 2000. SPE-62977-MS. http://dx.doi.org/10.2118/62977-MS
  13. ↑ Dumont, A., Kubacsi, M., and Chardac, J.L. 1987. The Oil-Based Mud Dipmeter Tool. Presented at the SPWLA 28th Annual Logging Symposium, 1987. SPWLA-1987-LL.
  14. ↑ 14.0 14.1 Cheung, R., Wendt, B., Borbas, T. et al. 2001. Field Test Results of a New Oil-Base Mud Formation Imager Tool. Presented at the SPWLA 42nd Annual Logging Symposium, 2001. SPWLA-2001-XX.

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See also

Types of logs

Borehole gravimetry

PEH:Specialized_Well-Logging_Topics

Category

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