Borehole Imaging (Borehole Imaging Technology)

Borehole Imaging Technology

BOREHOLE IMAGING TECHNOLOGY

Downhole Video Imaging

Although the first downhole cameras were patented during the 1950s, they did not prove to be commercially successful until the 1970s, when the water well industry began to employ cameras routinely to investigate shallow water wells. Oilfield applications of early systems were limited by the presence of opaque borehole fluids, and by their reliance on specially designed large-diameter coaxial cable to transmit real-time video data to the surface.

The development of special lens coatings, along with improved cable technology has increased the usefulness of these tools in oilfield applications. The lens coatings are designed to repel oil and inhibit condensation. The change to fiber optic telemetry improved signal quality by 75 percent, increased bandwidth capacity for the video signals, and reduced cable size to 7/32 inch. One company can even use mono or multi-conductor standard electric wireline, providing flexibility to use any wireline unit as a video-logging unit. While downhole video is often used as an aid for visualizing completion and production problems, the tool has also made limited inroads into the area of formation evaluation.

Operation

Video imaging technology uses a small video camera and light source to provide visual wellbore images ( Figure 1 – Schematic of downhole video tool; Ward, et al, (1994) Copyright SPE). Various models offer color or black-and-white, high-resolution, full-motion video in real-time; others offer still pictures that are updated every 3.5 seconds. The video service is used in vertical holes, but may also be run on coiled tubing to inspect horizontal wells. Most systems allow the operator to monitor, record, produce hard copy, and save to videotape or floppy disk for further analysis. These systems are small enough to be truck, skid, or trailer-mounted.

 

Companies offering downhole video services include Halliburton, Schlumberger, DHV International, and Hitwell Video Incorporated, as well as a number of slick-line service providers. To learn about features and capabilities unique to each company's system, contact your local sales representative.

Applications

Downhole video applications cover a wide range of applications, which have been grouped into three broad categories:

· Visual inspection of tubulars and downhole equipment,

· Visual characterization of the open hole, and

· Visual inspection of fluids.

The following overview addresses applications within each of these three categories (Maddox, Gibling, and Dahl, 1995).

Visual Inspection of Tubulars and Downhole Equipment

Applications of video imaging in this category include:

· Fishing services

· Detecting casing and tubing leaks

· Locating causes of diminished production

· Monitoring downhole equipment

The camera is used in fishing jobs to show the location, orientation, and size of the fish. The surface computer can then make quantitative measurements from the video monitor to aid in fabricating fishing tools. The video camera has also been used to find holes, cracks, and corrosion in tubulars. It is also often run in the hole to locate restrictions that impede production. The video system can show mineralization, corrosion, scale, or bacterial buildups that reduce the inside diameter of tubulars, and plug slotted liners, screens, or perforations. The camera can also be used to monitor the position of sliding sleeves and inspect subsurface safety valves during operation.

Visual Characterization of the Open Hole

Open hole sections of air drilled wells can be surveyed with video cameras, and many open hole inspections have been performed on gas storage wells.

Video cameras have been used successfully to determine the size and orientation of open hole fractures. When a view of breakout patterns is presented, the camera can aid in interpreting the directional stresses on the formation.

Visual Inspection of Fluids

The downhole video system provides graphic detail about the type and location of fluids entering the wellbore. The camera can even monitor production that occurs from a single, specific perforation. This capability is especially important where production is distributed over an extended perforated interval in which there are gradual changes of fluid phases. Often, such changes in production are too subtle to be detected by conventional flow-measurement tools. The system may also be used to:

Detect entry into the wellbore of fluids and particulates,

Supplement production and injection profiles,

Conduct tracer surveys, and

Monitor the performance of well treatments.

Downhole cameras allow the operator to visually identify and monitor fluid phases and particulate matter entering the wellbore. Each exhibits distinguishing characteristics.

Oil
usually bubbles into the wellbore with very little disruption to the other well fluids. The oil tends to form discrete bubbles that migrate to the high side of the well. This tendency may cause oil to bypass conventional logging tools.

Gas
entry is characterized by turbulence. Gas may enter the wellbore as a spray of white bubbles, as a smoke-like jet or plume, or as waves of distortion in a clear fluid, depending upon the gas velocity and condensate content. Gas bubbles are more reflective than oil, and rise faster than oil. If the turbulence is strong enough, the fluids can become stirred so that any bubbles of oil mix with the water to form a semi-transparent or opaque emulsion; however, the liquids separate out above the turbulent area.

Water
entry is indicated by waves of distortion caused by flow disruptions and currents. Changes in the movement of falling sand and suspended matter may indicate that water or clear fluids are entering the wellbore, as will changes in the movement of rising oil or gas bubbles. The motion of clear fluids can also be tracked by fastening a piece of string to the front of the camera. If there is no evidence of oil or gas entry at a perforation with obvious turbulence, then the perforation is producing water.

Sand and particulate matter are easily recognized as they enter the wellbore, and often indicate that water is entering as well. Enlarged perforations signal the entry of high velocity water and abrasive particles at that perforation.

Downhole video systems have also been used to supplement injection and production profiles.

Production profiles
show the amount of oil and gas being produced at each point within the producing interval. Downhole video images cannot directly measure absolute flow rates, but they can show relative flow rates and provide an approximation of each section's relative contribution.

Injection profiles
are analogous to the production profile, and can be obtained from spinner tools or downhole video. The data helps to identify layering, fluid entry points, and thief zones, as well as leaks in casing, tubing or packers.

Tracer surveys test for communication between an injection well and a production well. The video camera is used to monitor the entry of injection fluid into the production well.

The injection well pumps a fluid marked with dye into the reservoir. The dye must be concentrated enough to permit visual detection by the video camera located in the production well. Black and white cameras may have problems detecting the dye, but with newer color cameras, detection is easier.

The production well
is monitored by the downhole video camera. Any dye that enters the production well signals communication between the two wells. The length of time between injection and detection provides an indication as to reservoir flow capacity, and permeability patterns between wells. When the camera is positioned to see the perforation from which the dye enters the well, it provides additional insight into the reservoir configuration and how the wells are interrelated.

Downhole video surveys are useful for each stage of wellbore remedial treatment.

Prior to starting treatment, the video survey aids in diagnosing the problem, thus helping to ensure that the proper treatment will be selected.

During treatment, the downhole video provides real-time monitoring to determine whether treatments are proceeding as intended. For instance, downhole video images have been used on frac jobs to verify that frac proppant is going where intended.

After treating the reservoir or wellbore, video surveys are used to determine whether the treatment accomplished the intended results. Video confirmation also allows operators to learn more about the treatment effectiveness to improve future treatment processes.

Limitations

The level of success of downhole video imaging depends on fluid clarity and the operational limits of the camera system.

 

 

Fluid Clarity

Downhole video cameras work only in a clear medium, such as clear water, dry gas, or air. Drilling mud does not provide sufficient clarity. Generally, still camera systems require more light and a clearer viewing medium than full-motion cameras. Consequently, clean-up procedures are even more important with still cameras than with full-motion systems.

Many chemical treatments, with the exception of cements, use fluids of sufficient clarity to facilitate video surveys. Fluid clarity differs from well to well, however, so it is absolutely necessary to test the fluid before attempting to run a video service. The best way to determine clarity is to actually look through a sample of any fluid that will come between the camera and the target (Whitaker and Linville, 1996).

It is best to sample the fluid for clarity at the wellhead, rather than the pump or holding tank. Fluid clarity can change considerably as it moves through pumps and lines that are less than clean. Avoid sampling from the kelly hose, which is often a source of particulate matter that reduces visibility. If a brine solution is to be used, it should be pre-mixed and placed in a holding tank at least one day prior to being filtered and pumped downhole. Brine should be filtered down to 5 microns, using two filter units in parallel, so that one unit can be cleaned while the other is 'on line'.

Video cameras work within the visible light range. Therefore, if you can see through the fluid for 10 inches, the video camera can see through the fluid for 10 inches. If you have to let a sample of formation water settle for a day before you can see through it, then you will have to shut-in the well for a similar period before the camera will be able to see through the fluid at the bottom of the well. For a quantifiable measurement, downhole video imaging is best used in liquids that have a turbidity value of less than 11 Nephelometric Turbidity Units (NTUs), measured by a device that includes both transmission and scattering methods in the measurement. (By comparison, tap water has a turbidity value of approximately 1 NTU.) Turbidity is a reduction of transparency caused by particulate matter. Since the clarity decreases as the turbidity increases, it is easy to think of turbidity as the opposite of clarity.

Operational Limits

Most video imaging tools are pressure-rated between 10,000 and 12,000 psi and have been depth-rated from 11,800 feet to 18,000 feet. Most treatments typically are performed below fracturing pressure at matrix rates, and thus, pressure limits of the camera and cable will not be exceeded. Temperature ratings range from 225 to 400 F, with higher temperatures tending to cause fading of the image contrast. Consult your service representative for specific tool ratings.

BOREHOLE IMAGING TECHNOLOGY

Acoustic Imaging Method

An early acoustic imaging tool, called the Borehole Televiewer (BHTV - perhaps an unfortunate abbreviation, since it is often confused with the downhole video camera), was developed in the 1960s. This acoustic device employed a rotating piezoelectric transducer that transmitted sonic pulses to the borehole wall, and then measured the reflection times of these pulses ( Figure 1 —Borehole Televiewer schematic; Zemanek, et al (1969), Copyright SPE). Differences in the travel time and amplitude of the reflected signals indicated the presence of fractures and other formation irregularities, while a flux-gate magnetometer provided a means of determining the orientation of these features.

 

Although the BHTV was originally designed for fracture identification, it subsequently proved useful for evaluating other formation features, as well as monitoring casing condition (Zemanek et al., 1969). Modern-day acoustic imaging tools represent improvements to the original Borehole Televiewer.

Examples of acoustic imaging devices include:

Baker Atlas' Circumferential Borehole Imaging Log (CBIL^TM)

The CBIL operates at a frequency of 250 kHz for enhanced performance in larger holes and heavier muds. The tool is rated for 400 F, and 20,000 psi.

Halliburton's Circumferential Acoustic Scanning Tool- (CAST-V^TM)

The CAST-V tool takes 100 shots per scan in the horizontal plane per sample, and takes 40 vertical samples per foot. The tool is rated for 350 F, and 20,000 psi.

Schlumberger's Ultrasonic Borehole Imager(UBI^TM)

The UBI transducer can adjust to different hole conditions by running at either 250 or 500 kHz, to obtain optimum image resolution The tool is rated for 350  F, and 20,000 psi.

Operation

The acoustic imaging method relies upon the generation of ultrasonic pulses from a rotating transducer, as shown in Figure 2 (Schematic of the transducer and electrical motor assembly for Schlumberger's Ultrasonic Borehole Imager (UBI^TM); courtesy of Schlumberger Oilfield Services). The same transducer then measures the reflected echoes from the surface of the borehole wall.

The transducer records two measurements:

two-way travel time of the ultrasonic pulse, and

amplitude of the reflected signal.

The amplitudes and travel times of these reflected signals indicate irregularities in the borehole surface and geometry, which can be attributed to a variety of geologic features, wellbore conditions, or casing conditions.

The tool also measures the sonic velocity and acoustic impedance of the borehole fluid. Measurements of the fluid's sonic velocity are processed in the logging unit to provide high-precision caliper information. A signal-processing algorithm uses the acoustic impedance data to make environmental corrections.

The signals are processed to create a photograph-like image that covers the entire 360-degree circumference of the wellbore ( Figure 3 Acoustic reflection of borehole wall, showing bedding features imaged by the Baker Atlas Circumferential Borehole Imaging Log (CBILTM); courtesy of Baker Atlas). Dark colors represent low amplitudes and large radii, and are indicative of borehole rugosity, enlargements and areas of attenuative material.

Acoustic imaging devices work in all types of drilling fluids, including:

Fresh water-based muds,

Salt water-based muds,

Oil-based muds, and

Polymer muds.

 

 

Applications

Acoustic imaging tools have poorer resolution than microresistivity tools; however, acoustic imaging tools provide complete, 360-degree measurements around the borehole, (as opposed to 50 – 80 percent coverage provided by the resistivity imager). Furthermore, acoustic imaging tools can be run in a variety of drilling fluids, and are used in both open hole and cased hole applications.

Open hole applications include:

identifying and evaluating fractures, faults, folds, formation boundaries and other structural features,

identifying bedding types & frequencies,

determining sand counts in thin-bed sedimentary sections,

identifying primary and secondary porosity,

evaluating structural dip,

measuring borehole shape, and

complementing other formation evaluation data (i.e., cores, well tests, other logs).

 

Acoustic imaging can be used to shed light on borehole geometry, as shown in Figure 4 (UBI^TM presentation showing acoustic image of wellbore (left panel) and corresponding borehole radius (right panel); courtesy of Schlumberger Oilfield Services). In this example, the panel on the left shows gouges in the borehole wall attributed to borehole breakout, caused by anisotropic horizontal stress in the formation. The panel on the right shows how borehole breakout affects the radius of a well. The panel on the right also provides useful information about the orientation of the breakout, shown in a northwest-southeast direction.

 

Cased hole applications primarily consist of:

evaluating cement bond quality, and

evaluating the condition of casing.

An example of a cased hole acoustic imaging log is shown in Figure 5 (CAST-V^TM plot showing borehole geometry, casing thickness, microseismogram, and cement bond. Last track shows an impedance map, with a cement void indicated in blue near the bottom of the track; courtesy of Halliburton Energy Services)

 

Limitations

Borehole acoustic imaging measurements may be somewhat limited by large-diameter wellbores, tool eccentering, signal attenuation in heavy muds, and cycle skipping. Mud weight is the greatest limiting factor, because heavy muds tend to cause signal attenuation problems in muds exceeding 15.5 ppg.

These factors imposed a number of practical operating limitations on early versions of the technology; however, improvements in transducer design and processing technology have greatly enhanced the capabilities of the newer tools.

 

BOREHOLE IMAGING TECHNOLOGY

Resistivity Imaging Method

Resistivity imaging methods were introduced during the mid-1980s, as an outgrowth of dipmeter technology. These tools relied upon a series of electrodes mounted on a single pad that measured the formation microconductivity or microresistivity
at the borehole wall, from which a graphic of the borehole wall was generated. A single electrode pad provided only limited coverage of the borehole.

Modern tools utilize four to six independent arms, each with articulating pads containing multiple electrodes. Individual articulating sensors conform to the borehole wall to provide high-resolution measurements of formation resistivity, and can cover as much as 80 percent of an 8-inch borehole.

Examples of resistivity imaging devices include:

Schlumberger's Formation MicroImager (FMI^TM)

In addition to a 24-button microelectrical array pad on each of four arms, the FMI^TM
mounts an extendable pad to increase pad coverage to about 80% of an 8-inch borehole ( Figure1 – FMI^TM
tool; courtesy of Schlumberger Oilfield Services). Resolution is 0.2 inch, and the tool is rated to 350 F, and 20,000 psi.

 

Schlumberger's Azimuthal Resistivity Imager (ARI^TM)

The ARITM is not a pad-contact tool. It uses an array of 12 electrodes, spaced 30 degrees apart ( Figure 2 – Conceptual drawing of ARI^TM
tool; courtesy of Schlumberger Oilfield Services). This array of electrodes measures deep resistivity readings with a vertical resolution of eight inches. The ARI^TM tool is less sensitive to borehole rugosity than the other electrical imaging tools and is able to provide coarse structural dip measurements. This tool is rated to 350 F, and 20,000 psi.

Halliburton's Electrical Micro Imaging tool (EMI^TM)

The EMITM has six independent arms, with an articulating pad on each arm ( Figure 3 – EMI^TM
tool, courtesy of Halliburton Energy Services). Each pad contains 25 sensors, with a resolution of 0.2 inches. The central button on each pad produces high-definition quantitative resistivity measurements with a depth of investigation comparable to a short guard or digital focused log (Murphy, 1996). This tool is rated to 350 F, and 20,000 psi.

 

Baker Atlas' Simultaneous Acoustic/Resistivity tool (STAR^TM)

The STAR^TM tool simultaneously acquires high-resolution images of borehole features that have resistivity contrast or acoustic impedance. The combination of acoustic and resistivity measurements partially compensates for any shortcomings inherent in either of the individual measurements. This six-arm tool uses a powered standoff to improve pad contact with the borehole, providing resistivity coverage of 60 percent in an 8-inch hole, and 100 percent acoustic coverage. The tool is rated to 350 F. ( Figure 4 – STAR^TM
Imager; courtesy of Baker Atlas).

Operation

A typical tool emits an electrical "survey" current into the formation, while another current focuses and maintains a high-resolution measurement. The currents measured by each electrode vary according to formation conductivity, which reflects changes in fluid properties, permeability, porosity, rock composition, and grain texture. These variations are processed and converted into synthetic color or gray-scale images, which are interpreted according to the following convention:

·
Light Colors - reflect low micro-conductivity zones,
(i.e. low porosity, low permeability and high resistivity)

Dark Colors - reflect high micro-conductivity zones,

(i.e. high porosity, high permeability and low resistivity)

Applications

The resistivity imaging tool produces high-resolution measurements and images that are used in making geological and petrophysical interpretations ( Figure 5 - Fullbore Formation MicroImager (FMI^TM) display showing vugs in a dolomitic formation; courtesy Schlumberger Oilfield Services).

 

Borehole imagers use a fixed-contrast presentation for gross correlations, and a dynamic averaging display to enhance local features. The fixed, or absolute contrast allows the viewer to correlate color values between different zones of interest within the well, or between images from different wells. The dynamic averaging display is applied to local events, to allow the viewer to distinguish features on a smaller scale, such as oil-filled pores, or tight sands.

Applications include:

· identifying depositional environments,

· identifying general structural and sedimentary features,

· identifying diagenetic events,

· identifying mechanical deformations,

· detecting thin beds,

· locating potential secondary porosity,

· fracture analysis and fault mapping, and

· quantitative, high-resolution resistivity for improved net pay estimation.

Figure 6 (EMI display showing cross-bedding, shale drape and contorted bedding; courtesy of Halliburton Energy Services) shows how sedimentary features are characterized.

When integrated with a traditional suite of logs, the images produced by a resistivity imaging tool enable the analyst to differentiate laminated reservoirs from low-permeability shaly sands. The tool produces quantitative, high-resolution micro-resistivity measurements that aid in estimating hydrocarbon saturation and reserves in thin-bedded reservoirs, thus improving the net pay estimation of laminated reservoirs.

 

    

 

Limitations

Resistivity imaging tools are not as sensitive to borehole conditions as acoustic tools; however, there are three factors which must be considered before running the tool.

· Open hole environment,

· Water-based mud, and

· Tool centralization.

As expected, the resistivity imaging tool is limited to the open-hole environment; unlike the acoustic imaging tool and the downhole video camera.

Because electrical imaging methods depend on resistivity contrasts, these applications are limited to water-based muds. For best image quality, the resistivity contrast between the mud and the formation should not exceed 10,000 ohm-m. As mud conductivity increases, the current tends to flow into the borehole, thereby degrading the sharpness of the images (Serra, 1989).

Tool eccentering will adversely affect image quality as tool pad contact with the borehole decreases. When borehole deviation is less than 10, the tool should be centralized to

maximize pad contact. Poor pad contact will produce blurred images.