6. 2. 1 Formation micro-resistivity imaging logging
Formation micro-resistivity imaging logging was developed from high-resolution stratigraphy formation dipmeters, and was first developed with the Silen The formation micro-resistivity imaging logging tool FMS (Formation Micro Scanner) launched by Becher Company in the 1980s is a representative example. FMS can provide images that reflect the resistivity of the formation around the well wall. It has achieved great advantages in formation evaluation and geological applications as soon as it was launched, which has also promoted the rapid development of this technology. Schlumberger has made three major improvements to FMS in less than three years, launching the fullbore microresistivity scanning imaging logging tool FMI (Fullbore MicroscanImager). Atlas Company and Halliburton Company also followed suit and launched STAR Imager and EMI (ElectricalMicro Imaging). The following will mainly introduce Schlumberger’s full-bore microresistivity scanning imaging logging tool FMI.
6. 2. 1. 1 FMI instrument structure and measurement principle
FMI instrument mainly consists of 5 parts, including telemetry, control, insulation nipple, acquisition nipple and measurement The inclined part, plate and probe are shown in Figure 6.2.1 (a).
1) Telemetry part. It is used to transmit data. The formation information collected by button electrode scanning and various auxiliary measurement and control measurement values ??are sent to the surface through the logging cable. The data transmission rate is 200kb/s.
Figure 6. 2. 1 FMI structure and measurement principle diagram
2) Control part. The automatic control loop in the control sub-section can amplify signals describing rock characteristics, expand the dynamic range of the instrument, periodically check the working status of each branch, and provide feedback to the logging engineer to achieve optimal control of downhole instruments. , which enhances the flexibility of instrument use and facilitates the operation of the instrument, so that the three logging methods can collect the required data in the shortest time.
3) Insulation nipple. It can insulate the probe from the electronic circuit casing, so that the current flows from the plate to the ground and back to the electronic circuit casing, and there is a certain potential difference between the two. One advantage of this arrangement is that the FMI can serve as the low-end return electrode for the ARI when combining logs.
4) Collect pup joints and inclinometer parts. The acquisition nipple has the following functions: filter out DC components, such as SP, from micro-conductivity data; digitize the signal to improve the signal's anti-interference; filter the digital signal to improve the signal-to-noise ratio; process the digital signal to determine In-phase amplitude of formation microconductivity data.
The inclination measurement part can measure the inclination orientation of the instrument and the wellbore, as well as the inclination angle of the wellbore. The measurement accuracy of the azimuth angle is 2°, and the well inclination angle is 0. 2°. The acceleration of the instrument can also be measured, which is used for speed correction during image processing and tilt calculation.
5) Plate and probe. The plate part consists of a button electrode array and high-precision electronic circuits. Electronic circuits are used to sample, detect and amplify button electrode signals, ensuring the resolution and clarity of the image. The design of the plate allows the instrument to have reliable response in highly deviated wells or horizontal wells.
The instrument has 4 mutually perpendicular push arms. Each push arm is equipped with two electrode plates. The upper part is the main plate and the lower part is the folding plate, as shown in Figure 6. 2. 1(b). After the folding plates are opened, they can automatically adapt to the shape of the wellbore and make them close to the well wall. This ensures that when the main body of the instrument is not parallel to the well axis, each plate can still be in close contact with the well wall. There are two rows of button electrodes installed in the center of each plate, each row has 12 electrodes, and a total of 192 electrodes are installed on the eight plates.
The diameter of the button electrode is 0. 16in (4. 1mm), and the outer diameter of the insulating ring around it is 0. 24in (6. 1mm); the spacing between the two rows of electrodes is 0.3in (7.62mm), the upper and lower The rows of electrodes are staggered with each other, and the lateral distance between the upper and lower electrodes is the radius of the electrode 0.08in (2.05mm), which means that half of the electrodes overlap between the two electrodes [Figure 6.2.1(b)], so During measurement, within the range controlled by the electrode array, all borehole wall surfaces can be fully scanned by the electrodes, which is called full borehole scanning. The instrument resolution is 0.2in (5.1mm).
The measurement principle of FMI is shown in Figure 6.2.1(a). The current loop is upper electrode - formation - lower electrode. The upper electrode is the shell of the instrument's electronic circuit, and the lower electrode is the plate. During measurement, all eight plates are close to the well wall, and the imaging logging surface system controls the emission of current to the formation, recording the current and applied voltage of each electrode, which reflect changes in the micro-resistivity of the formation around the well wall. FMI can perform 3 modes of well logging.
1) Full borehole mode. Measurements were performed with 192 button electrodes. In the 6 1/4in borehole, the borehole wall coverage is 93; in the 8 1/2in borehole, the borehole wall coverage is 80; in the 12 1/4ing borehole, the borehole wall coverage is 50.
2) Quadrupole plate mode. Just using four main plates, this mode is similar to FMS logging and is suitable for areas with familiar formations. It can save costs and increase logging speed.
3) Formation dip model. Using only eight measurement electrodes on four plates, the same results as a high-resolution formation dip logging tool can be obtained.
6.2.1.2 Data processing
Mapping the FMI measurement information to the borehole wall microresistivity image requires the following processing steps.
(1) Preprocessing
1) Automatic gain and current correction. The dynamic range of the resistivity of the measured formation changes greatly. To make the dynamic range of the measured electrode current change correspondingly, it needs to be achieved through automatic gain control and changing the power supply current.
2) Failure electrode detection and compensation. By analyzing the current distribution histogram of each electrode current in the selected processing window segment, the electrode information whose electrode current does not change with the formation is removed, and the failed electrode is measured using the interpolation of the measurement values ??at the corresponding measuring points of the effective adjacent electrodes. value to fill in.
3) Speed ??correction and electrode orientation positioning. The first step is to use the measurement information of the three-component accelerometer to map the current time domain measurement information of the array electrode into the depth domain measurement information, that is, determine the depth of each measurement point. The correction method is completely equivalent to the velocity correction of formation dip log. The second step uses the three-component magnetic flux measurement information and the acceleration measurement information to determine the azimuth angle of each electrode relative to the magnetic north pole.
In addition, the information (or curve) measured by each electrode also needs to be "depth aligned". Since the distance between the two rows of electrodes on the plate is 0.3in, when depth alignment is not performed, the abnormality displayed by the two rows of electrodes has a depth offset. The electrodes on the wing plate (i.e., the folded plate) are 5.7 inches away from the electrodes on the main plate, and the displayed anomaly has a greater depth offset. When processing pixels, the measurement results of each electrode must first be depth aligned. Figure 6.2.2 shows the electrode abnormality display before and after depth alignment.
The above processing is also called preprocessing of imaging logging. The goal is to obtain an image information set with the correct spatial position of the electrode. Reconstructed into a well wall image.
Figure 6.2.2 FMI resistivity curve before and after depth alignment
(2) Convert into intensity image
In order to convert the current of each button electrode It is an image of variable intensity, which is displayed in 16 levels of grayscale in the output image. On the interpretation workstation, 256 color scales can be used to display the image. Each "pixel" point in the image corresponds to a specific range of current. level. There are generally two schemes for selecting grayscale and color levels, the so-called "static" normalization and "dynamic" normalization. Also called equalization processing.
1) "Static" normalization.
Within a larger depth interval (corresponding to a certain interval or a certain reservoir interval), the response of the instrument is normalized, that is, the resistivity represented by a specific color at one depth is different from the resistivity represented by the color at another depth. The same means that the resistivity at that depth is the same. The advantage of this normalization is to compare the resistivity through gray scale and color comparison in a longer well section. Its shortcoming is that it cannot distinguish changes in micro-resistivity within a small range. Figure 6.2.3(a) is the imaging image after "static" normalization processing.
Figure 6.2.3 FMI image
2) "Dynamic" normalization. That is, in a short well section, the depth of gray and the intensity of color are selected to represent the level of the current level, so it can reflect the changes in micro-resistivity in the local range, so that the rock structure, fractures, etc. of the well wall can be studied in a more detailed manner. Changes, usually the longitudinal window length is 3ft. The advantage of this method is that it can show the relative changes in micro-resistivity in a local range. Figure 6.2.3(b) is an imaging image of the same well section after "dynamic" normalization processing. Compared with Figure 6.2.3(a), it can divide the changes in the formations on the well wall in more detail, especially at the top of the profile. , clearly showing the changes in stratigraphic bedding, etc., but there is no such display in Figure 6.2.3 (a).
3) Graphical display. When a plane is perpendicularly tangent to the well cylinder, the well wall forms a straight line on the unfolded diagram from 0° to 360°. When a plane intersects obliquely with the well shaft cylinder, the well wall and the oblique intersection plane cut out an ellipse, which appears as a sinusoidal curve on the unfolded diagram from 0° to 360°. The greater the angle between the plane and the well axis, the sinusoidal curve The amplitude is also larger, and the inclination angle and direction of the plane can be determined from the expanded diagram (Figure 6.2.4). Based on this imaging display, the bedding of the formation or the occurrence of fractures can be determined, so that the relevant geological characteristics of the formation around the well can be studied using borehole imaging.
6.2.1.3 Interpretation and application of data
There is a difference in resistivity between rocks in adjacent formations, which will be reflected in the FMI image; the greater the difference in resistivity, the The difference reflected in the image becomes more obvious. In FMI images, high-resistivity lithology corresponds to light-colored images, such as oil and gas-bearing formations, tight layers, etc.; low-resistivity lithology corresponds to dark-colored images, such as mudstone and drilling fluid-filled (water-based drilling fluid) Cracks etc.
Interpreting FMI images requires relatively rich geological knowledge, because different geological phenomena may have the same or similar images displayed on FMI images, such as dissolved pores and highly conductive clay particles or highly conductive minerals. Nodules appear as black spots on FMI images. It is necessary to use geological laws and geological knowledge to scale FMI images and distinguish different geological phenomena in order to obtain correct interpretation results.
FMI images can be used to identify cracks and dissolved pores in rocks, and can also be used to explain stratigraphic pore characteristics, sedimentary phases, stratigraphic structure, and make lithological comparisons.
Figure 6.2.4 Display characteristics of borehole imaging
The main geological applications of FMI images include the following aspects: ① fracture identification and evaluation; ② geological structure interpretation; ③ formation sedimentation Interpretation of facies and depositional environment; ④ reservoir evaluation; ⑤ determination of in-situ stress direction; ⑥ core depth homing and orientation; ⑦ high-resolution thin layer analysis and evaluation.
Usually in an area, representative parameter wells are selected for coring, and full borehole micro-resistivity scanning imaging logging is performed. Through detailed comparison with the core column, the relevant geological characteristics in the well are studied. Through the display in wall images, these features can be fully utilized to solve geological problems. Some examples are used to illustrate its application below.
Picture (a) in Figure 6.2.5 clearly shows the bedding and fractures of the formation, and picture (b) clearly indicates low-angle fractures and high-angle fractures. Figure 6.2.6 shows holes, muddy bands, sandy conglomerates, and boulders.
Figure 6.2.5 Strata bedding and fractures shown in FMI images
Figure 6.2.6 Vugs, muddy strips, sandy conglomerates, and boulders shown in FMI images (a ) Vugs; (b) muddy strips; (c) sandy conglomerate; (d) boulder conglomerate
Due to its high resolution, formation microresistivity imaging logging is useful in identifying thin layers, pore changes, It has broad application prospects in terms of cracks and sedimentation characteristics. Therefore, it is necessary to select several representative parameter wells or key wells in an area to conduct formation micro-resistivity scanning imaging logging, and compare them with the cores to find out the changing patterns of the geological characteristics of the area, which can greatly reduce coring. The number of wells can also provide important and rich geological information for oil field exploration and development.
6. 2. 2 Borehole wall acoustic imaging logging
Borehole Television (BHTV, Borehole Television) developed by Mobile Company in the late 1960s was the first type of Downhole imaging equipment used in oil wells. Downhole TV is like an ultrasonic scan of the well wall, which can continuously record images of the well wall. Early imaging log images showed some interesting phenomena on the wellbore wall, such as fractures, collapses, major lithological interfaces, and casing perforations and connections. Amoco, Shell and Arco have successively improved this technology. All oil companies today offer ultrasonic borehole imaging measurements. Although some refraction experiments were also performed, all borehole ultrasonic imaging measurements were performed in reflection mode. These newer instruments still use most components of the original downhole television, except that the term "television" has been replaced by "ultrasound imaging" or "scanning." The current representative ultrasonic imaging logging instruments include: Schlumberger's USI (Ultra Sonic Imager) and ultrasonic borehole imager UBI (Ultrasonic Borehole Imager), Atlas' circumferential sonic imaging logging instrument CBIL (CircumferentialBorehole Imaging Log), Halliburton's circumferential borehole acoustic scanner CAST (Circumferential AcousticScanning Tool), downhole televisions in domestic North China Oilfield, etc. These instruments can be used for logging in open holes and cased holes filled with clean water, crude oil, conductive and non-conductive mud, and cannot be used in empty wells.
6. 2. 2. 1 Measurement Principle
The core component of the instrument is an ultrasonic transducer made of sheet piezoelectric ceramic material. Used as transmitter and receiver. It is driven by a motor and can rotate 360° underground [Figure 6.2.7 (a), (b)]. Typically a 1500Hz electrical pulse is used to excite the transducer, causing it to emit ultrasonic waves. Sound waves propagate along the wellbore drilling fluid, are reflected on the wellbore walls, and return to the transducer. The transducer converts the received acoustic signal into an electrical signal and then sends it to the ground system through electronic circuits. The operating frequency of the transducers in early instruments was about 1. 3 MHz, which has been reduced to several hundred kHz in current instruments. There is a three-axis accelerometer and magnetometer in the downhole instrument to obtain the orientation of the instrument. Using this as a reference mark (instrument zero), the orientation of the pulse emitted by the transmitter can be obtained.
Geophysical well logging tutorial Figure 6. 2. 7 Borehole wall acoustic imaging logging measurement principle | (a) Structural diagram of driving motor, transducer and magnetometer; (b) Transducer acoustic pulse Schematic diagram of scanning lines on the borehole wall; (c) Measured pulse-echo signal
The instrument can measure two parameters: ① The amplitude of the echo signal received by the transducer; ② The sound wave from the transducer The travel time to the well wall and back to the transducer is also called the propagation time or the two-way travel time [Figure 6.2.7 (c)]. Changes in rock acoustic impedance will cause changes in echo signal amplitude, and changes in well diameter will cause changes in propagation time.
The measured reflected wave amplitude and propagation time are displayed as an image according to the 360° orientation in the borehole, which can be a grayscale image or a color image. Some characteristic differences on the image can reveal the characteristics of the underground lithology and geometric interface. Changes such as erosion zones, cracks and holes.
The main factors that affect the resolution of ultrasonic imaging logging tools mainly include the following aspects: ① Working frequency of the transducer; ② Drilling fluid in the well; ③ Measurement distance; ④ Surface structure of the target layer; ⑤ Purpose The inclination angle of the layer; ⑥ The wave impedance difference of the rock.
6. 2. 2. 2 Data processing
After receiving the acoustic signal, the ultrasonic transducer converts it into an electrical signal. This electrical signal is an analog signal. In the early downhole television imaging logging, the analog signals from downhole instruments could not be corrected or processed after they were transmitted to the surface. Digital imaging technology can use a variety of methods to process various signals, optimize image parameters, and obtain high-quality images. Borehole wall acoustic imaging logging data processing includes image processing and image output.
(1) Image processing
The main tasks of image processing include: ① Signal mediation, making necessary corrections and scaling of raw logging data to eliminate interference and improve data quality; ② Image enhancement, processing well logging images to improve image clarity and visual effects; ③ Image analysis, performing geological interpretation on well logging images and counting fractures.
(2) Image output
Image output formats include: ① The well wall plane expansion diagram is also the most commonly used diagram. There are two types, the amplitude diagram and the propagation time diagram, usually two The images are displayed side by side for mutual comparison and explanation (Figure 6.2.8); ② Wellbore stereoscopic view (Figure 6.2.9); ③ Cross-sectional view; ④ Fracture trace map, including amplitude image, fracture Trace and crack parameters; ⑤ Fracture parameter curve diagram, including amplitude image and four parameter curves of crack density, crack length, crack width, and crack surface ratio; ⑥ Echo amplitude waveform diagram, there are two waveform representations, one is Vertical, the other is horizontal; ⑦ Acoustic well diameter waveform diagram, also has two ways of representation: vertical and horizontal; ⑧ Schmitt diagram of fractures, using icons to represent fractures on a hemisphere according to their occurrence, from The outward direction of the center of the sphere indicates inclination, and the clockwise direction indicates inclination. In addition, there are crack data tables and crack grouping data tables.
Figure 6. 2. 8 borehole wall expansion amplitude diagram and propagation time diagram
Figure 6. 2. 9 borehole wall expansion amplitude diagram and three-dimensional view
Image The output colors are generally black and white and color (Table 6.2.1). The black-and-white image is actually a grayscale modulation. It is generally stipulated that black represents a weak echo amplitude or a long propagation time, while white represents a strong echo amplitude or a short propagation time. The color image is actually a pseudo-color. The modulation signal intensity value is divided into 256 (0,...,255) levels. Different intensity values ??correspond to different colors. There are many different schemes, such as black-red-yellow-white scheme and red-white-green scheme.
Table 6. 2. 1 Image color classification scheme
6. 2. 2. 3 Interpretation and application of data
Expand the amplitude image on the borehole wall plane Above: ① Any structure that intersects with the wellbore, whether obliquely or vertically, has mirror symmetry in its characteristic line shape, and scratches on the wellbore surface caused by drilling tools, logging cables and fishing tools, etc., Generally, it is impossible to produce this kind of mirror-symmetric characteristic line type (Fig. 6. 2. 8). ② Natural fractures, holes, casing cracks, perforations, etc. in casing wells appear as black characteristic lines or areas; hard and smooth well walls lacking structures appear as a white area due to strong reflection signals [Figure 6 . 2. 9]. ③ Planar fractures (or bedding planes) that intersect with the wellbore obliquely are black sinusoidal (Figure 6.2.8); plane horizontal fractures that intersect with the wellbore can be regarded as a special case of inclined fractures, appearing as a cross-well log The horizontal line segment of the graph.
④ The vertical structure that intersects the wellbore appears as a vertical straight line; any deviation from the vertical structure, such as the depression near the middle of the vertical fracture in the picture, appears as a curve. ⑤ The holes on the well wall appear as isolated, irregularly shaped spots (Figure 6. 2. 8).
On the wellbore plane expansion propagation time diagram: ① The open fractures that intersect with the wellbore have similar characteristic line shapes as those on the amplitude diagram. ② The well wall collapses, the wellbore is out of round, the casing is corroded and damaged, etc.
Currently, borehole acoustic imaging logging plays a great role in the oil field and can be used to solve the following related problems:
1) High resolution within a 360° spatial range Measure the well diameter at a high rate, analyze the geometric shape of the wellbore (Figure 6. 2. 8, Figure 6. 2. 10), and estimate the direction of in-situ stress;
Figure 6. 2. 10 Wellbore stereogram 1in≈ 2. 54cm
2) Determine the formation thickness and dip angle;
3) Detect fractures, identify fractures, and divide fracture zones (Figure 6. 2. 8);
4) Analyze the formation morphology and structure;
5) Return the borehole wall coring (Figure 6. 2. 11);
6) Measure the inner diameter of the casing and thickness changes to check perforation quality and casing damage;
7) Cement bonding evaluation.
Figure 6. 2. 11 Core homing using BHTV images