42 Middle East Well Evaluation Review

Transcription

1 Analysis of waves passing through rocks is taking a new direction. Geophysicists, keen to maximize the benefits from seismic data, are gleaning fresh information about formations by analysing some of the more unusual waveforms contained in their data. They are also using advanced reprocessing techniques to clarify the seismic picture. Carl Poster, Andy Fryer and Iain Buchan outline some of the new approaches. Analysis of old seismic data, gathered almost a decade ago, is also helping the search for water in the region. Don Hadley, Christopher Menges and Dennis Woodward of the United States Geological Survey explain how seismic data can be used to help locate groundwater resources. 42 Middle East Well Evaluation Review

2 Photo: Wave rock, Hyden, Western Australia (Tony Stone) Number 10,

3 Mixing oil and water Seismic data amassed for oil exploration is now being reprocessed in the United Arab Emirates and is revealing new knowledge on water resources. This reprocessing work, believed to be the first of its kind, is part of a water resources project covering hundreds of square kilometres of desert bordering the western margins of the Oman mountains. The investigation is being undertaken by the United States Geological Survey (USGS) and the UAE s National Drilling Company (NDC), with technical support from the Abu Dhabi National Oil Company (ADNOC). Altogether, a team of about 50 people is working on the project. Abu Dhabi is keen to find new supplies of water. A rapid growth in population, plus increased reclamation of land for agriculture, has stimulated demand for freshwater from 54 to 89 million gallons per day in the last 10 years. Over the last 20 years, demand has risen 10- fold. Much of the annual runoff from the Oman mountains enters the alluvial fill lying beneath the desert s dunes. Geological field studies, and examination of existing water wells, indicates there are two formations that can serve as aquifers for this water - a coarse gravel of Quaternary age and, beneath, a slightly older and finer-grained mixture of gravel and mudstone. With larger pores, less silt and higher permeability, the upper aquifer is the better of the two. There were two main problems confronting the hydrogeologist studying Fig. 4.1: National Drilling Company rig ND-85 at NDC/USGS well no. GWP-30. The well is located about 20km north of Al Ain and 2.5km west of the Al Ain - Dubai Highway. The well is being logged and sidewall cored by a Schlumberger logging unit from Abu Dhabi.(Photo courtesy USGS/NDC). Saudi Arabia The Gulf Abu Dhabi Liwa Area these zones: what is the regional level of the water table, and where are the best places to drill the aquifers? Numerous tools are available to the hydrogeologist: * Satellite imagery shows the regional surface geology in great detail, * Field studies of outcrops indicate the character of the aquifers in some areas, * Logging of test wells and monitoring of existing wells provides some information on the aquifers thickness, properties and extent. However, the groundwater explorationists in the UAE needed a detailed view of the aquifers subsurface properties over a very large area. They decided Dubai Al Ain Area Jebel Hafit Oman Oman Mountains Buraimi Al Jaww Plain Oman Gulf of Oman km Fig. 4.2: Abu Dhabi has two main sources of groundwater - to the west of the Oman mountains around Al Ain and in the more southerly Liwa region. to look at ADNOC s maps, showing seismic coverage for past oil exploration. The region had been densely covered with seismic lines and numerous shallow velocity measurements had been made in boreholes. The seismic data, they hoped, would show evidence of shallow structures affecting the aquifers, and the shallow velocity results might give an indication of the regional stratigraphy, and thus the freshwater-bearing rocks. However, the seismic data had been originally processed to show deeper images of interest to the oil explorationists. To get an improved view of events nearer the surface, the data had 44 Middle East Well Evaluation Review

4 Fig. 4.3: The photograph at the top shows the surface terrain of the aquifer near Al Ain. Most of the recharge is in the form of runoff from the mountains in the background. The tracks of the vibrators which were used by surface seismic crews can be seen in the foreground. The seismic data at the bottom of the illustration revealed the area s subsurface structure and stratigraphy. It was essential to find the deeper, thicker parts of the aquifers so that the wells could be correctly positioned. A geological model was constructed (centre) from geological, well and seismic data. The character and thickness of each formation was determined in detail from the logs. Their lateral extent and regional structure was provided by the surface seismic data. A synthetic seismogram was computed from sonic and density logs (inset) and this confirmed that there was a good match between the log and seismic data. Number 10,

5 to be re-processed using a slightly different approach. The first step was to remove the lower frequencies (below about 20Hz) from the original data, and it was observed that shallower events were enhanced. For normal, deeper targets, the higher frequencies are attenuated, and it is necessary to keep the lower frequencies in the data. Next, the statics were recomputed to a datum level nearer the surface (Middle East Well Evaluation Review, Number 8, 1990). The purpose was to exclude from this correction large thicknesses of deeper material for which there are no direct measurements of velocity. This reprocessing step significantly enhanced the section. Then the stacking operation was repeated. The velocities were determined from the pre-stack data at a considerably closer spacing than originally used. Also, test stacks were produced to determine which trace offsets improved and which degraded the stack at shallow depths. Only those traces which gave a clear image were used in the final stacking process. Finally, and perhaps the most important factor in the re-processing, was the close co-ordination between the processing group at GECO and the hydrogeologists. The data processors had to clearly understand the objectives and targets of the interpreters, and made repeated tests and preliminary versions before a final section was selected. To solve the problem of mapping the water s surface, the hydrogeologists turned to the shallow wells used to measure velocities near the surface. It was these holes that were used to determine the static corrections used in the reprocessing. As water saturation in the alluvial fill significantly increases seismic velocities, they were able to analyse the arrival times of the seismic signal versus depth and locate the point in each well at which the velocities suddenly increased. A map of these depth points provided an accurate view of the water table s surface. Multiple vision One of the oldest problems plaguing seismic interpreters is how to confidently identify real events on a seismic section. Is the event seen by the interpreter a true reflection, perhaps from a potential reservoir, or is it a multiple, ringing down from the near-surface? Figure 4.6 shows one onshore example in the southern Gulf. The section, part of a 3-D data set, shows prominent, flat events Fig. 4.4: Demand for water in Abu Dhabi has increased 10-fold in the past two decades. Boundary of concession area N Buraimi Al Ain Fig. 4.5: Altitude of water near Al Ain, calculated from uphole data, The higher altitudes run parallel to the mountains to the east and the contours drop smoothly towards the west Application of uphole data from petroleum seismic surveys to groundwater investigations, Abu Dhabi (United Arab Emirates), by D. Woodward and C. Menges. Published in Geoexploration, 28 (1991). Elsevier Science Publishers B.V., The Netherlands km 46 Middle East Well Evaluation Review

6 Fig. 4.6: Seismic section from the southern Gulf. How do you differentiate the real events from the multiples? Computing the autocorrelation function may help. 100ms Before predictive deconvolution 100ms After predictive deconvolution crossing the shallow portion (around 400ms), which possibly contained a reservoir. However, multiples were thought to be strongly generated in this area and, even though the section had been processed to try to remove them, the interpretation prior to the drilling was suspect. However, before the start of the oil well, a water well had been drilled at the site to provide water for the subsequent drilling programme. It was realized that the well, about 600m deep, could accommodate a VSP, which should be able to provide considerable assistance in discriminating true from false reflections both above and below the well s TD. To produce a data set, a VSP was acquired over 30 levels with a 20m interval. Also, a full suite of logs was obtained to provide geological control for the VSP s interpretation. The VSP was processed in the usual manner and close attention was paid to the downgoing waves which should contain considerable information on the multiple pattern. By analysing that part of the VSP, a very good idea of the extent of multiples in the final upgoing wavefield could be established. A comparison of this with the seismic section would indicate the degree to which multiples were present. Number 10, A simple way to indicate the extent of multiples on the downgoing VSP waves is to compute its autocorrelation function. This function is simply the result of shifting the trace in steps relative to itself, multiplying the two together, and plotting the product against the total shift. When the original trace repeats itself, the autocorrelation function is high at that point. Figure 4.7 shows the initial downgoing trace and its autocorrelation function; note the ringiness in both. After the application of predictive, or gapped deconvolution (the parameters of which are selected on the basis of the autocorrelation results) the downgoing wavetrain and its autocorrelation function have been significantly smoothed. This same processing is applied to the VSPs upgoing waves, which are stacked into a final single trace. Figure 4.7 shows this stack, played out four times. (In addition to the processing noted previously, an additional wavelet deconvolution operation has been applied, to compress the wavelet visible in figure 4.7 to a short, zero-phase pulse.) In the figure, the VSP is juxtaposed with the geological details, indicated by the interpreted well logs scaled into time. Based on the analysis of the downgoing wave field, the final VSP stack in fig- Fig. 4.7: (Top): Both the VSP downgoing waves and their autocorrelation functions (right) have a high degree of ringiness before predictive deconvolution. After processing (below) both sets of traces have been smoothed significantly. 47

7 SHALE ANHYDRITE LIMESTONE DOLOMITE WATER ure 4.7 is assumed to be multiple-free. By comparing this with the seismic section in figure 4.7 a very good correlation of events can be seen, and indicates that the events in question are real reflections. Using the water well for VSP acquisition before the main drilling program, provided valuable information for interpreting this section and proved to be a cost-effective method for obtaining seismic processing parameters. A VSP in the oil well, obtained over a much deeper section, of course extended this information Fig. 4.8: EVENTFUL PROCESSING: There is now a good correlation between the upgoing VSP stack (right), the surface seismic (centre) and log data. The seismic signature of the shallow aquifer (ringed) can be determined by correlating the interpreted openhole logs with the VSP (far right traces) and then the surface seismics (centre). Since the VSP has both a time and depth scale, the tie of the interpreted logs and the events on the VSPs is unambiguous. As the VSP has been determined to be free of multiples, the good correlation with the surface seismics indicates that it too is mainly multiple free. Sensor achievement Solving these problems with seismic methods rests on one key requirement - good data. Good seismic data for the geophysicist has several qualifications. It should first of all have a high signal-to-noise ratio, with minimum noise originating from the sensor system itself. Then, it should have a wide bandwidth, and include as many frequencies as possible while maintaining the signal s original phase. Next, it is important that the orientation of the sensor has a minimum effect on the signal, especially in the borehole. Seismic waves come from all directions, and if the same sensor can be positioned in vertical and horizontal orientations without introducing its own distortions, the three-dimensional results from the data will be more reliable. Finally, the data should have a large dynamic range, so that the interpreter can see and accurately compare low and high amplitude reflections. A new seismometer which fills many of these requirements is now becoming available for borehole seismic acquisition. Conventional sensors signals come from motion above their natural frequency, at which the output voltage is proportional to velocity. This sensor operates at its natural frequency where voltage is proportional to acceleration (for high damping). The new sensor is call a geophone accelerometer, or GAC*. Figure 4.9 shows how the device is constructed. Similar to conventional geophones, it has a moving coil around a magnet. However, quite strong rareearth magnets produce a large mechanical damping with high sensitivity. The high damping, combined with a lightweight coil produce a broader, flatter response compared to conventional sensors. The GAC s natural frequency is 25Hz. This positions its effective bandwidth in the middle of a broad range of frequencies of interest to geophysicists - from about 3Hz to 200Hz. The lower values permit the recording of deep, low frequency reflections, which are especially important for seismic interpretation processes such as inversion. The high values allow the detection and imaging of thin formations. 48 Middle East Well Evaluation Review

8 Magnet Flux lines Fig. 4.9: RARE BREED: The rareearths used in the GAC s construction have produced a highly damped system with a broader, flatter response than conventional geophones. Maximum tilt angle (degrees) Vertical sensor GAC 40 Horizontal sensor Natural frequency (Hz) The sensors responses are compared in figures 4.10a, 4.10b and 4.12 (overleaf). In figures 4.10a & b, the ratio of frequency to the sensors natural frequency is plotted on a logarithmic horizontal scale, and the vertical scale is normalized amplitude. The conventional geophone s velocity response is shown in figure 4.10a, and the GAC s acceleration signal is in 4.10b. On the low end of the spectrum, the signal for a conventional 10Hz geophone is lowered by 5dB at 8Hz, while on the GAC this point is at about 2Hz. On the upper end of the spectrum, the response in figure 4.10a shows a spurious signal around 15 times the natural frequency, which is not present within the GAC s 5dB range up to 300Hz. Figure 4.12 shows the GAC s smoother phase change with frequency compared to that of a conventional geophone. The GAC s high natural frequency has another useful consequence. Figure 4.11 (above) shows how the maximum tilt angle (in degrees) varies with the natural frequency of horizontal and vertical sensors. (These relationships ÀÀÀÀ ÀÀÀÀ QQQQ Normalized amplitude Amplitude (db) (db) dB Magnet for a moving coil sensor with a maximum displacement of 1mm). This indicates, for example, that a 10Hz horizontal geophone can only operate to less than 25 degrees of tilt. As indicated, the GAC has omni-tilt capabilities, and the same physical device can be used for any direction in a three-component tool. The output of acceleration from the GAC also effectively increases its dynamic range relative to the conventional output of velocity. Because acceleration is the derivative of velocity, the GAC s signal, compared to that of a normal geophone, indicates how one sample changes relative to the previous one. More information can be transmitted in this way and when the acceleration signal is integrated, to produce a velocity signal, it has gained in dynamic range. 8Hz 2Hz Frequency / sensor's natural frequency Fig. 4.11: WORKING THE ANGLES: Depending on the design (for horizontal or vertical orientation) there are specific limits to the angle of tilt at which a geophone can operate. Because of the GAC s high natural frequency, it will operate at any angle, eliminating sensor differences in threecomponent geophones. Figure 4.10a (Below left): The velocity response of a conventional geophone is shown here, as a function of frequency divided by the geophone s natural frequency. For a 10Hz geophone, the signal is lowered by 5dB at about 8Hz. Figure 4.10b (Below right): This shows the acceleration signal from the GAC as a function of frequency divided by the GAC s natural frequency (25Hz). A 5dB drop occurs at about 2Hz on the low end of the spectrum and above 300Hz on the high end. -5dB 300Hz Frequency / sensor's natural frequency Conventional geophone GAC Number 10,

9 Shear wave analysisthe extra dimension Phase angle 50 GAC Conventional Geophone Frequency (Hz) Fig. 4.12: How the sensor changes the signal s phase can be quite important. Here, the GAC s phase response as a function of frequency (coloured line) is compared to that of a conventional geophone. There is less of a change in the GAC s signal over the critical band of 10Hz to 100Hz. Conventional geophone 500ms GAC geophone Fig. 4.13: Comparison of signals for maximum horizontal response for a conventional 14Hz geophone (left) and the GAC (right). The GAC is detecting latearrival events, with low frequencies, which are not detected by the conventional geophone. Also, the GAC s signal/noise is higher than that of a conventional sensor. By far the majority of seismic data that geophysicists work with is based on compressional wave motion through rocks. This is because surface seismic sections can be produced efficiently using predominantly compressional wave sources and sensors on the surface designed for detecting vertical motion only. It then follows that the requirement for borehole seismics, typically used for time-to-depth functions, stratigraphic correlations, etc, is only for the corresponding compressional wave velocities. However, it is usually overlooked that, in obtaining this borehole compressional data with both seismic and sonic tools, the acquired waveforms are also rich in shear wave information, and that the shear waves can also yield additional useful answers. Some of the procedures and results that are being pursued in the Middle East for such shear wave studies have been compiled in the following example. Going with the flow The alignment of fractures in a reservoir formation is one of the key factors in determining the direction of maximum permeability, and thus to a great extent how a reservoir should be best developed. Several logging tools can indicate the presence and alignment of fractures within the well, but their large-scale extent and trend may not be so easily discerned. It has been frequently observed that shear waves are sensitive to the fabric of the rocks they travel through. In systematically fractured formations, shear waves may travel notably better (that is, faster, with less attenuation) parallel to the fractures trend than across their trend. This could be due to the increased effective volume of material with lowered shear strength (produced by the net effect of all the relatively small fracture planes) through which the transverse shear waves must travel. Other stratigraphic factors, such as channelling or preferred grain orientation, may have similar effects, so correlation with other measurements is always desirable. 50 Middle East Well Evaluation Review

10 Fig. 4.14: IN SEARCH OF FRACTURES: Typical field acquisition arrangement for seismic fracture surveys. The two vibrator sources are positioned at least 45 apart. The ASI tool can record VSPs for each source azimuth and from this data it may be possible to deduce the presence and direction of fractures. In the past, it has been difficult to confidently measure these effects, since accurately recording shear waves has been difficult, both on the surface or down the borehole. Obviously, it is important to eliminate all undesirable tool effects from such measurements. But now with high-performance tri-axial borehole receivers, like the Combinable Seismic Imager Tool (CSI*) and the Array Seismic Imager Tool (ASI*), such experiments are becoming more feasible. Figure 4.14 summarizes one field acquisition arrangement, which is a common one for obtaining offset (compressional wave) VSP images in several directions around the well. Multiple shooting positions, at least 45 apart and offset from the well by perhaps half the tool depth, are occupied by vibrators. In the well, the ASI is positioned over the reservoir formations. A series of sweeps from each source generates sufficient Fracture directions data to compute VSPs for each source azimuth. For better resolution of velocity differences, the sources could be rotated around the well, or more sources could be used. What should the interpreter do next with the VSP data to reach a reliable conclusion about possible fracture trends? Shear amplitudes may hold information but are easily affected by many other factors, in and outside the borehole. The angles at which the shear waves arrive at the tool may also indicate transmission differences, and can be determined by careful measurements of receiver orientations and intercept angles. Also, the analysis of how the directions of shear particle motion change with time, even using data from a single source, may be used to deduce fracture trends. However, one familiar property of shear waves is fairly easily accessible and can be measured robustly - their velocity. This approach is feasible because of recently-developed processing algorithms (see reference below) for separating and inverting wave modes (to loglike velocity functions). Inversion of P and SV waves from Multicomponent Offset Vertical Seismic Profiles by C. Esmersoy, in Geophysics, v. 55, January Number 10,

11 Fig. 4.15: Processing steps involved in the analysis of tri-axial shear wave data. ASI Wireline (Armored cable) DEPTH fig 3.3a TRY projection DEPTH fig 3.3c HMX projection Cartridge Bridle cable ONE-WAY TIME (S) ONE-WAY TIME (S) Triaxial Sensor Packages 50 ft Inversion Figure 4.15 indicates how this procedure works. The initial sections are produced from combined processing of the vertical axis data and the wavefield created from the projection of the horizontal axes data in the direction of maximum horizontal particle motion - which is mainly toward the sources (Middle East Well Evaluation Review, Number 4, 1988). The resultant compressional and shear VSPs are then inverted to determine their velocities as a function of depth. This is done for each direction and these results can be compared by a simple method such as cross-plotting. This readily shows up variations over particular depth zones. Differences of about 3% to 4%, in shear velocities, have been noted in such studies in the Middle East. In projects now underway these velocity variations, and other shear wave attributes, are being correlated with, among other things, fracture density and orientation. These studies require complete log data sets, including Formation MicroScanner data (for fracture logging), and borehole ovality results, to indicate in situ stress fields. Offset -2 shear velocities Offset -1 shear velocities 52 Middle East Well Evaluation Review

12 Shear wave y Offset shot points Minimum stress Direction of wave x Maximum stress Wells Maximum stress x z 3-component geophone array y Compressional waves Minimum stress Shear waves Track that crack Besides recording the wavefields transmitted from seismic sources, the new high-performance, threecomponent tools are being used to address a very different problem: determining the extent of hydraulically-induced fractures. This technique essentially consists of positioning the CSI or ASI tool in or near a well undergoing hydrofracturing, and listening for the acoustic signals generated when the rock bursts. The field operation is shown in figure In order to increase a field s productivity, fluid is injected into the reservoir through perforations in the well s casing. The object is to overcome the ambient pressure at this depth holding the natural fracture planes together, and force them apart. The most likely direction in which these fractures will open up is at right angles to the minimum stress direction, which is the direction in which the force holding the fractures together is least. While this is going on, three-component recordings can be made, either in the injection well or in an adjacent well. The orientation of these tools must be determined before the recording, either from orientation tools attached to them, or by offset shot points, as shown in the figure. The angle of incidence of the waves from these shot points, which have a known location, can be determined and used to find the alignment of the tool s horizontal axes. The process for doing this is shown on the right side of the figure. The wavefronts received at the tool s horizontal axes will have a particular phase depending upon the specific angle. Plotting one axis response against the other s gives a type of cross plot. The direction of this plot indicates the wave s angle across the array, and since the alignment of the array has been determined from the check shots (for which the same procedure was used) we know the true direction that the wave is travelling in. In the figure, the compressional event is the main plot, and the later-arriving shear wave would produce a plot roughly at right angles to the compressional s. After many of these events have been recorded and analysed in this way, they can be compiled for each well and tool position. When this is done in the injection well, where particle motion is in the plane of the fracture, the fracture s azimuth can be determined. When obtained from an adjacent well, the direction to the source is indicated, and thus intersections can be obtained for multi-well data sets. Development work is continuing with this kind of data. More information on fracture height and width are being Fig. 4.16: BIRD S EYE VIEW: Field acquisition set up for determining the extent of hydrofracturing. Fluid is pumped into a well to induce fracturing. The fractures open in the direction of maximum stress (ie. at right angles to the minimum stress direction). At the same time, threecomponent recordings can be made to determine the orientation of the borehole seismic tool. The signals from the wave fronts arriving at the axes of the three-component array can be cross-plotted against each other to determine their arrival angle relative to the tool s sensors. The different particle directions of the different modes (compressional, shear) should be recognizable in this analysis. sought from amplitudes and from the differences in compressional and shear arrival times. Number 10,

13 Sharpening shears The growing interest in shear wave seismic data has placed a new demand on sonic logging tools: how to get highquality, continuous shear waves, even in shallow, low velocity rocks? Such results are important, because complete shear logs are critical for tying, in time, logs to shear seismic sections. A new tool which accomplishes this feat in a novel fashion is the Dipole Shear Sonic Imager Tool (DSI*). Previous sonic tools used monopole acoustic sources, which pulsed symmetrically outward from the tool (figure 4.17a). The compressional wave created by the source was partially converted into a shear wave at the borehole, if the shear velocity in the rock was suitably high. The dipole source, however, operates like a piston and produces an asymmetric pressure field (figure 4.17b). This pressure field flexes the borehole wall back and forth, and directly creates a shear-like wave travelling up the hole. The wave is detected by an array of receivers and wave slowness is measured by techniques developed in previous arrayed sonic tools (Middle East Well Evaluation Review, Number 8, 1990). Also, by having two pairs of these transmitters at 90 to each other, the shear wave velocity can be measured simultaneously in two directions. Compressional waves are also created and measured at the same time. The dipole tool has another strength - improved Stoneley wave measurements, thanks to a special low frequency (monopole) transmitter. The usefulness of Stoneley waves for detecting open, producing fractures in formations was described in Profiling Permeability in Middle East Well Evaluation Review, Number 5, This technique is now enhanced with the new tool, and estimates of fracture width can even be made. Figure 4.18 is an example data set, combined with an interpreted FMS image which has fracture strikes and dips noted. The Stoneley wavefield shows strong reflections off the open fractures (reflecting upwards when the tool is above the fracture and downwards when it is below). Processing and interpretation of the reflected Stoneley events can indicate the fractures reflection coefficient and their degree of openness. Fig. 4.17a: Monopole source. Fig. 4.17b: Dipole source. Fig. 4.18: Detection of fractures with Stoneley waves from DSI: Low frequency Stoneley waves reflect off open fractures in the formation, creating the chevron pattern in the wavefield on the right. An analysis and interpretation of the strength of the reflected events produces a Stoneley reflection coefficient log, indicating the extent and openness of the fractures. Correlation with the FMS interpretation (left) confirms the sonic results. 54 Middle East Well Evaluation Review

14 Hole in one Distance out from well Geophysicists can never get good enough data. Especially in the borehole, good data can be hard to come by with the seismic sensor suspended beneath several miles of wire, temperatures over 300 F and with the adjoining formation crumbling away. And on top of these factors, an entire drilling rig is standing by, waiting. The ideal for drillers is to minimize this time in the hole, by using more receivers or by adding other tools. The answer to these demands is the Combinable Seismic Imager, or CSI* tool. Its key feature is the separate sensor package which totally decouples the gimbaled, tri-axial geophones from the tool s mass. Therefore, no matter what is added to the tool, the seismic signals will be unaffected. This has several important implications. It is sometimes necessary to know the orientation of the horizontal receivers, so that the direction of incoming seismic waves can be determined. Two such examples are discussed in this article - monitoring acoustic emissions, and determining the azimuths of shear waves. This need also arises when recording reflections in wells adjacent to features such as fault planes or salt domes. With the CSI, an orientation tool can be added with no degradation of the signal. Another important use is in horizontal wells. The CSI can be added to the drill stem for operation horizontally, and still receive high-quality seismic waveforms. Finally, to speed-up the acquisition of offset and walkaway VSPs, several CSIs can be combined, to significantly reduce the number of separate tool positionings. Figure 4.19 shows the basic features of the tool. CSI tools are now being used throughout the Middle East. One important application for the tool in Egypt, where it has been used for more than one year, is in obtaining high-quality seismic images away from the borehole, using offset and walkaway VSP techniques (Middle East Well Evaluation Review, Number ). These images can indicate, with greater precision than that of surface seismic sections, the lateral changes in formations identified in the well. Figure 4.20 is one such data set acquired in Egypt. The left side of the figure shows the well s geology and petrophysics, based on Elemental Log Analysis (ELAN*) processing of the logs; Acoustic impedance log ELAN Fig (Above): Offset VSP acquired with the CSI tool. The well s logs have been used to compute an ELAN, which has been converted into time and is aligned with the VSP s seismic events. This allows the formations and reservoir features to be tracked in detail out from the well. Shaker Gimballed geophones Isolating spring to the right is the offset VSP, after processing with all three of the tool s components. The section has thus had shear events separated from the compressional. The shear might have distorted the continuity of the events and made the interpretation difficult. In this case, we can see details of the formations continuity, and discontinuity, out to more than 700m in the direction of the source. Fig. 4.19: Basic features of the CSI tool. Telemetry Combined tools Extended sensor module CSI array 100ms Two-way time Number 10,