New Directions in Sonic Logging

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1 New Directions in Sonic Logging Reaching the reservoir, and doing so safely, is made easier by recent advances in shear-wave logs. Anisotropy measurements spotlight more efficient ways to drill and stimulate formations and real-time sonic-while-drilling alerts drillers to overpressured zones. These and other developments are helping solve tough production problems. Alain Brie Takeshi Endo David Hoyle Fuchinobe, Japan Daniel Codazzi Cengiz Esmersoy Kai Hsu Sugar Land, Texas, USA Stan Denoo Englewood, Colorado, USA For help in preparation of this article, thanks to Michael Kane and Christopher Kimball, Schlumberger- Doll Research, Ridgefield, Connecticut, USA; Philippe Laurent and Julian Singer, Schlumberger Wireline & Testing, Caracas, Venezuela; Frank Morris and Robert Young, Schlumberger Wireline & Testing, Sugar Land, Texas, USA. CDR (Compensated Dual Resistivity), CMR (Combinable Magnetic Resonance), DSI (Dipole Shear Sonic Imager), ELAN (Elemental Log Analysis), EPT (Electromagnetic Propagation Tool), FMI (Fullbore Formation MicroImager), GeoFrame, ISONIC (IDEAL sonic-while-drilling), LSS (Long-Spaced Sonic Tool), PowerPak, PowerPulse and UBI (Ultrasonic Borehole Imager) are marks of Schlumberger. Michael C. Mueller Amoco Exploration and Production Houston, Texas Tom Plona Ram Shenoy Bikash Sinha Ridgefield, Connecticut, USA 1. Esmersoy C, Koster K, Williams M, Boyd A and Kane M: Dipole Shear Anisotropy Logging, Expanded Abstracts, 64th SEG Annual International Meeting and Exposition, Los Angeles, California, USA, October 23-28, 1994, paper SL3.7. Shear Wave Logging with Dipoles, Oilfield Review 2, no. 4 (October 1990): In the language of sonic logging, slowness the reciprocal of velocity is most commonly used. It is identical to the interval transit time, which is a basic measurement made by sonic logging tools. 3. Armstrong P, Ireson D, Chmela B, Dodds K, Esmersoy C, Miller D, Hornby B, Sayers C, Schoenberg M, Leaney S and Lynn H: "The Promise of Elastic Anisotropy, Oilfield Review 6, no. 4 (October 1994): Aron J, Chang SK, Dworak R, Hsu K, Lau T, Masson J-P, Mayes J, McDaniel G, Randall C, Kostek S and Plona T: Sonic Compressional Measurements While Drilling, Transactions of the SPWLA 35th Annual Logging Symposium, Tulsa, Oklahoma, USA, June 19-23, 1994, paper SS. One of the greatest challenges in optimizing development of a reservoir is placing wells correctly. Getting them in the right place, whether vertical or horizontal, not only decreases cost but improves recovery. Today, service companies are focusing their effort on developing new technology to help plan field development, optimize well location and improve drilling safety. Solutions to the problem require integrating many types of data. At the forefront are measurements that take advantage of evolving technology in sonic logging. During the last decade important advances have been made in sonic logging. 1 Using dipole sources that can excite flexural waves shear-like vibrations of the borehole these tools are capable of measuring sonic compressional and shear-wave slowness data in hard and soft formations. 2 Shearwave anisotropy measurements are sensitive to stress and fracture density and directions. 3 This is vital information for those who want to optimize production by drilling a borehole aimed at encountering as many fractures as possible. Sonic logging is becoming a routine way to plan well placement strategies leading to improvements in reservoir production. Mechanical rock properties from sonic measurements can help predict formation strength and potential sanding problems. In both vertical and horizontal wells, this information allows prediction of the best direction to perforate for maximum production. Stress magnitude derived from sonic logging helps forecast maximum sand-free drawdown pressures. Logging-while-drilling (LWD) sonic tools have been improving, too. Since the first LWD sonic tool designed to provide compressional-slowness measurements while drilling was reported in 1994, many successful real-time and memory logs have been recorded in hard and soft rocks. 4 These realtime LWD sonic measurements bring fresh information, obtained soon after the drill bit penetrates the formation. This information is vital to the driller, helping to avoid costly mistakes such as drilling into overpressured zones without proper mud-weight adjustments. In addition, experience is showing that the formations around the wellbore change when exposed to drilling fluids. LWD sonic logs from freshly drilled boreholes compared with wireline measurements usually taken days after the drilling has exposed the formation show remarkable differences. Both bring important, but different, information about wellbore properties. 40 Oilfield Review

2 Fractures CAUTION Overpressure Maximum stress Perforations Minimum stress With the introduction of dipole sonic logs, the petrophysical community has the ability to record high-quality shear and compressional slownesses in a variety of formations, and for the first time in slow formations. These measurements are helping to solve some of the mysteries in formation interpretation. In this article we look at how sonic shearwave anisotropy measurements are used to find fractures and their orientation, understand stress directions in formations and predict the best directions for perforating or drilling stable vertical and horizontal wellbores that yield optimum flow rates. We discuss how real-time sonic LWD measurements are being used, first as a means to avoid costly drilling mistakes, and then as an effective way of determining unaltered formation properties and pay zones in hard and soft formations. Both formation types present special problems for LWD measurements. Finally, we will see how petrophysicists are interpreting sonic logs in gas-saturated shaly sands one of the most difficult environments for sonic logging. Spring

3 Borehole radii S min S max -3-1 Borehole radii Drilling fractures Breakouts Damage Mechanical state of rock and failure mechanisms. The annulus around the wellbore may be damaged by drilling and tectonic stresses on the openhole. Damage in the form of breakouts or washouts usually first appears in the direction of minimum stress (S min ), and drilling-induced fractures occur with their strike direction along the direction of maximum stress (S max ). 5. Fletcher PA, Montgomery CT, Ramo GG, Miller ME and Rich DA: Using Fracturing as a Technique for Controlling Formation Failure, paper SPE 27899, presented at the 64th SPE Annual Western Regional Meeting, Long Beach, California, USA, March 23-25, Upchurch ER, Montgomery CT, Berman BH and Rael EL: A Systematic Approach to Developing Engineering Data for Fracturing Poorly Consolidated Formations, paper SPE 38588, presented at the 1997 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, USA, October 5-8, Fletcher et al, reference 5. Using Shear-Wave Anisotropy to Improve Production To produce hydrocarbons efficiently, reservoir engineers need to know tectonic and wellbore stresses and their direction. These properties first affect wellbore stability (breakouts), and then the ability to hydrofracture the well. Permeability impairment and sanding problems can be influenced by stress. The presence of a borehole will influence the state of stress of the rock and the formation strength around the borehole (left). Sonic measurements, such as those from the UBI Ultrasonic Borehole Imager tool for breakout measurements and the DSI Dipole Shear Sonic Imager tool for shear-wave anisotropy, provide a foundation for understanding formation geomechanics. Stress directions can be determined by measuring the locations of wellbore breakouts (below). Shear-wave anisotropy is a more robust method for determining stress directions because the measurement is in the rock and does not rely on formation wall failure washout which may not always be present in the well (see Dipole Shear-Wave Anisotropy Analysis, page 44). Natural and induced fracture orientations are also important considerations for reservoir management. Since hydraulic fractures open in a plane perpendicular to the minimum stress, determining stress direction is crucial. Consider the case of reservoir drainage from a hydraulically fractured well in a low-permeability formation. Since the drainage pattern is elliptical, optimum reservoir drainage depends on the correct placement of multiple wells (next page, top left). 5 Stress direction is especially important when fracturing from horizontal wells in which control of the fracture orientation with respect to the wellbore is important (next page, top right). Since shear-wave anisotropy measurements are sensitive to fracture orientation, they provide useful directions for drilling a horizontal section aimed at encountering as many natural fractures as possible. Even in soft unconsolidated formations, where sonic measurements are difficult, shear-wave anisotropy measurements are recommended reservoir engineering practices for planning fracture treatments. 6 While enhancing productivity through fracture stimulation is the primary goal, fracturing is also used as a means of implementing effective sand control in unconsolidated formations. It has been shown that unprotected (unpropped) perforations are a major cause of sand production. 7 Once stress direction is determined, 180 phased oriented perforations can be used to optimize the fracture treatment, as well as minimize the number of unpropped perforations that cause sanding problems (next page, bottom). In addition, the use of 180 phased perforations aligned normal to the minimum stress direction helps minimize wellbore tortuosity after fracturing. (continued on page 46) X066 Images versus depth X067 4 Top N 2 X068 Depth X66.7m 0 Breakout Hole deviation 37.7 degrees Breakout degrees N 111/2 degrees top 0.8 in. -2 Breakout Borehole radius, in. 2 4 Breakouts from the UBI tool. The UBI Ultrasonic Borehole Imager tool uses a pulse-echo reflection measurement that provides high-resolution images (left) of borehole size and shape. The radius plot (right) shows breakouts (red arrows). Breakouts, caused by the borehole being in compression failure, have been observed worldwide to cause ovalization of the borehole with the oval s long axis parallel to the minimum stress. 42 Oilfield Review

4 S min Smin S min Good Drainage Incomplete Drainage S min S min Good Areal Sweep Injector wells Producer wells Poor Areal Sweep Fracture azimuth and geometry determination. Incomplete reservoir drainage can occur if fracture orientation is ignored when well spacing and placement are designed (top). An understanding of fracture orientation can be useful in determining optimum well location for waterflooding, and enhanced oil recovery (EOR) applications (bottom). [Adapted from Lacey LL and Smith MB: Fracture Azimuth and Geometry Determination, in Recent Advances in Hydraulic Fracturing, SPE Monograph No. 12. Henry L. Doherty Monograph Series. Richardson, Texas, USA: Society of Petroleum Engineers (1989): ] Smin Fracturing horizontal wells. Wells drilled along the line of minimum horizontal stress will fracture in planes perpendicular to the wellbore. Wells drilled in the direction normal to the minimum stress (S min ) will fracture along the wellbore. Fracture placement can influence the drawdown along extended horizontal sections. Knowing stress directions and magnitude from formation mechanical properties helps orient perforations to contain fractures in the desired directions. Effective perforations Ineffective perforations Stable perforations Fracture S min Unstable perforations S max Oriented perforations for sand control. In sand control, the 180 phased perforations ensure that all the perforations connect to the fracture and are propped. This procedure eliminates the unconnected perforations that produce sand during drawdown. The use of 180 phased perforations, oriented perpendicular to the minimum stress (S min ), is helpful in fracturing because these perforations minimize breakout that causes borehole tortuosity. Spring

5 Dipole Shear-Wave Anisotropy Analysis X Fractures Formation slow axis Slow shear For sonic measurements, it is well recognized that sedimentary rocks generally exhibit some degree of anisotropy. 1 Anisotropy may arise from intrinsic structural effects, such as aligned fractures and layering of thin zones, or from unequal stresses within the formation. These effects lead to differences in formation elastic properties, and if they are on a smaller scale than the sonic wavelengths, then sonic wave propagation can be used to detect and quantify the anisotropy. Sonic waves travel fastest when the direction of particle motion polarization is aligned with the material s stiffest direction. Shear-wave particle motion is in a plane perpendicular to the wave propagation direction. If the formation is anisotropic in this plane, meaning that there is one direction that is stiffer than another, then the shear-wave polarization aligned in the stiff direction will travel faster than one aligned in the other, more compliant direction. As a result, the shear wave splits into two components, one polarized along the formation s stiff (or fast) direction, and the other polarized along the formation s compliant (or slow) direction. 2 For example, in the case of vertically-aligned dense microcracks or fractures, a shear wave that is polarized parallel to the fracture strike will propagate faster than a shear wave polarized perpendicular to it (above right). In general, a shear (or flexural) wave, generated by a dipole source, will split into two orthogonal components polarized along the X- and Y-directions in the formation. As they propagate along the borehole, the fast wave will be polarized along the direction parallel to the fracture strike and a slow wave in the direction perpendicular to it. With two orthogonal dipole transmitters and multiple receiver pairs aligned in orthogonal directions, the DSI Dipole Shear Sonic Imager tool can measure the components of shear slowness in any direction in a plane perpendicular to the borehole axis (next page). The measurement involves recording the waveforms on receivers pointing in directions parallel and normal to each transmitter along the tool x- and y-axes. 3 Four sets of waveforms are recorded at each depth and receiver level. These measurements are labeled xx, xy, yx and yy. The first direction refers to the transmitter and the second direction to the receiver. The direction and speed of the fast and slow split shear waveforms traveling in the formation can be easily determined by mathematically rotating the measured waveforms through an azimuthal angle so that they line up with the two orthogonal formation X- and Y-directions. Z Formation fast axis Y Fast shear Shear-wave splitting. Shear waves travel in an anisotropic formation with different speeds along the directions of the formation anisotropy. In this example, anisotropy is caused by the vertical fractures (or microcracks) with a strike direction along the formation Y-axis, and the fastest shear wave with the longer wavelength component will be polarized along the fracture strike direction as it propagates along the borehole (Z-axis). When shearwave splitting is the result of stress anisotropy, the Y-axis corresponds to the direction of maximum stress, and the X-axis corresponds to the direction of minimum stress. This is done by minimizing the cross-receiver energies, xy and yx. The rotated direction of the fastest shear wave becomes the fast-shear tool azimuth; and the tool orientation, measured by a magnetometer, is used to determine the fast shear azimuth relative to true north. This rotation, called the Alford method, uses the fact that the anisotropy model expects the amplitude of the cross-receiver measurements to vanish when the measured axes x and y align with the anisotropy axes X and Y. 4 In addition to the fast and slow shear-wave velocities determined by a slowness-timecoherence (STC) processing on the rotated waveforms three measurements of anisotropy are computed. 5 These are energy anisotropy, slowness anisotropy and time anisotropy. 44 Oilfield Review

6 Slowness anisotropy is the difference between the fast and slow slownesses calculated by STC on the rotated waveforms. It yields a quantitative measure of slowness anisotropy, and has the best vertical resolution at about 3 ft [1 m] the size of the receiver array. It can be compared directly with seismic or core measurements of slowness anisotropy. Traveltime anisotropy is the arrival-time difference between the fast- and slow-shear waves at the receivers. It is obtained from a cross-correlation between fast and slow shear-wave arrivals at each receiver spacing. Time lags computed at each receiver are referenced to the largest offset receiver and averaged across the receiver array. This is divided by the average of the fast and slow arrival times to compute a percentage difference. The traveltime anisotropy indicator is robust and quantitative, and has the vertical resolution of the average transmitter-receiver spacing, 13 ft [4 m]. Slowness and traveltime anisotropy indicators are identical in formations with homogeneous beds thicker than 13 ft. Energy anisotropy is the energy in the crosscomponent waveforms as a percentage of energy in all four components. In an isotropic formation, energy anisotropy reads zero. In an anisotropic formation, the reading depends on the degree of anisotropy. Two curves are computed from the waveforms: minimum and maximum cross-energy. The minimum cross-energy is the energy in the cross-components when the tool measurement axis lines up with the formation anisotropy axis. Minimum cross-energy reads zero in an ideal formation whether anisotropic or not. This curve is a good relative measure of whether the assumed model for anisotropy inversion fits the real formation. The maximum cross-energy is a measure of the amount or strength of anisotropy. Unlike the two previous anisotropy measurements (slowness Flexural waves induced by dipole transmitters. During logging, flexural waves are induced by dipole transmitters fired sequentially in two perpendicular directions, first along the tool x- and then the tool y-axes. In this example, the fastest component of the induced shear wave is polarized along the formation Y- axis direction, which is aligned along the fracture strike or maximum stress direction. The slowest component of the shear wave is polarized along the formation X-axis. Projections of these two shear-wave components are received by each of the dipole sonic tool x- and y-receiver pairs. The inline signals xx and yy are the x-receiver and y-receiver waveforms received when the x- and y- transmitters are fired. Cross-signal components xy and yx are the y- and x-receiver waveforms received as the x- and y-transmitters are fired. The Alford rotation angle, θ, is determined by minimizing the crosssignal components. This would happen automatically if the tool axes were rotated through an angle, θ, and aligned with the two orthogonal directions in the anisotropic formation. Undisturbed borehole Dipole transmitter pair and time), energy anisotropy is a measure of both slowness and amplitude differences of the fastand slow-shear waves. Large differences between the maximum and minimum values, especially when the minimum energy is low, indicate zones of significant anisotropy. Energy anisotropy, though qualitative, is little affected by processing, and is the principal measure of anisotropy. X R 8x R 7x x R 6x T x R 5x R4x R 3x R 2x R 1x Tool axis R 8y R 7y R 6y R 5y T y R 4y θ R 3y R 2y R 1y y Receiver-8 pair Receiver-7 pair Receiver-6 pair Receiver-5 pair Receiver-4 pair Receiver-3 pair Receiver-2 pair Receiver-1 pair Borehole flexural wave (exaggerated) Y Formation fast shear wave axis Tool orientation relative to formation 1. Armstrong et al, reference 3, main text. 2. For compressional waves, the particle motion is the same direction as the wave propagation. 3. Esmersoy et al, reference 10, main text. 4. Alford RM: "Shear Data in the Presence of Azimuthal Anisotropy: Dilley, Texas," Expanded Abstracts, 56th SEG Annual International Meeting and Exposition, Houston, Texas, USA, November 2-6, 1986, paper S Kimball and Marzetta, reference 8, main text. Receiver array Spring

7 12,800 Aiming for Minimum Stress Sonic velocity anisotropy was used by Seneca Oil Company in the USA to determine the most productive position and direction for a horizontal well. A pilot hole for horizontal drilling was drilled through a moderate-porosity 10 to 15 p.u. shaly sand interval. The operator s objective was to determine natural fracture orientation and understand tectonic stress direction (left and below). DSI logs were recorded for Stoneley, monopole P- and S-wave and both crossed receivers (BCR) dipole modes. The BCR mode was processed for anisotropy. Three different computations of shear-wave anisotropy are presented, dealing with the time and energy of the dipole shear waveform. First, shear-wave energy anisotropy the minimum and maximum cross-component energy difference is the most obvious indication of anisotropy. Large energy differences, when the minimum stays low, indicate significant shear-wave splitting and signal zones of interest. The interval from 12,750 to 12,870 ft contains several zones with significant anisotropy. 12, Kimball CV and Marzetta TL: Semblance Processing of Borehole Acoustic Array Data, Geophysics 40 (March 1984): Sinha B and Kostek S: Stress-Induced Azimuthal Anisotropy in Borehole Flexural Waves, Geophysics 61 (November-December 1996): Esmersoy C, Kane M, Boyd A and Denoo S: Fracture and Stress Evaluation Using Dipole-Shear Anisotropy Logs, Transactions of the SPWLA 36th Annual Logging Symposium, Paris, France, June 26-29, 1995, paper J. Depth, ft Emax % Emin % Energy anisotropy Tool orientation deg Caliper 5 20 in. Gamma ray API Fast shear wave azimuth deg Azimuth uncertainty Time anisotropy 50 % 0 Shear waveforms Slowness anisotropy µs 5000 % Slow-wave slowness 250 µs/ft 50 Processing window Fast-wave slowness 250 µs/ft 50 Anisotropy evaluation. The difference between the minimum and maximum cross-component shear energy, shown in the depth track, is an indicator of anisotropy. The tool orientation (blue), track 2, is used to determine the absolute fast-shear azimuthal direction (red), with its uncertainty (gray shading), track 3. The interval between 12,750 and 12,870 ft [3886 and 3923 m] contains several anisotropic zones. The average of the fast component of the shear-wave direction, shown in the azimuthal projection (inset, right), is between 20 and 30. Acoustic time anisotropy (black with shaded gray) is shown in track 4. This measurement is more sensitive to acoustic properties deep within the formation than surface effects such as drilling-induced fractures. Both fast (blue dashed) and slow (red) components of the shear slowness are computed by STC processing and are shown in track 4. For visual quality control, the fast (red) and slow (blue) waveforms from the largest spacing receiver are shown in track 5. The light yellow band shows the shear-wave processing window, which should include the first few cycles of the shear arrival. Both moveout and energy differences between the fast and slow shear waves are easily visualized and can be verified on the display. Both waves would be identical in an isotropic formation Frequency, % 46 Oilfield Review

8 8 Breakout S max Energy anisotropy Shear waveforms Fractures in in. Four-arm caliper projections as qualitative indicators of stress direction. The zone containing significant anisotropy seen by the DSI tool also shows hole breakouts shown by enlarged hole size measured by the fourarm caliper in this vertical borehole. The breakouts occur in the direction of minimum horizontal stress. Perpendicular to the breakout direction is the principal tectonic stress direction of 25. Bit size is shown by the green circle, and the borehole walls are compressed inward slightly along the maximum stress direction. The data inside the bit size represent the calipers opening up as they come off bottom. Second, large shear-wave traveltime anisotropy indications based on arrival time of the fast and slow waves correlate well with the energy-anisotropy indications throughout the interval. The third anisotropy measurement, slowness anisotropy, is derived from the computed shear-wave, fast- and slow-component slownesses using slowness-time-coherence (STC) processing to obtain slowness. 8 This deep-reading measurement suggests that the anisotropic properties are from within the reservoir and not from surface effects such as shallow drilling-induced fractures. 9 The fast shear-azimuth direction for this interval is between 20 and 30 with respect to north. This azimuth, aligned with the maximum horizontal stress direction, is the direction of the current tectonic stress field and is the orientation of any drilling-induced fractures. This is also the direction that would produce the least stable horizontal borehole, and be least likely to intersect open fractures. The oriented four-arm caliper summation data over this zone give a qualitative overall view of the borehole profile (above left). Hole breakout is found in two opposing quadrants, which straddle the axis of maximum horizontal stress. Perpendicular to the breakout direction, the maximum horizontal stress direction is found to be 25, which agrees with the direction found by the fast shear-wave azimuth Fractures Fractures Depth, ft Gamma ray Fast shear-wave azmuth Fast shear-wave slowness Processing window Offline 0 API µs/ft µs 6000 energy Shear-wave splitting in cased hole. The DSI tool differential-energy measurements, shown in the depth track, identify the zones with high shear-wave anisotropy caused by fractures. The difference in the two shear-wave amplitude components (track 5) increases in the fractured zones. The operator sidetracked the horizontal leg of this well at right angles to the maximum horizontal stress, along the direction intersecting the largest number of natural fractures for maximum production. In another application, shear-wave anisotropy was used by Louisiana Land & Exploration Company in southwest Wyoming, USA to find fractures in a cased well drilled in a tight gas-bearing sandstone. Openhole logs were not run because of poor wellbore conditions. 10 However, shear-wave anisotropy logging was used to find the fractured intervals behind casing (above). The fractured zones are easily identified from the DSI differential-energy curves shown in the depth track. Here the maximum in the energy difference between the fast and slow shear waves quickly identifies three zones in which large shear-wave velocity anisotropy exists because of the fractures. These zones were perforated, and subsequent production logs show good gas entry from each zone. This well subsequently produced 4.5 MMcf/D of gas from these perforations. Spring

9 Measuring Stress with Anisotropy One major challenge is to distinguish between stress-induced and other sources of shear anisotropy, such as fractures. Currently, this distinction is difficult to make from sonic measurements alone, and remains a topic of ongoing research. Recently, it has been found that borehole stress concentrations cause a crossover in the two flexural dispersion curves (right). 11 This crossover is caused by stress-induced radial gradients in the acoustic-wave velocities that are different in the two principal stress directions. Other sources of intrinsic anisotropy caused by finely layered dipping beds, aligned fractures or microstructure found in clays exhibit neither radial velocity gradients nor flexural dispersion crossover. Consequently, a crossover in the flexural dispersion curves can be used as an indicator of stress-induced anisotropy. In the presence of stress-induced anisotropy, the fast-shear direction coincides with the maximum stress direction, and the magnitude of the shear anisotropy is proportional to the stress magnitude. 12 Velocity, km/s Velocity, km/s Slow shear wave Fast shear wave Unstressed Frequency, khz Polarized perpendicular to stress Polarized parallel to stress Stressed 5 MPa Frequency, khz Dipole dispersion crossover. Laboratory experimental (circles) and theoretical (solid curves) flexural dispersion curves in Berea sandstone. The plots show the shear-wave anisotropy velocities measured without stress (top), and with 5 MPa [725 psi] uniaxial stress (bottom). The effects of stress on shear-wave anisotropy depend on signal frequency and stress magnitude. As stress increases, the shear-wave component polarized parallel to the stress direction becomes the fastest component at low frequencies. The reverse is true at high frequencies. Fault Compressional stresses Finding Faults with Anisotropy In fracture systems, faults are major events that impact not only fracture distribution, but also the rock stresses. Significant rock deformation, fracturing and variations of the stress fields are found near faults (below right). An example of fault-induced fractures is seen in an Egyptian oil-producing well drilled in granite basement rock. 13 Traditional sonic techniques, such as Stoneley wave attenuation and reflection were combined with anisotropy using shear-wave splitting to evaluate fractures near a fault in this hard rock formation. These techniques react in different ways to the presence of fractures in the formations, and their combined analysis reveals the complex picture of this formation. The direction of the fast shear wave provides information on fracture orientation, but the shear-wave azimuthal measurements differ somewhat from that of traditional Stoneley fracture analysis; in particular shear-wave anisotropy investigates a volume of formation up to several borehole diameters farther from the borehole and can sense fractures missed by other techniques. 14 Combining measurements provides addi-,,,,, Prefaulting extensional Extensional fractures stresses tional information about reservoir characteristics, and is especially helpful in locating the fault. Faults as a major disruption in stress and fracture orientation. A fault can cause a drag zone in which rock deformation is large. Bending of the beds next to the fault causes extensional stresses with fractures on one side of the bed, and compressional stresses with conjugate shear fractures on the other side (inset). Measured stress directions will change rapidly when a well crosses the fault. 48 Oilfield Review

10 Gamma ray Fault signature Processing window Anisotropy 0 API Slowness, % 0 Energy Caliper anisotropy 0 Time, % in. 16 Tool azimuth Fast shear azimuth Shear slowness Shear waveforms 0 deg µs/ft µs 7000 Depth, ft X300 X400 Maximum energy Minimum energy X500 Caliper Gamma ray Tool azimuth Fault Error bar The trick is to identify and locate the fracture system associated with the fault zone. Many wells in the same field did not intercept the fault zone and as a result never reached commercial production levels. DSI logging, using monopole P-, S-wave, Stoneley and BCR modes, was combined with conventional openhole porosity logging and FMI Fullbore Formation MicroImager measurements to locate productive fractures and their orientations. The FMI fracture orientation data (not shown) agree with the results from the fast shear-wave azimuth in the upper zones of the well and suggest a major tectonic stress in the area oriented in a NW (320 ) direction (above). Slow shear Slowness anisotropy Time anisotropy Fast shear Fault found with anisotropy evaluation. Fast shear azimuth (track 3) shows major rotation of the fast shear azimuth from 315 to 20 across a relatively short depth interval centered at X400 ft, the fault location. Anisotropy indicators (track 4) are large below the fault, indicating small cracks in the rocks, probably caused by high stress in this region. Waveforms and the processing time window used to determine shear-slowness velocities are shown in track 5. The shear-wave anisotropy analysis shows the fast shear azimuth changing gradually from 320 to 340 below X325 ft. There is substantial shear-wave splitting at X300 ft indicated by the energy, slowness and time differences. However, there are no indications of major fractures at this depth from the traditional Stoneley analysis (not shown). The FMI images confirm the anisotropy indications, showing primarily closed fractures with their strike oriented at 315. Major fracture events were recorded between X380 and X460 ft with Stoneley fracture analysis, and Stoneley permeability indicators were strong down to X490 ft. Porosity is 15 p.u. from X350 to X460 ft and significantly less above and below this zone. Shear-wave splitting shows an abrupt rotation of the fast shear azimuth from 315 above X400 ft to 20 below and then back to 0 in the lowest part of this interval. It is worth observing that at X400 ft, where the azimuth change is taking place, there is no significant evidence of anisotropy. However, shear-wave anisotropy is present above and below this depth. All evidence indicates that the well crossed the fault at X400 ft. The events detected as fractures in the Stoneley analysis are likely to be fractures caused by the fault or the fault itself. Faults are common in granite, and though faults were identified in a higher section of this well using a vertical seismic profile, VSP measurements were not available in this interval. However, in shear-wave anisotropy logging, the fault signature is clear the fast shear azimuth starts changing slowly 70 ft [21 m] above the fault, then quickly changes by nearly 65 across the fault and returns to an intermediate value 100 ft [30 m] below the fault until it finally returns to the regional trend. Faults typically have large effects on the producibility and stability of a reservoir and must be accounted for when completing a well. The fault seen in this example exhibits high permeability and is expected to have a good production potential. The fast shearwave anisotropy indicates the presence of fractures or stress, and the directional variation of the fast shear azimuth can be used to detect faults and their associated highpermeability, fractured zones. 11. Winkler KW, Sinha BK and Plona TJ: Effects of Borehole Stress Concentrations on Dipole Anisotropy Measurements, Geophysics 63, no. 1 (January-February 1998): Sinha BK, Papanastasiou P and Plona TJ: Influence of Triaxial Stresses on Borehole Stoneley and Flexural Dispersions, Expanded Abstracts, 67th SEG Annual International Meeting and Exposition, Dallas, Texas, USA, November 2-7, 1997, paper BH Endo T, Ito H, Brie A, Badri M and El Sheikh M: Fracture and Permeability Evaluation in a Fault Zone from Sonic Waveform Data, Transactions of the SPWLA 38th Annual Logging Symposium, Houston, Texas, USA, June 15-18, 1997, paper R. 14. Sinha and Kostek, reference 9. Spring

11 Early Warning While Drilling Real-time LWD sonic data in formations where pressures are either unknown or known to vary rapidly can be critical. Knowledge of expected overpressured formations provides the ability to efficiently and safely drill wells with correct mud weights. 15 For example, after there were kicks attributed to overpressured formations in two offset wells nearby, real-time LWD overpressure detection capability was tried in an exploratory well drilled offshore Angola, West Africa. The in. casing was set down to X905 ft and drilled out using a in. bit with the sonic-while-drilling tool in the bottomhole assembly (BHA). A long single-bit run was conducted over a 7-day period that covered a depth from X1000 to X8300 ft (below). The wellbore was deviated 20 in this interval. The BHA consisted of a PowerPak mud motor, CDR Compensated Dual Resistivity tool, PowerPulse MWD telemetry system for realtime transmission and an ISONIC sonicwhile-drilling tool. The ISONIC tool, placed above the PowerPulse system, was approximately 104 ft [32 m] away from the bit. At the average rate of drilling, the LWD measurements were made fewer than four hours after the formation was first cut. Wireline sonic logging was run after the 7-day drilling run was completed, and then only after circulating the well for several hours. The gamma ray log indicated that the entire interval is primarily shale, with sand-shale sequences dominating the bottom 2000 ft [610 m] of the formation. A trend of decreasing slowness with increasing depth is observed in the upper interval from X1000 to X4800 ft. This trend is normal and caused by the overburden stress, which compresses the rock and decreases the porosity with depth. As long as slowness readings follow this trend, formation porosities are maintaining a normal compaction with depth. If overpressured formations are encountered, the slowness data points will diverge from the expected trend toward abnormally high values (above right). Increasing depth Entering overpressured zone Increasing slowness Normal pressure zone Normal compaction trend Real-time overpressure alert. Formation compaction, resulting from increasing overburden weight, causes porosity and thus acoustic slowness to decrease with depth. High deviation from the natural trend is a sign of an overpressured zone. Real-time LWD acoustic slowness measurement can warn a driller of entry into an overpressured zone, early enough to allow mud-weight adjustments avoiding costly damage to the borehole. Depth, ft X2000 X3000 X4000 X5000 X6000 X7000 X8000 Gamma ray 0 API 150 Attenuation resistivity 0.2 ohm-m 20 Phase shift resistivity 0.2 ohm-m 20 Wireline slowness 150 µs/ft 50 Compaction trend ISONIC slowness 150 µs/ft 50 Wireline slowness 150 µs/ft 50 ISONIC slowness 150 µs/ft 50 Detecting overpressure while drilling. The log display shows a gamma ray, CDR phase and attenuation resistivity and the LWD and wireline sonic slowness log comparisons in a long 7000-ft [2134-m] bit run. The gamma ray log (track 1) indicates that the entire interval is primarily shale. The wireline and LWD slowness logs are shown in tracks 3 and 4, respectively, and are shown overlaid in track 5. Real-time LWD sonic readings detected an overpressured zone 5 hours ahead of expectations, Zone A. There is a consistent difference of up to 10 µs/ft [33 µs/m] between the ISONIC reading and wireline slownesses in Zone B attributed to formation alteration near the borehole. B A This is what happens at about X4800 ft. The real-time LWD slowness diverges from the compaction trend, indicating the approach of potential overpressured formations. Similarly, the CDR resistivity log shows a departure from its normal trend of increasing resistivity with depth toward lower than normal resistivity values, because of increasing porosity in the overpressured formations and resulting higher saline-water content in shale. This interval, showing logging values diverging from their usual trends, extends down to about X4850 ft. For the two wells previously showing kicks, the tops of overpressured formations were found at X5000 ft 200 ft [60 m] below the first sign of overpressure encountered in this well. The LWD real-time sonic logs provided warning that the driller was entering an overpressured formation hours ahead of expectations. Another example shows the use of realtime LWD sonic logging in soft formations to locate a gas-sand pay zone. This vertical well was drilled by an operator in the Gulf of Mexico. The ISONIC tool was mounted in a BHA 77 ft [23 m] behind the bit, and at the average rate of penetration, the formation was logged less than an hour after the bit cut through it. The slowness projections on the LWD memory semblance 50 Oilfield Review

12 X100 X300 X500 Density porosity Deep induction Depth, ft 60 p.u ohm-m 20 Neutron porosity Medium induction 60 p.u ohm-m 20 analysis an indicator of data quality verify the accuracy of the real-time compressional-slowness log (above). It is clear that high semblance coherence for the compressional arrival was obtained throughout the entire interval. There are good correlations between the sonic compressional and resistivity curves, especially below X400 ft, where both are responding to changes in porosity. In the sand bed, Zone B, the neutron and density curves show a large crossover a classic gas signature. This is supported by the high-resistivity readings. The compressional slowness also reads extremely high in this zone much higher than would be expected LWD Wireline Gas sand ISONIC slowness 180 µs/ft 80 LSS slowness 180 µs/ft 80 STC projection ISONIC slowness 30 µs/ft 210 Real-time gas detection in slow formations. The LWD sonic compressional slowness (red) shows a large increase (track 4) in Zone B, a gas-sand pay zone. Comparisons with wireline sonic (blue) are generally good, except for a systematic difference in Zone A between XX50 and X180 ft. This is attributed to stress relaxation in the shales caused by the drilling process. In the gas-sand pay zone confirmed by the classic neutron-density gas crossover (track 2) the wireline sonic log, track 4, is beginning to show signs of invasion (Zone B) because its gas signature is not as strong as that of the real-time LWD sonic log. from a normal porosity variation indicating gas. The gas sand appears to have a thin shale stringer in the middle, which is also visible on the porosity and resistivity logs. It is interesting to note that the wireline sonic log shows less response to gas in this zone, particularly in the upper section of the gas sand above the shale stringer. This is thought to be due to borehole filtrate invasion gradually depleting over a few days the volume of gas in the annular zone surrounding the borehole, thus decreasing the gas signature seen by the wireline tools. Details such as these, seen in many LWD and wireline log comparisons, help show the value of early real-time answers. A B Changing Formation In the previous offshore Angola example, real-time sonic LWD data helped the operator safely drill the well. However, subsequent comparison of the LWD logs with their wireline counterparts sparked the curiosity and interest of log interpretation experts. Although LWD and wireline logs agree in many wells, experience has shown that sometimes there are zones, especially in shales, where the slowness measurements can differ. In the upper interval, Zone B, of the offshore Angola well, the LWD slowness log reads consistently lower than the wireline log by 5 to 10 µs/ft [16 to 33 µs/m]. Everywhere else, the agreement between the LWD and wireline sonic logs is excellent. The agreement in most of the well indicates that the differences are not caused by the different processing methods STC processing was used for LWD; and for wireline, a firstmotion-detection scheme (FMD), which is triggered by waveform amplitudes exceeding a selected threshold. Other explanations were sought. Sonic measurements are known to be affected by borehole washouts. These borehole irregularities can cause the measured slowness values to oscillate around the true formation slowness values. Although the LWD log was not borehole-compensated and the wireline was, the systematic difference between the two observed measurements was probably not caused by washouts. First, the borehole should be in excellent condition during drilling, thus making the need for borehole compensation minimal. This is particularly true since this borehole was drilled with oil-base mud, which minimizes washout problems. Second, the consistently faster trend of the LWD slowness values conflicts with the expected effect of washouts, which make the uncompensated slowness values fluctuate around the compensated wireline measurements. Because the faster trend of the LWD sonic is persistent, the absence of borehole compensation is probably not the cause of the discrepancy. 15. Hsu K, Minerbo G, Hashem M, Bean C and Plumb R: Sonic-While-Drilling Tool Detects Overpressured Formations, Oil & Gas Journal 95, no. 31 (August 4, 1997): 59-63, Spring

13 X1,000 X1,200 X1,400 X1,600 X1,800 Wireline LWD Phantom arrival Altered shale Borehole Altered shale compressional arrival Sonic logging tool Undamaged formation Virgin formation compressional arrival Bicompressional arrival. Water takeup in certain shales or stress relief near the borehole can change the elastic moduli of the annular rock. The altered zone traps wavefronts in the same way as the borehole does. The extraneous second arrival is shown leading to a second compressional wave trapped in the altered zone. X2,000 Waveform VDL Depth, ft 500 µs 3500 Wireline slowness 180 µs/ft 80 STC projection ISONIC slowness ISONIC slowness 180 µs/ft µs/ft 200 Time-lapse logging using sonic while drilling. Formation alteration is taking place in the 6 to 7 days between the running of the LWD sonic and the wireline measurement. Details in both slowness logs seen in track 2 correlate closely, but there is a systematic shift to larger slowness in the wireline log. The reason for the shift can be seen in the slowness-time-coherence (STC) projections from the ISONIC tool, track 3, where a second slower coherent arrival is emerging. This phantom arrival, too fast to be a shear arrival in these slow formations, is likely to be caused by shale alteration. It is clear that detailed features of the two slowness logs in the upper shaly zone are correlated (above left). However, the consistent difference between the two measurements in this interval and the STC projection fronts in the same way that a borehole does. The extraneous second arrival in this example known as a bicompressional wave corresponds to a compressional wave trapped in the altered zone (above right). In stresses produce a decrease in porosity and a derived from the ISONIC recorded waveforms North American test wells, many early wireline stiffening of the bulk-frame modulus. 16 The in track 3 provides clues to what was happening. Specifically, the STC projection shows that there is a second coherent arrival becoming apparent about 10 to 20 µs/ft [33 to 66 µs/m] slower than the first arrival. This second arrival is too fast to be the shear in such a slow formation. A slow-formation phenomenon known as an altered zone provides a possible explanation for the second arrival. An altered zone is created by the drilling process which may damage the borehole wall and cause the elastic modulus in an annular zone around the borehole to change. This is particularly true in soft formations. Water take-up in certain shales and shaly sands or stress relief near the borehole can also change the elastic modulus of the annular rock, generally reducing it. The altered zone traps wavepressional digital sonic field tests recorded bicom- waveform arrivals. The time delay between the LWD sonic measurements and the wireline sonic measurements in the altered zone is about 6 to 7 days. The presence of a well-developed altered zone can cause the wireline tool to read slowness values somewhere between the altered and unaltered formation-slowness values, depending on the type of tool and spacing used. In this well LWD sonic measured the formation only hours after rock was drilled before any significant alteration had occurred. With all the evidence collected, the operator concluded that the slowness difference seen while drilling and at wireline time was likely caused by changed formation properties over time a time-lapse effect. Confident in the accuracy of the sonic-while-drilling results and realizing the potential for real- overall effect of this consolidation phenomenon can decrease the shale s slowness with time, in an annular zone a foot or more away from the borehole. 17 The distance into the formation will depend on formation permeability, magnitude of the pressure difference, rock properties and the time since the well was drilled. In such cases, the LWD slowness can be larger than the wireline slowness. This phenomenon may have occurred in the previous Gulf of Mexico shaly-sand example. In this well, the wireline LSS Long-Spaced Sonic Tool slowness shows overall good agreement with the real-time sonic slowness. However, close examination shows that in the upper shale interval, Zone A, the LWD slowness tends to read 3 to 5 µs/ft systematically larger than the wireline slowness again indicating shale consolidation near the borehole, caused by the drilling process. 52 Oilfield Review time overpressure detection, the operator continued using the ISONIC tool in its highprofile wells in a neighboring block, later making a major discovery there. In cases like this when a systematic difference is observed between LWD and wireline logs taken some time after drilling was completed, it usually happens in shaly zones. Experience shows that the two logs generally agree in hard rock and clean sands. The slowness difference can be expected to increase with time, due to shale swelling. In these cases, the LWD slowness would always be less than the wireline slowness. In some wells the opposite occurs. A well drilled in a plastic shale can lead to borehole deformation due to compaction from high vertical stress. In such cases, the high mean

14 Since the LWD measurement has the potential of determining unaltered formation slowness, it has significant implications for two seismic applications, specifically, the time-depth relationship and the synthetic seismogram. Seismic waves, with their long wavelength, see the bulk unaltered formation and are insensitive to small features such as the borehole region. However, wireline sonic logs are frequently affected by formation alteration, and under those conditions they do not provide the most appropriate velocities for comparison with seismic data. Hard Rock LWD Although hard rock formations are considered routine for wireline sonic logging because the formation signals are fast and separate from the borehole mud signal they present a major challenge for LWD measurements. Experience indicates that the level of drilling-induced noise is high in hard formations, and under these conditions, downhole waveform processing requires special care. In such wells, waveform stacking is indispensable. The stacked waveforms in the ISONIC slowness tool are filtered with a narrow band-pass filter, tuned to frequencies at which drilling noise is minimal and drill collar arrivals noise are highly attenuated. 16. This situation would occur if the drilling fluid pressure was less than the pore pressure. Also, because of the high ionic strength of the water phase in some drilling mud (200 to 300 kppm calcium chloride), the mud can pull water out of the formation, particularly the shales. This can lead to embrittlement of the formation, and possible fracturing. 17. Hsu K, Hashem M, Bean CL, Plumb R and Minerbo G: Interpretation and Analysis of Sonic While Drilling Data in Overpressured Formations, Transactions of the SPWLA 38th Annual Logging Symposium, Houston, Texas, USA, June 15-18, 1997, paper FF. 18. Aron J, Chang SK, Codazzi D, Dworak R, Hsu K, Lau T, Minerbo G and Yogeswaren E: Real-Time Sonic While Drilling in Hard and Soft Rocks, Transactions of the SPWLA 38th Annual Logging Symposium, Houston, Texas, USA, June 15-18, 1997, paper HH. 19. The empirical time-averaged Wyllie model is a sonic-porosity interpretation mixing law that works in many low-porosity applications. It is a linear volumetric mix of the formation and fluid slownesses. It does not account for the fact that real rocks are not homogeneous, nor microscopically continuous, or isotropic and not ideally elastic. 20. The first significant model of sonic properties in fluid-filled porous rock was developed by Gassmann. See Gassmann F: Elastic Waves Through a Packing of Spheres, Geophysics 16, no. 18 (1951): Then Biot developed a more complete model by allowing relative motion between the fluid and rock matrix. See Biot M: Theory of Propagation of Elastic Waves in Fluid- Saturated Porous Solids, Journal of the Acoustical Society of America 28 (1956): The Biot equations converge to those of Gassmann at low frequencies. For a general review of sonic properties in fluid-filled porous media, see Ellis D: Well Logging for Earth Scientists. New York, New York, USA: Elsevier, XX900 X1000 X1100 X1200 Stoneley waves Shear waves Compressional waves Drilling noise Compressional slowness Shear slowness X1300 Limestone bed Wireline comp. slowness 200 µs/ft 50 Depth, Gamma ray LWD comp. slowness m API 200 µs/ft 50 LWD shear slowness µs/ft 50 The stacked and filtered waveforms are then archived in memory, while the downhole tool microprocessor and digital signal processor determine the slowness of the coherent arrivals in the waveforms using STC processing and selecting the arrival that corresponds to the compressional slowness known as labeling. Once the compressional slowness is extracted downhole, it is transmitted to surface via the mud telemetry system. The ISONIC slowness log is generated at surface in real time as the tool passes the formation. An example in a highly deviated North Sea well shows the current capability of LWD real-time sonic logging in hard rock ISONIC waveform VDL 400 µs 3400 Petrophysics: Sonic Logs in Gas Sands After the structure of the reservoir is known traps are located, faults are mapped and fractures and their orientations identified pay zones must be quantified (see "Localized Maps of the Subsurface, page 56). Hydrocarbon identification, and determination of porosity and saturation are important petrophysical applications for sonic logging. The Biot-Gassmann theory is widely used today to relate wet rock to dry rock frame properties for sonic applications. 20 With the introduction of dipole sonic logs, and the ability to record high-quality shear and compressional slownesses for the first time in slow formations, trends can be identified in sands and shales and matched with semi-empirical correlations based on Biot-Gassmann theory. These trends can be used as a quality-control check on sonic logs and for quicklook lithology interpretation. However, the effects of partial saturation pose special problems. Gas and liquid mixtures in soft formations make the interpretation more complicated, as these can affect the sonic slowness significantly, in particular the compressional slowness. The compressional-to-shear velocity ratio, V p /V s, has been used in unconsolidated sands to qualitatively detect gas. The fluid distribution in the pore system at the microscopic level and the acoustic frequency have a strong influence on the strength of the gas effect on acoustic (above). 18 In this well, the ISONIC logging tool was attached 114 ft [40 m] behind the drill bit, which put its measurements more than 4 hours after drilling. The recorded waveform variable density log (VDL) shows the good compressional signal, followed by a strong shear and even stronger Stoneley arrivals. Some residual drilling noise is visible in the harder sections of the formation. The compressional slowness from the LWD matches the wireline results throughout this well. Many fast carbonate stringers correlate between both sonic logs and the gamma ray, all dipping in value as the clean hard stringers are passed by the logging tools. In the lower limestone zone at X1300 m, a Wyllie time-averaged porosity of about 7 p.u. is computed for this limestone bed. 19 These results enable the operator to determine formation rock properties for planning Spring 1998 a hydraulic fracturing program. 53 A LWD Sonic in fast formations. The ISONIC tool recorded waveforms plotted in the VDL display in track 3 show a compressional arrival near 1150 µs, a strong shear near 1700 µs and a stronger Stoneley arrival near 2500 µs. Compressional (red) and shear (green) slowness values are displayed in track 2. The LWD compressional slowness matches the wireline results (blue) throughout this interval. The formation slowness and the amplitude of the compressional arrival correlate, especially just below X850 m, where the formation slowness drops from 95 to 80 µs/ft [312 to 262 µs/m] and the amplitude of the compressional arrival increases by about a factor of two. In the faster harder portions of this interval, Zone A, increases in drilling noise are visible on the early part of the VDL waveforms, just before the compressional arrival.

15 Vp, km/s Frequency, Hz Sonic 100 Seismic Gas saturation, % Relationship of compressional velocity to frequency and gas saturation. Seismic frequencies lie near the front of this plot, which shows an abrupt change in velocity with only a few percent increase in gas saturation. Sonic logging measurements are in the center of the graph, and show a more gradual increase in velocity as gas saturation increases. Vp / Vs North Sea shales Malaysia shaly sands North Sea water sand Unconsolidated sediments Shales Porosity, p.u. Sonic crossplot. Wet formations, such as the Wet Sand trend (blue curve), show an increase in their V p /V s velocity ratio due to decreasing shear velocity, caused by fluid-rock coupling. Shales (green curve) show even greater effect. The new mixing law for computing the effective fluid-bulk modulus of gas-saturated formations successfully explains the observed trends in logging data. slowness. Although the Biot-Gassmann model together with Wood s mixing law have been successfully used at seismic frequencies for geophysical interpretation, they give deceptive results in partially gas-saturated formations at sonic frequencies. 21 The Biot-Gassmann model itself is not the problem. The effect of gas on elastic-wave slowness has been observed by a number of authors, and the problem lies in determining the effective modulus of the pore-fluid mixture (above). 22 To evaluate gas volume from sonic logs in shaly sands, a new mixing law for computing the average sonic properties of gas-saturated fluids has been proposed recently. 23 K liquid (Fluid bulk modulus) K f K f = (K liquid - K gas ) S e x o + K gas e = 1 K gas S xo (Invaded zone liquid saturation), % Pore-fluid mixing laws. The observed pore-fluid bulk modulus K f changes from K liquid to K gas in a nonlinear manner as liquid is replaced by gas in the formation. Field data suggest an average mixing-law coefficient, e, of between 2 and 5. The curves are scaled according to liquid saturation in the invaded zone, S xo, because the sonic properties of oil and water are similar, and sonic measurements are mostly sensitive to fluid present in the invaded zone. For high values of the mixing coefficient (e 40), the mixing law behavior approaches that of Wood s mixing law Compressional slowness, µs/ft The new mixing law differs from Wood s mixing law in that it relates the effective fluid bulk modulus to the liquid and gas moduli through a power law function of the liquid saturation (left). The interpretation proceeds straightforwardly from here. The apparent pore-fluid bulk modulus can still be computed from the Biot-Gassmann model, which relates it to the formation velocity ratio measured by the sonic logging tool; and the porosity can be derived from neutron and density logging. To derive the gas saturation, the apparent fluid modulus is compared with the one computed by the new mixing law based on the liquid saturation in the invaded zone. The crossplot of the velocity ratio versus compressional slowness illustrates how gas-bearing formations are differentiated from liquid-filled formations (above). The Biot-Gassmann model along with openhole density, porosity and lithological interpretations are used to derive the expected dry formation properties, which enable computing fully liquid-saturated formation moduli and slowness values. These results can serve as an effective quicklook gas Invaded 80 zone 70 fluid saturation Gas 40 Dolomite Limestone Wet sands Shales Dry or gas sandstones Anhydrite Salt Quartz indicator on the log plots by comparing them with the measured slowness values. The dry compressional and shear slowness curves are what the logging values would be if the formation was completely filled with dry gas. Similarly the wet slowness curves are what the logs would read if the formation was completely filled with liquid oil or water. The quicklook gas saturation is computed from the difference between the derived wet slowness and observed slowness. These dry formation parameters also find application as inputs to rock mechanics computations. These properties are independent of the pore fluid in the rock, and therefore provide a more reliable basis for rockstrength estimation than the moduli computed directly from the measured slowness. Finally, the dry formation properties can be used to estimate the acoustic response for any pore fluid mixture as an input to amplitudeversus-offset (AVO) modeling known as fluid substitution. 24 Wood s mixing law, which has a more dramatic effect from gas saturation, should be used at seismic fre- 54 Oilfield Review

16 quencies because seismic compressional velocities are more sensitive to gas saturation. In practice, when gas is present, the dry acoustic parameters provide a suitable approximation to the seismic response. An example in a well drilled through a shaly sand formation with oil-base mud shows the capability of sonic logging to quantitatively differentiate between liquid and gas (right). The logged compressional and shear slownesses fall between the expected dry-gas and wetliquid limits. Porosities are high, averaging 33 p.u., in the interval shown, and the compressional slowness shows a large gas separation, often as much as 35 µs/ft [115 µs/m], which is characteristic of these soft formations. Hard formations show less separation. The gas effect seen on the shear slowness is small. This is expected because the shear modulus is independent of pore fluid in the Biot-Gassmann model, and the effect on shear slowness is coming from density alone. Over most of the interval shown, gas is clearly seen in the sonic interpretation except in the 5-m [16-ft] zone at X100 m, where both compressional and shear slownesses agree with the expected wet values. The traditional ELAN Elemental Log Analysis openhole interpretation, using resistivity and EPT Electromagnetic Propagation Tool data, indicates hydrocarbons in this zone. This is the only place where there is marked disagreement between the sonic logging- and the resistivity-based interpretation. However, this zone consists of fine-grained silt, and the resistivity interpretation using Archie s equation did not take into account the effects of high irreducible water saturation associated with silt in this zone, which leads to an incorrect saturation result. Sonic compressional-slowness logs are mostly sensitive to the fluid present in the invaded zone. Compressional waves follow refraction laws, and when the invaded zone is faster than the deep formation as in a gas zone then only the invaded zone is seen. The slower, gas-filled, virgin zone lying deep in the formation is not measured because the 21. Wood s law is frequently used in many geophysics applications to compute the effective fluid compliance inverse bulk modulus from a linear volumetric mix of the gas and liquid compliances. 22. Murphy W, Reischer A and Hsu K: Modulus Decomposition of Compressional and Shear Velocities in Sand Bodies, Geophysics 58, no. 2 (February 1993): Brie A, Pampuri F, Marsala AF and Meazza O: Shear Sonic Interpretation in Gas-Bearing Sands, paper SPE 30595, presented at the 70th SPE Annual Technical Conference and Exhibition, Dallas, Texas, USA, October 22-25, Chiburis E, Frank C, Leaney S, McHugo S and Skidmore C: Hydrocarbon Detection with AVO, Oilfield Review 5, no. 1 (January 1993): Depth, m XX50 X compressional wave in this slower formation is refracted away from the wellbore. The important conclusion is that fluid analysis obtained from the sonic logs represents invaded-zone saturation. These sonic interpretation techniques are implemented in the PetroSonic module of the GeoFrame interpretation program. They can be used to evaluate hydrocarbon saturation from sonic slowness, remove pore-fluid effects and analyze frame properties for rock mechanics evaluation, and replace the pore fluid present at logging time (invaded zone) with another fluid combination, either to reproduce the original reservoir conditions, or to simulate other situations for AVO modeling. Slowness, µs/ft 50 Dry Modulus, GPa Sonic Volume ELAN Volumes p.u % Clay Shear slowness Wet Log Dry Compressional slowness Dry Log Wet Gas Moduli Liquid G Kdry Total porosity Quartz Gas Water Feldspar Gas evaluation in shaly sands. The compressional and shear slowness logs are shown in track 2, and compared with the dry and wet slowness predicted by the Biot- Gassmann model for fully gas- and water-saturated formations. The difference between the expected wet and observed compressional and shear slownesses are used to determine gas volume, shown in track 3. Dry bulk and shear moduli of the rock shown in track 2 can be used in rock mechanics applications. The ELAN interpretation, track 4, shows fluid and formation volumes. Sonic measurements make important contributions to our knowledge of a field during every phase of reservoir life drilling, completion, formation evaluation, stimulation, even fluid characterization and monitoring. Sonic waves don t solve every problem, but when combined with other measurements neutron-density for gas identification, FMI measurements for fractures or CMR Combinable Magnetic Resonance Tool readings for permeability they strengthen our understanding of the subsurface and ultimately help find and produce hydrocarbons more efficiently. RCH Spring

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