4
Fracture Detection Methods

This chapter addresses methods for the remote detection and characterization of fractures in the subsurface. These indirect detection methods are mainly geophysical in nature and rely on the physical principles introduced in Chapter 3. Recent advances in theory and in available technology have greatly increased our ability to detect fractures at depth and to characterize their properties. Many of these techniques were first introduced for other purposes and have been refined for use in fracture detection and characterization.

Fractures in the subsurface are zones of anomalous physical properties that can be detected remotely by various means, ranging from simple extrapolation of surface observations to sophisticated seismic and electromagnetic soundings. In general, methods that probe deeply into the subsurface have a poor ability to spatially resolve the locations of fractures and those with shorter ranges have correspondingly better resolutions. Some exceptions to this rule exist in certain circumstances and are noted below; however, the rule is sufficiently strong that the discussion here is organized according to the range and resolving power of the methods. Geophysical fracture detection methods naturally divide themselves into three distinct scales: (1) large scales associated with surface soundings, (2) intermediate scales associated with surface-to-borehole and borehole-to-borehole soundings, and (3) small scales associated with measurements made on rocks immediately adjacent to a borehole or tunnel. Table 4.1 provides a general overview organized by the type of method, which thus serves as a cross-reference for the discussion below.

Fracture detection methods rely on the fact that fractures are thin compared to their lengths and heights; that is, they are essentially two-dimensional anoma-



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Rock Fractures and Fluid Flow: Contemporary Understanding and Applications 4 Fracture Detection Methods This chapter addresses methods for the remote detection and characterization of fractures in the subsurface. These indirect detection methods are mainly geophysical in nature and rely on the physical principles introduced in Chapter 3. Recent advances in theory and in available technology have greatly increased our ability to detect fractures at depth and to characterize their properties. Many of these techniques were first introduced for other purposes and have been refined for use in fracture detection and characterization. Fractures in the subsurface are zones of anomalous physical properties that can be detected remotely by various means, ranging from simple extrapolation of surface observations to sophisticated seismic and electromagnetic soundings. In general, methods that probe deeply into the subsurface have a poor ability to spatially resolve the locations of fractures and those with shorter ranges have correspondingly better resolutions. Some exceptions to this rule exist in certain circumstances and are noted below; however, the rule is sufficiently strong that the discussion here is organized according to the range and resolving power of the methods. Geophysical fracture detection methods naturally divide themselves into three distinct scales: (1) large scales associated with surface soundings, (2) intermediate scales associated with surface-to-borehole and borehole-to-borehole soundings, and (3) small scales associated with measurements made on rocks immediately adjacent to a borehole or tunnel. Table 4.1 provides a general overview organized by the type of method, which thus serves as a cross-reference for the discussion below. Fracture detection methods rely on the fact that fractures are thin compared to their lengths and heights; that is, they are essentially two-dimensional anoma-

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Rock Fractures and Fluid Flow: Contemporary Understanding and Applications TABLE 4.1 Fracture Detection Methods Method Length Scale of Investigation and Resolution Remarks Chapter Reference in this Volume Differential methods 0.1-5,000 m Most of the methods below best detect actual flow if performed both before and after a known stimulus. Chapter 4 Elastic methods: seismic band (10-100 Hz) 100-5,000 m Zero shear modulus in fracture fluid is critical. Chapter 3; Chapter 4 P-wave reflection (2D) [1-2 (velocity)]a; [1/4 (amplitude)] Surface methods best detect horizontal fractures; fracture shape is critical. Chapter 3; Chapter 4 P-wave reflection (3D) [1-2 (velocity)]; [1/8 (amplitude)] Very subtle features recognizable in patterns. Chapter 3; Chapter 4 S-wave reflection (2D) [1-2 (velocity)]; [1/4 (amplitude)] Surface methods best detect vertical aligned fractures. Chapter 3; Chapter 4 P-wave vertical seismic orofiling (VSP) (including offset, reverse) [<1 (velocity)] Minimizes overburden difficulties; fractures cause tube waves. Chapter 3; Chapter 4 S-wave 3C vertical seismic profiling (VSP) [<1 (velocity)] Minimizes overburden difficulties. Chapter 4 P-wave tomography 10-100 m; [1/2 (velocity)] Zero shear modulus in fracture fluid is critical. Chapter 4; Chapter 4 Cross-hole reflections 10-100 m; [1/2 (velocity)] Zero shear modulus in fracture fluid is critical. Chapter 3; Chapter 4 Coupled methods 100-5,000 m; [<1 (velocity)] Iteration of reflection and transmission inversion steps. Chapter 3; Chapter 4

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Rock Fractures and Fluid Flow: Contemporary Understanding and Applications Method Length Scale of Investigation and Resolution Remarks Chapter Reference in this Volume Elastic methods: sonic band (2-20 kHz) 0.1–10 m Zero shear modulus in fracture fluid is critical. Chapter 3; Chapter 4 P-wave transmission (acoustic Log, 1D) [1–2 (velocity)]; [1–2 (amplitude)] Best detects fractures oriented transverse to rays. Chapter 3; Chapter 4 Acoustic waveform Log, P and S [1–2 (velocity)]; [1–2 (amplitude)] Best detects fractures oriented transverse to rays. Chapter 3; Chapter 4 Acoustic emissions 10–100 m; [1–10 m] Emissions accompany fracture growth (e.g., during hydrofrac pumping operations). Chapter 4 Elastic methods: ultrasonic band (200-2,000 kHz) 0.1–5 m Fracture aperture is critical. Chapter 3; Chapter 4 Borehole televiewer 10–30 cm; [0.3–5 cm] Detects fractures in boreholes. Chapter 4 Electrical methods 10–300 m Contrasting resistivity of fracture-filling fluid is critical. Chapter 3; Chapter 4 Electric sounding [1–10 m] Best detects horizontal fractured zones. Chapter 4 Electric profiling [1–10 m] Best detects vertical or dipping fractured zones. Chapter 4 Electric resistivity tomography [1–10 m] Still under development. Chapter 4 Formation microscanner (FMS) [0.1–3 cm] Best detects open fractures. Chapter 4 Electromagnetic methods [10–300 m] Contrasting resistivity of fracture-filling fluid is critical. Chapter 3; Chapter 4 Electromagnetic sounding [3–10 m] Best detects horizontal fractured zones. Chapter 4 Electromagnetic profiling [3–10 m] Best detects vertical or dipping fractured zones. Chapter 4 Electromagnetic tomography [3–10 m] Best detects conductive anomalies, like fluid-filled fractures. Chapter 4 Radar methods 3–100 m Contrasting resistivity of fracture-filling fluid is critical. Chapter 3; Chapter 4 Ground-penetrating radar (reflection) [0.1–5 m] Conductive overburden presents difficulties, limits penetration. Chapter 4

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Rock Fractures and Fluid Flow: Contemporary Understanding and Applications Method Length Scale of Investigation and Resolution Remarks Chapter Reference in this Volume Borehole radar (reflection) [1–5 m] Determines both location and orientation from a single borehole. Chapter 4 Radar tomography (transmission) [2–10 m] May be used to image velocity, attenuation, or differences over time. Chapter 4 Conventional well logs 0.1-10 m Near-borehole environment. Chapter 4 Neutron log [0.1 m] Detects clay and porosity in fracture washouts. Chapter 4 Resistivity log [0.1 m] Detects clay in fractures and washouts. Chapter 4 Density log [0.1 m] Detects clay in fractures and washouts. Chapter 4 Gamma ray log [0.1 m] Detects radioactive fillers, rock-type identification. Chapter 4 Caliber log [0.01 m] Detects borehole enlargement. Chapter 4 Temperature log [0.01 m] Detects temperature changes owing to flow in fracture system. Chapter 3; Chapter 4 Fluid conductivity log [0.01 m] Detects salinity changes owing to flow in fracture system. Chapter 4 Fluid replacement log 1–100 m; [1–10 m] Detects salinity changes owing to flow in fracture system. Chapter 4 Geological observation 0.1–500 km Surface lineations, structures, etc., may indicate fractures at depth. Chapter 2; Chapter 4 Satellite airborne imaging 1–500 km; [1–100 m] Direct observation of lineaments and inference of fractures from geological structures. Chapter 2 Core inspection [0.1–10 cm] Core may not be representative. Chapter 4 Optical imaging [0.1–10 cm] Borehole fluid must be clear. Chapter 4

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Rock Fractures and Fluid Flow: Contemporary Understanding and Applications Method Length Scale of Investigation and Resolution Remarks Chapter Reference in this Volume Tiltmeter methods 100–2,000 m Expansion of fracture by hydrofrac pumping operations is critical. Chapter 3; Chapter 4 Flowmeters 1–100 m Directly detects fracture flow. Chapter 3; Chapter 4 Heat pulse flowmeter [1–10 m] Directly detects fracture flow. Chapter 4 Electromagnetic flowmeter [1–10 m] Still under development. Chapter 4 Acoustic doppler flowmeter [1–10 m] Still under development. Chapter 4 a is the wavelength of seismic or sonic energy.

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Rock Fractures and Fluid Flow: Contemporary Understanding and Applications lies. In addition, because they are commonly organized into one or more sets, each of which has a preferred spatial orientation, fractures commonly impose some anisotropy in physical properties on the rock mass. This anisotropy may be an important characteristic for fracture detection, especially when the anisotropy is simple and not aligned with other fabric (such as bedding planes) in the rock mass. In mildly deformed bedded rocks, fractures are commonly oriented nearly vertical, with a single preferred azimuth, or two orthogonal azimuths. Several of the detection techniques rely on this characteristic. However, in tectonically active areas, there may be several sets of fractures or fracture zones with a variety of orientations. The methods listed in Table 4.1 detect fractures indirectly. Typically, the reduced data from each detection method (e.g., seismic travel times) must be inverted to yield estimates of local rock properties (e.g., seismic velocities). Normally, these rock properties are not fracture properties (e.g., fracture density). Instead, the fracture properties must be indirectly deduced from the rock properties. This deduction requires the help of rock property theory (see Chapter 3), which may unavoidably rely on strong idealizations of fracture geometry. These fracture properties are not always the properties (e.g., fracture permeability) of direct interest in many applications. Instead, they must be interpreted from the deduced fracture properties. This interpretation requires higher levels of subjectivity than the first (inversion) or the second (deduction) steps. SURFACE METHODS Seismic Reflection Elastic properties can be determined at greater ranges than electric or electromagnetic properties; hence, seismology is the technique most widely used to explore the deep subsurface. Seismological investigations use P waves, in which the rock deforms (compresses and dilates) along the direction of wave travel (as with ordinary sound in air), or S waves, in which the rock deforms (shears) transverse (or perpendicular) to the direction of wave travel. S waves may be further classified according to polarization (i.e., the orientation of the transverse deformation); this distinction is ignored in most seismological studies but turns out to be crucial for fracture detection. Some of the energy of P waves is converted to S waves at reflecting horizons, and these S waves also return to the surface, where they can be detected and analyzed. In reflection seismology a controlled seismic source (or a closely spaced array of sources) imparts energy into the ground. The energy travels through the rock, reflects off features (e.g., lithologic boundaries and fractures) where the rock properties change abruptly, and returns to the surface, where it is received and recorded at many points. The receivers, which are a closely spaced array of sensors, record the vertical component of the seismic motion, one or two horizon-

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Rock Fractures and Fluid Flow: Contemporary Understanding and Applications tal components, or all three components. Shear waves are not transmitted by fluids, so in a conventional marine survey the receivers record only the pressure pulse (P wave). Each recording consists of a digital record, several seconds long, of arriving energy from all paths. After each shot, the source and receivers are moved to new locations, and the procedure is repeated. Extensive data processing is required to extract useful information from this voluminous data set. An elementary step in this data processing gathers together the records corresponding to reflections under the common midpoints of various source-receiver pairs. The records are digitally stretched in time so that obliquely traveling waves arrive at the same adjusted time as vertically traveling waves; then the records are averaged together. This is called stacking. In conventional two-dimensional (2-D) surveys the sources and receivers are distributed and moved together along a straight line on the surface, and the processed data are displayed in a format similar to a 2-D vertical section of the subsurface below that line. More common in recent times is the 3-D survey, where both sources and receivers are distributed in a 2-D pattern on the surface. As these patterns are moved in a swath across the surface, the investigated region is a 3-D volume of rock, and the processed data are presented to the interpreter in vertical, horizontal, or oblique slices through this volume. These same principles apply even if the survey is not conducted at the earth's surface but from a tunnel or borehole. P Waves P-wave reflection seismology at near-vertical incidence is the primary means by which most of the world's oil and gas reservoirs have been found. However, this technique is not very sensitive to the presence of vertical fractures, as evidenced by the lack of consistent success at finding the ''sweet spots" (i.e., the zones of fracture concentration) in fractured reservoirs. This is due to the insensitivity of near-vertically traveling P waves to the presence of vertical fractures (Hudson, 1980; Thomsen, 1995; see Chapter 3). In modern surveys, seismic data are not necessarily restricted to near-vertical raypaths. Typically, the maximum source-receiver offset can be adjusted so that the reflections at the target depth span an angular aperture of 25° or more. Obliquely traveling P waves are affected by vertical fractures, both in velocity and attenuation, if their rays do not lie in the plane of the cracks (see Chapter 3). Hence, when data from a set of such oblique paths are processed into a conventional seismic reflection section, the zones of intense fracturing may appear as velocity or amplitude anomalies, most commonly as "dim spots." Kuich (1989) discusses how such techniques have been used to locate fractured oil reservoirs in the Austin Chalk fields in central Texas. Garotta (1989) discusses the limitations of this technique, noting that dim spots may occur for a number of other reasons, not involving fractures at all. To

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Rock Fractures and Fluid Flow: Contemporary Understanding and Applications test whether a particular dim spot is due to fractures, it is useful to look for the characteristic azimuthal anisotropy of fractures by collecting data along another survey line that crosses the dim spot at some angle (usually 90°) to the first survey line. Fractures are indicated by an azimuthal variation in the dimness of the stacked reflection at the intersection point or in the amplitude variation with source-receiver offset. This procedure is expensive and must be repeated separately for each spot to be investigated. An additional complication is that the set of oblique raypaths from the crossing survey line averages a different volume of rock than for the first survey line. When comparing the two data sets, the possibility of confusing lateral heterogeneity with anisotropy arises. However, in offshore areas this technique may be the only one available because the S-wave techniques discussed below are not applicable, for S waves are not transmitted by fluids. In situations where near-horizontal fracture zones are present, vertically traveling P waves can be used to indicate their size and orientation, although individual fractures cannot be resolved (Green and Mair, 1983). An example is shown in Figure 4.1, where reflections obtained from a subhorizontal fracture zone or fault are compared to acoustic televiewer (BHTV; see "Borehole Imaging FIGURE 4.1 Comparison of a conventional P-wave reflection seismogram with acoustic televiewer image logs. The image logs show the distribution of fractures where two boreholes penetrate the reflector at locations close to the center of the seismic line. Modified from Green and Mair (1983).

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Rock Fractures and Fluid Flow: Contemporary Understanding and Applications Logs" in the section of this chapter entitled "single-Hole Methods") images of fractures intersecting boreholes near the center of the seismic section. The scale differences between the remote seismic sounding and the local borehole measurements are apparent in the figure. The P-wave reflections indicate a single, horizontally continuous fracture zone, whereas the borehole images indicate a great deal of variability in the local distribution of fractures in the fracture zone. This illustrates the low spatial resolving power of remote sensing methods, like seismic reflection, when used to probe to depths of several kilometers. Three-dimensional seismic data (usually P-wave data) are remarkable for their ability to detect subtle features in the subsurface. For example, differences in the amplitudes of reflected waves may be too slight to be noticeable on a vertical section from a 2-D survey, yet they may form a distinctive pattern that is easily recognized on a horizontal section from a 3-D survey. Figure 4.2 shows a horizontal section through the 3-D survey of an oil field in Oman. The section clearly shows a pattern of orthogonally intersecting quasi-linear features, interpreted to be the seismic expression of sets of regional faults and fractures. These features are oriented vertically and in two orthogonal horizontal directions by the stress (or paleostress) field. The fractures form preferred pathways for the movement of fluids; the difference in seismic velocities between oil-filled and brine-filled rocks accounts for the linear features in the image. Advanced processing and color displays further enable the recognition of such subtle patterns. FIGURE 4.2 Horizontal section (more precisely, a map of processed reflection amplitudes, corresponding to constant reflection times) over a portion of the Yibal oil field, in Oman, showing patterns of near-orthogonal lineations interpreted as vertical faults and fractures. From Paillet (1993).

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Rock Fractures and Fluid Flow: Contemporary Understanding and Applications In 3D surveys on land the source and receiver patterns may include sufficient distribution of azimuths that the amplitude variation with offset of reflected P waves is measurable (cf. Lefeuvre and Desegaulx, 1993). This "azimuthal AVO" effect also is indicative of the presence of fractures, following the principles of Chapter 3. S Waves As discussed in Chapter 3, seismic shear waves are markedly influenced by aligned fractures, even though their wavelengths may be much greater than the size of the fractures. If the fractures are uniformly distributed and small compared to the wavelength, the waves propagate as though in a homogeneous anisotropic medium. By contrast, if the wavelength is small compared to the fractures, the waves will be scattered. However, long waves can penetrate much deeper into a rock mass than short waves (the range is approximately proportional to the wavelength), thus permitting deep investigation. Anisotropies in the rock arising from aligned fractures split incident shear waves into two modes: (1) one polarized roughly in the plane of predominant fracturing and (2) one polarized roughly perpendicular to this plane. Of course, both of these shear modes are polarized roughly perpendicular to the raypath. To visualize this fact, imagine a pile of business cards standing on edge, with the spaces between the cards representing a set of vertical fractures. Imagine your hands holding the cards (from above and below), with your palms flat and horizontal, representing the wave fronts of a vertically traveling wave. Orient your fingers across the cards (representing shear motion in that direction), and shear the deck of cards sideways. It deforms easily, shearing along the zones of weakness between the cards (the fractures), indicating that the deck (representing a rock mass) is compliant for this sense of shear. With your palms still flat and horizontal, orient your fingers along the cards and try to shear the deck in that direction. It is much stiffer for this sense of shear because you must deform the cards themselves, without help from the zones of weakness between them. Shear waves polarized obliquely to the fractures resolve themselves vectorially into these two particular directions, determined by the rock mass. These two modes travel at different speeds; the faster mode is polarized in the plane of the fractures. The difference in speed depends on the degree of fracturing. In a simple case (see Chapter 3) the delay depends on the dimensionless fracture density, , defined for penny-shaped cracks as where Nv is the number of fractures per unit volume (called the fracture density elsewhere in this report), and < l3 > is the average of the cube of the fracture

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Rock Fractures and Fluid Flow: Contemporary Understanding and Applications length. The second formulation above (Eq. 4.lb) gives the nondimensional fracture density in terms of the fracture porosity, фf, and crack aspect ratio, , the ratio of fracture thickness to fracture length. In a simple 2-D case (see Hestir and Long, 1990), the 2-D analog of parameter (rather than, e.g., фf or Nv) controls the fracture network permeability. The theory is valid for fractures that are small compared to a seismic wavelength, that is, for microfractures up through joints; however, the < l3 > factor in the equation indicates that a few large cracks will dominate the behavior of the fracture network. Differences in arrival times of the two shear-wave modes after propagation through an interval several wavelengths thick provide stable averages of the nondimensional fracture density over that interval. Using typical oil industry acquisition practice, for example, average velocity differences of as little as 1 percent can be measured reliably. It is possible to measure such small differences even though neither velocity is known to within 10 to 20 percent of its absolute value. This is because shear modes both travel through the same rock and share the same uncertainties (e.g., the same unknown thickness of the interval), as with an interferometer (Thomsen, 1988). It follows that the average nondimensional fracture densities can be determined with similar high sensitivity and similar low spatial resolution. Recent advances in the application of these principles have come because of the capability to manipulate the source polarization and to record all signal components. Petroleum industry experience has shown (e.g., Willis et al., 1986) that a low "background" density of fractures ( = 0.01) is ubiquitous in sedimentary rocks and that failure to account for it may result in uninterpretable shear-wave data. Such low fracture densities may not correspond to fracture permeabilities of great production significance; however, they may affect the subsurface fluid pressure regime. This happens because fractures may penetrate formations (e.g., shales) that would otherwise form pressure seals, thus establishing hydraulic continuity and a local hydrostatic pressure gradient over thousands of meters of section. See Powley (1990) for a discussion of these "subsurface fluid compartments." It is possible to apply S-wave reflection analysis by using converted P waves (i.e., P → split S waves; Garotta, 1989) to detect vertical fractures at depth. Of course, such an application involves only one source polarization. However, a single horizontal source orientation with two horizontal receiver components can provide sufficient information for the analysis (Thomsen, 1988). Meadows and Winterstein (1994) report the detection and characterization of an artificial hydraulic fracture via analysis of the reflection of split shear waves back to the surface. Macbeth (1991) discusses the practicality of various methods to estimate shear-wave anisotropy from raw seismic data. These seismic techniques for fracture detection can be expensive. A full acquisition scheme (three source orientations, three-component receivers) may be two to five times as expensive as a traditional one-source vertical recording

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Rock Fractures and Fluid Flow: Contemporary Understanding and Applications FIGURE 4.C2 Example of high-resolution flowmeter measurements used to characterize changes in fracture properties induced by hydraulic stimulation at a site in Colorado. Left, distribution of fractures indicated by caliper and BHTV logs; right, distribution of vertical flow under about 7 m of hydraulic head during injection before and after stimulation. From Paillet et al. (1989b).

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Rock Fractures and Fluid Flow: Contemporary Understanding and Applications APPENDIX 4.D EXAMPLE OF SHEAR-WAVE ANISOTROPY IN FRACTURED RESERVOIRS Shear waves have properties that make them very attractive for characterizing fractured rock. When shear waves propagate through an anisotropic material, their polarization (the direction of the transverse deformation) is controlled by the material's anisotropy rather than by the source. The study of fractured reservoirs has shown that in such cases fracturing is the dominant cause of seismic anisotropy. Figure 4.D1 is a schematic representation of shear-wave propagation in a homogeneous medium with aligned fractures. The incident wave is shown to be FIGURE 4.D1 Schematic illustration of shear-wave propagation in a homogeneous medium with aligned fractures. From Martin and Davis (1987).

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Rock Fractures and Fluid Flow: Contemporary Understanding and Applications polarized east-west. While traveling through the fractured interval, the incident wave splits into two shear waves—a fast wave polarized parallel to the fractures (N45W) and a slow wave polarized perpendicular to the fractures (N45E). After leaving the fractured interval, both shear waves propagate with the same velocity but have different polarizations and travel times, which were established by the fractured interval. The orientation of the fractures can be determined from the polarization of the first-arriving shear wave. Digital processing of shear-wave recording allows them to be resolved into the components parallel and perpendicular to the natural coordinate system (a coordinate system assumed to be defined by fracture orientation). The presence of fracturing is seen in travel time differences between parallel and perpendicular orientations, and the orientation of fracturing is determined from the rotation angles. The use of shear-wave anisotropy information is demonstrated by a case history from a seismic reflection survey of the Silo field in southeastern Wyoming (Martin and Davis, 1987). This field is a naturally fractured reservoir that produces oil from chalks within the late Cretaceous Niobrara formation at depths of about 2,440 m. Because the production in this field is controlled by the orientation and density of fractures, a multicomponent seismic line was obtained to record both P waves and shear waves. Figure 4.D2 shows a P-wave reflection profile with a P-wave VSP (vertical seismic profile) from a nearby well. The VSP gives depth control to the seismic travel times. The P-wave profile clearly shows the Niobrara formation (labeled "Kn") at 1.7 s, about 2,744 m (9,000 feet) in depth, but there is no fracture information. Figure 4.D3 shows the parallel (left) and perpendicular (right) shear-wave reflection sections. Various reflections, labeled A through F, clearly show fracture induced time delays between sections, with reflection C, the top of the Niobrara, having a 120-ms time difference. The parallel polarized section (left side) has less travel time because these shear waves are faster. A shear-wave VSP acquired in a nearby well, and polarized perpendicular to fracturing, is shown in the perpendicular reflection section (right side). The observed delay times between orthogonally polarized shear waves correlate with both mapped fracture orientations and fracture intensities inferred from production data throughout the Niobrara formation. This example demonstrates the utility of split shear waves for mapping from the surface the locations, orientations, and intensities of fractures at great depth.

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Rock Fractures and Fluid Flow: Contemporary Understanding and Applications FIGURE 4.D2 P-wave reflection profile and P-wave vertical seismic profile from a well in the Silo field in southeastern Wyoming. The y axis represents two-way travel time. From Martin and Davis (1987). FIGURE 4.D3 Parallel (left) and perpendicular (right) shear-wave vertical seismic profiles from the Silo field in southeastern Wyoming. From Martin and Davis (1987).

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