Until recently, geoscientists using

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3 Anisotropy can be thought of as directional inequality - the variation of properties with direction. Anisotropy occurs at all scales from core plugs to reservoirs. Until recently, anisotropy was ignored - or treated as noise to be removed from reservoir models. Recent research has changed this perception. Modern techniques and tools can detect and use the small variations in velocity which are found in sonic and seismic studies. Anisotropy can make a huge difference to reservoir performance. Variations between horizontal and vertical permeability and the presence of low-permeability barriers can turn a carefully planned and executed waterflood or gasflood into a production lottery, with early and unpredictable water or gas breakthrough. In this article, Bruce Cassell, Mahmood Akbar and Roy Nurmi examine the origins of anisotropy in the reservoir and describe the advanced interpretation techniques which are helping to bring anisotropy into the mainstream of reservoir characterization.

4 Until recently, geoscientists using seismic methods to survey sedimentary sequences assumed that waves travelled through rock at the same speed in all directions. However, this assumption is now known to be inaccurate, because rock sequences are variable. While it might be convenient to assume that a reservoir is basically homogeneous this rarely proves to be the case. This phenomenon, where certain physical properties vary with direction, is called anisotropy. It is caused by an alignment of crystals, bedding planes, joints or fractures at a scale which is smaller than the wavelength of the ultrasonic, sonic or seismic waves passing through the rock. Despite field and laboratory experiments confirming the presence of anisotropy, it has usually been neglected by exploration and production geophysicists. The velocity differences are small and were usually treated as noise to be removed from the seismic image signal. However, as a result of recent advances in acquisition, processing and interpretation some highly anisotropic velocities have recently been recorded in ultrasonic, sonic and seismic data. Anisotropy, whether on a small or large scale, is the rule in oil and gas reservoirs. Only by understanding more about the ways in which mechanical and stress-related properties vary between and within layers can geoscientists improve their reservoir models. Compression or shear? There are two main types of wave motion: compressional waves and shear waves. The difference between them can be illustrated by considering the behaviour of a single rock particle. In compressional waves, particles move parallel to the direction of wave propagation, whereas in shear waves particle motion is perpendicular to propagation (figure 3.1). There are two main types of anisotropy. TIV (transverse isotropy with a vertical axis of symmetry), where vertical velocity differs from horizontal velocity. This is caused by differences between adjacent rock strata or by fine sedimentary layering as found in shales (figure 3.2a). TIH (transverse isotropy with a horizontal axis of symmetry), where vertical velocities are identical in a vertical plane parallel to the fractures, but the horizontal velocities are different. TIH is usually caused by stress-induced micro-fractures or other discontinuities in the formation (figure 3.2b). (a) (b) (c) Fig. 3.2: There are two basic types of anisotropy. TIV (a) is caused by the fine layering typically found in shales. Micro-fractures produce TIH (b) where the horizontal velocities are different. Wave propagation direction (a) Shale (a) (b) Fig. 3.3: Shear waves propagating through Maximum Minimum an isotropic rock horizontal horizontal mass (a) do so stress stress without modification. Shear waves passing through a layered mass (b) will split into two separate components - a fast wave and a slow wave. These components align themselves with the maximum and minimum horizontal Slow stress directions. Fast Compressional (b) Fast shear Slow shear Vertical stress Fractures Fig. 3.1: Particle motion reveals the difference between compressional and shear waves. In compressional waves (a) particle motion is parallel to the wave propagation direction; in shear waves (b and c) particles oscillate in a direction perpendicular to the direction of wave propagation. 44 Middle East Well Evaluation Review

5 In a borehole, compressional waves always propagate along the length of the hole (i.e. in the direction of the long axis), whether the borehole is horizontal or vertical. For this reason a sonic logging method designed to measure anisotropy using compressional waves alone would require a number of boreholes with different orientations in the zone of interest. In a field containing only (a) Fig. 3.4: Normal sedimentary layering and associated processes lead to anisotropy. The irregular layering in the siltstone (a) and the more regular layers in the sandstone (b) reflect variations in depositional environment, original mineralogy and grain size or diagenetic events. All of these factors will combine to give these rocks very different degrees of anisotropy. (b) vertical wells compressional acoustic anisotropy cannot be assessed as measurements are in the vertical direction only. Compressional waves do not split in anisotropic formations, so for any given well deviation there is only one log value for a compressional wave. Shear waves are different. For any sub-vertical direction of propagation through an anisotropic layer, shear Fig. 3.5: The clay grains in this sediment have a random distribution at deposition. However, as the weight of accumulating sediment increases in the early stages of diagenesis, the grains are rotated to develop a rock fabric which exhibits elastic anisotropy. waves split into two separate components (figure 3.3). These propagate at different slownesses (the fast and slow waves) and have orthogonal particlemotion properties (i.e. the two waves vibrate the rock in directions which are 90 to one another) parallel to the directions of maximum and minimum horizontal stress. The origins of anisotropy Anisotropy in oil and gas reservoirs starts to develop during the deposition and diagenesis of the sediments. Sandstones can develop anisotropic features during and after deposition whereas in carbonate rocks anisotropy is generally caused by post-depositional events such as fracturing or diagenesis. Sandstone anisotropy generally develops where there is an ordering of sediment grains. This typically occurs in one of two ways: an alternation of sediment types deposited sequentially as bedding (figure 3.4) alignment of individual grains caused by directional deposition (this generally reflects the predominant water or wind direction at time of deposition) or diagenetic effects (figure 3.5). Fracturing forces Fracturing is a major source of anisotropy, particularly in carbonate sequences. Whether open or filled with porous breccia, the properties of fracture zones are very different to those of the surrounding rock. This fact, and the directional nature of fracture sets, makes them important sources of anisotropy at every scale from core plug to reservoir. Mineralized fractures have the same directional controls, but may be quite similar to the surrounding rock and will produce less obvious anisotropic effects than open fractures. An additional complication with anisotropy is that it varies with scale as well as direction. For example, a single crystal may have an atomic structure that is anisotropic for electric current flow or acoustic propagation, while a piece of rock formed from a randomly packed group of the same crystals might be isotropic for the same properties at the larger scale. So the detection of anisotropy depends on the technique being used and the scale of investigation. Number 18,

6 Fast, slow or in between? The Dipole Shear Sonic Imager (DSI*) tool makes dipole measurements in orthogonal directions, detecting the shear wave and allowing the measurement of sonic-scale anisotropy in fast and slow formations (figure 3.6). If one of the DSI tool's dipole transducers is aligned with the fast-shear direction, fast-shear waves are logged in that plane and slow-shear waves in the orthogonal plane. When, as is usually the case, the dipole transducers are aligned somewhere between fast and slow directions, both sets of shear waves will split into fast and slow components and will be recorded by the inline and offline receivers. Inline implies that the transducer and receivers are in the same plane; offline means that the receivers are measuring in the plane orthogonal to the transducer. Offline energy changes as the orientation of the tool changes. It is at a minimum when the transducers are aligned with the fast or slow shear directions and reaches a maximum when the transducers are arranged at 45 to these fast and slow shear planes (figure 3.7) There are two major applications of sonic anisotropy measurements: assessment of stress directions which reveal the orientation of faults and fractures (prior to drilling horizontal wells). determination of mechanical rock properties by using the two horizontal Poisson s ratios. On the right line At present, dipole shear logging is used mainly to obtain shear logs in slow formations where conventional monopole shear measurements are not possible. Dipole logging provides the directional measurements which monopole logging cannot. Two dipole transducers are mounted orthogonally around the tool and can excite shear waves in these different directions. Inline measurements are made at the receiver whose polarization direction corresponds to that in the transmitter (i.e. the receiver operates in the same plane as the transmitter). Conversely, offline measurements are made at receivers polarized at 90 to the signal. If there is no azimuthal variation in stress, shear waves generated in one plane will not split and will, therefore, not be recorded in the offline. Fast S wave Slow S wave Source pulse Slow Dipole receivers Rotation angle of dipole source and receiver Fast Dipole source 0 Minimum 45 Maximum 90 Minimum Offline energy Fig. 3.7: The orientation of the dipole transmitters and receivers, with respect to the fast and slow shear planes, controls the energy level recorded at the offline sensor. When the transmitters and receivers are aligned with the fast and slow planes the energy recorded in the offlines is at a minimum. When they are at 45 to these planes offline energy reaches its maximum value. Fig. 3.6: The DSI tool fires its shear sonic pulse alternately from two perpendicular transmitters to an array of receivers. The pulse splits into two components and the shear wavefield is recorded. Using amplitude and traveltime difference data, the operator can identify the fast shear wave direction which corresponds to the orientation of any aligned fractures or the maximum horizontal stress. 46 Middle East Well Evaluation Review

7 WAVEFRONTS AND VELOCITY VARIATIONS If there is an orderly arrangement of crystals, fractures, grains, joints or bedding planes on a scale smaller than the length of the incident wave, then wave velocity will vary with direction. Laboratory and field experiments in the 1950s detected velocity anisotropy: vertically and horizontally propagating waves were found to have different velocities. However, the directional velocity variations produced by anisotropic effects were so small (typically less than 5% in standard surface seismic measurement techniques) that they were usually ignored. The idea that waves propagated through a rock at equal rates in all directions was a standard oilfield simplification for many years. Early assessments of anisotropy predicted an elliptical relationship for waves travelling at angles between the Vertical velocity (km/sec) (a) qs Horizontal velocity (km/sec) (b) qp Fig. 3.8: Velocity variation plotted around an axis of symmetry for a shale, showing wavefront velocities for compressional (qp) and shear (qs1) waves. The elliptical model of anelastic anisotropy had to be modified because the relationship between velocities at different angles for shear waves is not elliptical but anelliptical. Tick marks on the particles indicate the directions of particle motion. horizontal and vertical. Ellipses were applicable because, once the horizontal and vertical velocities were known, velocities at intermediate angles could be computed easily. Later laboratory and field experiments aimed at quantifying anisotropy continued to measure velocities parallel and perpendicular to perceived alignments and many older publications list anisotropies of different rock types in terms of the percentage of difference between the fast and slow velocities or the ellipticity. Unfortunately, an ellipse does not reflect the true complexity of anisotropic rocks. Experiments have established that the relationship for shear waves is not elliptical but a squarish non-ellipse (figure 3.8). The elastic properties of a rock can be used to correlate with other properties such as lithology or porosity. Most geoscientists would say that when the density and P-wave and S-wave velocities have been established the rock is completely described; but this is correct only for isotropic rocks where velocities do not vary with direction. Because most oil industry research has focused on reservoir rocks (which are usually relatively isotropic sandstones or carbonates) anisotropy has not had a major influence on reservoir characterization. However, most of the rocks around a reservoir are anisotropic shales. In the most extreme case 21 numbers would be required to characterize a rock, and even in the simple anisotropic rocks described in figure 3.2, five velocities (two transversely polarized S, vertical P, horizontal P, P at 45 ) plus density would be necessary. Change of a stress Taking cap-rock variation into account can be very important when explorationists are trying to assess target formations. If an Amplitude Versus Offset (AVO) survey does not take account of the transverse isotropy (TIV) in a shale cap rock, the underlying gas-bearing sandstone may be overlooked because the modelled AVO curve (for an oil sand overlain by an anisotropic shale) would not fit the observed AVO response from the survey. Recognizing that rocks are anisotropic, or may become so under stress, is important when evaluating the relationships between the velocity at which seismic waves propagate through a rock and its reservoir properties. While most reservoirs are composed of relatively isotropic sandstones or carbonates, their properties may be modified by stress (figure 3.9). Non-uniform compressive stress will have a major affect on randomly distributed microcracks in a reservoir. When the rock is unstressed all of the cracks may be open, However, compressional stresses will close cracks oriented perpendicular to the direction of maximum compressive stress, while cracks parallel to the stress direction will remain open. Elastic waves passing through the stressed rock will travel faster across the closed cracks (parallel to maximum stress) than across the open ones. Fig. 3.9: Non-uniform compressive stress operating on microcracks. In unstressed rocks with randomly oriented microcracks (a) the cracks may be open whatever their orientations. However, when stress is applied (b) cracks perpendicular to the direction of maximum compressional stress will close, while cracks parallel to it will remain open. Number 18,

8 Waveform processing principles The DSI tool gathers a mass of sonic data that can be processed and presented using IMPACT* (Integrated Mechanical Properties Analysis Computation Technique). Having completed a statistical analysis of the acoustic anisotropy dataset, the operator can generate theoretical results for any orientation of the tool within the borehole. This avoids the potential difficulties of turning the tool with sufficient precision to measure the offline minimum value. When the dipole source is aligned with the fast- or slow-shear polarization planes of the rock layer the offline energy (or cross-components) becomes zero. Consequently, one way to determine the fast- and slow-shear directions at each depth is to rotate the data mathematically to find the angle which minimizes energy in the offline readings. The logs generated by the DSI tool show which parts of the section are anisotropic and give an indication of data quality throughout the logged interval. The basis of waveform processing involves geometrical (mathematical) rotation of the inline and offline waveforms. Seven of these overlap at each recording depth so there is considerable data redundancy. After the theoretical rotation the offline is minimized and, if there is indeed azimuthal anisotropy and no other noise present, the offline energy will have zero amplitude. The amount of rotation required to minimize the offline energy indicates how much the DSI tool would have to be rotated in order to align the receivers parallel to the anisotropic or fractured system. As the absolute orientation of the tool is known, it is possible to display the anisotropy direction with respect to true north. Anisotropy is often observed in individual layers so it is very important to determine whether or not it is actually present before proceeding to interpret the results. Figures 3.10 and 3.11 are from the central Arabian Gulf while figure 3.12 is from an Egyptian field where the well penetrates fractured basement rock. The green area in the left track of each figure is the most important information. It allows the interpreter to determine whether or not the other results are based on the observation of anisotropy. The left edge of the green shaded area shows the effect of offline amplitude minimization. If the offline energy is not produced by anisotropy it will not become zero. This indicates that other effects (e.g. borehole rugosity or altered zones) have generated the amplitude anomaly and further indicators in these zones are meaningless. x160 x170 x180 x190 x200 x210 x220 1:200 (ft) MinEne% MaxEne% Off Ene x180 x190 x200 x210 x220 x230 x240 1:200 (ft) MinEne% MaxEne% Off Ene Fast shear azimuth -90 (deg) (µs/ft) (µs) 3000 Azimuth uncertainty DT slow shear Slow shear waveforms Fast shear azimuth DT fast shear (µs/ft) DT based anisotropy Fast shear waveforms 1000 (µs) Processing window Fig. 3.10: The left track (green area) is the most important part of the log, indicating whether or not the results are due to anisotropy. This example indicates a general ENE stress direction with azimuthal anisotropy values up to 15%. -90 (deg) (µs/ft) (µs) 3000 Azimuth uncertainty DT slow shear Slow shear waveforms 250 DT fast shear (µs/ft) Fig. 3.11: This log shows one zone of major anisotropy between x180 and x Fast shear waveforms 1000 (µs) Processing window Middle East Well Evaluation Review

9 x300 x310 x320 x330 x430 x440 x450 x460 x470 x480 x :200 (ft) MinEne% 100 MaxEne% 100 Off Ene -90 Fast shear azimuth DT fast shear Fast shear waveforms (deg) (µs/ft) (µs) 3900 Azimuth uncertainty DT slow shear Slow shear waveforms 250 (µs/ft) (µs) 3900 DT based anisotropy Processing window Fig. 3.12: Fractured basement rock in Egypt. This example contains two zones of different stress directions or fracture alignment - northwest and due north. The anisotropy in the top zone is small but measurable. Similarly, the right edge of the green track shows how much anisotropy is present. It maximizes in intervals of measurable anisotropy. The second track shows the direction of the fast shear (stress direction). This is usually displayed from west (-90) to east (90). The third track contains the fast and slow shear slownesses which have been determined by processing (red and blue curves). When there is anisotropy these curves separate and the amount of slowness difference is linked to the percentage of anisotropy. The curve on the left edge of the third track indicates the quantitative timebased anisotropy. Other indicators can be displayed as an interpretation aid. The fourth track contains the fast and slow waveforms after processing. In the anisotropic zones, i.e. where the left edge of the green area in the first track minimizes and the right edge maximizes, the waveforms separate. The first two examples show a general ENE stress direction, with azimuthal anisotropy values up to 15%. The fractured basement example (figure 3.12) contains two zones of different stress directions or fracture alignment, northwest and north. The degree of anisotropy in the top zone, although measurable, is small. Number 18,

10 Surface shear The shear anisotropy technique is not confined to the borehole. A similar approach has been attempted using borehole seismic methods (figure 3.13). The surface system has severe limitations and complications in that the downgoing seismic wave can be affected by one or more shallow anisotropic layers which split the signal into fast and slow components before it reaches the target layer. To counteract this problem, the effects of the shallow layers have to be stripped from the signal. This technique is called Alford Rotation. A shear wave moving through the first anisotropic layer will split into fast and slow waves. Each of these waves will, in turn, act as an independent source, splitting into fast and slow waves at the next interface, and so on (figure 3.14). A layer-stripping procedure is necessary to remove the time delay between the two sources when they reach the interface, effectively predicting the effect the interface would have if it were at the surface. Dipole Shear Logging techniques, using the DSI tool downhole, eliminate this processing problem because they consist of insitu measurements within layers. Assessing stress In-situ stress has a major influence on the permeability and morphology of fractures. Fractures which strike perpendicular to the maximum horizontal stress are likely to be closed and, clearly, have a lower permeability than open fractures which are oriented parallel to the maximum stress. Accurate information about in-situ stress is extremely helpful in predicting injectivity of natural fractures, particularly for acidizing, waterflooding and gasinjection projects. Advance modelling for frac jobs in vertical and horizontal wells requires a prior knowledge of in-situ stresses to obtain the best results. Borehole failures in horizontal wells are costly and time-consuming but they can be avoided if the in-situ stresses are known and the orientation of the borehole adjusted accordingly. Horizontal boreholes drilled parallel to the maximum horizontal stress direction are unlikely to be distorted. Anisotropic rock S 2 Upper anisotropic rock Lower anisotropic rock Source Natural coordinate frame for vertical rays σ H P σh Source S' 2 Slow S wave S 1 Fast S wave S' 1 S 2 Surface Surface Lag from upper layer Fig. 3.14: The complexity of wave splitting increases with depth. The separate fast and slow waves produced in the shallow anisotropic layer each split within the next layer, giving a total of four waves from a single source. These effects must be countered by layer stripping. S 2 S 1 S 1 H 1 Well H 2 S' 2 S' 1 Waves sourced by S 2 Waves sourced by S 1 3-component downhole receiver σ H Fig. 3.13: Borehole seismic surveys can use shear wave splitting to investigate reservoir layers. However, anisotropic rock layers close to the surface distort the shear waves before they reach the target layer. Geophysicists must take account of this effect and correct for it by using a layer-stripping technique. S 2 S 1 Upper natural coordinate frame S' 2 S' 1 Lower natural coordinate frame R.M. Alford (1986) Shear data in the presence of azimuthal anisotropy. 56th Ann. International Meeting Soc. Explor. Geophys. Expanded Abstracts, pp Middle East Well Evaluation Review

11 Dead Sea transform fault Red Sea rift Orientation of induced hydraulic fractures Orientation of borehole ellipticity Najd fault system Zagros crush zone Zagros fold belt Yemen Qatar Iran UAE Oman Gulf of Aden rift Makran fold belt Fig. 3.15: STRESS ASSESSED: Regional stress patterns can provide a general indication of fracture orientation and borehole ellipticity across the region, but rock stresses vary on a local scale and models that rely on accurate stress determination will require the local information which sonic anisotropy measurements provide. Regional stress determinations (figure 3.15) give a general indication of the likely fracture orientations, but local variations and the effects of localized structures, such as large faults, can alter the stress pattern completely, counteracting or adding to the regional stress. Because the permeability of fractures is influenced by regional and local stresses both must be assessed to ensure that wells do not collapse and that water production is minimized. Fracture orientation Most natural fractures are vertical or sub-vertical. As a result, horizontal wells encounter many more fractures than vertical wells. The orientation and characteristics of each fracture set can have a profound influence on production efficiency and water entry into a well, so fracture strike is a crucial factor for anyone drilling horizontal wells (figure 3.16). The DSI sonic anisotropy technique also helps to estimate fracture height and azimuth more accurately after hydraulic fracturing, providing a quantitative assessment of a frac job. It also allows the geoscientist to predict fracture closing stress. The DSI tool makes high-quality Stoneley wave measurements available for fracture evaluation. When a borehole Stoneley wave encounters an open fracture that intersects the wellbore, some of its energy is reflected as a result of the large acoustic impedance contrast caused by the fracture. Processing of the acquired Stoneley waveforms measures the reflection and, therefore, fracture characteristics. Closed fractures Maximum horizontal stress Open fractures Minimum horizontal stress Fig. 3.16: FACING UP TO FRACTURES: Horizontal wells intersect many vertical and sub-vertical fractures. Water can move easily along open vertical fractures, leading to early water production and high water cut in horizontal wells. Detailed anisotropy measurements help to avoid this problem by characterizing these fractures more accurately. Number 18,

12 SHEAR INSPIRATION FOR OLD CORE Hydraulic stimulation and natural fractures can greatly enhance oil and gas recovery in tight (low matrix permeability) formations. However, they affect flow and can set up unusual drainage patterns within a reservoir. Effective reservoir management relies on a clear understanding of existing fracture networks, particularly during in-fill drilling when the positioning of wells is critical. Effective hydraulic fracture stimulation is strongly influenced by fracture direction. The type of treatment selected can be modified by fracture azimuth, especially if there are geological structures to be intersected or avoided by the stimulated fractures. Waterfloods and other enhanced oil recovery (EOR) projects require models of fracture direction. Waterfloods designed without reference to the reservoir's fracture pattern may lead to premature water breakthrough and reduce ultimate recovery rates. Waterflood designs which incorporate fracture data can maximize sweep efficiency. In a typical waterflood pattern the producing well is surrounded by a ring of injectors. If the fracture direction in the reservoir coincides with the route from injector to producer, then injected fluids will travel along the fractures, bypass the non-fractured rock, break into the producer very early and sweep only a small portion of the reservoir (figure 3.17a). However, if the injectors lie along a line parallel to the fracture direction and the producers along another parallel line (figure 3.17b) the fractures can be used as a line injector, greatly increasing sweep efficiency across the reservoir. Most hydraulic fractures and many natural fractures are near-vertical and their propagation direction is parallel to the direction of maximum horizontal stress. Horizontal fractures are found only in shallow reservoirs where the weight of overlying rocks (the overburden) is relatively small. Fracture direction can therefore be predicted by measuring the direction of maximum horizontal stress before stimulation fractures are generated. (a) Injector Water Injector Fig. 3.17: Traditional waterflooding methods which ignore the fracture pattern in this field (a) will lead to early water production and leave a large volume of bypassed oil in the reservoir. The poor sweep efficiency is the result of rapid water migration along fracture planes. If the waterflood is adjusted to take account of the fracture pattern (b) a more efficient sweep and delayed water production should result. Water Producer Oil Oil Injector Oil Injector (b) Injectors Fractures Fractures Producers Fastest velocity Maximum stress Fig. 3.18: WHAT A RELIEF: When a core is removed from a formation the stresses acting upon it are relieved. In many rocks this stress relief causes time-dependent anelastic strains and produces microfractures with strikes perpendicular to the maximum horizontal stress of the formation. Stress relief cracks Slowest velocity Core sample Exaggerated strain relaxation Minimum stress 52 Middle East Well Evaluation Review

13 Core samples can also provide important information about reservoir stress patterns. When a core sample is removed from a formation the stresses which acted upon it are relieved and the rock expands (figure 3.18). In the horizontal plane, the greatest expansion occurs in the direction of the maximum horizontal in-situ stress. The stresses which affected the core were anisotropic and the rock expands less in some directions and more in others. This differential expansion causes cracks in the core. The cracks are not distributed uniformly through the rock; the largest proportion have strikes perpendicular to the maximum horizontal stress of the formation. One technique of core analysis (the vertical shear velocity anisotropy method) involves cutting two parallel surfaces on an oriented core sample and propagating a shear acoustic wave in a direction parallel to the vertical direction of the formation. The transmitting and receiving planar shear transducers are arranged so that their directions of polarization are parallel. Rotating the core sample relative to the transducer polarization shows the variation in shear velocity through the core as the direction of shear wave polarization varies with azimuth. When the direction of polarization of the transducers is parallel to the microfracture direction shear velocity is at a maximum; when perpendicular, it is a minimum. When the transducers are in any other orientation with respect to the fractures two orthogonally polarized shear waves are propagated in the core and shear wave splitting is observed at the receiving transducer. This technique is sensitive and accurate, but the shear anisotropy is usually small. Few rocks show vertical shear velocity anisotropies greater than 10% and most are in the range 1-5%. Heading for extinction To overcome the problem of measuring small anisotropies a method of crosspolarizing the transmitting and receiving shear transducers has been developed. When the core sample is rotated between these cross-polarized transducers acoustic extinction patterns (similar to the optical extinction patterns in light microscopes which use crosspolarized lenses) are produced. Energy from the transmitting transducer has its polarization split and rotated as it enters the sample so that the energy is polarized parallel and perpendicular to the microfracture direction. As the core rotates, the microfracture direction will be aligned with the polarization direction of one of the transducers (figure 3.19). At that orientation, the energy is a single wave as it enters the rock. This wave has no component of motion in the direction of the receiving transducer and no energy will be received - resulting in acoustic extinction. If the core is rotated through 360 there will be four such extinctions, as in optical microscopy. Two of these four directions will be parallel to the microfractures which cause the anisotropy and the others will be perpendicular. The technique has been tested on cores from a number of wells (figure 3.20) and the fracture directions determined from acoustic anisotropy have been within 15 of other fracture direction measurements including anelastic strain relaxation, tiltmeter surveys, core fracture descriptions, overcoring of minifracs and horizontal velocity anisotropy. Shear acoustic anisotropy is a simple laboratory technique - easier to perform and more cost-effective than field techniques such as anelastic strain relaxation, where results will vary over time. Acoustic anisotropy is not time-dependent: old core samples still display measurable shear acoustic anisotropies even 20 years after collection. (C) (A) Acoustic anisotropy Strain relaxation Core fractures Other methods Field A Field B Field C Acoustic anisotropy Sample rotation Acoustic extinction crosspolarized transducers Polarization direction of transmitting acoustic transducer Microfracture strike Polarization direction of receiving transducer Fig. 3.19: The acoustic extinction technique propagates plane-polarized shear waves along the vertical axis of the core and receives them at a shear transducer which is cross-polarized relative to the transmitter. These polarizations remain fixed as the sample is rotated. (B) Fig. 3.20: Comparison of fracture directions derived from acoustic anisotropy measurements on oriented core samples and results from other measurement methods. Strain relaxation Core fractures Other methods D.P. Yale and E.S. Sprunt (1989) Prediction of fracture direction using shear acoustic anisotropy. The Log Analyst (30) pp Number 18,

14 Faults found and followed Borehole images reveal information about faults that dipmeters cannot provide. In dipmeter analysis, the strike of the fault is defined by the drag along normal or reverse faults or rollover structure with growth faults. However, if there is a component of strike slip even the strike analysis of the fault can be in error by a significant angle. Imagery can reveal, without ambiguity, the type of fault present, its exact dip angle and direction, allowing an estimate of the location where that fault will intersect a reservoir zone. Many faults, especially late-stage faults in brittle rocks, have little or no deformation or drag zone, so they may not be detected by dipmeters. In areas dominated by wrench tectonics, vertical displacement of beds on opposite sides of the fault may obscure it. Using imagery these faults can be found and investigated for aperture and mineralization. In a reservoir it is very important to understand faults around the wellbore. Large open faults can produce water and should be avoided. Smaller faults and their associated fractures, however, can boost oil output without early water production. Integration of 3D seismic data and imagery is helping to locate wells close to smaller faults which cannot be detected using conventional 2D seismic methods. However, fault characterization is most easily and reliably achieved by examining the fault plane. This can be critical for the detection and geometrical analysis of growth faults and normal faults which are common in deltaic reservoirs. A review of many dipmeter surveys has shown that the actual fault plane of growth faults is rarely correlated. This is because the bedding dip direction is opposite to the fault direction (a result of fault rotation and bedding dip into the fault plane). For associated normal faulting it was found that if the correlation lengths used during dipmeter processing were too long, the dip of the fault and the deformation immediately around it would be averaged with smaller dips in beds further from the fault. The borehole image, however, allows the geoscientist to examine each fault zone individually in sufficient detail for dip and orientation of the fault to be defined accurately, even if the profile is produced using dipmeter software. Stresses old and new Mærsk Oil Qatar AS has carried out appraisals in the Cretaceous oil-bearing reservoirs of the Thamama and Wasia groups, offshore Qatar. These sedimentary groups are dominated by a series of upward shallowing cycles of shelf carbonates, notably the Kharaib, Shuaiba, Khatiyah and Mauddud formations. The reservoirs in this study occur at relatively shallow depths ( ft). One of the most important aspects of the programme involved determining the productivity of multiple, hydraulically-fractured horizontal wells. A high-resolution 3D seismic survey was designed to generate a migrated stratigraphic and structural image of the oil-bearing Cretaceous reservoirs at Al Shaheen. Cross-sections extracted from the interpreted 3D seismic dataset were used to place the horizontal borehole trajectories within the reservoir section accurately and to predict fault positions along the planned trajectories. A large amount of rock mechanical data was gathered from the vertical appraisal well, ALS-1, to optimize the design of hydraulic fractures. The combined surface seismic and rock mechanical datasets form a unique resource for understanding palaeo and present day stress fields and fracture patterns. The full-fold coverage of the 3D seismic survey amounts to 50 km 2 centred on well ALS-1. The 2D survey km in total - was designed to incorporate existing well information and to image and identify Jurassic and Cretaceous exploration targets within the area. The 3D seismic data was ana-lysed for fault and fracture trends at the Cretaceous reservoir levels and at shallower Tertiary levels. Horizontal time slices and seismic attribute maps were used to develop a detailed interpretation around the ALS-1 well and along the planned ALS-2 and ALS-3 trajectories. Mechanical responses Having gathered the seismic data, the next step involved assessing rock mechanics in the reservoir. Many different methods were used, including: Microfrac pressure analysis Borehole extensometer used during microfracture testing Anelastic strain recovery of oriented core sample Borehole ellipticity from FMS caliper records Over-coring and imaging of induced microfractures. The results obtained (figure 3.21) indicate that there is close agreement between some methods, notably the borehole breakout and core recovered microfrac, while others (such as anelastic strain recovery) proved to be of little value for this type of study. The observed stress orientation from Mærsk's detailed testing programme was found to coincide with the regional Zagros Stress direction (see figure 3.15) - Microfrac extensometer N Borehole breakout Core recovered microfrac Anelastic strain recovery N N N Fig. 3.21: Several methods were used to determine the various rock mechanical properties required to optimize the propped hydraulic fracture treatments in the ALS-1 well. The methods gave results with varying degrees of accuracy and reproducibility. 54 Middle East Well Evaluation Review

15 the dominant stress component in this part of the Arabian Plate since the early Tertiary. The modern stress field measured in ALS-1 predicts two primary shear components oriented N-S and ENE-WSW. The fractures observed in a wellbore using the Formation MicroScanner* (FMS) method agree with this interpretation and suggest that the ENE-WSW fractures are dominant (figure 3.22). On a larger scale, the results of 2D and 3D seismic mapping show a predominance of WNW-ESE trending features with a subordinate N-S trend. This suggests that while the regional scale faulting was triggered by the Zagros Stress, at least one of the shear components has initiated movement along pre-existing fault directions in older rocks. A study of Zakum Field in Abu Dhabi has shown that the E-W oriented Oman Stress influenced fracture directions in Thamama Group reservoirs deposited after the Oman Stress became inactive. W-E N σ max N NE NE-SW N E-W Fault and fracture trends Regional fault and fracture trends can be useful for predicting fracture orientation in some fields, but the regional values are only certain to agree with induced fracture orientations if there is no local perturbation in the stress field. For example, localized compressional folding may generate an induced fracture set which is completely different to the regional average (figure 3.23). In addition, natural fracture sets can be influenced by older stress regimes and so be completely different to existing regional stress patterns. Fold-related fault and fracture orientations that do not coincide with regional patterns must be identified when reservoirs in structural traps are the target. Orientation of natural fractures interpreted from FMS N σ min SW Fractures caused by regional stress S Fractures caused by folding Fig. 3.23: The regional stress pattern produces fractures which are oriented NE-SW perpendicular to the minimum stress direction. In the anticline, however, stresses associated with folding have overprinted the regional pattern with fractures aligned N-S. Waterflooding or horizontal drilling in this anticline would encounter fracture orientations and potential problems which could not be predicted from the regional stress pattern. Having proved its value in field tests, dipole shear anisotropy logging is now being made available to the industry. The actual logging time for sonic anisotropy measurements is only slightly greater than for a standard DSI logging run. Future development of this technique will be controlled by the rate at which interpretation skills evolve. This, in turn will require data on the operational limits of the method in fast formations, careful investigation of the influence of borehole shape, comparisons with other methods and refinements in data processing. W S E Fig. 3.22: The orientation of natural fractures derived from Formation MicroScanner (FMS) data. The orientations appear to match the stress field orientation, with a marked dominance of ENE-WSW oriented fractures. On a larger scale, however, the results of 2D and 3D seismic mapping show a predominance of WNW-ESE trending features with a subordinate N-S trend also present. Number 18,