Seismic Waves and Rays in Elastic Media: 34 (Handbook of Geophysical Exploration: Seismic Exploration)
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Initially, output from reservoir simulators was used to provide input to Gassmann fluid-substitution schemes to compare with seismic observations; then, some pressure effects on the rock frame were included. The comparison between predicted seismic changes and those observed was sometimes used to update the original reservoir model, just as history-matching is used to improve the initial model.
Currently, there is an effort to fully link the reservoir simulation and its history-matching capability with the data provided by seismic time-lapse monitoring, guiding the simulator or the engineer in the interwell regions and further constraining the initial model. There are multiple reasons to consider passive seismic monitoring, which include: earthquake hazard evaluation and subsequent mitigation ; deformation monitoring for reservoir management and optimization; monitoring of fluid leakage for environmental and economic considerations; and providing additional time-lapse constraints for reservoir simulation.
The link between injection or production practices and seismicity, however, is complicated and not yet well-understood. The location and timing of microseismic events, or even large earthquakes, cannot easily be linked to a simple failure criterion in an otherwise static and nondeforming crust. The overall deformation of the rock surrounding the producing reservoir or zone of injection , as well as spatial variation in pore pressure, can alter the state of stress in the host rock; subsequent changes in either pore pressure or deformation-induced stresses can then cause seismic events, even though these may occur at conditions that would not have originally induced seismicity.
Conversely, the history of production and injection may inhibit seismicity that would have occurred under similar conditions but with a different history.
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Thus, the evolution of stresses in and near a reservoir seems to be almost as important as the absolute values of those stresses, in determining whether or not seismicity will occur. Because of these complicating aspects and perhaps other reasons not necessarily related to reservoir engineering, passive seismic monitoring is not currently used widely as a tool for reservoir management.
Improved geomechanical reservoir modeling is likely to aid in interpretation of microseismic event observations for reservoir management purposes, and environmental monitoring considerations are likely to increase; given these enhanced applications for the technology, it is probable that microseismic passive monitoring will become more widespread in the near future. Microearthquake location in map view upper left diagram and cross-section view lower left diagram ; and tracer results and microearthquake density with depth right diagram showing good correlation.
The results suggest that these fractures have been confined to narrow vertical zones over significant lateral distances after Rutledge and Phillips . Example locations of tiltmeters are shown.
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The left side shows a plot of the seismic interval velocity, determined from stacking velocities, as a function of depth and a smooth monotonically increasing trend line; the right side shows the pore-pressure interpretation from these data. Notice the overpressured zone where the velocity departs from the trend. The top diagram shows an interpreted seismic line with faults and specific horizons indicated.
The same faults and horizons are also shown on the bottom diagram with predicted pore pressure displayed in color. Notice that the major faults seem to act as pressure barriers in this case. The upper figure is a porepressure volume determined from interval velocities that had been calculated from stacking velocities. The relationship of dynamic and static shear modulus to shear strength is shown for some selected weak sandstones after Fjaer et al.
The monitoring of reservoir production in some instances includes monitoring of compaction,  partly for environmental or facility-design considerations e.
Laboratory studies on core samples can be conducted to provide a relationship between pore pressure and porosity, bulk volume, compressibility as a static measure , and seismic wave velocities dynamically measured. In general, the dominance of seismic technology in reservoir geophysics is because of three factors: seismic waves respond fairly well to reservoir and host-rock properties of interest; they provide high-resolution images; and there is a wide and deep base of knowledge of seismic techniques in the petroleum industry.
However, other technologies can often be shown to investigate properties of the earth that correlate better with the properties of interest. If the images from these technologies can be provided at appropriate resolution, and the knowledge required for interpretation and wise application of these technologies is available within the industry, they should be used. For example, electrical methods are extremely sensitive to variations in saturation, yet surface-based methods provide very poor resolution.
Reservoir compaction can be directly observed from surface deformation, and pore-volume or gas-saturation changes can be detected from changes in the gravitational field. This subsidence map was obtained using satellite interferometry over the Lost Hills and Belridge oil fields for a period covering days after Xu and Nur .
The white line represents the outline of the salt as determined from seismic data; various symbols indicate different aspects of the inversion constraints, while the color indicates the resistivity after Hoversten et al. The upper diagram shows, schematically, the different conductivity paths crossing the reservoir target when a borehole EM source is used in one well, and a set of receivers in another. The lower diagram shows a three-dimensional representation of the change in resistivity as a result of waterflooding operations over eight years for a reservoir in California from Wilt and Morea .
I Elastic continua
As geophysical techniques have matured over the years, they have provided an increasingly fine level of detail, and many are now used routinely for purposes related to reservoir production. The most widely used technique, just as in exploration, is reflection seismic, where it is almost exclusively 3D. Emerging techniques, having successfully proven their capabilities but in various stages of commercial availability, include: crosswell, forward and reverse VSP, single-well imaging, and passive seismic monitoring gravity, electromagnetic, and other techniques. The distinct advantage provided to reservoir geophysics over exploration geophysics lies in the quantity and quality of existing data on the reservoir target, enabling surveys to be focused on specific targets and allowing calibration necessary to have confidence in the results, as well as to improve imaging of the geophysical observations to the formation.
As geophysical techniques become more familiar to the engineer and as engineering practices become more familiar to the geophysicist, continuing and increased use of reservoir geophysical techniques can be expected. This chapter was prepared with support provided by a contract from the U. The author gratefully acknowledges the assistance provided by Schlumberger and Michigan Technological U. Jump to: navigation , search. Publication Information. Petroleum Engineering Handbook Larry W.
Lake, Editor-in-Chief. Copyright , Society of Petroleum Engineers. Chapter 1 — Reservoir Geophysics. By Wayne D. Pennington, Michigan Technological U. Overview Differences from Exploration Geophysics There are several specific differences between exploration geophysics and reservoir geophysics, as the term is usually intended. Well Control In exploration, extrapolation of well data from far outside the area of interest is often necessary, and the interpretation is required to cross faults, sequence boundaries, pressure compartments, and other discontinuities that may or may not be recognized.
Rock Physics Control Reservoir geophysics studies are directed at differentiating between competing reservoir models or at developing new ones. Nearly all seismic data collected for reservoir studies is high-fold, three-dimensional, vertical-receiver data see the petrophysics chapters in the Reservoir Engineering and Petrophysics volume of this Handbook , and many good case histories have been published.
Most seismic surveys are designed to exploit compressional P waves using hydrophones or vertical geophones, but some are designed to record shear S waves using horizontal and vertical geophones. One increasingly common usage of multicomponent seismology involves imaging beneath gas clouds.
Gas clouds encountered above reservoirs obscure the P -wave image by intense scattering of these waves because of the strong velocity dependence of P -waves on saturation. Seismic waves that are converted from P to S at the reflecting horizon also called C -waves are often used to image reservoirs beneath such gas clouds, by allowing a downgoing P -wave to pass underneath the gas cloud, while the upcoming converted S or C wave, which is much less sensitive to scattering by gas, passes through the cloud without significant distortion. Attributes In most exploration and reservoir seismic surveys, the main objectives are, first, to correctly image the structure in time and depth and, second, to correctly characterize the amplitudes of the reflections.
Well Calibration Calibration of seismic attributes at wellbores, using all available log data, core data, and borehole seismic information, should be undertaken in order to test the correlation of observed attributes with rock properties. The most common attribute is simply amplitude, although its interpretation in thin-layered beds is not necessarily straightforward. The "bright-spot" identifiation of hydrocarbons, as demonstrated in Fig. Imaging and Inversion The ability of seismic reflection technology to image subsurface targets is possible largely through the geometry of sources and receivers.
Stacking and Interval Velocities The geometry of sources and receivers in a typical reflection seismic survey yields a number of seismic traces with common midpoints or central bins for stacking. These traces were recorded at different offset distances, and the travel times for seismic waves traveling to and from a given reflecting horizon varies with that distance Fig. If the overburden through which the seismic waves pass is of constant velocity, then the time-variation with distance is a simple application of Pythagorean geometry, and the shape of the reflector on a seismic "gather" of traces is hyperbolic.
An analysis is then made of selected seismic gathers to establish the ideal moveout required to "flatten" each reflection in the gather. This moveout is expressed in terms of a velocity and represents the seismic velocity that the entire overburden, down to the point of each particular reflection, would have to result in the idealized hyperbolic shape observed.
This velocity analysis is usually conducted by examining the semblance or some other measure of similarity across all the traces, within a moving time window, and for all reasonable stacking velocities Fig. The seismic processor then selects the best set of velocities to use at a variety of reflectors and constructs a velocity function of two-way travel time.
These velocity functions are interpolated, both spatially and in two-way travel time, and all seismic gathers are then "corrected for normal moveout" using them. Each moveout-corrected gather is then summed or "stacked" after eliminating "muting" those portions of the traces that have been highly distorted by the moveout process. Borehole Seismic and Sonic Methods Reservoir geophysics should aggressively take advantage of data from boreholes that are very close to the target itself, not just for correlating seismic data to the well but also using those wells for the collection of novel geophysical data from below the noisy surface or weathered zone.
Single-Well Techniques Single-well techniques involve placing seismic sources and receivers in the same well and include sonic logging and single-well imaging. Sonic logging has become routine, and the collection of compressional and shear velocities in fast and slow formations is more-or-less straightforward, particularly with the use of dipole sonic tools and waveform processing. The application of modified sonic-logging tools for imaging near the wellbore is not routine but has been demonstrated in several cases; research and development continues in this area.
Modern sonic logging tools can provide a good measure of compressional and shear velocities, values that are required for calibrating seismic data at wells and for the investigation of lithology and fluid content from seismic data. Of course, the interpreter must be careful to know if the data represent invaded or uninvaded conditions and make appropriate corrections if necessary.
Modern sonic logging tools can often provide reliable values for velocities through casing; often, the most-reliable sonic logs in soft shales can only be found behind casing because of the inability to log openhole the depth intervals in which shales are flowing or collapsing. Compressional sonic log values are used in reservoir geophysics to tie well depths to seismic two-way travel time. First, the sonic transit time is integrated to obtain a depth-calibrated time scale, and then synthetic seismograms are created through determination of reflection coefficients including the density log and convolution with a known or assumed wavelet.
This synthetic seismogram is often adjusted to account for borehole effects, absence of data in the shallowest section, and other unspecified effects, including velocity dispersion caused by thin-bed layering below seismic resolution. The shear sonic log values are then added to create synthetic seismograms that demonstrate AVO behavior for comparison with the prestack data near the well. Often, additional work is conducted to model the changes in seismic response when rocks of slightly different lithology or fluid saturation are encountered away from the well.
Both the compressional and shear sonic data are required to accomplish fluid-substitution modeling, although some empirical models and other short-cuts are available. The experiment then becomes similar to a surface reflection-seismic experiment, except that reflections may come from any direction around the well, not just from beneath it. The technique has been shown to be useful to image fractures  and to determine proximity to upper and lower interfaces in horizontal wells  as demonstrated in Fig. Seismic Time-Lapse Reservoir Monitoring Traditional methods of monitoring reservoir behavior, including reservoir simulation and history-matching with production rates and pressure, can produce nonunique solutions for reservoir behavior in the interwell regions.
In some instances, the uncertainty can be significant, and additional information is needed to optimize production and improve estimates of ultimate recovery. The desire to minimize differences in acquisition parameters between surveys has led, in some cases, to permanent installation of sensors in the oilfield. Many seismic time-lapse monitoring experiments have been conducted offshore, where the wells are few and very far apart, and interwell information is especially important.
Other experiments have taken place in unusual or expensive production scenarios, such as steamflooding operations in heavy oil,  CO 2 flooding,   or thermal recovery. These can consist of straightforward stacked data volumes or stacks created from partial offsets if AVO aspects are considered. They may also consist of inverted volumes obtained from stacked full-offset or partial-offset data.go
The Leading Edge - August Elastic Anisotropy in SEAM Phase II Models
The comparison can be made in any number of ways, including simple visual inspection. But, it is important to recognize that differences can occur in seismic data even without changes in reservoir properties because of variations in acquisition or processing of the data sets. For example, 3D seismic data acquired from a towed-streamer marine experiment will contain an imprint that results from the direction traveled by the ship.