Mark A. Meadows

Shear-wave polarizations and subsurface stress directions at Lost Hills Field

2 × 2 S-wave data matrix, accomplished by computationally rotating sources and receivers. Although polarization directions obtained by assuming a homogeneous subsurface were moderately consistent with depth, considerable improvement in consistency resulted from analytically stripping off a thin near‐surface layer whose fast S-wave polarization direction was about N 6°E. S-wave birefringence for vertical travel averaged 3 percent in two zones, 200–700 ft and 1200–2100 ft (60–210 m and 370–640 m), which had closely similar S-wave polarizations. Between those zones, the polarization direction changed and the birefringence magnitude was not well defined. S-wave polarizations from two concentric rings of offset VSPs were consistent in azimuth with one another and with polarizations of the near offset VSP. This consistency argues strongly for the robustness of the S-wave polarization technique as applied in this area. The S-wave polarization pattern in offset data fits a model of vertical cracks striking N 55°E...

Changes in shear-wave polarization azimuth with depth in Cymric and Railroad Gap oil fields

Shear‐wave (S-wave) polarization azimuths, although consistent over large depth intervals, changed abruptly and by large amount of various depths in nine-component vertical seismic profiling (VSP) data from the Cymric and Railroad Gap oil fields of the southwest San Joaquin basin. A simple layer‐stripping technique made it possible to follow the polarization changes and determine the S-wave birefringence over successive depth intervals. Because the birefringence and polarization azimuth are related to in‐situ stresses and fracture, information from such analysis could be important for reservoir development. Near offset VSP data from Cymrix indicated that the subsurface could be appproximated roughly as two anisotropic layers. The upper layer, from the surface to 800 ft (240 m), had vertical S-wave birefringence as large was about 6 percent down to 1300 ft (400 m). In the upper layer the polarization azimuth of the fast S-wave was N 60°E, while in the lower layer it was about N 10°E. Refinement of the laye...

Seismic detection of a hydraulic fracture from shear-wave VSP data at Lost Hills Field, California

A shear-wave (S-wave) VSP experiment was performed at Lost Hills Field, California, in an attempt to detect hydraulic fractures induced in a nearby well. The hydrofrac well was located between an impulsive, S-wave source on the surface and a receiver well containing a clamped, three-component geophone. Both direct and scattered waves were detected immediately after shut-in, when the hydraulic pumps were shut off and recording started. The scattered energy disappeared within about an hour, which is consistent with other measurements that indicate some degree of fracture closure and leak-off within that period.Although S-wave splitting was evident, no change was detected in the fast wave (polarized parallel to the fracture). However, the slow wave (polarized perpendicular to the fracture) did change over a period of about an hour, after which the prehydrofrac wavelet shape was recovered. The fact that only the wave polarized perpendicular to the fracture was affected is a dramatic confirmation of both theoretical predictions and laboratory observations of S-wave behavior in a fractured medium.Subtracting the prehydrofrac wavelet from the wavelets recorded within the first hour after shut-in revealed scattered wavelets that were diminished and phase-rotated versions of the incident (prehydrofrac) wavelet. Arrival times of the direct and scattered waves were matched by ray tracing. We accounted for the scattered-wave amplitudes by using numerical solutions of S-wave diffractions off of ribbon-shaped fractures. Amplitudes derived from full-wavefield Born scattering, however, did not match recorded amplitudes. The phase of the scattered wavelets was matched very well by Born scattering when the incident wavelet was input, but only for fracture lengths no larger than half those predicted from fracture-simulator models. These results show that a carefully controlled experiment, combined with accurate modeling, can provide important information about the geometry of induced fractures.

4D Seismic Data Processing Issues And Examples

4D seismic data acquisition efforts can be divided into three major categories: “legacy”, “re-shoot” and “4Ddesign ” projects. In legacy 4D seismic projects, multiple vintages of overlapping 3D seismic data sets are analyzed for time-lapse effects, but none of the 3D surveys were originally acquired with a 4D application in mind. In reshoot 4D seismic projects, the baseline 3D seismic survey was not acquired for 4D purposes, but the subsequent reshoot 3D survey was designed, at least in part, with a 4D objective in mind. Finally, in 4D-design projects, at least two of the time-lapse 3D seismic surveys were specifically designed and acquired to optimize the subsequent reservoir monitoring analysis.

Comparison of P- and S-wave velocities and Q's from VSP and sonic log data

We compared P‐ and S‐wave velocities and quality factors (Q’S) from vertical seismic profiling (VSP) and sonic log measurements in five wells, three from the southwest San Joaquin Basin of California, one from near Laredo, Texas, and one from northern Alberta. Our purpose was to investigate the bias between sonic log and VSP velocities and to examine to what degree this bias might be a consequence of dispersion. VSPs and sonic logs were recorded in the same well in every case. Subsurface formations were predominantly clastic. The bias found was that VSP transit times were greater than sonic log times, consistent with normal dispersion. For the San Joaquin wells, differences in S‐wave transit times averaged 1–2 percent, while differences in P‐wave transit times averaged 6–7 percent. For the Alberta well, the situation was reversed, with differences in S‐wave transit times being about 6 percent, while those for P‐waves were 2.5 percent. For the Texas well, the differences averaged about 4 percent for both P...

Estimation of Reservoir Pressure And Saturations By Crossplot Inversion of 4D Seismic Attributes

We present a method to simultaneously estimate pressure and saturation changes in a producing hydrocarbon reservoir using time-lapse (4D) seismic attributes. 4D seismic attributes are displayed in a crossplot domain, where pressure and saturation axes can be estimated deterministically or interpretively. These axes form the basis for a linear or nonlinear coordinate transformation to the pressure-saturation domain. A final calibration to production data is required to convert the qualitative results to quantitative estimates of pressure and saturation. Our method is applied to 4D seismic data sets acquired over producing North Sea reservoirs in the Schiehallion and Gullfaks fields.

Twelve years of vertical birefringence in nine‐component VSP data

Since 1986, when industry scientists first publicly showed data supporting the presence of azimuthal anisotropy in sedimentary rock, we have studied vertical shear‐wave (S-wave) birefringence in 23 different wells in western North America. The data were from nine‐component vertical seismic profiles (VSPs) supplemented in recent years with data from wireline crossed‐dipole logs. This paper summarizes our results, including birefringence results in tabular form for 54 depth intervals in 19 of those 23 wells. In the Appendix we present our conclusions about how to record VSP data optimally for study of vertical birefringence. We arrived at four principal conclusions about vertical S-wave birefringence. First, birefringence was common but not universal. Second, birefringence ranged from 0–21%, but values larger than 4% occurred only in shallow formations (<1200 m) within 40 km of California’s San Andreas fault. Third, at large scales birefringence tended to be blocky. That is, both the birefringence magnitude...

Enhancements to Landro's method for separating time -lapse pressure and saturation changes

Landro’s (1999) method is an inversion technique that solves for time-lapse pressure and saturation changes from seismic amplitude-versus-offset (AVO) data. The method relies on the fact that pressure changes affect the slope and intercept of the AVO curve differently than do saturation changes. Specific assumptions are made about the range of validity of various parameters and the behavior of the Pand S-velocity and density as functions of pressure and saturation. We present two modifications of Landro’s method that are valid under different, but less restrictive, conditions, and we test these modifications using synthetic seismic data from a North Sea reservoir model. In the first modification, P- and S-wave impedances are used instead of the slope and intercept, while in the second modification, the P-velocity is assumed to vary quadratically, instead of linearly, with saturation. The first modified method yields results similar to Landro’s original method when the slope is calculated exactly. Inversion results from the second modification yield more accurate saturation values than those estimated by Landro’s method. In all cases, however, pressure changes “leak” onto the saturation map, and pressure decreases are not accurately determined, a result that can be explained by the poor sensitivity of P- and Swave velocities to decreases in pore pressure.

A risk analysis spreadsheet for both time-lapse VSP and 4D seismic reservoir monitoring

Summary We have developed a risk analysis spreadsheet suitable for both time-lapse VSP and 4D seismic reservoir monitoring projects. It is an enhanced version of the risk spreadsheet by Lumley et al. (1997). The significant new parameters developed for this study include measures of vertical and lateral resolution, source and receiver repeatability, and image aperture area, relevant for both VSP and 3D seismic acquisition. A scoring system quantifies the risk measured in each new parameter. We then describe a detailed risk analysis of six reservoir scenarios suitable for time-lapse (TL) VSP monitoring using the new spreadsheet technique. The six scenarios include CO2 injection in land-based carbonate reservoirs, steam injection in land-based sand reservoirs, and waterflood in marine-based sand reservoirs – all focused on monitoring a 20’ thin target zone. The six scenarios are fully evaluated in terms of reservoir and seismic parameters, and cross-plotted in a final combined analysis of all parameters. The results show that TL-VSP has the potential to be much lower risk than 4D seismic for all six scenarios, provided that TL-VSP surveys are highly repeatable, and attain excellent frequency content, areal coverage and image quality. The results also show that the best candidates for successful field tests of TL-VSP technology are steam injection projects in shallow soft sand reservoirs, and water-drive projects in soft sand reservoirs with high-GOR oils.

Determination of transversely isotropic velocity parameters at the Pluto Discovery, Gulf of Mexico

The collection of both a checkshot and multi-level walkaway vertical seismic profile (VSP) in the initial exploration well at the Pluto Discovery in the Mississippi Canyon area of the Gulf of Mexico provided a unique opportunity to assess and model the velocity anisotropy present in the area. Pre-well depth estimates based on a 3D pre-stack depth migration were found to give horizon depths that were five percent greater than those actually encountered in the well. A transversely isotropic (TI) velocity model was chosen to image the velocity anisotropy, which, for P-wave propagation, depends essentially on three independent parameters the interval stacking velocity and two unitless parameters, delta and eta. The sediment velocity model for the Pluto Discovery area was divided into five layers conformable with the water bottom surface. Constant delta and eta parameters were determined for each layer. These two parameters combined imply a horizontal P-wave velocity that is eight to sixteen percent faster than the vertical P-wave velocity in the top 14,000 feet of sediments. Travel time estimates from the ray tracing program agreed with the checkshot and walkaway VSP travel times to within one percent, when anisotropy was taken into account, as opposed to six percent for isotropic ray tracing. Based on this information, a 3D poststack depth migration using the TI velocity model showed, versus an isotropic velocity model, correct positioning of events in depth and better resolution of high dipping events. These are outcomes that we would expect from a TI velocity model migration. A checkshot and offset VSP were collected in the second exploration well at the Pluto Discovery. The checkshot data showed a similar vertical velocity structure to that indicated in the first well. The receiver depth range used for the offset VSP included greater depths than in the first well, so the anisotropic nature of the area could be explored deeper. For at least this sedimentary sub-basin, there appears to be little lateral change in the velocity or TI parameters. The TI velocity model at the Pluto Discovery is useful in correcting the depth implied from the pre-stack depth migration and in computing the correct travel paths of the seismic energy. Additionally, a post-stack depth migration using the TI velocity model resulted in sharper images from the sedimentary section. INTRODUCTION It has been known for some time that seismic waves in the earth can travel with different velocities depending on the direction of travel. In most localities this difference in seismic velocity with direction is small. However, in some areas the difference is large enough to cause distorted seismic images and inaccurate depth predictions. The collection of both a checkshot and multi-level walkaway VSP at the Pluto Discovery in the Mississippi Canyon area of the Gulf of Mexico provided an opportunity to assess and model the velocity anisotropy present in the area. Pre-well depth estimates based on a 3D pre-stack depth migration were found to give horizon depths that were five percent greater than those actually encountered in the well. A checkshot could easily correct this problem; however, a broader assessment and interpretation of the velocity anisotropy were desired. A walkaway VSP acquired in the sidetrack well provided the data necessary to measure the vertical versus horizontal velocity in the area. A transversely isotropic velocity model was chosen whose parameters (described below) were taken from Thomsen (1986), and Tsvankin and Thomsen (1994). The Pluto Discovery is in the Mississippi Canyon area of the Gulf of Mexico, approximately 150 miles southeast of New Orleans. The discovery lies in about 2,800 feet of water. The partners in the drilling of the well were British Petroleum, Chevron, and BHP Petroleum. The first well was drilled to 22,389 feet. A checkshot survey was recorded at approximately 250 foot intervals throughout the length of the original well. A sidetrack well was oriented northward from the original hole to investigate additional targets. A walkaway VSP survey was recorded at two different levels in the sidetrack well. An isotropic earth model is easy to imagine. The velocity of the seismic wave at any point within the earth section depends not on its direction, but rather on its spatial location. This holds true even for a vertically gradient earth. For a TI earth, the velocity is considered constant within a horizontal plane, but that velocity is different from the vertical velocity. A TI earth can arise in three main ways. First, a truly anisotropic rock has velocities that differ parallel and perpendicular to bedding planes. A shale could be seen to have this characteristic. Secondly, a series of isotropic rock layers can give rise to an anisotropic earth. 1998 SEG Expanded Abstracts TI velocity parameters at Pluto, GOM Lastly, stress fields within the earth may cause velocities to vary with direction. It is the first two of these mechanisms, anisotropic rocks and/or layered isotropic rocks, that are thought to give rise to the anisotropy found in the Gulf of Mexico. The horizontal velocity is generally greater than the vertical velocity, and theoretically must be if the TI anisotropy arises from layers of isotropic rocks. The parameters necessary for completely characterizing a TI earth include the interval stacking velocity, delta, and eta. The delta parameter is the percentage difference between the squares of the interval stacking velocity and interval checkshot velocity. The delta parameter has been thought of as the vertical anisotropy and corrects the seismic stacking velocity to the checkshot velocity. Eta is a measure of the difference between the squares of the horizontal and stacking velocities. VELOCITY COMPARISONS There are several different relevant velocity functions useful in seismic exploration. Checkshot velocities provide the definitive tie between seismic and well data. Stacking and migration velocities are used in processing seismic data and are normally picked to provide the best seismic image. Thus they are not necessarily tied to the petrophysical parameters of the geologic section. Figure 1 shows that there is a distinct difference between these three velocity functions of checkshot, stacking, and migration for the Pluto area. The stacking velocity function is the average of the velocity functions from the velocity control locations near the well. The migration velocity function is the one used in the prestack depth migration of the seismic data set. Obviously if either the stacking or migration velocity functions were to be used for time-depth conversions, the estimated depths would be too deep. The pre-stack depth migration for Pluto proved to have depth estimates that were 5% too deep at TD.