J. Helen Isaac

Image mispositioning due to dipping TI media: A physical seismic modeling study

A scaled physical model was constructed to investigate the magnitudes of imaging errors incurred by the use of isotropic processing code when there is seismic velocity anisotropy present in the dipping overburden. The model consists of a block of transversely isotropic (TI) phenolic material with the TI axis of symmetry dipping at an angle of 45°. Its scaled thickness is 1500 m, and it is intended to simulate the dipping clastic sequences found in many fold‐thrust belts. A piece of isotropic Plexiglas, affixed to the underside of the anisotropic block, has a step function in it to simulate a target reef edge or fault. The anisotropy parameters of the material are δ = 0.1 and e = 0.24. On zero‐offset data the imaged position of the target is shifted laterally 320 m in the updip direction of the beds, whereas on time‐ and depth‐migrated multichannel sections the shift is 300 m. The lateral shift is offset dependent, with the amount of shift in any common‐midpoint gather decreasing from 320 m on the near off...

A practical method for estimating effective parameters of anisotropy from reflection seismic data

The location of any event imaged by P‐wave reflection seismic data beneath a tilted transversely isotropic (TTI) overburden is shifted laterally if isotropic velocities are used during data processing. The magnitude of the shift depends on five independent parameters: overburden thickness, angle of tilt, symmetry‐axis velocity, and the Thomsen anisotropy parameters and δ. The shift also varies with source–receiver offset.We have developed a procedure to estimate these five parameters when the tilt of the symmetry axis from the vertical is equal to the dip of the TTI layer (except in the special cases transverse isotropy with vertical or horizontal axis of symmetry). We observe three attributes of seismic data processed using isotropic velocities: the zero‐offset arrival time of a selected reflection, the difference in arrival time between a near‐offset and a far‐offset arrival, and the difference in imaged location (smear) of this target event between the same offsets. We then perform a cascaded scan of t...

A case history of time-lapse 3D seismic surveys at Cold Lake, Alberta, Canada

Time-lapse 3D seismic surveys were acquired across a bitumen field at Cold Lake, Alberta, Canada, during a production cycle (1990) and a steam-injection cycle (1992) of a thermal-enhanced oil recovery (EOR) program. We observed changes in interval traveltime and amplitude distributions between the processed surveys. We interpret the increased traveltimes observed over most of the injection survey to be a result of lowered interval velocities in the reservoir, caused primarily by higher temperature and lower effective pressure. Reflection-strength variations within the reservoir are present in each data set and change spatially between the surveys. In general, we interpret the amplitude anomalies seen only on the production survey to be caused by local free gas and the amplitude anomalies seen only on the injection survey, which are close to the perforation depths, to be caused by thin, vertically restricted steamed zones.

Slip-slidin' away—some practical implications of seismic velocity anisotropy on depth imaging

Recent advances in imaging mean that we no longer need to ignore seismic velocity anisotropy. Laboratory and field studies provide compelling evidence that shales exhibit intrinsic transverse isotropy (TI). In this symmetry class, the seismic velocity parallel to the laminations is greater than that perpendicular to the layering, and the difference can be as high as 30%. In flat-layered clastic sequences, such as in the Western Canada sedimentary basin, the TI axis of symmetry is essentially vertical, and isotropic depth migration of reflection seismic data tends to overestimate the true depths of reflectors. This occurs because the imaging velocity, based on moveout analysis, is generally greater than the true vertical velocity.

Comparison of structural imaging in anisotropic media using P-wave and S-wave data

Various laboratory and in situ measurements have shown that certain rocks, including sandstone, shale, and limestone, exhibit seismic anisotropy. If not accounted for, anisotropy can cause several problems in the processing and imaging of seismic data. Typical errors are incorrect lateral position of events and errors in depth estimates.

Seismic velocity model building in an area of complex geology, southern Alberta, Canada

We developed velocity models to prestack depth migrate two seismic lines acquired in an area of complex mountainous geology in southern Alberta, Canada. Initial processing in the time domain was designed to attenuate noise and enhance the signal in the data. The prestack and poststack time-migrated sections were poorly focused, implying the velocity models would be inadequate for prestack depth migration. The velocity models for prestack depth migration, developed by flattening reflections on common image gathers, ineffectively imaged the complex geology. We developed our most effective velocity models by integrating the mapped surface geology and dips, well formation tops, geological cross sections, and seismic-velocity information into the interpretation of polygonal areas of constant velocity on several iterations of prestack depth-migrated seismic sections. The resulting depth-processed sections show a more geologically realistic geometry for the reflectors at depth and achieve better focusing than either the time-migrated sections or the depth sections migrated with velocity models derived by flattening reflections on offset gathers.

Interpretive velocity‐model building for seismic data acquired across a complex structure in Southern Alberta, Canada

We processed in time and depth two seismic lines from an area of extremely complex geology in the Turtle Mountain area of Southern Alberta. The time processing was desinged to attenuate noise and enhance signal in the data. To develop a velocity model for pre-stack depth migration (PSDM) we integrated all available sources of velocity and geological information into the interpretation of preliminary depth migrated seismic data. We used the near-surface velocity models derived from refraction statics analysis together with constant velocity migrations for velocity information in the shallow section. The location of velocity pull-ups on the time migrated sections acted as a guide to the extent of high-velocity carbonates carried in the hangingwall of a major thrust fault. We integrated the mapped surface geology, geological cross-sections, well depths and interval velocities from sonic logs into the velocity model. The depth processed sections show a more realistic geometry than the time sections for the reflectors at depth. The seismic data cannot image the shallow, steeply dipping strata in Turtle Mountain itself. Our interpretation is based upon published geological models, surface geology maps, well data and the seismic character where the reflections are imaged adequately. Time Processing Before embarking on PSDM we processed the data in time to attenuate noise and enhance signal. We applied an f-k filter to reduce the surface noise and applied deconvolution and a coherency filter to the shot gathers. Refraction statics were calculated using GLI3D (Hampson and Russell, 1984). We also calculated and applied residual statics. The sub-weathering velocities from GLI3D corresponded well with the mapped surface exposure of high velocity Palaeozoic strata and formations of the lower velocity Brazeau and Alberta Groups. We integrated this nearsurface velocity information into the velocity models for PSDM.

Integrated gravity and seismic interpretation in the Norman Range, Northwest Territories, Canada

We integrate the interpretation of gravity data acquired across the Norman Range near Norman Wells, Northwest Territories, Canada, with geologic mapping and the processing and interpretation of a 2D reflection seismic line. Our purpose is to determine which of two contrasting structural models of deformation is supported by both gravity and seismic data. Interpretation of the gravity data implies that the more likely structural model is that of thin-skinned deformation with a low-angle thrust fault having a decollement within Upper Cambrian evaporites. We use this structural model to guide the development of a velocity model for prestack depth migration of the seismic line. Interpretation of the processed seismic line supports the thin-skinned deformation model.

Geophysical evidence for thin-skinned structural deformation in the Norman Range, Northwest Territories

Abstract Interpretation of a gravity survey acquired across the Norman Range, near Norman Wells, NWT, Canada, was integrated with geological and reflection seismic data to determine the most likely structural model for the subsurface. A thin-skinned structural interpretation of a low-angle thrust fault with a decollement within the Cambrian Saline River Formation yielded the best match between the calculated and observed gravity data and was supported by processed reflection seismic data. The interpretation predicts that potential reservoir rocks of the Devonian Ramparts Formation extend only a short distance below the Norman Range in the footwall of the Norman Range Thrust.

A case history of experimental time-lapse 3C 2D seismic reflection data for reservoir monitoring at Cold Lake, Alberta, Canada

AbstractWe processed, interpreted, and analyzed experimental time-lapse converted-wave 2D-seismic reflection data that were acquired across a bitumen field undergoing cyclical steam injection and production at Cold Lake, Alberta, Canada. The purpose was to assess whether multicomponent-seismic data could be used to detect lateral and/or temporal changes caused by steam injection into the reservoir. We interpreted horizons on PP and PS sections that bracket the reservoir, and calculated VP/VS over this interval. Away from the steam injection wells, VP/VS values average 2.20±0.02 during steaming and production and are close to the theoretically predicted value of 2.21 for a cold reservoir. Near the wells, VP/VS is lower during steam injection than during production, averaging 2.11±0.02, and the lowest values are observed close to the injection wells. We attributed the changes in VP/VS to changes in the reservoir caused by the injection of steam.