Brian Fuller

Seismic anisotropy in microseismic event location analysis

Seismic velocity anisotropy has been known for many years to be an important factor in correctly imaging subsurface structures with reflection seismic methods (Alkhalifah et al., 1996). Fine vertical velocity layering naturally gives rise to VTI (vertical transverse isotropic) velocity in which seismic-wave velocity is faster in the horizontal direction than in the vertical direction. Similarly, vertically oriented natural fractures and stress fields influence seismic velocities in an azimuthal or compass direction which is described as HTI (horizontal transverse isotropic) velocity variation (Schoenberg and Sayers, 1995). HTI velocity analysis in seismic reflection imaging commonly has two main objectives: placing geologic features in the correct spatial location and characterizing fracture orientation and density to optimize oil and gas production strategy.

Weighted correlation pairs for improved velocity analysis

Automaticstacking velocity analysis ofseismic ~etlectionsoften involves calculating a coherency measure (such as semblance) along a range of hyperbolic trajectories at a time ?b. Most coherency measures are formulated 50 that the maximum coherency value can be assunred to be the correct stacking velocity for the tiine To . It is therefore very iinportant that the furmulaGon of the coherency measure uses the maximu1n amount of the velocity information in the data in order to minimize the uncertainty in the velocity determination. l‘ho purpose of this paper is to introduce a coherency measure chat is a modification of semblance that provides more accurate velocity esthuation than standard semblance. The coherency measure is a normalized sum of weighted correlations between trace pairs in a CDP gatber. ‘The weighting applied lo the trace-pair correlations is proportional to the reflection travel time difltiencc betwceu thy two data traces. lhis weighting is used because trace pairs rhat have a large difference in travel lime for a given reflection contain more velocity information than trace pairs tbat have nearly the saine refleclion travel time small values of f/T than for trace pairs with large values of dT.

Diffraction Processing of Downhole Passive Monitoring Data to Image Hydrofracture Locations

Summary Seismic monitoring of hydrofracture operations can provide valuable information to guide production strategy. We present an algorithm for processing seismic fracture monitoring data. The method is more closely related to seismic reflection imaging methods such as the diffraction stack or Kirchhoff migration than the commonly used methods that use the delay time between P-wave and Swave arrivals.

Integration of Surface Seismic, 3D VSP, and Microseismic Hydraulic Fracture Mapping to Improve Gas Production in a Tight Complex Reservoir

Summary Completion techniques in tight hydrocarbon reservoirs typically include hydraulic fracturing to increase permeability. In this study surface seismic data, 3D VSP data, and microseismic mapping of induced hydraulic fractures were combined to understand the magnitude, direction, mechanisms, and lithologic controls on hydraulic fracturing in a tight gas reservoir. Fracture points were mapped from 3D surface seismic data, VSP data were used to tie borehole measurements to the surface seismic volumes, and 3D VSPs and offset VSPs were used to increase resolution and determine specific influences of reservoir zones or faults on the direction and magnitude of the fractures. Detailed velocity information obtained from multi-level multi-component VSP data (measured with the same instruments as the microseismic events) provided accurate locations of the measured fracture events in addition to providing well-constrained ties to the surface seismic volumes. Integration between disciplines improved the reliability of all of the data and provided the interpreter a unique opportunity to ‘see’ where the induced fractures occurred, thus highlighting fluid pathways within the complicated reservoir. These insights significantly improved design and implementation of hydraulic fractures. The integration methodology can be applied in other settings and projects.

Multivariate pattern recognition of seismic data for exploitation

When s discovery well has been drilled into a new hydrocarbon reservoir, seismic reflection data can be used to determine the reservoir’ s lateral extent only when reflection character changes can be correlated with changes in lithology at the edge of the reservoir. In cases where the reservoir rocks are vertically thin however, reflection character changes that indicate the lateral reservoir limits may be too subtle for interpreters to reliably detect. In such cases, specialized data processing techniques can be used to increase the information that can be extracted from the data. We applied multivariate Pattern Recognition techniques to seismic reflection data recorded over Eartzog Draw oil field in the Powder River Basin, Wyoming. The field produces oil from a sand ridge sequence that averages less than 10 m in thickness. The multivariate method was able to predict the location of the field’ s edge even though the reservoir sand was less than 10 m thick at the edge.

Imaging of thin beds using advanced borehole seismology

The high cost of data acquisition and the limitations of energy sources have impeded the widespread use of borehole seismic techniques. While piezoelectric and air‐gun sources continue to improve, these fluid‐coupled sources have severe problems associated with generation of tube waves. Additionally, the piezoelectric sources have a narrow frequency bandwidth which peaks above 1 kHz, thus limiting their application to high-Q sediments. Consequently there is a need to complement the fluid‐coupled sources with one which generates lower frequencies and which, by clamping to the borehole wall and thus achieving more efficient coupling of energy into the formation, will propagate energy to a greater range and minimize tube waves.

AVO For Thin Sand Bed Detection

Shelf-deposited sand ridges enveloped in marine shale are common oil traps in the upper Cretaceous sedimentary section of the Powder River Basin, Wyoming. Seismic detection of this class of oil trap is difficult because the reservoir sands average less than 10 m in thickness and they commonly occur at depths of 2500 m or more; they are therefore too thin to image given the frequency content of most seismic data sets. The presence of the sand ridge sequences can be detected however, by means of Amplitude-Variation-With-Offset (AVO) analysis. The AVO effect is a result of the difference in Poisson’ s ratio between clean, fluidfilled sand and marine shale. Both synthetic seismograms and field data recorded over Hartzog Draw field in the Powder River Basin, Wyoming show that reservoir sands that are less than 10 m in thickness produce an observable amplitudevariation-with-offset effect on the reflected wavefield. The results of this work show that amplitude-variation--with-offset techniques can be used as an exploration tool for thin sandsdthat are enveloped in marine shale. The technique also has potential uses for development of newly discovered reserves that are trapped in such sand-shale sequences. Amplitude-Variation-With-Offset (AVO) analysis is a seismic technique by which the lithology of the subsurface is studied by analyzing seismic reflections at various offsets in CDP gathers (Ostrander, 1984). The technique is based on the physical principle that the reflection coefficient at the interface between two rock layers varies with increasing angle of incidence when the ratio of P-wave velocity, Vp, to S-wave velocity, Vs, of one of the layers is significantly different from the Vp/Vs ratio of the other layer (Koefoed, 1955). In order to take full advantage of the AVO technique, the seismic data must be carefully processed so that any variation in amplitude is due solely to reflection coefficient changes and not some physical process such as attenuation or the result of a data processing step (Yu, 1985).

Time Domain 3D VSP Processing as a Step Before 3D PSDM

In nearly all cases within the seismic data processing industry, 3D Prestack Depth Migration (PSDM) of surface land and marine seismic data is preceded in the processing flow by time domain imaging steps. The time-domain steps include iterative NMO velocity analysis, residual statics and often 3D Prestack Time Migration (PSTM). The value of the time-domain steps is that source and receiver statics can be determined and a spatially variant 3D velocity field can be determined and later used in 3D PSDM steps. We have found that high quality 2D and 3D VSP PSDM results can be obtained by following the same time-then-depth process that is used in surface seismic data. Time-domain processing of 2D VSP and 3D VSP data is achieved by first applying upward continuation of the VSP data to effectively transform the VSP data into surface seismic data. The upward-continued VSP data can then be treated as surface seismic data, hence allowing computation of surface-consistent residual statics and development of a spatially variant time-domain stacking velocity field through NMO analysis. Then, in a process identical to that used in surface seismic data processing, PSDM can be applied to the upward-continued VSP dataset. By this procedure the same benefits of time-domain residual statics and velocity analysis can be realized for 2D VSP and 3D VSP data.

Design through interpretation of a very large 3D VSP in a complex area in Jonah Field, Wyoming

In the spring of 2005, EnCana Oil & Gas (USA) proposed the acquisition of a 3D VSP data set in a well later drilled in a complex compartmentalized portion of the Jonah gas field in Wyoming. Development of this area would benefit from the greater reliability of structural and stratigraphic interpretation enabled by the increased resolution of this 3D VSP. Figure 1 illustrates the acquisition geometry. Seismic data are recorded by downhole geophones at the center of ap-proximately 1400 source points. Surface source point signals are collected by a receiver array in the borehole. The resulting 6.5 mile2 survey was designed, permitted and acquired within a nine-month period in 2005. Innovative design and acquisition techniques led to successful acquisition on time and within budget.

Crosswell Source-receiver Geometry And Drilling Economics

Crosswell seismic methods can be used as an integrated part of the drilling decision process during development of an oil or gas field. The cost of the crosswell data acquisition and associated extra drilling can only be justified if the crosswell data is less than the risk-weighted cost of drilling additional production wells. Modelling of the crosswell objective prior to data acquisition helps to minimize both crosswell data acquisition costs as well as drilling costs.