Bruce E. Cornish

Velocity calibration for microseismic monitoring: A very fast simulated annealing (VFSA) approach for joint-objective optimization

To accurately locate microearthquakes that are genetically related to hydraulic fracture stimulation, a thorough knowledge of the velocity structure between monitoring and fracturing treatment wells is essential. Very fast simulated annealing (VFSA) is implemented to invert for a flat-layered velocity model between wells using perforation or string-shot data. A two-point ray-tracing method is used to find the ray parameter p for a ray traveling from a source to a receiver. The original traveltime-calculation formula is modified to account for the borehole source-receiver geometry. VFSA is used as a tool to optimize P- and S-wave velocities simultaneously. Unlike previous applications of VFSA, two improvements result from a new study: (1) both P- and S-wave arrival-time misfits are considered in a joint-objective function, and (2) P- and S-wave velocities are perturbed simultaneously during annealing. The inverted velocities follow the true values closely with a very small root-mean-square error, indicating the inverted model is close to the global minimum solution whose rms error should be zero for synthetic examples. Data noise contaminates inverted models, but not substantially in synthetic test results. A comparison of models inverted using VFSA and Occams inversion technique indicates that inverted models using VFSA are superior to those using Occams method in terms of velocity accuracy.

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.

Multi-sensor seismic while drilling: field test results

Summary While it may be widely accepted that borehole seismic surveys utilizing a standard surface seismic source can be obtained while drilling there are at least two main issues that need to be well understood in order to make these seismic measurements accurately and reliably: sensor coupling/fidelity, and precision timing. To further complicate matters, the rigors of the drilling environment impose significant constraints on the design and mounting of the seismic sensors and the accuracy of the clock. We have developed a next-generation tool that addresses coupling issues through the deployment of multiple, multiaxis sensors, including ruggedized geophones, seismic accelerometers, and hydrophones, in combination with a novel, highly accurate clock and contingent surface systems. This paper investigates the performance of the new tool design and presents the results of field tests and operations in which seismic data were acquired using multiple sensors and multiple types of sensors in various types of formations, and in deviated boreholes. The data acquired while drilling are compared to baseline commercial wireline VSP measurements in order to verify that the system provides accuracy comparable to that of a standard commercial wireline.

Processing of 3-D VSP data from a permanent borehole array

Summary A permanent, 40-level, 3-component geophone cable was installed in a temperature observation well near a steam pilot at Chevron’s Lost Hills Field, San Joaquin Valley, California. Data were recorded through this cable during a 3-D surface seismic survey conducted by Chevron in September 1998 using the same sources and the same recording system as the surface acquisition. We selected a subset of 45 source positions located within a radius of 800 feet of the observation well for 3-D VSP processing. The objective was to form a 3-D image volume to test the feasibility of time-lapse reservoir monitoring by the borehole array method. The permanent nature of the array and its proximity to the reservoir were expected to improve image quality and repeatability and to reduce the cost of repeated monitoring surveys.

Improved Methods for Hydrofrac Event Detection and Phase Picking

The ability to detect small microseismic events and identify their P and S phase arrivals is a key issue in hydraulic fracture monitoring because of the low signal-to-noise ratios. We propose a array-based waveform correlation approach to detect small magnitude events with similar mechanisms and locations as a nearby master event. For the phase picking part, a transformed spectrogram method is used to identify the weak P arrivals. We have applied the technique to a downhole monitoring dataset of the microseismic events induced by hydraulic fracturing. The results show a better phase identification.

Production Tubing Conveyed VSP Acquisition - A Case History

As part of a permanent down-hole seismic system project, a wireline multi-offset, vertical seismic profile (VSP) was acquired in a well at Halliburton’s Carrolton, Dallas, Texas, test facility. A vibratory source was used to acquire four offset VSP profiles, one walk-away (five-source positions) and a zero-offset VSP. The zero-offset VSP was also acquired with an air-gun source. The down hole threecomponent receiver arrangement consisted of a wireline multi-station tool with eight levels at 50-ft separation and with a hydraulic clamping system. The tool was run up from 2900 to 1000 feet using the vibrator and from 2050 to 900 feet using the air-gun source.

3-D VSP migration imaging with constraints in Lost Hills, California

SUMMARY We have developed a 3-D VSP prestack Kirchhoff depth migration algorithm that takes into account the irregular sampling of the wavefield due to the acquisition geometry and the structure of the target. To mitigate the migration artifacts that arise, we use dip and incident angle constraints in the migration. The information to develop these constraints is usually available from near-borehole dip measurements and prior surface seismic surveys. Additionally, we use migration resolution measurements to evaluate the resolution properties with and without migration constraints and the effect of data preprocessing steps on resolution. We have applied the algorithm to a data set collected in 1998 at Lost Hills, California.