Bjorn N. P. Paulsson

Elastic‐wave velocities and attenuation in an underground granitic repository for nuclear waste

The behavior of a quartz monzonite rock mass subjected to a thermal load from emplaced canisters with electric heaters simulating high-level nuclear waste was monitored by a cross-hole seismic technique in a drift 340 m below the surface in the Stripa mine facility in Sweden. Traveltimes and amplitudes of 20 to 60 kHz ultrasonic compressional (P) and shear (S) waves were measured over the experiment duration of 750 days, on 2 to 4 m paths between four diamond-drilled boreholes around a heater. The signals were transmitted between the boreholes in six different directions and at different depths. Path-averaged P- and S-wave velocities were obtained from the times of flight of pulses of acoustic waves between separate P- and S-wave piezoelectric transmitter and receiver crystals. The attenuation Q (super -1) was obtained by a spectral ratio technique. When the heater was turned on, the P- and S-wave velocities increased to 4 and 10 percent, respectively, and stabilized at the elevated values. The P-wave velocities along a particular profile were found to increase linearly with the mean temperatures in the profiles sampled. These mean temperatures increased 25 degrees to 55 degrees C during the course of the experiment. When the heater was turned off after 398 days of heating, the velocities decreased with temperature and finally reached levels in most cases below those observed prior to heating the rock. The highest thermal stress close to the heater was estimated at 55 MPa. Q (sub alpha ) values increased throughout the heating interval, reaching changes of up to 60 percent shortly after turning off the heater. The Q values reveal no direct correlation with temperature or the closely associated thermal stress, although these phenomena clearly are driving the variation in Q. There is strong evidence relating attenuation properties to fracture closure and pore pressure changes associated with draining of the rock mass.

The use of VSP techniques for fault zone characterization: An example from the San Andreas Fault

Vertical seismic profiling (VSP) technology is increasingly being used in the fields of earthquake seismology and tectonics. This is motivated in part by the growing number of oil field microseismic monitoring surveys, but more so by projects that involve drilling deep wells for monitoring crustal activity at depth. Examples of these projects are the San Andreas Fault Observatory at Depth (SAFOD), the Nankai Trough Seismogenic Zone Experiment, the Gulf of Corinth Rift Laboratory, and the Taiwan Chelungpu Fault Drilling Project, and other projects by the International Continental and Ocean Drilling Programs (ICDP and IODP). These projects require instrumentation and surveying in deep and possibly hot borehole environments. With higher resolution than surface seismic data, images from 2D and 3D VSP data contribute to better characterization and interpretation of complex reservoirs at smaller scales. The location of receivers in the low-noise borehole environment yields higher signal-to-noise ratios, higher ...

Near-wellbore VSP imaging without overburden

In seismic exploration a complex overburden can cause defocused and distorted seismic images of deeper target areas. While in surface seismic imaging it is difficult to overcome this problem, vertical seismic profile VSP borehole seismic imaging with its well-oriented recording geometry has proven able to circumvent the overburden’s detrimental impact.Recently,VSPnear-wellboresaltflankimagingwithout knowledge of the overburden has shown encouraging results. In this paper, we introduce another method for a more common imaging purpose: imaging near-wellbore horizons without knowledge of the overburden. A key component of ourmethodisareverseray-tracingtechniquethatusesactual VSPdirect-wave traveltime picks and extrapolates through a local velocity model to obtain the direct-wave traveltimes in the vicinity of the well. The extrapolated traveltimes then serve as references for migration of the VSP reflected data from near-wellbore horizons. The merits of this method are that all source-side effects such as shot position and triggeringtimestaticsareavoided,anditcanefficientlyandrobustly imagethenear-wellborehorizonsbecauseitdoesnotneedan estimated overburden velocity model prone to errors. However, the image is limited to a diamond-shaped area around the well whose size is proportional to the VSP array. A synthetic VSP experiment on the SEG/EAGE 2D overthrust modelshowsthatthismethod,withalocalevenanestimated 1D velocity model, effectively images structural features, suchasdipdirectionanddiscontinuitiesofthenear-wellbore horizons.

3D VSP technology now a standard high-resolution reservoir-imaging technique: Part 2, interpretation and value

This second part of an article about a large 3D VSP survey in Abu Dhabi describes the interpretation effort which quantifies the value that a 3D VSP seismic image can bring when supplementing even a 640-fold, high-resolution surface seismic volume.

3D VSP technology now a standard high-resolution reservoir-imaging technique: Part 1, acquisition and processing

Abu Dhabi Company for Onshore Oil Operations (ADCO) undertook a two-well 3D VSP pilot project in 2007. Because it was acquired concurrently with a high-resolution wide-azimuth surface seismic survey, it was at the time the largest 3D VSP ever recorded. The project consisted of four main parts: acquisition, processing, interpretation, and quantifying value. In part 1 of this paper the acquisition and processing of the 3D VSP is described with an emphasis on the lessons learned. Significant advances in processing are described that demonstrate how larger 3D VSP images with better amplitudes and structural preservation can be produced. In part 2, the results of the 3D VSP interpretation and economic evaluation effort are described and illustrate different ways that a VSP image can help characterize a hydrocarbon reservoir.

Optimized 3D VSP Survey Geometry Based On Fresnel Zone Estimates

Summary We present a method to optimize the acquisition geometry of 3D VSP data, that is, seismic data recording surface sources in large-aperture borehole receiver arrays. By estimating the Fresnel volume of specular rays at the target depth of interest, we are able to adapt the shooting geometry to the varying size of the Fresnel zone with offset from the well. Such an adaptive pattern of varying shot spacing helps to reduce illumination artifacts close to the receiver well and, at the same time, reduces the overall number of shotpoints, and thus, effort required to obtain the same image volume. We show a real data example where our approach has successfully been applied to optimize the shotpoint geometry.

VSP data‐referenced‐only migration without overburden

Traditional migration methods have a numerical source whose forward propagation serves as a reference for the migration of seismic reflections. These methods can be seen as sourcereferenced migration methods from one point of view. In this abstract, we outline the theory of data-referenced-only migration (DROM) in which the migration of one group of seismic waves is referenced to the migration (or migrations) of another group (or other groups) of seismic waves in the recorded seismic data. All source-side effects such as shot position and triggering time statics are absent, and sometimes the overburden problem is avoided in some VSP DROM applications. DROM can be implemented by traditional migration methods with some modifications, and in some cases, the traditional reverse-time migration becomes pure reverse-time migration without any forward modeling and is very efficient.

McKittrick Cross-Well Seismology Project: Part I. Data Acquisition and Tomographic Imaging

Summary A cross-well seismic tomography survey was conducted jointly between Chevron anh Teiaco in ihe Texaco portion of the McKittrick oilfield. The McKittrick oil field is shallow, less than 1300 feet, and contains low gravity oil which is perched above the water table. The formation consists of unconsolidated sands, conglomerates and diatomite. The P- and S-wave velocities are slow, sometimes very slow, and the sediments are highly attenuating. A downhole hydraulic vibrator developed at Chevron was used as the seismic source. The primary objective of the survey was to map a sealing fault that separates saturated from unsaturated parts of a thick oilsand. A second objective was to evaluate the performance of the downhole vibrator. The source depths ranged from 200 to 920 feet with mostly a 20 feet vertical spacing. There were four receiver wells, two within 100 feet of the source well, one 3 15 feet from the source well, and the fourth 467 feet from the source well. The vertical spacing between each receiver was 20 feet in the far wells and 10 feet in the near wells. The cross-well data are of generally good quality, and the vibrator operated without problems for over 3ooO sweeps. Both P and Shear wave direct arrivals are clearly seen as well as a number of reflections. The latter can be used to map bed boundaries and apply constraints to the tomogram inversion. The tomogram presented in this paper was computed using an ART algorithm. The sealing fault and saturated zone can be identified by a sharp P-wave velocity contrast, and the velocity distribution provides a detailed picture of the geologic structure between the wells.

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.

A 3D VSP Recorded in Abu Dhabi Yields New Understanding of a Complex Reservoir

A two well 3D VSP pilot project recorded in 2007 by the Abu Dhabi Company for Onshore Oil Operations (ADCO) was successful at demonstrating the value that can be gained from a high quality 3D VSP image. This second part focuses on interpretation and value addition. It is understood that for recovery to be optimized and by-passed resources to be minimized especially in later stages of field production more accurate models of a reservoir’s architecture and characteristics are needed. The results of this first 3D VSP survey was successful in characterizing details of the reservoir that could not be derived from the surface seismic or well log data alone. The higher quality images made it possible to map detailed stratigraphy and previously unknown important faults. The improved structural map and updated geologic model generated with information from the 3D VSP images were verified by wells drilled inside the 3D VSP image areas. Based on the successful results from this pilot project the 3D VSP technology is now considered a tool for projects that require detailed reservoir characterization in an area around a well within a diameter equal to the image depth, in this case 3,000 m.