3D VSP Data Research Articles

Joint Obn and 3D Das-Vsp Data Acquisition and Processing in the East China Sea

Borehole and surface joint seismic exploration is a 3D seismic exploration method formed by the combination of surface seismic and VSP survey simultaneously. Using the 3D DAS-VSP data, accurate time-depth relationship, formation velocity, deconvolution operator, spherical diffusion compensation factor, absorption attenuation factor, anisotropy parameters and high-resolution structural imaging around the wellbore can be obtained. These parameters can be used to significantly enhance the surface 3D seismic data processing. This paper describes the 3D DAS-VSP data acquired by a downhole armoured optical cable simultaneously with an OBN data acquisition project in East China Sea, and the results of 3D DAS-VSP data imaging processing. The usual 3D VSP data imaging processing steps include: observation system definition, preprocessing, first arrival picking, static correction, amplitude compensation, deconvolution, wavefield separation, velocity analysis and imaging. Based on the characteristics of offshore 3D VSP downgoing multiples, the offshore 3D VSP downgoing multiple imaging technique has been innovatively developed. This greatly expands the 3D DAS-VSP imaging range and improves the overall 3D DAS-VSP imaging quality. The 3D DAS-VSP downgoing multiple reflection wave imaging shows significant imaging quality improvement in comparison with the vintage 3D OBC data imaging. The detailed structure, tracing of the reservoir and formation tops becomes easier and less ambiguous using both new OBN data imaging and 3D DAS-VSP data imaging when compared with the vintage 3D OBC data imaging.

Extraction and characterization of faults and fractures from 3D VSP data in a carbonate reservoir: A workflow

We present a workflow for the extraction and characterization of fractures and faults using a Reverse Time Migrated (RTM) volume from 3D Vertical Seismic Profile data (3D VSP) acquired in an oilfield offshore Abu Dhabi in the United Arab Emirates. The workflow consists of: preconditioning of the input RTM volume, which involves removal of acquisition footprints; extraction of faults and fractures using a semblance based discontinuity attribute; binary filtering and clustering for characterization and interpretation using prior geological information, as well as removals of unwanted features such as those related to stratigraphy; and finally interpretation. Complex networks of lineaments were extracted after application of the workflow. The location of lineaments with length greater than 200 m and orientated WNW-ESE to NW-SE correlates with a known flower structure which has a trend similar to that of the Proterozoic Najd Fault System that cut the Arabian Peninsula. Lineaments with strike directions ENE-WSW and NE-SW are interpreted to be related to reactivation of basement faults and correspond to the Hormuz Salt basin's major trend in the Arabian Gulf. Dominant strike directions of lineaments at three reservoir levels correlate with dominant strike directions of interpreted fractures from Fullbore Formation Microimager (FMI) and core data; thus implying that they are likely related to fractures or fracture corridors. Lineaments with orientation NNE-SSW correlate with closed fractures while lineaments with orientation NNW-SSE correlate with open fractures. Zones with relatively high fracture intensity are generally located north and north-west of the VSP well in the reservoir zones. The good correlation of the results with interpreted fractures from core and FMI data shows the robustness of the workflow and gives confidence to the results.

CO2 Storage Site Characterisation at Harvey, Western Australia Using Non-Conventional Seismic Survey Geometries

This stage of the South West Hub Carbon Capture and Storage (CCS) project aims to produce an in-depth integrated study of the fault and fracture network surrounding the Harvey 3 well to obtain an understanding of their propensity to act as conduits for the injected CO2. An additional interest to the seismic component of the study was to find an optimum CO2 sequestration monitoring methodology. This was of key importance since acceptance by the farming community across the area of the potential reservoir extent is crucial for successful completion of the project. These two factors were taken into account for the survey design that was comprised of more conventional components consisting of simultaneous recorded 3D surface and 3D VSP data sets and an alternative component that recorded multi-offset VSP (MOVSP) survey along the public roads. A comparative analysis of seismic imaging achieved with different geometries is discussed. One of the important results was that MOVSP surveys produced good results and hence this technique may be preferred for monitoring CO2 sequestration in this area. This was since it caused no disturbance to the farming ground and it was much more likely to gain acceptance with the landowners.

Seismic characterization and monitoring of a deep CO2 storage reservoir with 3D VSP using direct shear waves

We show a low-cost option for shear wave imaging of CO2 storage reservoirs that utilizes seismic waves that have been ignored by reflection seismologists for decades. These overlooked waves are direct-S waves generated by vertical-displacement vibrators and explosive sources. Shear waves are known to be helpful for detecting fractures and subtle faults which is critical for evaluating of CO2 storage capacity and sealing properties of the caprock. Utilizing direct-S waves produced by P-wave sources provides these benefits with no need to deploy special shear-wave sources. In addition, the SV-P mode, which is the upgoing P-wave produced by SV-to-P conversion, makes it possible to utilize S-wave attributes with data recorded by vertical geophones only.We developed a processing workflow to extract SV-SV and SV-P seismic modes from 3D VSP data acquired over a CO2 storage reservoir at Decatur, Illinois and tested these modes for seismic imaging and monitoring of the reservoir. In addition, we inspected an SH-SH mode that appeared interpretable in our data. We observed that direct-S images were consistent with traditional VSP direct-P images and calibration synthetic seismograms. A joint analysis of all available seismic modes allowed a constrained interpretation of faults within the reservoir. Direct-S waves appeared to not be advantageous for CO2 plume growth monitoring in the Decatur project. The SV-P mode demonstrated low sensitivity to CO2 concentration. The time-lapse difference for the SV-SV mode was uninterpretable due to the low signal-to-noise ratio of that mode.

3D VSP: A mine of information for mining exploration

The 3DVSP technique becomes more popular with the emergence of multilevel 3 component borehole tools. The value of the information derived from VSP is not always well understood. In this paper we will present a case history of a joint surface and borehole seismic acquisition, with the goal to de-risk a shaft sinking location on a platinum mine. TD was about 650m and the VSP tool was 110m long. On surface a dense grid of receivers and vibrator source points were laid out in 1.2 km radius circle centered on the well head. A12 level 3C VSP digital tool was lowered in the borehole, in three successive depth positions. The surface 3D cube was processed and interpreted independently from a the 3D VSP data. On a near target reflector, the surface data structural interpretation showed mainly a clear E/W fault, and additional subseismic lineaments of differing azimuths, difficult to identify in terms of fault. The 3D VSP image limited to a short radius around the borehole confirmed the fault/dyke nature of these lineaments, separating monocline compartments. As a consequence, the surface data was carefully re-interpreted and on the second structural images derived from two surface seismic reflectors and the near surface fault footprint from 3DVSP residual statics, a series of subtle faults were clearly assessed. last, the few faults intersecting the borehole can be clearly recognized on the logs and the borehole radar logs. This case study demonstrates the added value of a joint interpretation of surface and borehole data in a decision making process for shaft sinking.

Prediction of the seismic time-lapse signal of CO2/CH4injection into a depleted gas reservoir - Otway Project

Stage I of the Otway project conducted by the Cooperative Research Centre for Greenhouse Gas Technologies (CO2CRC) in 2007-2010 included injection of 66000 tons of CO2-rich gas into a depleted gas reservoir at Naylor field, Otway Basin, Victoria. In this paper we present a seismic modelling study that estimates the time lapse response of CO2/CH4 injection into the Waarre C reservoir. Based on the static geological model, acoustic impedance inversion of the seismic baseline data as well as log data, two models with different levels of detail in the reservoir properties are built. The distribution of the injected CO2/CH4 mixture in the reservoir and the gas properties are obtained from flow simulations. In order to predict the change in acoustic impedance after injection, we employed the Gassmann fluid substitution workflow. The modelled total differences in acoustic impedance for different amounts of CO2/CH4 injected are of the same order of magnitude for both models and reflect the CO2 mass fractions predicted by flow simulations. Finally zero incidence synthetic data are computed for these cases using a statistical wavelet of the baseline data. The computed synthetics are compared to surface seismic and VSP monitoring data. The repeatability of the surface seismic data is too low to detect the predicted signal. For the 3D VSP data, the time-lapse signal/noise has a similar order of magnitude as the predicted signal. It may have the level required to detect the signal.

Slowness surface construction and inversion from 3D VSP data

The emerging technology of three-dimensional vertical seismic profiles (3D VSPs) allows the extensive sampling of reflecting surfaces over a wide range of incident angles and azimuths. Such data can be used to provide additional insights into the effective rock properties associated with features that are below seismic resolution, such as layering or aligned systems of fractures which lead to elastic anisotropy. Here we analyse two 3D VSPs acquired in the Arabian Gulf and show how the data may be processed to extract slowness surfaces, how these surfaces can be used to estimate anisotropy parameters, and how the anisotropy relates to the geological characteristics of the formation and its stress history.

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.

Near-surface velocity and static model estimation from downgoing VSP multiples

Processing land walkaway or 3D VSP data often requires the application of source static corrections. Because of the effect of statics on the final image, the determination of an accurate near-surface velocity model and statics are critical, especially in desert areas such as in Saudi Arabia.

Processing/integration of simultaneously acquired 3D surface seismic and 3D VSP data

VSP surveys use surface sources and borehole receivers and record both downgoing and upgoing wavefields. Different configurations of VSP surveys are possible and the various types of VSP data sets are valuable to the interpreter in areas where surface seismic data are of limited help. Common applications of zero-offset VSPs are correlating logs and seismic data, getting information about variations in seismic velocity with depth, and detecting multiples. Offset VSPs are usually recorded where subsurface structures are not well known, or are complex. Their images, which are of higher frequency than surface seismic, are used to obtain structural detail around boreholes. Multioffset or walkaway VSPs are a means of lateral reservoir definition away from the borehole. They combine the advantages of VSP (including the possibility of anisotropy determination) with the continuous profiling aspects of surface methods. However, these single or multioffset VSPs are usually obtained as 2D sections and these sections, though useful, cannot be used to construct a 3D data volume around the borehole. Different acquisition geometries are needed to achieve that objective. The first 3D VSP acquisition was attempted in 1986 by AGIP, and several have been acquired since then (Table 1). Simultaneous acquisition of 3D VSP and 3D surface seismic acquisition has been attempted on several occasions and the results have been encouraging in terms of cost effectiveness and the enhanced imaging of the subsurface. This innovative acquisition and analysis offers exciting possibilities for determining data attributes such as anisotropy, Q, and measurement of reflection and transmission amplitudes at the wellbore which can then be used to calibrate AVO attributes estimated from surface seismic 3D data. View this table: Table 1. Some highlights of 3D VSP history Although many 3D VSPs have been discussed in the literature, few articles go into detail about the processing (Gulati et al., 2002). Therefore, a paper …

High-frequency restoration of surface seismic data

Often we come across examples in which the initial processing of a 3D seismic volume results in interpretations that are geologically suspect—e.g., cases involving complex faulted patterns or subtle stratigraphic plays. Similarly, postmortem analysis may cite small fault displacements or obscure seismic data as reasons for dry wells. In such cases, the usual practice is to create a new version of the 3D volume with some target-oriented processing to improve imaging in the zone of interest that will, in turn, lead to more accurate interpretation. This helps in some cases, but in others some questions remain unresolved. In the latter, more often than not, more accurate stratigraphic interpretation is needed but the available bandwidth of the data is inadequate to image or resolve the thickness of many thin targets seen in wells. This can be addressed by having data of reasonable quality and augmenting it by some frequency restoration procedure that improves the vertical resolution. Frequency restoration is necessary because seismic waves propagating in the subsurface are attenuated and this phenomenon is frequency dependent—higher frequencies are absorbed more rapidly than lower frequencies. Consequently, the highest frequency recovered on most seismic data is usually about 80 Hz. This article describes a new method for restoring high frequencies within the seismic bandwidth that is based on the frequency decay experienced at different VSP depth levels in a well. It is well known that VSP data contain higher frequencies than surface seismic data because the energy recorded by VSP traverses the unconsolidated weathering zone just once. Figure 1, which shows sectional amplitude spectra computed for a profile through spatially coincident 3D seismic and 3D VSP volumes, confirms this observation. The frequency content of the surface seismic data extends to 60–65 Hz but it reaches 90 Hz in the 3D VSP data. Figure 1. Sectional …