Extracting the vibration response of the subsurface from noise is a rapidly growing field of research [Curtis et al., 2006; Larose et al., 2006]. We carried out broadside imaging of the San Andreas fault zone (SAFZ) using drill bit noise created in the main hole of the San Andreas Fault Observatory at Depth (SAFOD), near Parkfield, Calif. Imaging with drill bit noise is not new, but it traditionally requires the measurement of the vibrations of the drill stem [Rector and Marion, 1991]; such measurements provide the waves radiated by the drill bit. At SAFOD, these measurements were not available due to the absence of an accelerometer mounted on the drill stem. For this reason, the new technique of deconvolution interferometry was used [Vasconcelos and Snieder, 2008]. This technique extracts the waves propagating between seismometers from recordings of incoherent noise.
Two 126 level 3-component 3D-VSP's (Vertical Seismic Profiles) were acquired coincident with a high-resolution surface seismic survey. Figure 1 shows the location of the first 3D-VSP on the crest of the field and the second 3D-VSP on the flank of the field. Using the surface seismic sources, 11712 shot points were used per VSP to collect 4.5 million traces per VSP, which produced a 6–9 km2 final 3D-VSP image around each of the two wells. Due to the large offsets and high density of traces available it was possible to experiment with acquisition and processing methodologies to produce images that resolve thinner beds, see more structural definition and improve reservoir characterization. Results from the first phase of processing are very encouraging and show the 3D-VSP images to be able to resolve subtle faults that were not seen in older surface seismic data and have higher frequency content than the new 640 fold, high resolution surface seismic data. Source and receiver decimation tests are aiding in efforts to better understand how to acquire high quality 3D-VSP's in the future with minimal effort and cost. Efforts to expand the size of the 3D-VSP volumes around the wells have been successful. The largest image produced so far has been able to image more than 1.5 km away from the wellbore. The high quality VSP images and the fact that VSP's can be repeated at much lower cost than surface seismic makes this technology very attractive for future time-lapse reservoir monitoring studies.
Hydraulic fracturing operations in unconventional reservoirs are increasingly being monitored with fiber-optic (FO) Distributed Acoustic and Temperature Sensing (DAS/DTS). In this paper, we discuss how a single well equipped with fiber optics and DAS can be used as a diagnostic tool to better understand the completions program of three offset wells and the fiber instrumented well. Strain measurements were initially conducted for seismic studies, then followed by measurements of fluid injections from monitoring wells to better understand placement along the lateral section of the wellbore for programs such as hydraulic fracturing, water flooding, and steam injection. The broadband DAS signals have shown of value for the monitoring of microseismic, as well as thermal and mechanical strain of the fiber over the entire well-pad's completion process. During well stimulation, as a fracture propagates to an offset wellbore with fiber deployed, the DAS measurements can be used to monitor very small changes of strain on the fiber. Analysis of the Cross-Well Communication (CWC) strain measurements provide information about possible fracture numbers and locations, as well as the fracture propagating rate based on known well distance. Changes in the strain measurements are coupled with microseismic events that can be simultaneously monitored using the same interrogator unit and fiber optic cable. Here we present various diagnostic tools for DAS that help to better understand the completions program. A variety of physical effects, such as temperature, strain and micro seismicity are measured and correlated with the treatment program to aid in the analysis. Two of the offset wells were zipper-fractured first, then the fiber installed well was zipper-fractured with the third offset well. By monitoring CWC strain measurements we show that DAS can assess the treatment and performance of neighboring wells that are not instrumented with fiber optic cable. Low frequency strain events from neighboring wells provide direct measurements of the fracture density and possible fracture network post fiber well completion. CWC measurements can provide strain levels that can be analyzed in the context of the various completion parameters including stage length, clusters, and well spacing, etc. We also discuss the fluid and proppant allocations measurements that can be performed on the well with fiber installation. We show how DAS can be used as a tool for investigating cluster efficiency, diverter effectiveness, and for determining completions problems like screen-outs and stage communication. The analysis of the DAS data demonstrates that current fiber-optic technology can provide enough sensitivity to detect a significant number of frac events that can be used for an improved reservoir description and as an assessment of the completions program.
The 3D VSP method is being increasingly employed as a tool to produce high-resolution images for detailed reservoir characterization and to address reservoir challenges. These challenges include thin layer reservoirs, thief zones and stratigraphic features that affect recovery. The main challenges in processing VSP datasets are twofold: First to ensure that the high frequency and better vector fidelity is being used and carried through to the final image. This requires special care and appropriately adapted processing techniques to the smaller scale and high frequency contained in the VSP data. Second, is dealing with the unique geometry of a 3D VSP, which has laterally varying fold coverage and aperture that has to be accounted for in order to minimize any footprint on the final image. In this project VSP processing advances have been made using data from the largest 3D VSP recorded to date, which was acquired in an Abu Dhabi oil field. Different types of static corrections were tested and optimized to recover the high frequencies required for optimum event delineation. A combination of static corrections that takes full advantage of the 3D VSP geometry and includes surface seismic data results that helped achieve optimal coherency of events. A careful analysis of the irregular fold geometry resulted in good target imaging using a detailed illumination analysis. Such an analysis aids in the correct treatment of the high resolution events and helps to interpret their character along the area illuminated. This analysis provides critical information about the velocity model and the corresponding kinematics. The ability of VSP's to recover high frequencies is demonstrated in this processing flow, by showing the difference in resolution between new high resolution surface seismic and the final 3D VSP image. Introduction The availability of 3D VSP data has resulted in more detailed characterizations of the reservoir because of the high resolution given by the VSP data compared to surface seismic techniques. Its usage includes detailed stratigraphic analysis of thin and often deep targets that the surface seismic cannot adequately image. In addition the VSP technology has been used in areas within complex near surface environments or areas where there is limited surface access. The use of receivers within the well has led to seismic images in the vicinity of the well that have high resolution and high signal to noise ratio. More importantly receivers in the borehole environment have led to high frequency data because of shorter travel paths. In the VSP case less energy is attenuated as it only travels once through the near surface weathering layer or complex overburdens. The high frequency recorded by the borehole array (Figure 1) consequently results in smaller Fresnel zones at the target in the vicinity of the well, therefore enhancing its lateral characterization.
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