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• W1999604296 abstract "Abstract In June 2006, in a production well in a tight sandstone shale sequence, on-shore USA, two borehole seismic arrays were deployed in separate wells during a proppant-baring hydraulic fracture treatment. The intent was to delineate the treatment-generated fracture network by recording the microseisms triggered by the treatment, map the microseism source locations, and then use the map as an overlay to delineate the fracture network. The treatment was one facet of a proprietary, multi-faceted injection strategy with microseismic mapping used to determine if neighboring fracture networks overlap. In addition to mapping the network, the objective of this facet was to compare maps from the two arrays. One array was in a remote well, the other in the treatment well. The remote array was offset ∼700 ft from the treatment well and at the injection depth. This array was ∼500 ft long; self-locking; contained 15, 3-component motion sensors; and operates on a fiber-optic cable. The treatment-well array, the TABS or TriAxial Borehole Seismic array (licensed by ExxonMobil Upstream Research), is ∼75 ft long; self-locking; operates on a standard, 7-conductor wireline; and includes (1) 3, 3-component motion sensors, (2) an ambient fluid pressure sensor, and (3) a gyroscopic, sensor orientation package. During the treatment, a 45-minute injection immediately followed by a 1–1/2-hour well shut-in, the remote array failed to detect any discernable treatment-triggered, microseisms. However, TABS, which recorded microseismicity only during the shut-in, recorded ∼400 microseisms. During the operation, the remote array maintained one position; TABS was unlocked, repositioned, and relocked twice; Moving TABS allowed different perspectives for recording the microseismicity, improving the accuracy of mapping and enhancing additional characteristics extractable from the microseismic waveforms. Introduction Since the 1890's, the petroleum industry has tried injecting a potpourri of energetic and energized liquids and solids to stimulate well production (Howard and Fast, 1970). In 1947 the industry began hydraulic fracturing, injecting above the in situ fracture pressure to create deep-penetrating fractures and increase productivity. Productivity was increased, but the below-surface hydraulic fracture geometry has always been an above-surface debate (Mahrer, 1999). In the last few decades we have learned that fracturing can create a simple, planar fracture; a complicated fracture zone; or something in between (Mahrer, 1999), plus it generates small earthquakes or microseisms. The locations of microseisms overlay the fractures and the overall fractured zone. Mapping the microseismic locations maps the fracture geometry. Using traditional and well-established earthquake analysis methods, the microseisms are located recording and analyzing the ground motion that radiates from the microseisms. Monitoring, detecting, and recording the ground motion from injection-induced microseisms can be done by three different deployments:motion sensors at the surface (not a topic of this paper),in a remote or neighboring well or wells, andin the treatment well. In oil and gas field deployments for monitoring hydraulic fracture stimulations, only two deployments, remote and treatment well, have met with successes. A typical oil and gas field uses only one of these." @default.
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• W1999604296 date "2007-01-29" @default.
• W1999604296 modified "2023-10-15" @default.
• W1999604296 title "Simultaneous Recording of Hydraulic-Fracture-Induced Microseisms in the Treatment Well and in a Remote Well" @default.
• W1999604296 doi "https://doi.org/10.2118/106025-ms" @default.
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