fax 01-972-952-9435. AbstractWe illustrate the use of a new technology for navigating and characterizing various types of oil reservoirs. Real-time images from Azimuthal Propagation Resistivity measurements provide a "map" of the resistivity patterns up to several meters around the wellbore. In addition, recently developed processing and quantitative interpretation techniques help guide the placement of the well and provide a new perspective of the formation.When navigating in gas drive reservoirs, the azimuthal resistivity measurement is used to maintain the wellbore at a prescribed distance above the oil-water contact. With its exponential sensitivity to distance, the measurement is able to detect even small changes in the distance to the oil-water interface. In a few instances, the azimuthal information provided by the real-time deep resistivity images indicates probable coning due to offset well production.Similar principles are applied in high angle drilling of water drive reservoirs. The deep azimuthal information allows the drilling engineer to maintain the wellbore at a prescribed distance immediately below a shale roof. The deep resistivity image from the azimuthal resistivity measurement also makes it easy to distinguish the roof from the occasional approaching shale lens.Whereas shallower reading LWD image logs (e.g. Gamma Ray and Density) only indicate a geological feature proximal to wellbore, the deep reading azimuthal resistivity measurement can provide geologic structure information at the reservoir scale. Visual displays show the subsurface surrounding the wellbore; quantitative algorithms accurately compute the distance, direction, and apparent dip for reservoir related geological events. A new conductivity unit named "Transverse Siemens" is proposed to help quantify the new azimuthal propagation measurement.
With the use of both azimuthal propagation resistivity main and cross component data, the resistivity anisotropy and its dip and azimuth angles of a massive formation (anisotropic shale or laminated sand) can be determined. The accuracy of the determined parameters depends on the amount of available data. A minimum amount of data are two frequency main components and real and quadrature cross components. The boundary effects will distort the solution eventually; however, the anisotropy enhanced processing will minimize the effects to extend the algorithm to a certain distance away from a boundary.
This paper presents a multidisciplinary approach to evaluating reservoir drainage patterns and hydraulic stimulation interactions among a development of both existing and new wells. Analysis of an extensive diagnostic package focuses on the potential to capture stranded reserves via refracs and infill drilling within the black oil window of the Lower Eagle Ford Shale, DeWitt County, Texas. The project consists of a unique setup of primary (parent) wells, new infill wells, and a horizontal well devoted exclusively to observation. Liner refracs were performed in two of the primary wells, with the remainder receiving preloads. It also included the collection of a horizontal core, formation imaging and advanced lateral logs, sealed wellbore pressure monitoring (SWPM), downhole fiber-optics (both permanent and deployable), seven downhole pressure gauges, time-lapse geochemistry, and iterative production interference tests. This substantial dataset provides vital calibration for well spacing, completion strategy, and field development. With the ability to measure the impacts of completion design, order of operations, refracs, re-pressurization, and infill drilling, detailed knowledge has been gained into improving redevelopment around a depleted parent network. The monitor well acquired 420 ft of horizontal core through the Eagle Ford target interval and is positioned between parent wells 225 ft laterally adjacent on either side. A significant number of hydraulic fractures were encountered, but only 8% contained proppant, indicating the original 2013 vintage completions had a very low conductive to hydraulically stimulated rock volume ratio. Fiber-optic and downhole pressure gauges on the monitor well also indicated that less than half of the parent laterals were effectively preloaded prior to infill completions, and these re-pressurization efforts were not sustained through time. SWPM was employed during refrac and infill completions to observe the stimulation of 156 stages, and over 750 treatment-to-monitor well pairings were captured. These interactions, coupled with findings from fiber and other diagnostic tools, were used to rank 6 different completion designs and define the optimal approach for future activity. Understanding depletion networks and parent/child well interaction is crucial to the future viability of the oil and gas industry. The diagnostic data collected during this project yields important insight into capturing stranded reserves from sub-optimally designed fields, bolstering new well results with higher unit recovery factors, and ultimately achieving a more effective and economic development strategy.
Summary With the use of both azimuthal-propagation-resistivity (APR) and main- and cross-component data, the resistivity anisotropy and its dip and azimuth angles of a massive formation (anisotropic shale or laminated sand) can be determined. The accuracy of the determined parameters depends on the amount of available data. The minimum amount of data required is two frequency main components and real and quadrature cross components. The boundary effects will distort the solution eventually; however, the anisotropy-enhanced processing will minimize the effects to extend the algorithm to a certain distance away from a boundary.
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