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Thingelstad B.L.,Enerplus Resources United States Corporation | Burns R.A.,Integrated Petroleum Technologies Inc. | Weijers L.,Pinnacle A Halliburton Service | Weijers L.,Liberty Oilfield Services LLC
SPE Production and Operations | Year: 2012

Multistage fracturing in the Bakken formation, Elm Coulee field, Williston basin, Montana, has been performed using hydraulic packers for zonal isolation with ball-actuated fracture sleeves to improve performance of horizontal wells. Optimizing development drilling and fracture-treatment designs for horizontal wells requires an estimation of the fracture geometry (azimuth, height, and half-length, with respect to lateral orientation). A fracture treatment designed under the assumption of a longitudinal fracture (along the length of the borehole) will be entirely inadequate if the actual fracture propagates in a transverse orientation (perpendicular to the length of the borehole) and vice versa. Recovery factor and reserves estimation, interference, drainage, and well spacing require an understanding of the created fracture geometry from multistage completions. This paper describes how real-time downhole microseismic monitoring, fracture-treatment pressure interpretation, and subsequent production evaluation were used to better understand the created-fracture geometry, completion staging efficiency, and fracture-stimulation effectiveness in a project with two parallel 4,000-ft middle-Bakken treatment horizontal wells 2,000 ft apart with a horizontal well in between. The following topics will be discussed as part of this paper: 1. Success and failure in achieving proper stage isolation, diversion, and fracture-stimulation coverage using hydraulic packers for zonal isolation with ball-actuated fracture sleeves in two 4,000-ft laterals. 2. Fracture azimuth and half-length as related to entry-point spacing and intersections with nearby wells. 3. Fracture-height growth up into the Lodgepole limestone and down into the Three Forks formation as related to microseismic location uncertainties and use of this information in fracture-model calibration. 4. Discussion and comparison of the production response for past completion strategies to the current approach, as well as discussion about production interference between horizontal wells. The integration of fracturing-mechanics studies that began with the initial vertical wells and concluded with current-day horizontal applications in concert with detailed reservoir-engineering evaluations has resulted in significant production improvement in the Bakken formation, Elm Coulee field, Williston basin, Montana. Detailed reservoir engineering led to optimized multistage fracturing that was applied using hydraulic packers for zonal isolation with ball-actuated fracture sleeves to improve performance of horizontal wells. Using a calibrated/customized fracture model that had been developed from evaluation of hundreds of wells in the basin, the fracture-treatment pump schedules were designed to minimize fracture complexity and optimize lateral proppant placement to attempt to create an ideal transverse-fracture geometry within a horizontal well. Microseismic imaging was used to confirm the historical information in the basin, fracture mechanics studies, and customized models relative to the azimuth, height, and half-length with respect to lateral orientation. Copyright © 2012 Society of Petroleum Engineers.

Warpinski N.R.,Pinnacle A Halliburton Service
SEG Technical Program Expanded Abstracts | Year: 2011

While there are many decades of experience with hydraulic fracturing in the petroleum industry, the recent exposure of the general public to this technology, particularly as practiced with large volume water fractures in the gas shales, has resulted in considerable fear and misunderstanding of what is occurring downhole. Fortunately, the industry has been studying the problem of fracture height growth for several decades and has been monitoring fractures with tiltmeters for two decades and with microseismicity for over one decade. This compendium of knowledge and measurements shows that the common practice of multi-stage stimulations of shale reservoirs in horizontal wells is not a threat to groundwater via fracture pathways. © 2011 Society of Exploration Geophysicists.

Zimmer U.,Pinnacle A Halliburton Service
SEG Technical Program Expanded Abstracts | Year: 2011

Microseismic event locations are increasingly used as input parameters for additional calculations, e.g. stimulated reservoir volume (SRV), moment tensor inversions. Uncertainties in the event locations often have a direct effect on the derived parameters and therefore it is important to quantify the location uncertainty. Although companies generally report location uncertainties in form of error bars, often along Cartesian coordinates, the calculation of these error bars and their interpretation is not standardized and sometimes obscure. By assigning each point in the localization grid a probability for the event location based on the available input data it is possible to use input from very different sources, e.g. traveltime residuals, hodogram analysis, velocity model uncertainties, and combine them in a probability grid. The distribution of the overall probability can then be used to define the uncertainty space based on the desired level of accuracy, e.g. the 95% confidence uncertainty space will be larger than the 90% confidence space. This method has the advantage that very different types of uncertainty, e.g. sensor position, can be included in the calculation and that an interpretation of the uncertainty space in terms of confidence is possible. The derived uncertainty space clearly represents the space where the event is with 90%, 95% or any other degree of probability. © 2011 Society of Exploration Geophysicists.

Warpinski N.R.,Pinnacle A Halliburton Service
48th US Rock Mechanics / Geomechanics Symposium 2014 | Year: 2014

Microseismic monitoring of hydraulic fracturing has provided great value for understanding hydraulic fracturing in unconventional reservoirs, including measurement of fracture geometry and optimization of stimulations, completions, and field development. Nevertheless, microseismic monitoring is a complex endeavor and many issues of fielding, analysis, uncertainty, and geophysics should be carefully assessed. The geomechanics of the generation of microseismicity are still being investigated, as well as the source mechanisms and how it all relates to the fracturing process. Besides the value for field development and resource recovery, microseismic monitoring has also proved useful for evaluating environmental and safety issues. Data from thousands of fractures show that the levels of induced seismicity in typical relaxed sedimentary basins are well below any levels that would be of concern for safety or damage. Similarly, data from thousands of fractures show that hydraulic fractures in shale reservoirs do not propagate into aquifers. Copyright (2014) ARMA, American Rock Mechanics Association

Flewelling S.A.,University of Cambridge | Tymchak M.P.,University of Cambridge | Warpinski N.,Pinnacle A Halliburton Service
Geophysical Research Letters | Year: 2013

The widespread use of hydraulic fracturing (HF) has raised concerns about potential upward migration of HF fluid and brine via induced fractures and faults. We developed a relationship that predicts maximum fracture height as a function of HF fluid volume. These predictions generally bound the vertical extent of microseismicity from over 12,000 HF stimulations across North America. All microseismic events were less than 600 m above well perforations, although most were much closer. Areas of shear displacement (including faults) estimated from microseismic data were comparatively small (radii on the order of 10 m or less). These findings suggest that fracture heights are limited by HF fluid volume regardless of whether the fluid interacts with faults. Direct hydraulic communication between tight formations and shallow groundwater via induced fractures and faults is not a realistic expectation based on the limitations on fracture height growth and potential fault slip. © 2013. American Geophysical Union. All Rights Reserved.

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