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Hydraulic fracture height and width are key parameters for completion design and evaluation of unconventional resources. Traditional measurement technologies like microseismic, tilt-meters, chemical or radioactive tracers, pressure temperature gauges, etc. either have low resolution or rely on sensitive models which can cause a high degree of uncertainty. Recent frac-hit measurement methods include the use of Distributed Acoustic Sensing (DAS) deployed in far-field wellbores offset from the treatment well. The DAS system directly measures the fracture propagation every second through the completion, with a few meters' spatial resolution sampled at 0.25-meter intervals along the monitored fiber well.
Cross-well fiber optic monitored far-field strain (FFS) results suggested elastic stress effects, intense inelastic fracture expansion and closure events which provide identification and measurement of frac height on a TVD plot, as well as width by measured depth along the wellbore laterals. Vertical wells or the heel-section of horizontal wells are suitable for frac-hit height (FHH) measurement; fracture azimuth and wellbore geometries need to be considered for precise evaluation. A specially designed engineered constellation fiber cable was tested and utilized in this method in combination with a true phase coherence DAS interrogator with a 20 dB improved sensitivity (Signal-to-Noise-Ratio (SNR)) for both low and high frequency ranges DAS.
The optic fiber can be either permanently installed outside the casing or temporarily deployed inside a monitor well. Comparable results can be achieved by the engineered fiber system and have been presented within case studies for both horizontal and vertical well sections. In addition, Distributed Temperature Sensing (DTS) and data from downhole gauge can confirm any temperature or pressure changes resulting from frac driven interactions (FDI).
With this approach, fracture azimuth, frac-hit corridor (FHC) width and FHH can be determined with a high degree of accuracy and resolution. Completion engineers were able to optimize frac models in real-time and further change completion schedules during the frac treatment.
Bohn, Rob (Silixa) | Hull, Robert (Silixa) | Trujillo, Kirk (Silixa) | Wygal, Ben (Silixa) | Parsegov, Sergei G. (West Virginia University) | Carr, Timothy (Northeast Natural Energy LLC) | Carney, B J
The study focuses on the MIP and Boggess pads of the MSEEL (Marcellus Shale Energy and Environmental Laboratory), a public-private partnership with a mandate to publicly release data for scientists and engineers to engage with. Multiple diagnostic tools are used to characterize the formation and monitor fracture treatment and propagation. Geomechanical modeling is used to understand the in-situ stresses, microseismic to describe half-lengths and heights, and fiber optics to characterize offset well Fracture Driven Interactions (FDI's) and interstage communication. Recent publications covering the MSEEL MIP-3H and MIP-5H wells are reviewed and discussed. A preview of the findings from the Boggess pad (first production in November 2019) is also shared here.
The Marcellus Shale Energy and Environmental Laboratory (MSEEL) is a joint project between the Department of Energy’s National Energy Technology Laboratory (NETL) and its partners, West Virginia University (WVU), and Northeast Natural Energy LLC (NNE), to develop and test completion technologies (DOE Award No.: DE-FE0024297). The objective of the MSEEL is to provide a long-term collaborative field site to develop and validate new knowledge and technology to improve recovery efficiency and minimize the environmental implications of unconventional resource development (Taylor 2019). At the time of this writing, the MSEEL has conducted three phases, two of which consisted of a multi-well pad instrumented with advanced diagnostics. Multi-terabyte datasets were produced from both pads and are made public to allow for better collaboration among engineers and scientists across disciplines and to validate crucial conclusions (Carr 2020).
The analysis will focus on both MSEEL pads, the MIP pad (Phase 2) and the Boggess pad (Phase 3), with an initial emphasis on the older MIP pad. Both have multiple fracture stimulated horizontal wells all targeting the Marcellus shale. Figure 1 shows a map view of both pads.
The MIP pad has four wells that were drilled and completed in pairs as noted in Figure 2. MIP-3H and MIP-5H wells have a spacing of approximately 1,700 ft.
Li, Xinyang (OptaSense, Inc.) | Zhang, Jimmy (Encana Corporation) | Grubert, Marcel (OptaSense, Inc.) | Laing, Carson (OptaSense, Inc.) | Chavarria, Andres (OptaSense, Inc.) | Cole, Steve (OptaSense, Inc.) | Oukaci, Yassine (OptaSense, Inc.)
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.
Ugueto, Gustavo A. (Shell Exploration and Production) | Todea, Felix (Shell Canada Limited) | Daredia, Talib (Shell Canada Limited) | Wojtaszek, Magdalena (Shell Global Solutions International) | Huckabee, Paul T. (Shell Exploration and Production) | Reynolds, Alan (Shell Exploration and Production) | Laing, Carson (OptaSense) | Chavarria, J. Andres (OptaSense)
Abstract The use of Distributed Acoustic Sensing for Strain Fronts (DAS-SF) is gaining popularity as one of the tools to help characterize the geometries of hydraulic fracs and to assess the far-field efficiencies of stimulation operations in Unconventional Reservoirs. These strain fronts are caused by deformation of the rock during hydraulic fracture stimulation (HFS) which produces a characteristic strain signature measurable by interrogating a glass fiber in wells instrumented with a fiber optic (FO) cable cemented behind casing. This DAS application was first developed by Shell and OptaSense from datasets acquired in the Groundbirch Montney in Canada. In this paper we show examples of DAS-SF in wells stimulated for a variety of completion systems: plug-and-perforating (PnP), open hole packer sleeves (OHPS), as well as, data from a well completed via both ball-activated cemented single point entry sleeves (Ba-cSPES) and coil-tubing activated cemented single point entry sleeves (CTa-cSPES). By measuring the strain fronts during stimulation from nearby offset wells, it was observed that most stimulated stages produced far-field strain gradient responses in the monitor well. When mapped in space, the strain responses were found to agree with and confirm the dominant planar fracture geometry proposed for the Montney, with hydraulic fractures propagating in a direction perpendicular to the minimum stress. However; several unexpected and inconsistent off-azimuth events were also observed during the offset well stimulations in which the strain fronts were detected at locations already stimulated by previous stages. Through further integration and the analysis of multiple data sources, it was discovered that these strain events corresponded with stage isolation defects in the stimulated well, leading to "re-stimulation" of prior fracs and inefficient resource development. The strain front monitoring in the Montney has provided greater confidence in the planar fracture geometry hypothesis for this formation. The high resolution frac geometry information provided by DAS-SF away from the wellbore in the far-field has also enabled us to improve stage offsetting and well azimuth strategies. In addition, identifying the re-stimulation and loss of resource access that occurs with poor stage isolation also shows opportunities for improvement in future completion programs. This in turn, should allow us to optimize operational decisions to more effectively access the intended resource volumes. These datasets show how monitoring high-resolution deformation via FO combined with the integration of other data can provide high confidence insights about stimulation efficiency, frac geometry and well construction defects not available via other means.
Abstract Hydraulic fracturing stimulation designs are moving towards tighter spaced clusters, longer stage length, and more proppant volumes. However, effectively evaluating the hydraulic fracturing stimulation efficiency remains a challenge. Distributed fiber optic sensing, which includes Distributed Acoustic Sensing (DAS) and Distributed Temperature Sensing (DTS), can continuously monitor the hydraulic fracturing stimulation downhole and be compared with other monitoring technology such as microseismic. The DAS and DTS data, when integrated with the microseismic, highlight processes relevant to the completion design and allow for a better understanding and interpretation of each dataset. This paper outlines a workflow to improve processing and interpretation of DAS and DTS data. In addition, an estimate of the slurry distribution can be made. These methods will be demonstrated for a horizontal Wolfcamp well in the Permian Basin. Here we compare key aspects of the microseismic, DAS, and DTS results in several fracture stages to understand the downhole geomechanical processes. In order to interpret the DTS data a thermal model is developed (using DTS data) to simulate the temperature behavior after pumping has ceased. A slurry distribution is obtained by matching the simulated temperature with the measured temperature from DTS. In addition, the DAS data signal is studied in the frequency domain and the dominant frequencies are identified that are mostly related to fluid flow and to reduce the background noise. This time frequency analysis enhances the ability to monitor and optimize well treatments. After reducing the background noise, the acoustic intensity is correlated to the slurry distribution. The fluid distribution data from DAS and DTS are compared with the microseismic and near field strain to better understand the completion processes. We utilized fiber optic microseismic to better understand and compare it to conventional microseismic. Finally, we highlight the dynamics of strain and microseismic signature as fluid moves from an offset well completion into the prior stimulated fiber well to better understand the reservoir and far field effects of the completion.