Summary More than 100 billion lbm of proppant are placed annually in wells across the globe, with the majority in unconventional reservoirs. The location of the proppant in these horizontal wells and formations is critical to understanding reservoir drainage, well spacing, and stage spacing. However, for many years proppant detection has primarily been limited to near-wellbore measurements. A novel method to detect proppant in the far field has been developed and is the subject of this paper. The proppant-detection method developed uses electromagnetic (EM) methods. This technology entails using a transmitter source and an array of electric- and magnetic-field sensors at the surface. A current signal with a unique wave form and frequency is transmitted to the bottom of the wellbore via a standard electric-line (E-line) unit. In addition, an electrically conductive proppant is pumped into the stage(s) of interest. The electric and magnetic fields are measured both before and after the detectable proppant stages, and a novel analysis method is then used to process and invert these differenced data to create an image of the propped reservoir volume (PRV). This technology is the product of years of development of computer models capable of forward modeling this technique. Once this modeling was completed, an initial field test was performed in west Texas (WTX), with a preliminary analysis of this work presented in a previous paper (Palisch et al. 2016). Since that paper, however, additional processing of the data has yielded a much-more-detailed image of the proppant location in this Bone Springs well. In addition, a subsequent field application has been performed in a major basin in the northeastern US. Multiple stages received detectable proppant of varying stage volumes, and the analysis has also shown a detailed image of the proppant location in that wellbore. Furthermore, the initial field test in WTX used only electric-field sensors, whereas this latest test used both electric- and magnetic-field receivers. The authors’ numerical simulations coupled with the field results indicate the percentage difference between prefracture and post-fracture results is two times higher using magnetic- vs. electric-field sensors. This paper will review the technology development and methods, will present the latest imaging from the initial WTX test, and will describe the latest learnings from the most-recent field test. This paper should be beneficial to all completions and development personnel who are interested in knowing where proppant is in their fractures. This technology has the potential to assist in understanding well drainage and spacing, stage and perforation-cluster spacing, vertical fracture coverage, and the effect of fracture-design changes.

This paper will present results from a modeling effort to derive best practices for the completion of hydraulically fractured horizontal Eagle Ford wells. The well, reservoir, completion/frac and production information used in this evaluation were provided by an operator from a five-county area in Texas. Hydraulically fractured horizontal completions pose significant modeling and evaluation challenges. This is primarily due to two issues: 1) lack of well-specific data about the reservoir/rock properties, and 2) improper assumptions used in the modeling process. As shown in this paper, a data-driven approach to modeling these completions provides a much needed pragmatic perspective, identifies high-impact parameters and provides direction about how to improve the effectiveness of these complex completions. Sensitivities performed on the predictive data model indicate that well-to-well variation in reservoir quality and geology has a dominant effect on Eagle Ford production. In addition, issues such as fracture spacing, frac volume, perforation distribution, proppant selection and wellbore length also affect well production and economics. A summary of completion and frac methodology for the Eagle Ford, in addition to a ranking of controllable (completion and frac design) and non-controllable (reservoir and geology) parameters that affect Eagle Ford production, will be included in this paper. The information contained in this paper will be useful to those interested in reservoir, completion and frac parameters that affect production from shales analogous to the Eagle Ford. Reservoir quality, completion and frac methodology effects on production results will be quantified in this paper.

Multi-stage hydraulic fracturing has been implemented in conjunction with horizontal drilling in order to make unconventional, low-permeability reservoirs economically viable. Earlier studies from the development of the Barnett Shale have suggested that high fluid volumes and low proppant concentrations were necessary to generate sufficient stimulated reservoir volume (SRV). However, other shale plays, including the Eagle Ford, have formation material with higher ductility and exist in an anisotropic stress environment that tend to generate planar fractures, where lower fluid volumes and higher proppant concentrations are more appropriate.One operator began exploring their Eagle Ford acreage by utilizing sliding sleeve systems in cemented casing, while trying to determine the best depth within the Eagle Ford sequence to target. Once the drilling target was decided upon, the operator transitioned to a plug-and-perf type of completion in cemented casing in order to improve formation contact and recovery. This provided an opportunity to evaluate different completion designs with enough variability in the data to evaluate fracture performance. This paper will explain the process used to evaluate drilling, completion, and production information in order to discover the parameters that have the highest influence on well productivity. Completion parameters were evaluated against production performance in a variety of ways, including bivariate, multivariate statistical analysis, and neural network modeling. One parameter that was discovered to have high impact was the amount of proppant used per effective cluster, and the data indicated that more proppant was required than what prior experiences in shale stimulations suggested. Changes to the completion and stimulation design were made based on this analysis, resulting in improved production results.

The combination of multistage hydraulic fracture treatments with horizontal drilling technology has been the primary driver to the successful development of resource plays. More than 85% of wells drilled in North America today employ these methods. However, while these technologies have been wildly successful, only recently has the industry begun to address in earnest, the efficiency of current practices. These completion and development optimization efforts require an understanding of which portions of the reservoir have not been adequately contacted/stimulated and are thereby failing to contribute to production, and ultimate hydrocarbon recovery. Understanding where the proppant is located, both near- and far-field, is the starting point for these evaluations, and is the basis for this paper. Traditional fracture mapping technologies provide indirect estimates of fluid distribution within the fracture network. However, there is little direct correlation between fluid distribution and proppant location, and since most unpropped portions of fractures rapidly collapse, identification of the proppant location better represents the region which contributes to ultimate recovery. Near-wellbore detection of proppant can provide insight into whether all perf clusters (in the case of plug and perf) have received proppant as well as the impacts of proppant overflush. Conversely, accurate determination of far-field proppant placement will affect everything from well and stage spacing, to stage design and refrac candidate selection, and allow significant optimization of diversion techniques. While knowledge of both near- and far-field proppant location is necessary for the industry to overcome the single-digit recovery factors that are now projected in many unconventional plays, far-field proppant detection techniques have been largely absent to date. This paper briefly reviews the current "state of the industry" regarding near-wellbore proppant detection technology. It then presents a novel far-field proppant detection technique which utilizes electro-magnetic differencing and a specialty detectable proppant. This includes a description of the technology as well as the methodology of the technique. In addition, the paper reviews the design and results from a recent (first-ever) field deployment of this technology in a horizontal Permian Basin well. Visualization of the proppant in the far-field is also shown. This paper should be beneficial to all engineers and technologists currently interested in evaluating completion efficiencies as well as fracture stimulation effectiveness. Understanding proppant location in both the near- and far-field regions has significant impact on well spacing, stage and perf cluster spacing, and ultimate recovery from stimulated horizontal wells.

Hydraulic fracturing stimulation in unconventional reservoirs has taken on a new emphasis in the search for oil and liquids from these low permeability reservoirs. Today, we are attempting to achieve economic production from reservoirs that were passed over just five years ago. The fracture stimulation goal: to provide a conductive path between the reservoir and the wellbore. However, these reservoirs are inherently difficult, at best, to evaluate and to fully understand the completion environment at a distance from the wellbore. Fortunately, there is a workflow that allows understanding of permeability sources as the fracture treatment is placed in real time and certainly in post-frac analysis. The toolbox uses a "planar" frac model to analyze data gathered from surface sources. This paper will discuss a workflow to differentiate between pressure trends due to fluid and/or proppant effects on friction, and actual net-pressure change due to permeability exposure by the frac fluid in the reservoir. By understanding that fracture stimulation is a highly invasive process, the authors will examine the data that can be used as a benchmarking tool for reservoir response. We will discuss examples from the Eagle Ford formation for naturally fractured permeability reservoirs and the Wolfberry trend for matrix-based reservoirs. The workflow will aid in fracture spacing in horizontal wells and well spacing in multi-layered vertical wells.