Hydraulic Fracturing Test Site Research Articles

Developing Upscaling Approach for Swarming Hydraulic Fractures Observed at Hydraulic Fracturing Test Site through Multiscale Simulations

Summary This work aims to address a challenge posed by recent observations of tightly spaced hydraulic fractures in core samples from the hydraulic fracturing test site (HFTS) in the Middle Wolfcamp Formation. Many fractures in retrieved cores have subfoot spacing, which is at odds with conventional models in which usually one hydraulic fracture is initiated per cluster. Models assuming a single fracture at each cluster, although a common practice, often predict excessive fracture propagation that is inconsistent with microseismic observation. Here, we aim to develop a numerical approach to effectively account for densely spaced hydraulic fractures in field-scale simulations. Because it is impractical to explicitly model all aforementioned fractures, we develop a new upscaling law that enables existing simulation tools to predict reservoir response to fracture swarms. The upscaling law is derived based on an energy equivalence argument and validated through multiscale simulations using a high-fidelity code, GEOS. The swarming fractures are first modeled with a spacing that is much smaller than the cluster spacing; these fractures are then approximated by an upscaled, single fracture based on the proposed upscaling law. The upscaled fracture is shown to successfully match the energy input rate and produce the total fracture aperture and average propagation length of the explicitly simulated swarm. Afterward, the upscaling approach is further implemented in 3D field-scale simulations and validated against the HFTS microseismic data of a horizontal well. Our results show that hydraulic fracture swarming can significantly affect fracture propagation behaviors compared with the propagation of single fractures as assumed by conventional modeling approaches. Under the considered situations, the conventional treatment yields fast propagation speed that far exceeds that indicated by the microseismic data. We also illustrate that this discrepancy can be reduced readily through the implementation of the upscaling law. Our results demonstrate the importance of accounting for the fracture swarming effect in field-scale simulations and the efficacy of this approach to enable realistic predictions of reservoir responses to fracture swarms, without the need to model tightly spaced fractures individually.

Geomechanical Template for Distributed Acoustic Sensing Strain Patterns during Hydraulic Fracturing

SummaryRecently more distributed acoustic sensing (DAS) data have been collected during hydraulic fracturing in shale. Low-frequency DAS signals show patterns that are intuitively consistent with the understanding of the strain field around hydraulic fractures. This study uses a fracture simulator combined with a finite element solver to further understand the various patterns of the strain field caused by hydraulic fracturing. The results can serve as a “type-curve” template for the further interpretation of cross-well strain field plots.Incorporating detailed pump schedule and fracturing fluid/proppant properties, we use a hydraulic fracture simulator to generate fracture geometries, which are then passed to a finite element solver as boundary conditions for elastic-static calculation of the strain field. Because the finite element calculated strain is a tensor, it needs to be projected along the monitoring well trajectory to be comparable with the DAS strain, which is uniaxial. Moreover, the calculated strain field is transformed into a time domain using constant fracture propagation velocity. Strain rate is further derived from the simulated strain field using differentiation along the fracture propagation direction.Scenarios including a single planar hydraulic fracture, a single fracture with a discrete fracture network (DFN), and multiple planar hydraulic fractures in both vertical and horizontal directions were studied. The scenarios can be differentiated in the strain patterns on the basis of the finite element simulation results. In general, there is a tensile heart-shaped zone in front of the propagating fracture tip shown along the horizontal strain direction on both strain and strain rate plots. On the sides, there are compressional zones parallel to the fracture. The strain field projects beyond the depth where the hydraulic fracture is present. Patterns from strain rate can be used to distinguish whether the fracture is intersecting the fiber. Along the vertical direction, the transition zone depicts the upper boundary of the fracture. A complex fracture network with DFN shows a much more complex pattern compared with a single planar fracture. Multiple planar fractures show polarity reversals in horizontal fiber because of interactions between fractures. Data from the Hydraulic Fracturing Test Site 2 (HFTS2) experiment were used to validate the simulated results.The application of the study is to provide a template to better interpret hydraulic fracture characteristics using low-frequency DAS strain-monitoring data. To our understanding, there are no comprehensive templates for engineers to understand the strain signals from cross-well fiber monitoring. The results of this study will guide engineers toward better optimization of well spacing and fracturing design to minimize well interference and improve efficiency.

Modeling of fiber-optic strain responses to hydraulic fracturing

We modeled cross-well strain/strain rate responses of fiber optic sensing, including distributed strain sensing (DSS) and low-frequency distributed acoustic sensing (DAS), to hydraulic stimulation. DSS and low-frequency DAS have been used to measure strain or the strain rate to characterize hydraulic fractures. However, the current application of DSS/DAS is limited to acquisition, processing, and qualitative interpretations. The lack of geomechanical models hinders the development of the technology toward quantitative interpretation and inversion. We have developed a strategy to use the displacement discontinuity method to model the strain field around kinematically propagating fractures. For a horizontal monitoring well, modeling results were able to explain the heart-shaped extending pattern before a fracture hit, the polarity flip due to fracture interaction during stimulation, and the V-shaped pattern when a fracture does not intersect with the monitoring well. For a vertical monitoring well, modeling shows the different characters of strain rate responses when a fracture is near and far away from a vertical monitoring well. We also investigated the effects of fractures with various geometries such as elliptic and layered fractures. We compared and verified the modeling with field data from the Hydraulic Fracturing Test Site 2, a research experiment performed in the Permian Basin. Our modeling work can be used to identify patterns in field observations. The results also help to improve acquisition design and lay the groundwork for quantitative interpretation and inversion.

Impact on Drained Rock Volume (DRV) of Storativity and Enhanced Permeability in Naturally Fractured Reservoirs: Upscaled Field Case from Hydraulic Fracturing Test Site (HFTS), Wolfcamp Formation, Midland Basin, West Texas

Hydraulic fracturing for economic production from unconventional reservoirs is subject to many subsurface uncertainties. One such uncertainty is the impact of natural fractures in the vicinity of hydraulic fractures in the reservoir on flow and thus the actual drained rock volume (DRV). We delineate three fundamental processes by which natural fractures can impact flow. Two of these mechanisms are due to the possibility of natural fracture networks to possess (i) enhanced permeability and (ii) enhanced storativity. A systematic approach was used to model the effects of these two mechanisms on flow patterns and drained regions in the reservoir. A third mechanism by which natural fractures may impact reservoir flow is by the reactivation of natural fractures that become extensions of the hydraulic fracture network. The DRV for all three mechanisms can be modeled in flow simulations based on Complex Analysis Methods (CAM), which offer infinite resolution down to a micro-fracture scale, and is thus complementary to numerical simulation methods. In addition to synthetic models, reservoir and natural fracture data from the Hydraulic Fracturing Test Site (Wolfcamp Formation, Midland Basin) were used to determine the real-world impact of natural fractures on drainage patterns in the reservoir. The spatial location and variability in the DRV was more influenced by the natural fracture enhanced permeability than enhanced storativity (related to enhanced porosity). A Carman–Kozeny correlation was used to relate porosity and permeability in the natural fractures. Our study introduces a groundbreaking upscaling procedure for flows with a high number of natural fractures, by combining object-based and flow-based upscaling methods. A key insight is that channeling of flow through natural fractures left undrained areas in the matrix between the fractures. The flow models presented in this study can be implemented to make quick and informed decisions regarding where any undrained volume occurs, which can then be targeted for refracturing. With the method outlined in our study, one can determine the impact and influence of natural fracture sets on the actual drained volume and where the drainage is focused. The DRV analysis of naturally fractured reservoirs will help to better determine the optimum hydraulic fracture design and well spacing to achieve the most efficient recovery rates.

US Fracturing Test Data Trickling Out With a Lot More Promised

A fracturing test site in West Virginia has quietly made a data trove available on the website of the Marcellus Shale Energy and Environment Lab (MSEEL). Meanwhile, completion experts and students are impatiently waiting for data owed by Hydraulic Fracturing Test Site I in the Permian Basin on wells drilled and completed back in 2015. At the 2018 Unconventional Resources Technology Conference (URTeC), an official with the partnership promised those results by the end of last year, and this year promised them by the end of 2019. The Marcellus website shares data on two highly instrumented gas well completions back in 2014 and 2015, plus two older wells and a monitoring well near-by. The federally funded public/private partnership conducted numerous tests on wells operated by Northeast Natural Energy, the oil company partner on the project. One of the most interesting tests tried to answer the question: can an engineered fracturing design, with stage lengths varied based on rock properties, outperform the commonly used geometric designs dividing the well into even-sized stages. The answer was yes. A paper at this year’s URTeC concluded that total production from “future wells could be 10-20% greater if one can exploit the technologic advantages gained for MSEEL in a more cost-effective fashion.” Those who argue against engineered designs say the value added by the engineered variations do not justify the added cost of executing a plan that varies from stage to stage. Engineers on both sides of that argument will want more testing, and the public/private partnership is now working on a six-well test site nearby. Data Shortage During URTeC, representatives of the Hydraulic Fracturing Test Site I offered seven presentations filling an afternoon session, but no papers were available with details. During the opening session, moderator Tom Blasingame, a professor at Texas A&M University, asked a US Department of Energy (DOE) official when the data would be publicly available. The $11 million in funding from the DOE included a standard requirement that the data be shared within 2 years. Shawn Bennett, DOE deputy secretary for oil and natural gas, pointed out that the industry partners that made significant contributions to these projects—in this case, $15 million including data and expertise—should be compensated with early use of the information before the industry sees it. Blasingame pointed out that college students and faculty lack real-world fracturing data to do research and teach students about shale. When asked about data sharing, Jordan Ciezobka, the general manager of the project, said data will be released later this year, but that there are many challenges associated with doing so. Those obstacles include finding a way to share pictures and CT scans of cores and dealing with massive volumes of data. There is also the problem of removing historical information contributed by Laredo Petroleum—the company that provided the test pad—and he said there were concerns about how to “handle the potential traffic; it could be a train•wreck.”

An Interpretation of Proppant Transport Within the Stimulated Rock Volume at the Hydraulic-Fracturing Test Site in the Permian Basin

Summary We collected more than 500 ft of through-fracture core in the Upper Wolfcamp (UWC) and Middle Wolfcamp (MWC) formations in the Permian Basin. As part of core characterization, we analyzed the core-sludge samples for the presence of proppant and natural-calcite particles. Apart from sample preparation and imaging, we designed and developed a novel image-processing work flow to detect and classify the particles. We used the observations from the identified particle distribution within the stimulated rock volume to understand proppant-transport behavior. We used relative distributions of smaller 100-mesh- and larger 40/70-mesh-proppant particles to interpret proppant placement in relation to perforation clusters. Finally, we used the relative distribution of particles to understand the interaction between natural and hydraulic fractures. We observe that stress variations and the degree of natural fracturing have a bearing on local proppant-screenout behavior. Smaller 100-mesh proppant seems to dominate at larger lateral offsets from the hydraulically fractured wells. We also observe indications of heel-side bias according to lateral proppant distribution. We share our work flow for particle detection and classification, which can serve as a template for proppant analysis in the future if significant through-fracture cores are collected in similar field experiments.

Using microseismic frequency-magnitude distributions from hydraulic fracturing as an incremental tool for fracture completion diagnostics

Microseismic measurements are becoming increasingly routine with many large, pad scale hydraulic fracturing programs particularly in the prolific unconventional shale basins of North America. Spatial and temporal frequency-magnitude distributions or ‘b-value’ measurements can provide useful information, which can help with hydraulic fracturing diagnostics as well as design. In this study, we discuss the significant differences in the seismicity distributions in the upper and middle Wolfcamp formations at the Hydraulic Fracturing Test Site located in the Midland Basin, a sub-basin of the Permian. We validate observed seismicity behavior in relation to other reservoir properties of interest, including 3D seismic derived attributes and petrophysical data. The in-situ stress state has a significant bearing on b-value and we validate this using various observations. Specifically, we observe an inverse correlation between b-value distribution and in-situ differential stress. We correlate observed microseismicity with available 3D seismic data. We see significant impact of in-situ discontinuities and rock brittleness on the microseismicity distributions. In particular, in areas with large identifiable discontinuities, which are ideally aligned for shear failure, we see lower b-value slopes when compared with areas, which lack significant discontinuities or where they are not ideally aligned. We also look at hydraulic fracturing treatment data, specifically, injection pressure, and tie it with variations in microseismicity during pumping. The analysis of microseismic b-value as shown in this study provides a template for future applications where microseismic surveys are available.

A Look Into What Fractures Really Look Like

Reports from the Hydraulic Fracturing Test Site offer a glimpse into what hydraulic fractures really look like. The featured attraction in the 13 technical papers presented over two mornings at the Unconventional Resources Technology Conference (URTeC) was 600 ft of rock fractured in late 2015 near wells in the upper and middle Wolfcamp. Those core samples spawned a mind-boggling array of observations about the rock, proppant, and natural and hydraulic fractures, and how they all interact. In the more than 2 years since the samples were gathered, the sections of core have been meticulously analyzed by teams of experts. More than 700 fractures were categorized based on whether each one was created by nature, hydraulic force, or the stress of drilling the slant well. And the majority of the 400 stages pumped were studied using tracers and/or monitored using advanced diagnostics. The density and distribution of the fractures were measured as the scientists worked to understand how natural and hydraulic fractures interact. The bits of sand, calcite, and drilling mud found in and around the rock were collected and sorted. Automated imaging and painstaking manual examinations were used to measure the size, shape, and translucence of each grain in order to identify and quantify the grains. The “incredible complexity” observed was “far beyond what current simulations can model and predict,” said Jordan Ciezobka, manager for research and development for the Gas Technology Institute (GTI), which managed the federal grant supporting test site 1 and is planning Hydraulic Fracturing Test Site 2 (URTeC 2937168). Ciezobka predicted that findings from the first Permian test site hosted by Laredo Petroleum in the Midland Basin would be studied for years to come. The public-private partnership is just beginning to deliver the delayed reports of what it learned from the $25-million research project. Federal funding for the project requires the partnership to ultimately disclose its results, with data releases beginning later this year. The lag time rewards companies that supported the project with a long first look. Cause and Effect? The completion engineers in the room those two mornings likely left wanting more. With one exception, the talks avoided mentions of the ultimate measure of what works—production. Instead, they challenged widely held mental images of fracturing. For one, fracture height is overrated. While microseismic testing indicated that fractures grew up about a 1,000 ft, the height of the propped fractures—the fractures most likely to produce oil and gas—was about 30 ft. Proppant distribution was sporadic. While there were thick fractures full of sand inside, a paper describing fracturing (URTeC 2902624) said that only three of them were found among hundreds of propped fractures. And all of those were found in the upper Wolfcamp. While the fractured lateral in the middle Wolfcamp was further from the slant well—135 ft vs. 90 ft from the nearest stage—the middle Wolfcamp core has a lot more proppant than the upper Wolf-camp core (URTeC 2902364).

Seismic and Geomagnetic Observations at the Hydraulic Fracturing Test Site near Yakedake Volcano, Central Japan

Seismic and Geomagnetic Observations at the Hydraulic Fracturing Test Site near Yakedake Volcano, Central Japan