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Editor's note: This is the first in a series of four reports with highlights from the Hydraulic Fracturing Test Site in the Permian Basin. A chance to see what hydraulic fracturing really looks like in the Permian Basin drew overflow crowds for the first reports of what was learned at the Hydraulic Fracturing Test Site 1. 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, natural and hydraulic fractures, and how it all interacts. In the more than 2 years since the samples were gathered, the sections of core have been meticulously analyzed by teams of experts.
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).
Objectives/Scope: The Hydraulic Fracturing Test Sites (HFTS) are large collaborative field-based R&D projects funded by the US Department of Energy through the National Energy Technology Laboratory (NETL) and the E&P industry, with support from academia. The projects' main objective is to improve the understating of the hydraulic fracturing process through utilization of advanced diagnostics and collection of through-fracture cores to provide undisputable evidence and attributes of the created hydraulic fractures.
Methods/Procedures/Process: The HFTS-I is a field-based hydraulic fracturing research experiment located in the West Texas Permian (Midland) basin. At the test site, about $30 million was used to perform hydraulic fracturing research, concentrated around eleven horizontal wells fractured with over 400 stages in the upper and middle Wolfcamp formations as well as two recompleted legacy wells. Comprehensive field data was collected, including advanced diagnostics such as time-lapse cross-well seismic and microseismic surveys to measure hydraulic fracture attributes. To supplement the fracture diagnostics, two slant core wells were drilled through the created hydraulic fractures and over 850 feet of core was recovered, capturing many hundred hydraulic fractures in their natural state. The research project also completed a huff-and-puff experiment using field gas as injectant, to determine the effectiveness of such treatments for fractured shale Enhanced Oil Recovery (EOR).
Building on learnings and unanswered questions from HFTS-1, a second hydraulic fracturing research experiment (HFTS-2) has been commissioned in West Texas Permian (Delaware) basin. At the HFTS-2 eight new producing wells and two existing (legacy) wells were used to perform hydraulic fracturing research. Multiple science wells were drilled to sample and characterize the subsurface, including the collection of 540 feet of vertical core and 950 feet of high-angle through fracture core. The project also installed permanent fiber optic cables in 3 wells to monitor near wellbore signals during fracturing and to collect cross-well strain measurements. Other advanced diagnostics included a five-array microseismic survey, time-lapse geochemistry sampling and analysis, proppant log in a child well, and others.
The Hydraulic Fracturing Test Site (HFTS) Program is a research and development (R&D) partnership sponsored by the U.S Department of Energy, National Energy Technology Laboratory (DOE-NETL) and major and independent operator and service companies, managed by the Gas Technology Institute (GTI) (Ciezobka, et al. 2018, Reeves, et al. 2020). The objectives of the HFTS program are to diagnose and understand the hydraulic fracturing process for field development optimization, minimize their environmental impacts by reducing the number of new wells required for effective resource recovery, and improve extraction economics to expand the economically viable resource at increasingly lower commodity prices.
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 nearby. The federally funded public/private partnership conducted numerous tests on wells operated by Northeast Natural Energy, the oil company partner on the project.
Pollock, Caleb (Pioneer Natural Resources) | Seiler, Christian (Midland Valley Exploration Ltd., Geoscience Australia) | Valcárcel, Manoel (Midland Valley Exploration Ltd.) | Macaulay, Euan (Midland Valley Exploration Ltd.)
Abstract Natural fractures influence the development of unconventional reservoirs in many ways. Production results indicate enhanced fluid rates associated with them. Microseismic and well interference during hydraulic stimulation suggest that they influence completions. Numerical models suggest that natural fractures may influence length and height dimensions of hydraulic fractures. Methods commonly used to quantify them can be costly, possibly risky or impractical. Here we present a method of fracture prediction using commonly available data in conjunction with commercial software. Two distinct fracture trends (NE-SW and NW-SE) are observed in the Wolfcamp and Spraberry unconventional reservoirs of the Midland Basin. A third, less prevalent E-W trending set, is observed in some intervals. These sets are consistent in orientation, spatially and stratigraphically, across the basin with mean trends varying by only a few degrees. Fracture intensity logs, calculated from a basin-wide set of horizontal image log interpretations, demonstrate an increasing intensity with proximity to faults in the middle Wolfcamp. In areas where multiple intervals are sampled, a similar relationship of fracture intensity to faults is observed in each. This suggests that the fractures are tectonic in origin and are coeval with faults or are the result of later fault reactivation. To predict fractures in under sampled areas and intervals of the basin, likely fracture formation mechanisms were evaluated in a study area with 3D seismic data (for horizon and fault surfaces) and image logs in multiple stratigraphic units. Mechanisms included: folding (curvature), geomechanical modeling and deformation related to fault reactivation under several potential stress regimes. Plausible paleo-stress regimes were determined by an inversion, varying differential stress orientations and magnitudes to maximize slip and dilation tendency of the observed fractures. Only fault reactivation models in a strike-slip regime (σ1 ~ 80°) predicted fracture orientations and mode consistent with observation. Proxy values for fracture intensity were also evaluated. Principal strains calculated for horizons in the fault reactivation model provide a means to predict fracture intensity. Comparisons of horizontal and vertical trends of maximum extensional strain (e0 to fracture intensity reveal similar trends. Strain intensity decreases exponentially away from faults and decreases with decreasing depth. This proxy relationship provides a promising means to estimate fracture orientations and intensity in areas where little image log data is available, whereas the more ubiquitous 3D seismic is available.