Technical Papers and Articles
The American Oil & Gas Reporter, November 2017
What if operators could map every development well’s completion to determine whether it is performing as expected or should be changed to match varying geology? According to Reveal Energy Services, that now is a technical and economic possibility with a pressure gauge on a monitor well. Using technology licensed from Statoil Technology Invest, the startup applies the recorded pressure response in the monitor well to calculate a fracture map of the newly created fractures in the treatment well.
Infill-Thinking.com, August 11, 217
They say necessity is the mother of invention, and no one in the oilfield understands necessity better than the operators themselves.
Today, tight oil is at the technological forefront of the oil and gas industry. Exploiting low permeability, heterogeneous rock at $50 oil makes invention and innovation a requisite not a luxury.
In fact, demand for subsurface technology progression has never been greater in the oil industry’s history than it is today. But how? Finding practical ideas that work to solve real-time shale problems at scale is not easy. Fostering the new tech is not easy. And optimizing the tech is not easy either.
In this update, we discuss the pros and cons of four primary innovation models available to today’s oil and gas producers. Focusing in on one model in particular (E&P tech carve-outs), we share the story of Reveal Energy Services as a case study of effective commercialization for new oilfield solutions.
Shale Technology Showcase, Hart’s E&P, July 2017
IMAGE Frac technology analyzes the recorded pressure data and determines the fracture attributes, including length, height, fracture growth rates and fracture asymmetry.
Technical paper: New Age Fracture Mapping Diagnostic Tools-A STACK Case Study
SPE Hydraulic Fracturing Technology Conference and Exhibition, 24–26 January, The Woodlands, Texas, USA
SPE Hydraulic Fracturing Technology Conference and Exhibition, 24–26 January, The Woodlands, Texas, USA Abstract The application of learnings from an underground laboratory has led to significant completion changes in a world-class North American unconventional asset. Understanding the stimulated fracture geometry in unconventional reservoirs allows for optimal development of the asset. In this paper, we will review a case study comparing both new and commonly accepted technologies to quantify stimulated fracture geometry. The technologies applied to improve the understanding of fracture geometry in this case study include fiber optic monitoring (Distributed Acoustic Sensing and Distributed Temperature Sensing), borehole microseismic, electromagnetic imaging, offset well pressure monitoring with IMAGE Frac technology, water hammer analysis, and fracture modeling. The validation tools used include a production interference test, Rate Transient Analysis (RTA), Oil Soluble Tracers (OST), and Fracture Fluid Identifiers (FFI). Fiber optic monitoring was used to assess cluster efficiency, fluid and sand distribution per cluster and diverter effectiveness. Hydraulic half-lengths, heights, and fracture azimuth were estimated using a borehole microseismic system consisting of three vertical arrays and two horizontal arrays. Electromagnetic imaging provided insight on hydraulic half-length for 12 stages. Offset pressure monitoring provided hydraulic and propped half-lengths, heights, and fracture azimuth. The fracture model was calibrated using a diagnostic fracture injection test and vertical logs from the section of interest. Results from the technologies suggest an increase in well density is required to maximize the project net present value. The offset well pressure data coupled with fiber optic monitoring led to optimization of diverter applications. A variety of completion variables were tested, including fluid design, proppant size, perforation designs and diverter types, results have been integrated into an improved completion design.
Unconventional Resources Technology Conference, August 1-3, 2016
San Antonio, Texas
Hydraulic fracturing has been instrumental in commercializing ultra-tight unconventional resources. Although hydraulic fracturing has been used for nearly half a century in more than a million wells, understanding and mapping hydraulic fracture growth remains a challenge for shales and ultra-tight reservoirs. A number of approaches have been taken to better understand and characterize hydraulic fractures in the subsurface, but a technology which can accurately map hydraulic fractures with minimal operational interference and negligible cost remains elusive. Microseismic based mapping is arguably the most ubiquitously deployed method, but this approach is costly and provides limited insight into characterizing hydraulic fractures. Alternative technologies for mapping hydraulic fractures are currently being explored, but many of these technologies provide only qualitative information or require expensive data acquisition tools. This paper discusses a novel hydraulic fracture and proppant mapping technology (IMAGE Frac), which is technically robust, easy to use, and low cost. The technology is founded upon basic poromechanic theory, utilizing measurements from surface pressure gauges during the stimulation process to determine the geometry, orientation, and spatial location of hydraulic fractures with higher precision than other traditional techniques, while providing insight into the proppant distribution. The data acquisition approach requires only minor deviations from traditional practices and can be implemented without impacting completions efficiency. This technology has been utilized successfully in over 30 wells in multiple plays including the Bakken and Eagle Ford and is targeted for deployment in several other plays in mid-2016. An overview of the technology is provided along with an in-depth discussion of the validation studies from both the field and simulations. Two case studies are provided, which show the potential of the technology to provide new insight and improve drilling and completions operations. The case studies illustrate specific examples of how this technology enables better selection of landing zones, proppant size, pumped volumes, well spacing, and overall completions strategy. A companion paper (Kampfer and Dawson, 2016) discusses the fundamentals of the technology and provides in-depth, simulation-based studies, which demonstrate the robustness of the technique.
US Rock Mechanics / Geomechanics Symposium
June 26-29, 2016
Joel Parshall, JPT Features Editor, Society of Petroleum Engineers
November 30, 2016