Fiber optic technology has been used in several wells at an oilfield to measure strain to monitor overburden deformation. The application of this technology involved a series of bench tests and field tests to gather some key learnings to enhance well design, well construction, and fiber optic operation. Prior to installation of the fiber optic, a series of bench tests were conducted to evaluate the coupling of fiber with the capillary lines to determine its impact on the measurement of strain. The testing demonstrated that anchoring the fiber at the top and bottom of the capillary line was sufficient to hold the fiber in place and enabled the effective measurement of strain along the length of the well, which was proven when applied to field conditions. To enhance well design for strain measurement, several wells had fiber optic capillary lines installed on the inside and outside of casing to investigate the potential dampening effect due to fiber being located inside a string of casing. This was used to determine the optimal casing string to install fiber optic to measure strain in the overburden. Additionally, a novel concept was utilized in the well design that involved using the fiber optic capillary clamps as borehole centralizers, which resulted in equipment and rig cost savings. The details of the bench tests, well design, operational experience, and their associated lessons learned are presented.
Binder, Gary (Colorado School of Mines) | Titov, Aleksei (Colorado School of Mines) | Tamayo, Diana (Colorado School of Mines) | Simmons, James (Colorado School of Mines) | Tura, Ali (Colorado School of Mines) | Byerley, Grant (Apache Corporation) | Monk, David (Apache Corporation)
In 2017, distributed acoustic sensing (DAS) technology was deployed in a horizontal well to conduct a time-lapse vertical seismic profiling (VSP) survey before and after each of 78 hydraulic fracturing stages. The goal of the survey was to more continuously monitor the evolution of stimulated rock throughout the treatment of the well. From two vibroseis source locations at the surface, time shifts of P-waves were observed along the well that decayed almost completely by the end of the treatment. A shadowing effect in the time shifts was observed that enables the height of the stimulated rock volume to be estimated. Using full wavefield modeling, the distribution of time shifts is well described by an equivalent medium model of vertical fractures that close as pressure declines due to fluid leak-off. Converted P to S waves were also observed to scatter off stimulated rock near some stages as confirmed with full wavefield modeling. The signal-to-noise ratio is a limitation of the current dataset, but recent improvements in DAS technology can enable stage-by-stage monitoring of the stimulated rock height, fracture compliance, and decay time as a well is completed.
Distributed Acoustic Sensing (DAS) has opened new possibilities for seismic monitoring of unconventional reservoirs. Using a laser interrogator to launch light pulses down a fiber optic cable, dynamic strain changes can be sampled along the cable from the phase shift of light backscattered to the interrogator (Hartog, 2017). Since the fiber optic cable can be permanently cemented outside the casing in a borehole, highly repeatable vertical seismic profiling (VSP) surveys can be acquired frequently without costly wireline geophone deployments that interfere with well treatment activities (Mateeva et al., 2017; Meek et al., 2017).
As described by Byerley et al., 2018, a unique interstage DAS VSP survey was conducted in 2017 during the stimulation of a horizontal well targeting the Wolfcamp formation in the Midland Basin, Texas. Using two vibroseis source locations offset about 1 mile from the heel and toe of the well, DAS data was acquired in the treatment well before and after each of 78 hydraulic fracturing stages. At the expense of fewer source locations, this type of acquisition allows the evolution of the stimulated rock volume (SRV) to be monitored on a stage-by-stage basis as the well is treated.
Carr, Timothy (West Virginia University) | Ghahfarokhi, Payam (West Virginia University) | Carney, BJ (Northeast Natural Energy, LLC) | Hewitt, Jay (West Virginia University) | Vargnetti, Robert (USDOE National Energy Technology Laboratory)
The Marcellus Shale Energy and Environment Laboratory (MSEEL) involves a multidisciplinary and multi-institutional team of universities companies and government research labs undertaking geologic and geomechanical evaluation, integrated completion and production monitoring, and testing completion approaches. MSEEL consists of two legacy horizontal production wells, two new logged and instrumented horizontal production wells, a cored vertical pilot bore-hole, a microseismic observation well, and surface geophysical and environmental monitoring stations. The extremely large and diverse (multiple terabyte) datasets required a custom software system for analysis and display of fiber-optic distributed acoustic sensing (DAS) and distributed temperature sensing (DTS) data that was subsequently integrated with microseismic data, core data and logs from the pilot holes and laterals. Comprehensive geomechanical and image log data integrated with the fiber-optic data across individual stages and clusters contributed to an improved understanding of the effect of stage spacing and cluster density practices across the heterogeneous unconventional reservoirs such as the Marcellus. The results significantly improved stimulation effectiveness and optimized recovery efficiency. The microseismic and fiber-optic data obtained during the hydraulic fracture simulations and subsequent DTS data acquired during production served as constraining parameters to evaluate stage and cluster efficiency on the MIP-3H and MIP-5H wells. Deformation effects related to preexisting fractures and small faults are a significant component to improve understanding of completion quality differences between stages and clusters. The distribution of this deformation and cross-flow between stages as shown by the DAS and DTS fiber-optic data during stimulation demonstrates the differences in completion efficiency among stages. The initial and evolving production efficiency over the last several years of various stages is illustrated through ongoing processing of continuous DTS. Reservoir simulation and history matching the well production data confirmed the subsurface production response to the hydraulic fractures. Engineered stages that incorporate the distribution of fracture swarms and geomechanical properties had better completion and more importantly production efficiencies. We are working to improve the modeling to understand movement within individual fracture swarms and history match at the individual stage. As part of an additional MSEEL well pad underway incorporates advanced and cost-effective technology that can provide the necessary data to improve engineering of stage and cluster design, pumping treatments and optimum spacing between laterals, and imaging of the stimulated reservoir volume in the Marcellus and other shale reservoirs.
Distributed acoustic sensing (DAS) is a rapidly evolving fiber optic technology for monitoring cement curing, perforation performance, stimulation efficiency, and production flow and, more recently, for performing vertical seismic profiling (VSP). VSP data can be acquired and processed to determine velocity models that are used in surface seismic imaging for reservoir characterization, or for microseismic monitoring of hydraulic fracturing operations. The limitation of conventional VSP data acquisition has been well accessibility, with wireline-conveyed tools deployed during openhole or casedhole logging campaigns before well completion or during workovers. Fiber optic cable conveyance by coiled tubing (CT) expands the opportunity for VSP data acquisition during planned CT interventions. This paper presents an example of a CT DAS VSP acquisition. The processing steps are shown to overcome some of the noise challenges inherent in CT DAS data, such as persistently strong borehole tube waves induced from the surface operations activities. A case study is shown for the depth tie between surface seismic data and the CT DAS VSP derived corridor stack image, demonstrating the viability of CT deployed fiber to acquire DAS VSP data.
Wang, Herbert (University of Wisconsin-Madison) | Fratta, Dante (University of Wisconsin-Madison) | Lord, Neal (University of Wisconsin-Madison) | Zeng, Xiangfang (Institute of Geodesy and Geophysics, Chinese Academy of Sciences) | Coleman, Thomas (Silixa LLC)
Each of the Wisconsin field trials used active sources that ranged from a hammer source to fixed and truck-mounted 40-270 kN swept-frequency sources. Two of the field trials were near highways where traffic was a source of ambient noise. Geophones were colocated near the DAS cable to benchmark and complement the DAS response. The goals of the studies were to understand the ground motions recorded by DAS and to prototype DAS applications using active sources, ambient or traffic noise, and earthquakes. Introduction Distributed Acoustic Sensing (DAS) technology can image the subsurface using dense arrays whose spatial resolution is on the order of ten meters and whose dimensions can be tens of kilometers given the relatively low cost of fiberoptic cable and currently available interrogator and processing technology (Parker et al., 2014). The flexibility of fiberoptic cable allows for many possible geometric configurations.
Summary Recent field experiments have demonstrated that distributed acoustic sensing (DAS) can be used to record strain in fiber optic cable at mHz frequencies. However, the effect of fiber optic cable construction on strain transfer has not been evaluated. The laboratory experiments presented here were designed to mimic fiber optic cable cemented into a borehole that intersects bedrock fractures. Hydraulic stress on the fracture is expected to stretch the cemented borehole which can be sensed by DAS. In the laboratory, we cemented five different fiber optic cable constructions into a pipe and then strained the pipe periodically using stepper motors.
ABSTRACT: Polarized shear wave travel times and spectral changes are used to determine natural fracture intensity and orientation. The study develops this concept for fracture density mapping associated with laboratory hydraulic fracturing experiments in pyrophyllite, a fine grained monomineralic metamorphic rock comprised of the mineral pyrophyllite, and hence an analogy for natural shale. A 6” long horizontal cylindrical pyrophyllite sample (wellbore parallel to bedding plane) is hydraulically fractured using water under uniaxial conditions with an effective maximum stress of 830 psi applied perpendicular to the bedding plane (breakdown pressure – 1914 psi). The pyrophyllite sample exhibits a P-wave anisotropy of 18% and displays transverse anisotropy. Acoustic emissions (AE) were recorded using sixteen 1-MHz piezoelectric P-wave transducers; the spatial acoustic emission density was mapped. Berryman’s strong anisotropy model was used to build an anisotropic velocity model for AE event locations. Post-fracturing shear wave velocity measurements were conducted using an array of seven pairs of polarized shear wave transducers which were systematically stepped across the end faces of the cylinder producing 931 discrete shear wave velocity measurements for every polarization. These arrays are used to record shear wave travel time with polarizations parallel and perpendicular to the direction of maximum stress before and after hydraulically fracturing the sample. Fourier analysis of the post-failure recorded shear waveforms mapped attenuation associated with the SRV which was consistent with the shear wave velocity analysis. The geometry of experiment reflects hydraulic stimulation in a horizontal wellbore condition. Orthogonally polarized shear velocities show measurable differences which reflect a preferred fracture orientation, with more than 32% post fracture reduction in shear velocity, in the fractured plane. The polarized shear wave map is consistent with the AE event locations recorded during the fracturing process. Secondary microfractures appear normal to the primary fractures in the horizontal plane.
Hydraulic fracturing in combination with horizontal drilling has made the extraction of hydrocarbon from certain geologic formations economically feasible, thereby boosting the available energy resources in US. It has induced an oil and gas “boom” in various parts of the country.
There are arguments that state that the physical laws governing fractures are known and fracture models are accurate, but the emergence of ‘new mechanisms’ every few years suggests that the basic physics incorporated into models has not been as comprehensive as required to model a fracture fully (Warpinsky, 1996).
It has become critical to understand the location of fracture and the extent to which it stimulates a reservoir to plan future drilling and completions. Thus, mapping hydraulic fracture is essential. There have been various methods that have been used to map the fracture propagation. Commonly used method in the field is to record the microseismic events generated because of release of elastic energy during the fracturing process, as established by Albright and Pearson, 1982, Rutledge and Phillips, 2003 and Warpinski et al., 2004. Acoustic emission (AE) techniques had been utilized in mapping hydraulic fractures and assessing fracture mechanisms in laboratory studies as well (Matsunaga et al., 1993, Masuda et al., 2003, Damani et al., 2012). Other methods include using temperature sensors to monitor the fracture propagation in real time (Holley et al., 2010). Third common method is to use Scanning Electron Microscope (SEM) to map the stimulated reservoir volume of the fracture generated by taking out a chip out of the fractured sample for analysis (Damani et al., 2012).
Ghahfarokhi, Payam Kavousi (West Virginia University) | Carr, Timothy (West Virginia University) | Song, Liaosha (West Virginia University) | Shukla, Priyavrat (Schlumberger) | Pankaj, Piyush (Schlumberger)
Recently, oil and gas companies started to invest in fiber optic technology to remotely monitor subsurface response to stimulation. Distributed Acoustic Sensing (DAS) and Distributed Temperature Sensing (DTS) record vibration and temperature around the fiber, respectively. In this research, we introduce new seismic attributes calculated from the DAS data that could suggest cross-stage fluid communication during hydraulic fracturing. The DAS data covers the entire 28 stimulated stages of the lateral MIP-3H well close to Morgantown, WV. We calculated the energy attribute for the DAS data of the studied stages. Subsequently, a Hilbert transform is applied to the DAS data to evaluate the instantaneous frequency of each trace in the DAS. In addition, we applied a fast Fourier transform to each trace for all the SEGY files to calculate the dominant frequency with a 30 second temporal window. The dominant frequency is compared to the DTS data and energy attribute for the stages in the horizontal MIP-3H well. The DTS analysis shows that stimulation of the stages 10 causes a temperature rise in the previous stage 9; in contrast, stage 18 stimulation does not affect stage 17 temperature. We suggest that the common low frequency zone identified in instantaneous frequency and dominant frequency attributes between stages 10 and 9 is related to presence of fluid and gas that transferred cross-stage during hydraulic fracturing. The fluid and results in the frequency damping of the vibrations around the fiber. We show that the frequency attribute reveals increases detail about the stimulation than conventional signal energy attribute of the DAS data.
Ajo-Franklin, Jonathan (Lawrence Berkeley National Laboratory) | Dou, Shan (Lawrence Berkeley National Laboratory) | Daley, Thomas (Lawrence Berkeley National Laboratory) | Freifeld, Barry (Lawrence Berkeley National Laboratory) | Robertson, Michelle (Lawrence Berkeley National Laboratory) | Ulrich, Craig (Lawrence Berkeley National Laboratory) | Wood, Todd (Lawrence Berkeley National Laboratory) | Eckblaw, Ian (Lawrence Berkeley National Laboratory) | Lindsey, Nathan (Lawrence Berkley National Laboratory and University of California–Berkeley) | Martin, Eileen (Stanford University) | Wagner, Anna (Cold Regions Research and Engineering Laboratory)
We present preliminary results from an intermediate scale field experiment exploring the seismic response of dynamic permafrost thaw generated by active heating. The focus of our project was to evaluate the utility of surface wave monitoring to detect precursors to thaw-induced subsidence, a common geotechnical hazard in polar regions. In this study, we present results from timelapse surface wave measurements conducted over the duration of the thaw experiment. The unique aspect of the experiment was the combination of a semi-permanent surface orbital vibrator (SOV) source and distributed acoustic sensing to measure variations in surface wave propagation. The SOV, energized for 22 sweeps every night, was deployed for approximately 2 months, collecting 60 daily surveys. Large temporal variations in surface wave velocity, as well as spectral characteristics were observed. After examination of precipitation and soil moisture data, such changes were convincingly linked to rainfall events. A cross-equalization approach was developed to assist in removing this effect; after processing, a decreasing trend in shear wave velocity appears to remain, potentially a seismic signature of the controlled permafrost thaw process.
Presentation Date: Monday, September 25, 2017
Start Time: 4:20 PM
Presentation Type: ORAL
Kavousi, Payam (West Virginia University) | Carr, Timothy (West Virginia University) | Wilson, Thomas (West Virginia University) | Amini, Shohreh (West Virginia University) | Wilson, Collin (Schlumberger) | Thomas, Mandy (Schlumberger) | MacPhail, Keith (Schlumberger) | Crandall, Dustin (National Energy Technology Laboratory, US Department of Energy) | Carney, BJ (Northeast Natural Energy LLC) | Costello, Ian (Northeast Natural Energy LLC) | Hewitt, Jay (Northeast Natural Energy LLC)
Distributed acoustic sensing (DAS) technology also known as distributed vibration sensing (DVS) uses optical fibers to measure the dynamic strain at all points along the fiber (Parker et al, 2014). The DAS senses the vibration in the local environment around the fiber and provides a measure of the relative strain of the optical fiber. This remote sensing technique has provided unparalleled acoustic sampling from the subsurface during hydraulic fracturing of the horizontal MIP-3H well drilled in Marcellus Shale near Morgantown, WV. We will show that the energy of the extracted phase of DAS data (hDVS) has a strong negative correlation with natural fracture intensity P32. The hydrofracking stages with lower P32 show a higher DAS phase energy and vice versa. In addition, we will evaluate the correlation between DAS phase energy, microseismic energy, and injection energy during the hydrofracking in MIP-3H. DAS phase energy is linearly correlated with injection energy. The calculated microseismic energies, which are less than 0.1% of the injection energies, do not show a significant correlation with either DAS phase energy or injection energy. The negative correlation between P32 and either DAS phase energy or injection energy suggests less vibration in zones that are more naturally fractured. Numerous observed fractures from wireline image logs are resistive (healed), and appear to significantly control the hydrofracking efficiency in MIP-3H.
Presentation Date: Tuesday, September 26, 2017
Start Time: 10:35 AM
Presentation Type: ORAL