Estimation of effective anisotropy simultaneously with locations of microseismic events

Geophysics ◽  
2011 ◽  
Vol 76 (6) ◽  
pp. WC143-WC155 ◽  
Author(s):  
Vladimir Grechka ◽  
Paritosh Singh ◽  
Indrajit Das
Keyword(s):  
Oil And Gas ◽  
Oil And Gas Industry ◽  
Time Lapse ◽  
Velocity Model ◽  
Convincing Evidence ◽  
Hydraulic Stimulation ◽  
Stimulated Reservoir Volume ◽  
Reservoir Volume ◽  
Industry Applications ◽  
Microseismic Events

Passive seismic tomography, in which the event locations and the velocity model are inferred simultaneously, is seldom used to process microseismic surveys acquired in the oil and gas industry. We discuss advantages of applying tomographic ideas to typical microseismic data recorded in a single, nearly vertical well to monitor hydraulic stimulation of a shale-gas reservoir. Microseismic events are conventionally located in the energy-industry applications using a velocity model derived from sonic logs and perforation shots. Instead of fixing the model, as is normally done, we alter it while locating the events. This added flexibility not only makes it possible to accurately predict traveltimes of the recorded P- and S-waves, but also provides a convincing evidence for anisotropy of the examined shale formation. While we find that velocity heterogeneity does not need to be introduced to explain the data acquired at each stage of hydraulic fracturing, the obtained models are suggestive of possible time-lapse changes in the anisotropy parameters that characterize the stimulated reservoir volume.

scholarly journals Development of Real-Time Time Gated Digital (TGD) OFDR Method and Its Performance Verification

Sensors ◽  
2021 ◽  
Vol 21 (14) ◽  
pp. 4865
Author(s):  
Kinzo Kishida ◽  
Artur Guzik ◽  
Ken’ichi Nishiguchi ◽  
Che-Hsien Li ◽  
Daiji Azuma ◽  
...  
Keyword(s):  
Real Time ◽  
Optical Fibers ◽  
High Speed ◽  
Oil And Gas ◽  
Scattered Light ◽  
Oil And Gas Industry ◽  
High Signal ◽  
Chirp Pulse ◽  
Sound Waves ◽  
Industry Applications

Distributed acoustic sensing (DAS) in optical fibers detect dynamic strains or sound waves by measuring the phase or amplitude changes of the scattered light. This contrasts with other distributed (and more conventional) methods, such as distributed temperature (DTS) or strain (DSS), which measure quasi-static physical quantities, such as intensity spectrum of the scattered light. DAS is attracting considerable attention as it complements the conventional distributed measurements. To implement DAS in commercial applications, it is necessary to ensure a sufficiently high signal-noise ratio (SNR) for scattered light detection, suppress its deterioration along the sensing fiber, achieve lower noise floor for weak signals and, moreover, perform high-speed processing within milliseconds (or sometimes even less). In this paper, we present a new, real-time DAS, realized by using the time gated digital-optical frequency domain reflectometry (TGD-OFDR) method, in which the chirp pulse is divided into overlapping bands and assembled after digital decoding. The developed prototype NBX-S4000 generates a chirp signal with a pulse duration of 2 μs and uses a frequency sweep of 100 MHz at a repeating frequency of up to 5 kHz. It allows one to detect sound waves at an 80 km fiber distance range with spatial resolution better than a theoretically calculated value of 2.8 m in real time. The developed prototype was tested in the field in various applications, from earthquake detection and submarine cable sensing to oil and gas industry applications. All obtained results confirmed effectiveness of the method and performance, surpassing, in conventional SM fiber, other commercially available interrogators.

Maximum Drag Reduction Asymptote of Polymeric Fluid Flow in Coiled Tubing

2008 ◽  
Vol 131 (1) ◽  
Author(s):  
Subhash N. Shah ◽  
Yunxu Zhou
Keyword(s):  
Drag Reduction ◽  
Oil And Gas ◽  
Guar Gum ◽  
Oil And Gas Industry ◽  
Flow Loop ◽  
Polymeric Fluids ◽  
Curvature Ratio ◽  
Coiled Tubing ◽  
Industry Applications ◽  
Maximum Drag Reduction

This study experimentally investigates the drag reduction characteristics of the most commonly used polymer fluids in coiled tubing applications. The flow loop employed consists of 12.7mm straight and coiled tubing sections. The curvature ratio (a∕R, where a and R are the radii of the tubing and the reel drum, respectively) investigated is from 0.01 to 0.076, which covers the typical curvature ratio range encountered in the oil and gas industry applications. Fluids tested include xanthan gum, guar gum, and hydroxypropyl guar at various polymer concentrations. It is found that the drag reduction in coiled tubing is significantly lower than that in straight tubing, probably due to the effect of secondary flow in curved geometry. The onset of drag reduction is also found to be delayed as the curvature ratio was increased. A correlation for the maximum drag reduction (MDR) asymptote in coiled tubing is developed. When the curvature ratio is set to zero, the new correlation reduces to the well-known Virk’s MDR asymptote for dilute polymer solutions in straight pipes. A new drag reduction envelope is proposed for the analysis of drag reduction behavior of polymeric fluids in coiled tubing. Application of the new drag reduction envelope is also discussed.

Results of the downhole microseismic monitoring at a pilot hydraulic fracturing site in Poland — Part 1: Event location and stimulation performance

2018 ◽  
Vol 6 (3) ◽  
pp. SH39-SH48 ◽  
Author(s):  
Wojciech Gajek ◽  
Jacek Trojanowski ◽  
Michał Malinowski ◽  
Marek Jarosiński ◽  
Marko Riedel
Keyword(s):  
Hydraulic Fracturing ◽  
Seismic Anisotropy ◽  
Transverse Isotropy ◽  
Velocity Model ◽  
Microseismic Monitoring ◽  
Baltic Basin ◽  
Hydraulic Stimulation ◽  
Lower Paleozoic ◽  
Event Location ◽  
Microseismic Events

A precise velocity model is necessary to obtain reliable locations of microseismic events, which provide information about the effectiveness of the hydraulic stimulation. Seismic anisotropy plays an important role in microseismic event location by imposing the dependency between wave velocities and its propagation direction. Building an anisotropic velocity model that accounts for that effect allows for more accurate location of microseismic events. We have used downhole microseismic records from a pilot hydraulic fracturing experiment in Lower-Paleozoic shale gas play in the Baltic Basin, Northern Poland, to obtain accurate microseismic events locations. We have developed a workflow for a vertical transverse isotropy velocity model construction when facing a challenging absence of horizontally polarized S-waves in perforation shot data, which carry information about Thomsen’s [Formula: see text] parameter and provide valuable constraints for locating microseismic events. We extract effective [Formula: see text], [Formula: see text] and [Formula: see text], [Formula: see text] for each layer from the P- and SV-wave arrivals of perforation shots, whereas the unresolved [Formula: see text] is retrieved afterward from the SH-SV-wave delay time of selected microseismic events. An inverted velocity model provides more reliable location of microseismic events, which then becomes an essential input for evaluating the hydraulic stimulation job effectiveness in the geomechanical context. We evaluate the influence of the preexisting fracture sets and obliquity between the borehole trajectory and principal horizontal stress direction on the hydraulic treatment performance. The fracturing fluid migrates to previously fractured zones, while the growth of the microseismic volume in consecutive stages is caused by increased penetration of the above-lying lithologic formations.

scholarly journals Multiphase Flow Effects in a Horizontal Oil and Gas Separator

Energies ◽  
2019 ◽  
Vol 12 (11) ◽  
pp. 2116 ◽  
Author(s):  
Michael Frank ◽  
Robin Kamenicky ◽  
Dimitris Drikakis ◽  
Lee Thomas ◽  
Hans Ledin ◽  
...  
Keyword(s):  
Oil And Gas ◽  
Petroleum Industry ◽  
Oil And Gas Industry ◽  
Fluid Mixture ◽  
Gas Industry ◽  
Liquid Phases ◽  
Industry Applications ◽  
Computational Fluid Dynamics Cfd ◽  
Gas Separator ◽  
Flow Effects

An oil and gas separator is a device used in the petroleum industry to separate a fluid mixture into its gaseous and liquid phases. A computational fluid dynamics (CFD) study aiming to identify key design features for optimising the performance of the device, is presented. A multiphase turbulent model is employed to simulate the flow through the separator and identify flow patterns that can impinge on or improve its performance. To verify our assumptions, we consider three different geometries. Recommendations for the design of more cost- and energy-effective separators, are provided. The results are also relevant to broader oil and gas industry applications, as well as applications involving stratified flows through channels.

A Case Study of Vertical Hydraulic Fracture Growth, Stress Variations with Depth and Shear Stimulation in the Niobrara Shale and Codell Sand, DJ Basin, Colorado

2021 ◽  
pp. 1-34
Author(s):  
Kevin L. McCormack ◽  
Mark D. Zoback ◽  
Wenhuan Kuang
Keyword(s):  
Principal Stress ◽  
Hydraulic Fracture ◽  
Oil And Gas ◽  
Velocity Model ◽  
Growth Stress ◽  
Hydraulic Fractures ◽  
Stress Profile ◽  
Microseismic Events ◽  
Stress Variations ◽  
Fracture Growth

We carried out a geomechanical study of three wells, one each in the Niobrara A, Niobrara C and Codell sandstone to investigate how the state of stress and stress variations with depth affect vertical hydraulic fracture growth and shear stimulation of pre-existing fractures. We demonstrate that the higher magnitudes of measured least principal stress values in the Niobrara A and C shales are the result of viscoplastic stress relaxation. Using a density log and a VTI velocity model developed to accurately locate the microseismic events, we theoretically calculated a continuous profile of the magnitude of the least principal stress with depth. This stress profile explains the apparent vertical hydraulic fracture growth as inferred from the well-constrained depths of associated microseismic events. Finally, we demonstrate that because of the upward propagation of hydraulic fractures from the Niobrara C to the Niobrara A, the latter formation experienced considerably more shear stimulation, which may contribute to the greater production of oil and gas from that formation.

scholarly journals Induced Seismicity and Detailed Fracture Mapping as Tools for Evaluating HDR Reservoir Volume

Energies ◽  
2021 ◽  
Vol 14 (9) ◽  
pp. 2593
Author(s):  
Elżbieta Węglińska ◽  
Andrzej Leśniak
Keyword(s):  
Induced Seismicity ◽  
Fracture Network ◽  
Flowing Fluid ◽  
Stimulated Reservoir Volume ◽  
Reservoir Volume ◽  
Cluster Evolution ◽  
Microseismic Events ◽  
Fracture Mapping ◽  
Mass Volume ◽  
Stimulation Of

The main goal of this paper was to estimate the heat exchange rock mass volume of a hot dry rock (HDR) geothermal reservoir based on microseismicity location. There are two types of recorded microseismicity: induced by flowing fluid (wet microseismicity) and induced by stress mechanisms (dry microseismicity). In this paper, an attempt was made to extract events associated with the injected fluid flow. The authors rejected dry microseismic events with no hydraulic connection with the stimulated fracture network so as to avoid overestimating the reservoir volume. The proposed algorithm, which includes the collapsing method, automatic cluster detection, and spatiotemporal cluster evolution from the injection well, was applied to the microseismic dataset recorded during stimulation of the Soultz-sous-Forets HDR field in September 1993. The stimulated reservoir volume obtained from wet seismicity using convex hulls is approximately five times smaller than the volume obtained from the primary cloud of located events.

Design of an Economical Polymer Flood Pilot Addressing Field Development Uncertainties in the Sabriyah Upper Burgan Reservoir of North Kuwait

2021 ◽  
Author(s):  
Mohammed T. Al-Murayri ◽  
Dawood Kamal ◽  
Najres Al-Mahmeed ◽  
Anfal Al Kharji ◽  
Hadeel Baroon ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Oil And Gas ◽  
Oil And Gas Industry ◽  
Polymer Flooding ◽  
Mobility Control ◽  
Field Development ◽  
Reservoir Volume ◽  
Polymer Flood ◽  
Incremental Oil Recovery ◽  
Commercial Size

Abstract The Sabriyah Upper Burgan is a major oil reservoir in North Kuwait with high oil saturation and is currently considered for mobility control via polymer flooding. Although there is high confidence in the selected technology, there are technological and geologic challenges that must be understood to transition towards phased commercial field development. Engineering and geologic screening suggested that chemical flood technologies were superior to either miscible gas or waterflood technologies. Of the chemical flood technologies, mobility control flooding was considered the best choice due to available water ion composition and total dissolved solids (TDS). Evaluation of operational and economic considerations were instrumental in recommending mobility control polymer flooding for pilot testing. Laboratory selected acceptable polymer for use with coreflood incremental oil recovery being up to 9% OOIP. Numerical simulation recommended two commercial size pilots, a 3-pattern and a 5-pattern of irregular five spots, with forecast incremental oil recovery factors of 5.6% OOIP over waterflood. Geologic uncertainty is the greatest challenge in the oil and gas industry, which is exacerbated with any EOR project. Screening of the Upper Burgan reservoirs indicates that UB4 channel sands are the best candidates for EOR technologies. Reservoir quality is excellent and there is sufficient reservoir volume in the northwest quadrant of the field to justify not only a pilot but also future expansion. There is a limited edge water drive of unknown strength that will need to be assessed. The channel facies sandstones have porosities of +25%, permeabilities in the Darcy range, and initial oil saturations of +90%. Pore volume (PV) of the two recommended pilot varies from 29 to 45 million barrels. A total of 0.7 PV of polymer is expected to be injected in 5.6 and 7.9 years for the 3-pattern pilot and the 5-pattern pilot, respectively, with a water drive flush to follow for an additional 5 to 7 years. Incremental cost per incremental barrel of oil of a mobility control polymer flood which includes OPEX and CAPEX costs is $20 (USD). This paper evaluates the (commercial size) pilot design and addresses field development uncertainties.

Erosion in choke valves—oil and gas industry applications

Wear ◽  
1995 ◽  
Vol 186-187 ◽  
pp. 401-412 ◽  
Author(s):  
L. Nøkleberg ◽  
T. Søntvedt
Keyword(s):  
Oil And Gas ◽  
Oil And Gas Industry ◽  
Gas Industry ◽  
Industry Applications

scholarly journals Synergizing Crosswell Seismic and Electromagnetic Techniques for Enhancing Reservoir Characterization

SPE Journal ◽  
2016 ◽  
Vol 21 (03) ◽  
pp. 909-927 ◽  
Author(s):  
Klemens Katterbauer ◽  
Ibrahim Hoteit ◽  
Shuyu Sun
Keyword(s):  
History Matching ◽  
Oil And Gas ◽  
Reservoir Characterization ◽  
Saline Water ◽  
Oil And Gas Industry ◽  
Time Lapse ◽  
Gas Industry ◽  
Matching Process ◽  
Weak Density ◽  
Reservoir History Matching

Summary Increasing complexity of hydrocarbon projects and the request for higher recovery rates have driven the oil-and-gas industry to look for a more-detailed understanding of the subsurface formation to optimize recovery of oil and profitability. Despite the significant successes of geophysical techniques in determining changes within the reservoir, the benefits from individually mapping the information are limited. Although seismic techniques have been the main approach for imaging the subsurface, the weak density contrast between water and oil has made electromagnetic (EM) technology an attractive complement to improve fluid distinction, especially for high-saline water. This crosswell technology assumes greater importance for obtaining higher-resolution images of the interwell regions to more accurately characterize the reservoir and track fluid-front developments. In this study, an ensemble-Kalman-based history-matching framework is proposed for directly incorporating crosswell time-lapse seismic and EM data into the history-matching process. The direct incorporation of the time-lapse seismic and EM data into the history-matching process exploits the complementarity of these data to enhance subsurface characterization, to incorporate interwell information, and to avoid biases that may be incurred from separate inversions of the geophysical data for attributes. An extensive analysis with 2D and realistic 3D reservoirs illustrates the robustness and enhanced forecastability of critical reservoir variables. The 2D reservoir provides a better understanding of the connection between fluid discrimination and enhanced history matches, and the 3D reservoir demonstrates its applicability to a realistic reservoir. History-matching enhancements (in terms of reduction in the history-matching error) when incorporating both seismic and EM data averaged approximately 50% for the 2D case, and approximately 30% for the 3D case, and permeability estimates were approximately 25% better compared with a standard history matching with only production data.

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