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- Volume 36, Issue 4, 2018
First Break - Volume 36, Issue 4, 2018
Volume 36, Issue 4, 2018
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A new concept — fluid substitution by integrating rock physics and machine learning
By Anders DrægeAbstractThis study presents a new and patented concept for fluid substitution that can be integrated with Machine Learning to provide robust and simple fluid substitution with approximately the same or better accuracy as Gassmann theory. The method is called ‘ROck physics Fluid Substitution’ (ROFS) and integrates machine learning and rock physics. ROFS allows for rapid and simple fluid substitution that in many cases give more physically consistent results than applied Gassmann theory. A stepwise workflow for the method is given. Comparison with Gassmann theory shows that the ROFS approach better predicts velocities in core plugs that are substituted from dry to brine filled. When applying the method on well logs, it is also demonstrated that for high porous rocks where the Gassmann assumptions are met, the methods give very similar results. But for intermediate-to-low porosity rocks, Gassmann theory seems to overpredict the fluid effect while the new model is more realistic. The method can be applied for both siliciclastic rocks and carbonates. By using a rock physics model for carbonates, the new method can account for the effect of microstructure variations such as pore shape variations and cracks when performing fluid substitution.
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Finite-difference modelling of microseismicity associated with a hydraulic-fracturing stimulation in a coalbed methane reservoir
Authors Germán Rodríguez-Pradilla and David W. EatonAbstractOwing to the large capacity for matrix storage, substantial volumes of methane gas are stored in coal beds in the form of adsorbed gas (Nuccio, 2000). According to Langmuir’s theory that relates the adsorbed gas volume to the reservoir pressure (Langmuir, 1918), a fast dewatering process is required to achieve rapid reduction of the reservoir pressure and thus to release the adsorbed methane gas (Anderson and Simpson, 2003). The effectiveness of this dewatering process depends on the coal permeability, which is mostly related to the aperture and spacing of its natural fractures (or cleats).
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What can we infer about a hydraulic fracture from microseismic? Towards a microseismic interpretation framework
By S.C. MaxwellAbstractMicroseismic monitoring has been established as the ‘go to’ technology for mapping hydraulic fractures. With the rapid expansion of massive hydraulic stimulation of horizontal wells, fracture diagnostics are critical for understanding the hydraulic fracture geometry. Indeed, microseismic observations have led to a paradigm shift towards complex fracture networks developing and injection interacts with pre-existing fractures (for example see Maxwell, 2014, and references therein). In this light, basic microseismic data often tends to be qualitatively interpreted in terms of estimating hydraulic fracture dimensions including an estimate of the stimulated reservoir volume (SRV).
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Real-time passive monitoring with a fibre-optic ocean bottom array
Authors Alex Goertz and Andreas WuestefeldAbstractTo achieve high recovery rates, modern-day production management can benefit from not only snapshot images of the state of the reservoir at regular time intervals, but also continuous monitoring of the dynamic processes induced by pressure changes and fluid movement during production. Production management using time-lapse 4D snapshots is reactive, i.e., adjustments addressing the sweep efficiency or reservoir integrity can only be instigated once the next snapshot image is available after acquisition, processing and interpretation, often years later. For a more proactive reservoir management, it is important to have dynamic reservoir information in real time between the seismic time-lapse snapshots. Such information is contained in microseismic monitoring data and in surface or borehole deformation measurements. If sensors are permanently installed, this information comes at a negligible additional cost, provided that the data can be transferred to shore in real-time and processed automatically.
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Real-time microseismic overburden surveillance at the Grane PRM field offshore Norway
Authors S. Bussat, M. Houbiers and Z. ZarifiAbstractReal-time microseismic detection at offshore hydrocarbon fields is on its way to becoming a standard monitoring tool. Recently, increased focus on injection and overburden surveillance for an improved health, safety and environment (HSE) and cost saving has led to this development. Several hydrocarbon fields are already equipped with permanent reservoir monitoring (PRM) systems with seismic sensors permanently installed at the seafloor (Caldwell et al., 2015), and similar installations are planned or under consideration for some other offshore fields. PRM systems are in principle designed for acquiring active time-lapse seismic data 1–2 times per years, and as such, they are not used during most of their lifetime. But apart from active seismic, PRM systems can also be used for recording passive seismic data. With appropriate processing and analysis methods, such as microseismic event detection, the continuous stream of passive data can be converted into useful real-time subsurface information. This results in improved HSE, and therefore a more valuable PRM system.
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Broadband, short-period or geophone nodes? Quality assessment of Passive Seismic signals acquired during the Maupasacq experiment
Authors K. Polychronopoulou, A. Lois, N. Martakis, S. Chevrot, M. Sylvander, J. Diaz, A. Villaseñor, S. Calassou, M. Collin, E. Masini, A. Bitri and L. StehlyAbstractPassive Seismic is a broad term, incorporating various techniques and methodologies, which all exploit some part of the seismic signal that naturally exists or occurs in the Earth’s subsurface. This signal may differ significantly in the form and/or the provenance (e.g. earthquakes, ambient seismic noise, etc.), as well as the frequency content and, subsequently, the part of the subspace on which it may carry useful information.
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Influence of geological setting on stress released by hydraulic fracture-induced earthquakes
Authors Gisela Viegas, Ted Urbancic and Hannah ChittendenAbstractRecent studies of injection-induced seismicity suggest that induced events have lower stress drops than tectonic earthquakes, suggesting stress drop can potentially be used as a discriminant parameter between natural and anthropogenic earthquakes. The main physical mechanisms responsible for low stress drop earthquakes, that is earthquakes that release less stress during failure than the average natural earthquake in a similar tectonic setting, are related to the increase in pore pressure and fault lubrication that result from the presence of fluids on the fault surface. Fluids reduce the effective normal stress applied on a fault allowing it to slip under lower stress conditions. Hough (2014) found that induced earthquakes have a factor of 2 to 10 lower stress drops relative to natural earthquakes, for 11 injection-induced moderate earthquakes in central and eastern United States based on their intensity reports. Sumy et al. (2016) also found a factor of 10 difference between the stress drops of natural and induced earthquakes when studying 87 Mw1.8 to Mw3.5 induced earthquakes in Oklahoma. A few other studies found opposing results. Huang et al. (2016) found the stress drops of 25 small earthquakes in central Arkansas to be comparable to Californian tectonic earthquake stress drops, and Viegas and Abercrombie (2011) also found the stress drops of a sequence of moderate earthquakes in Colorado to be comparable to the stress drops of Californian earthquakes. However, Viegas and Abercrombie (2011) noted that Central and North America intraplate earthquakes are expected to have higher stress drops than plate boundary California earthquakes (Viegas et al., 2010) making the comparison a false equivalency.
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Microseismic monitoring in unconventional reservoirs: are natural fractures hiding in plain sight?
More LessAbstractAs the shale revolution is adjusting to the realities of the new market and lower oil prices, the operators’ focus is shifting towards unconventional reservoirs and increasing hydrocarbon production efficiencies. The oil and gas operators’ demands are transforming our paradigm of reservoir characterization, forecasting, and monitoring. As such, heterogeneity of an unconventional reservoir is one of the main factors impacting well productivity. Well performance is driven by the size and efficiency of the interconnected fracture ‘plumbing system’ which is influenced by the presence of natural fractures and the process of multistage hydraulic fracturing. A complex, interconnected natural fracture network can significantly increase the size of the stimulated reservoir volume, provide additional surface area contact and enhance permeability. However, the interaction of the natural fracture networks and the completions-induced fractures is complex and can be affected by multiple factors, such as present-day maximum horizontal stress orientation, character of pre-existing natural fractures, presence of faults, lithology types that the horizontal well is being drilled through, as well as the well completions design itself.
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Characterization of thin bed reservoirs of Linch area, Cambay Basin using complex trace transform method to enhance temporal resolution of seismic data
Authors Vivek Kumar Singh, Kamal and P.K. ChaudhuriAbstractIn the last few decades, the interest in thin hydrocarbon reservoirs has grown progressively justifying the great effort spent on developing techniques for quantitative interpretation of thin bed seismic response. The detection and resolution of reflections from thin layers are major problems in reflection seismic. Many a times it is difficult to precisely estimate the vertical and lateral extensions of a significant portion of discovered hydrocarbon reservoirs due to the thin layer effect.
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Volumes & issues
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Volume 42 (2024)
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Volume 41 (2023)
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Volume 40 (2022)
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Volume 39 (2021)
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Volume 38 (2020)
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Volume 37 (2019)
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Volume 36 (2018)
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Volume 35 (2017)
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Volume 34 (2016)
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Volume 33 (2015)
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Volume 32 (2014)
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Volume 31 (2013)
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Volume 30 (2012)
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Volume 29 (2011)
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Volume 28 (2010)
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Volume 27 (2009)
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Volume 26 (2008)
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Volume 25 (2007)
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Volume 24 (2006)
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Volume 23 (2005)
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Volume 22 (2004)
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Volume 21 (2003)
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Volume 20 (2002)
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Volume 19 (2001)
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Volume 18 (2000)
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Volume 17 (1999)
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Volume 16 (1998)
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Volume 15 (1997)
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Volume 14 (1996)
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Volume 13 (1995)
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Volume 12 (1994)
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Volume 11 (1993)
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Volume 10 (1992)
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Volume 9 (1991)
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Volume 8 (1990)
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Volume 7 (1989)
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Volume 6 (1988)
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Volume 5 (1987)
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Volume 4 (1986)
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Volume 3 (1985)
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Volume 2 (1984)
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Volume 1 (1983)