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- Volume 34, Issue 6, 2016
First Break - Volume 34, Issue 6, 2016
Volume 34, Issue 6, 2016
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Monitoring hydraulic fracturing complexity and containment with time-lapse, multi-component and microseismic data, Pouce Coupe, Alberta
Authors Tom Davis and Dave D'AmicoFracture complexity occurs when the hydraulic fracturing process causes multiple sets of natural fractures to open in a reservoir. Keeping these sets open is another problem as they must be propped to stay open and communicate with the well bore. Fracture complexity can be monitored and it could have a significant effect on well orientations and completions. Stresses and natural fractures can create conditions favourable for generating multiple fracture sets. Generally, if we can tell where the natural fractures are prior to the drilling and completions, we can take advantage of the natural fractures to increase effective permeability and create greater conductivity to the well bore. Monitoring to see if the fractures are propped and remain conductive over time can be accomplished with shear wave splitting and birefringence. Hydraulic fracture containment during the hydraulic fracturing process is especially relevant to optimizing the effectiveness of hydraulic fracture treatments. Many reservoirs have issues related to height growth and containment within the zone. Monitoring containment is important for purposes of increasing the recovery factor in shale reservoirs. Monitoring technologies can be used to assess containment issues associated with reservoirs affected by fault and natural fracture systems.
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Exploration leads in a proven petroleum system - Offshore Northern Perth Basin
Authors Gareth O'Neill, Karyna Rodriguez and David EastwellThe Offshore Northern Perth Basin is a north to northwest trending basin located on the West Australian margin. Formed during the separation of Australia and Greater India in the Permian to Early Cretaceous, it includes a series of NW - SE trending sub-basins and structural highs (Figure 1). Exploration success in the basin has been sparse to date with the exceptions of the Cliff Head Field, three non-commercial discoveries and numerous hydrocarbon shows (Figure 2). Despite limited success, evidence from exploration to date provides invaluable information of a working petroleum system and the key risks to be addressed. In 2015 Spectrum acquired the modern long offset ‘Rocket’ 2D seismic survey, covering the majority of the Houtman sub-basin and extending northwards into the South Carnarvon Basin, providing further seismic coverage within licensed blocks and open acreage (Figure 1). Improved seismic imaging obtained from this dataset is expected to form an integral part in reviving interest in this basin and in helping operators to exploit this underexplored portion of the Australian margin. Integrating new modern seismic data with information provided by key wells within both the Abrolhos sub-basin and the South Carnarvon basin, points to the presence of an extensive, viable, petroleum system within the province.
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Lack of temporal correlation between seismicity and injection in Arkansas, US
Authors Ivo Oprsal and Leo EisnerDifferentiating between the induced (or triggered) and natural seismicity is an important part of understanding the effect of man-made processes. Should we call any seismicity in the vicinity of oil or gas fields induced (or triggered), we would never understand how to mitigate associated risks because we would mix unrelated processes. Temporal correlation is one of the most objective criteria to differentiate the two groups of seismicity we use. Seismic activity induced without proper objective evaluation leads to emotional discussions further reducing our ability to understand and mitigate hazards. Therefore we developed a technique based on temporal cross-correlation (Oprsal and Eisner, 2014) and carefully benchmarked the methodology on well-known cases of induced seismicity. This study shows a proper application of temporal cross-correlation to earthquakes which occurred in Central Arkansas in 2011-2012. The results show a lack of temporal correlation between injection rate and seismicity rates, implying that seismicity may not be triggered by injection at depth (Horton, 2012).
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Quantitative estimation of permeability enhancement, production and depletion from microseismic data
Authors Sudhendu Kashikar and Hasan ShojaeiIt is a known fact that cost efficiency is the number one priority across the industry, perhaps even more so in today’s price environment. Operators are seeking technologies to improve profitability for unconventional field development. Getting a reliable estimate of production within days of completing an unconventional well is every operator’s dream. Armed with this knowledge operators would be able to evaluate the effectiveness of treatment and well spacing strategies without having to wait for months of actual production, allowing for them to arrive at an optimum development plan in a more timely fashion. In this article we demonstrate that microseismic monitoring, taken as an insitu, real time field observation of the completion of a well that integrates all the effects of rock properties, tectonic stresses and treatment parameters enables an estimate of well productivity within reasonable limits. In this method, microseismic data is used to describe a deterministic discrete fracture network model, differentiating between propped and un-propped fractures and further defining a fracture intensity in a given rock volume. This fracture intensity is translated into a measure of permeability enhancement, both magnitude and distribution, achieved through the process of hydraulic fracturing. Through reservoir simulation using this more complete model it is possible to estimate each well’s current and future productivity and the reservoir pressure depletion as a function of time. Current practices rely on unrealistic planar fracture models leading to to inaccurate predictions of unconventional wells’ production and drainage patterns. The approach presented here explicitly honours the microseismic measurements and provides a realistic representation of the induced fracture geometry and thus improved production and drainage estimates. These early production predictions are available within a few days after a well’s treatment, eliminating the typical 6-to-12-month waiting time for production results. The ability to create a model that is consistent with actual production, as shown in the case histories presented here, suggests that uncertainty is sufficiently constrained through the workflow outlined in this article.
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Time-lapse seismic monitoring of hydraulic fracture stimulations within the Niobrara-Codell Reservoir Wattenberg Field, Colorado
Authors Matthew White and Tom DavisTime-lapse seismic interpretation is demonstrated as a viable method for observing physical modification of a tight reservoir resulting from the hydraulic fracturing process. Compressional seismic data sets were acquired before and after completions of 11 horizontal wells within a section (one-square mile) of Wattenberg Field, Colorado. The time-lapse seismic data sets, after crossequalization, showed an acoustic impedance anomaly within the reservoir interval consistent with pressurization of the reservoir from surface operations. The spatial location of the anomaly is interpreted such that pressure compartmentalization exists due to faulting within the reservoir. A decrease in the acoustic P-impedance of up to 7% was observed from the baseline to the monitor survey in the reservoir interval. An increase in pore pressure owing to hydraulic fracturing was interpreted as the physical mechanism causing the greatest change in P-impedance. Hydraulic fracturing is highly dependent on local geology, and the integration of geoscience with parameter design is necessary for optimization. Time-lapse seismic reservoir monitoring can assist in documenting fault-related reservoir compartmentalization. The Colorado School of Mines Reservoir Characterization Project (RCP) undertook a monitoring project with Anadarko Petroleum Corporation (APC) in Wattenberg Field, Colorado. The Wishbone section is a one-square mile area containing 11 horizontal wells. Each well was fractured with multiple stages and completion design was varied from stage-to-stage. The completions parameters that varied were: well spacing, targeted formation, hydraulic fracturing volumes, pressure, rates, completion type, and number of stages.
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Modelling of a deepwater Brazilian field to assess fault reactivation and the insitu stresses during production
Authors William Ferguson, Adam Bere, Carlos Rodriguez, Liciana Félix, Marcelo Marsili and Luana MedeirosFault reactivation and stress distribution are considered during a 30-year production period on a deep-water oil field using a 3D finite element geomechanical numerical simulation. Field geometry is constructed as a geomechanical model with the simulation carried out in terms of total stress; the model incorporated a network of 54 pre-existing faults which permits actual slip to occur. The principal objective is to determine whether the existing faults would propagate through to the seabed during production. The pre-production phase aims to capture material and stress states of the field accounting for salt creep and stress realignment due to the presence of the predefined faults. Preproduction stresses show good agreement with minifrac experimental results; the 3D simulation overestimates the minimum horizontal stress by 1.7-3.7%. The production stage shows that vertical compaction of the reservoir is the major influence on fault slip; the rate and magnitude of the fault slip is directly related to the rate and magnitude of depletion. The maximum fault slip is 0.82 m with normal faulting occurring beneath and thrust faulting occurring above the reservoir. Fault slip is not significant close to the seabed and the pre-existing faults are not anticipated to propagate to the seabed.
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Land seismic acquisition testing strategies and results – Southern Chad, Africa 2013-2015
Authors Cameron Crook, Andrea Crook, Chaminda Sandanayake and Paul StephensonIn order to improve imaging in areas with surface laterites/near surface scatters, over the past four years, 23 seismic acquisition tests were incorporated into the regular Glencore seismic acquisition programmes in Chad. Seismic acquisition testing provided tremendous benefit by improving subsurface imaging, increasing operational efficiency and reducing costs. These tests included eight vibroseis parameter tests, four maximum offset/record length tests, three sweep effort tests, three 2D Swaths (adding 50 km of high-resolution subsurface data), two noise tests, one receiver array test, one sweep force test and one 3D Cross-Spread test, which provided targeted 3D imaging. Most of the acquisition tests were incorporated into the regular seismic acquisition production with little delay or additional cost, so that any potential improvements could be applied immediately. This paper will focus on the tests and results in two areas: Region 1, which has near surface laterites and only fair-to-good data quality; and Region 2, where mixed laterite / laterite free zones resulted in good-to-excellent data quality. Region 1 area is covered in red, iron-rich clay soils with areas of crystalline laterite at the surface. Laterite is a soil and rock type which is rich in iron and aluminium, and is commonly formed in hot and wet tropical areas. Laterites are typically rusty-red due to high iron oxide content. Laterite may form chunks and boulders in the subsurface which may act as scatterers. Additionally, vibrator coupling deteriorates in areas with hard laterite at the surface. Data quality in Region 2, which is medium to highly structured, is excellent except under large continuous areas of laterite, where the data quality is only good. Away from laterite, 80 Hz continuous reflectors were seen as deep as 3 seconds with excellent imaging. Under laterite, frequencies and signal-to-noise ratio were significantly reduced, with only 50 Hz along reflectors at 2 seconds.
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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)