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- Volume 33, Issue 10, 2015
First Break - Volume 33, Issue 10, 2015
Volume 33, Issue 10, 2015
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The man putting the geophysics into Brunei
Pieter van Mastrigt, chief geophysicist at Brunei Shell Petroleum, reflects on 25 enjoyable years with the company and his current leadership role in promoting geoscience at BSP.
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An integrated workflow for hydraulic fracture stage design
As unconventional resource plays have moved into development mode, there has been a focus on increasing the efficiency of the drilling process to reduce costs and drill more wells to maintain pro¬duction levels. Given that the completion and stimulation of these wells may account for 40% to 60% of the well con¬struction costs, it may be a surprise that driving efficiency and return on investment during completion design and execution have generally received little attention because of the prevalence for geometric completion designs. This trend has recently changed with an increased focus on engineered completion and stimulation designs to take into account the variation in fracture potential (Shahri et al., 2015) along the length of the lateral wellbore and also the variability in well-to-well production. Vertical and lateral heterogeneity in what were once thought of as homogeneous ‘shales’ are now widely acknowledged. Also recognised is that geometric comple¬tion designs have largely failed to take these variations into account and have, instead, applied a ‘one size fits all’ approach. If the entire lateral section is composed of rock with constant reservoir and geomechanical attributes and fracture potential, it is logical to divide the lateral into geometric stages and apply the same stimulation design to each. However, if the reservoir and geomechanical proper¬ties vary along the length of the lateral section, then it is logical to divide the lateral into stages of similar or like properties, and then to apply a stimulation design optimised for the fracture potential of each stage. For example, design ‘A’ may be optimised for stages with high fracture potential, and design ‘B’ may be optimised for stages with low fracture potential.
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High-density point-receiver seismic survey of a deep carbonate cave reservoir system: a case study from the Tarim Basin, Western China
In the northern rim of the Tarim Basin, western China, oil is being produced from an extensive system of interconnected caves, faults and fractures in Ordovician carbonates buried about 6000 to 7000 m below the surface. Although onshore, drilling costs are high due to the depth of the field, so, to produce the field economically, wells must be accurately located within the cavernous features to access as large a drainage area as possible. However, imaging fine details of the reservoir structures presents challenges due to a complex overburden. While the surface terrain and near-surface geology are relatively benign for land seismic operations, the subsurface exhibits large lateral velocity changes related to widely distributed Permian volcanic formations around 1000 and 1200 m above the target zone. These formations are considered to have led to errors in the imaging of the target layers in legacy datasets due to incorrect velocity modelling of the overburden. Improved imaging of detailed features of the deep cavernous carbonate reservoir beneath the complex overburden would require an accurate velocity model in addition to seismic data with both high temporal and spatial resolution. To determine whether new land seismic acquisition and processing technologies could provide a significant uplift in imaging quality, in 2013 PetroChina Tarim Oil Company (TOC) acquired a high-density full-azimuth 3D seismic survey using a point-source and point-receiver geometry. The dataset was recorded using an advanced high-channel count acquisition system and processed with high-end processing techniques designed to address the various challenges presented in the area. Three approaches were used over different depth ranges to develop an accurate velocity model for prestack depth migration (PSDM). Model velocities were constrained using available well data, providing confidence in the accuracy of the resulting image. Relative amplitude preserving (RAP) methods were used for noise attenuation and signal processing to maximise the reliability of subsequent inversion and interpretation work.
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Further de-risking source rock maturity in the Luderitz Basin using basin modelling to support the BSR-derived near-surface geotherm
Authors Anongporn Intawong, Mads Huuse, Karyna Rodriguez, Neil Hodgson and Martin NegongaThe discovery of Kudu gas-condensate accumulation and recent wells drilled offshore in the Namibian margin have successfully de-risked source rock presence and maturity (Hodgson and Intawong, 2013). Both the acquisition of an extensive 2D seismic dataset in 2012 and a recently acquired cross-border survey 2015 off¬shore Namibia and South Africa have facilitated the evaluation of source rock maturity distribution for the Early Aptian and Cenomanian-Turonian source rocks along this margin (Figure 1). Conventionally, we have no tools to interrogate heat flow and geothermal gradient in an undrilled basin and have to rely on extrapolation from offset wells, imposing models on a structural interpretation of the basin margin. Near-surface geotherm estimation derived from seismic measurement of the thickness of a gas hydrate accumulation with respect to the water depth found in the Luderitz Basin has been employed as a preliminary approach for the initial evaluation of source rock maturity in this margin (Hodgson et al., 2014). The approach remains an under-utilised seismic method for initial evaluation of source rock maturity in undrilled basins. Public domain heatflow data (Davies, 2013), knowledge of subsurface thermal conductivity and crustal heat production can be used to predict geotherms and thus temperature spatially away from control points. Petroleum system modelling is the most efficient way of systematically investigating the thermal maturity of sedimentary basins. This can be tailored to available constraints, which in the case of the deepwater Luderitz Basin include shallow temperature data derived from BSR (60°C/km in the upper 500 mbsf) and heatflow measurements (40-60 mW/m2; Davies 2013). The uppermost sediments have a thermal conductivity of < 1 W/m/K, which is 2-3 times lower than deeper (compacted) clastic sediments. That would provide an average geothermal gradient of 30°C/km as previously proposed by Hodgson et al. (2014).
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2b... or not 2b? Interpreting magnitude distributions from microseismic catalogs
Authors David W. Eaton and Samira MaghsoudiMicroseismic monitoring has been extensively used as a surveillance technology for hydraulic fracture (HF) well completions, in addition to other applications such as monitoring reservoir monitoring during production, heavy-oil stimulation, mine safety and subsurface storage of CO2. For all of these applications, event magnitudes and their statistical behaviour are of inter¬est, since complete and accurate magnitude information can contribute to a better understanding of fracture growth as well as activation of fracture networks and/or geohazards. It is usually assumed that the magnitude distribution of microseismic events can be described by the well-known Gutenberg-Richter (GR) relationship for earthquakes, log N = a - b M , (1) where N is the total number of events with magnitude ≥ M. The slope, b, describes the relative size distribution of events while the intercept, a, describes the productivity, which rep¬resents the total number of events with magnitude greater than 0. When cast in terms of seismic moment, this formula constitutes a power-law relation that implies scale-invariance of the underlying rupture processes.
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Evergreen workflows that capture uncertainty – the benefits of an unlocked structure
Authors Ingrid Aarnes, Knut Midtveit and Arne SkorstadUncertainty in the reservoir’s geological structure is the reservoir modelling profession’s version of the ‘elephant in the room’. Its significance is well known to most practitioners, but often overlooked due to time constraints. Structural uncertainty is, however, one of the most important factors when determining both in-place and recoverable hydrocarbons, and it tends to remain substantial throughout the E&P lifecycle (Figure 1). One of the key challenges is to avoid locking the structural model early on in the reservoir modelling lifecycle. This is unfortunately a natural consequence if the available tools are not designed for revisiting these early assumptions. The locking of geological structure can be attributed to two key factors: 1) The fact that the logical process of build¬ing a reservoir model in a sequential workflow chain starts with defining the structure, and 2) the limitations in common reservoir simulation practices, where changing the geometry of the simulation grid is comparable to starting from scratch. In many applications of best practice, the revisiting of assumptions made early in the modelling process, such as the choice of a velocity model, is usually not prioritised because the traditional model update is manually-based, resource demanding, and takes too much calendar time. The same arguments apply for adding uncertainty to the structure at a later decision gate. Hence, after the structural modelling job is finished, exploring uncertainties in static and dynamic volumes tend to be limited to parameters that do not affect the grid layout. Changing faults and horizons are not among those. The higher risk of geological inconsistencies emerging in the simulation model(s) is a consequence of this sequential approach, where flow simulation is seen as ‘the last step’ and where there is a lack of iteration back to the starting point.
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Reservoir property estimation using only dual-sensor seismic data – a case study from the West of Shetlands, UKCS
Authors Cyrille Reiser, Tim Bird and Matthew WhaleyMarine broadband towed streamer seismic analysis and case studies in recent years have revealed several benefits of extended seismic bandwidth for the reservoir geoscientist – both for structural and quantitative seismic interpretation. Since 2007, dual-sensor towed streamer seismic technology (Tenghamn et al., 2007) has provided industry-wide access to seismic data with a significantly broader range of low and high frequencies. Benefits on the interpretation side include improved vertical resolution, enhanced geological texture, cleaner event continuity and character, sharper fault plane truncations and improved seismic-to-well correlations. The key benefit for quantitative seismic interpretation (QI) is a significant reduction of the low frequency model requirement and this allows seismic inversion to be derived from the seismic data rather than from a model extrapolation of a priori information. In addition, the quality and prediction of the reservoir properties derived from seismic data, without well log information, has significantly improved – resulting in the potential de-risking of prospects and discoveries. This paper describes the data analysis of dual-sensor 3D seismic from the West of Shetlands area and specifically focuses on wavelet extraction and low frequency phase stability. The study explores the relevance of these aspects to the inversion and investigates the estimation of reservoir properties, including porosity prediction, without the direct use of well information. The match of results from seismic only inversion to ‘blind wells’ demonstrates the potential of dual-sensor pre-stack data to reliably estimate elastic and reservoir properties in an exploration setting. Estimating reliable absolute reservoir properties away from wells has been a continuous challenge for reservoir geoscientists. Where it can be achieved, the value of the information can be significant in de-risking an opportunity and/or better characterising a prospect. In addition, in appraisal, development and reservoir optimisation, any reliable elastic information extracted from seismic data can potentially assist in optimising a well location and its trajectory for maximum recovery.
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Common characteristics of remobilised sand mounds from seismic attributes
Authors M. Ackers and Bjørn Kåre Lotsberg BrynShallow remobilised sand mounds found in the Miocene and Oligocene sections of the North Sea are thought to be caused by the migration of gas from deeper within the basin, which instigates sand liquefaction and lateral remobilisation in uncon¬solidated sandy units. It has been proposed that these processes can be equally applied to understanding mounded sand geometries observed in the Eocene and Palaeocene reservoirs of the northern North Sea, although the driving fluid phase may vary. Through the linkage of examples of shallow and deeply buried mounds, and their respective geomorphological settings, a set of common characteristics will be developed that appear to support the theory that similar processes are involved in the creation of shallow and deeply buried mounded structures. This theory has implications for hydrocarbon exploration since shallow unbreached mounds are more likely to contain gas-filled sandstone reservoir whereas deeply buried mounds could be oil-filled. The prerequisite for mound generation in the studied examples appears to be gas generation and migration within the basin. There then appears to be, in this case, a genetic relationship between the presence of primary sand depositional features (terminal splays or confined channels), mounds and candidate pockmarks in the unit undergoing remobilisation.
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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)