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- Volume 25, Issue 4, 2019
Petroleum Geoscience - Volume 25, Issue 4, 2019
Volume 25, Issue 4, 2019
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Introduction to the thematic collection: Naturally Fractured Reservoirs
Authors Thomas Finkbeiner, Giovanni Bertotti and Sebastian GeigerThematic collection: This article is part of the Naturally Fractured Reservoirs collection available at: https://www.lyellcollection.org/cc/naturally-fractured-reservoirs
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Degradation of fracture porosity in sandstone by carbonate cement, Piceance Basin, Colorado, USA
Authors Tobias B. Weisenberger, Peter Eichhubl, Stephen E. Laubach and András FallCretaceous Mesaverde Group sandstones contain opening-mode fractures lined or filled by quartz and, locally, calcite cement. Fracture occlusion by quartz is controlled primarily by fracture size, age and thermal history. Fracture occlusion by calcite is highly heterogeneous, with open and calcite-sealed fractures found at adjacent depths. In the Piceance and in other basins, processes that control the distribution of these calcite cements have been uncertain. Using pore and fracture cement petrography, fluid inclusions, and isotopic and elemental analysis, we show that host-rock calcite distribution and remobilization govern porosity degradation and occlusion of fractures >1 mm wide by calcite. Fluid-inclusion analyses indicate calcite cement precipitation at 135–165°C. 87Sr/86Sr ratios of calcite and the presence of porous albite suggest that detrital feldspar albitization released Ca2+, driving carbonate cement precipitation. In host rock, both albite and calcite content decreases with depth along with greater fracture porosity preservation. Although the cement sequence Fe-dolomite → ankerite → calcite is widespread, Fe-dolomite and ankerite occur as host-rock cements only, with detrital dolomite as preferred precipitation substrate. We find that the rock-mass calcite cement content correlates with fracture degradation and occlusion, and can be used to accurately predict where wide fractures are sealed or open.
Thematic collection: This article is part of the Naturally Fractured Reservoirs collection available at: https://www.lyellcollection.org/cc/naturally-fractured-reservoirs
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Genesis and role of bitumen in fracture development during early catagenesis
Bitumen-bearing fractures and vugs were investigated in the highly organic-rich Jordan oil shale (JOS) of Late Cretaceous–Eocene age, which has potential as a highly fractured, unconventional hydrocarbon play. Bitumen is present as macroscopically visible deposits, and as inclusions in the cement of abundant natural fractures and adjacent vugs. The frequency of bitumen occurrence in fractures closely correlates with total organic carbon (TOC) and burial depth. Petrographical and organic-geochemical analyses on bitumen samples extracted from fractures and their host-rock matrix show that the fracture-filling bitumen comprises indigenous low maturity hydrocarbons derived from the surrounding organic-rich oil shale and has not migrated from a deeper source. Maturity indicators imply that the oil shale is in the pre-oil generation stage of early catagenesis throughout the investigated area, but with a regional increase in thermal maturity from west to east as the result of greater maximum burial depth. Bitumen mobilization in the host rock was mainly controlled by vertical loading stress acting on the non-Newtonian bitumen phase in load-bearing configurations in the organic-rich matrix. Bitumen fractures were developed by hydraulic fracturing as the result of fluid overpressure in the organic matter. Overpressured bitumen has acted as a fracture driver, generating bitumen veins in both the organic-rich mudstones and the adjacent chert and silicified intervals.
Supplementary material : A summary of core data and photographs of the fracture bitumen and matrix bitumen are available at https://doi.org/10.6084/m9.figshare.c.4602290
Thematic collection: This article is part of the Naturally Fractured Reservoirs collection available at: https://www.lyellcollection.org/cc/naturally-fractured-reservoirs
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A new look into the prediction of static Young's modulus and unconfined compressive strength of carbonate using artificial intelligence tools
Accurate estimation of rock elastic and failure parameters plays a vital role in petroleum, civil and geotechnical engineering applications. During drilling operations, continuous logs of rock elastic and failure parameters are considered very helpful in optimizing geomechanical earth models. Commonly, rock elastic and failure parameters are estimated using well logs and empirical correlations. These are calibrated with rock mechanics laboratory experiments conducted on core samples. However, since these samples are expensive to get and time-consuming to test, artificial intelligence (AI) models based on available petrophysical well logs such as bulk density, compressional wave and shear wave travel times are utilized to predict the static Young's modulus (E static) and the unconfined compressive strength (UCS) – with an emphasis on carbonate rocks. We present two AI techniques in this study: an artificial neural network (ANN) and an adaptive neuro-fuzzy inference system (ANFIS). The dataset used in this study contains 120 data points obtained from a Middle Eastern carbonate reservoir from which we develop an empirically correlated ANN model to predict E static and an ANFIS model to predict the UCS. A comparison between the UCS, predicted by the proposed ANFIS model, and the published correlations show that the ANFIS model predicted the UCS with less error and with a high coefficient of determination. The error obtained from the ANFIS model was 4.5%, while other correlations resulted in up to 30% error on a published dataset. On the basis of the results obtained, we can say that the developed models will help geomechanical engineers to predict E static and the UCS using well logs without the need to measure them in the laboratory.
Thematic collection: This article is part of the Naturally Fractured Reservoirs collection available at: https://www.lyellcollection.org/cc/naturally-fractured-reservoirs
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An integrated approach for fractured basement characterization: the Lancaster Field, a case study in the UK
Authors Daniel A. Bonter and Robert TriceTo date, naturally fractured crystalline basement reservoirs (‘basement’) in the UK Continental Shelf (UKCS) have been underexplored and underexploited. Over the last 12 years, Hurricane Energy have explored and evaluated the potential of the basement play, West of Shetland. Data acquired by Hurricane Energy through drilling and drill stem testing of five wells on the Lancaster Field has provided sufficient insight into the reservoir properties of the basement reservoir that Hurricane is now progressing Lancaster towards the first UK basement full-field development. The development is designed to be phased with production from the first phase achieved in 2019. Fractured basement reservoirs require a specific approach when acquiring and interpreting formation and well test data. A multi-disciplined team ethic, carefully integrating these data while avoiding a siloed approach, has proved essential to understanding the behaviour of the connected fracture network. Hurricane incorporates drilling and mudlogging data, high-resolution gas chromatography, logging while drilling (LWD) and wireline logs, drill stem test (DST) and production logging tool (PLT) data to analyse and model the reservoir. It is the combination of these disparate datasets which is key to Hurricane's analysis and has led to the technical de-risking that has underpinned the final investment decisions leading to the first phase of the Lancaster development.
Thematic collection: This article is part of the Naturally Fractured Reservoirs collection available at: https://www.lyellcollection.org/cc/naturally-fractured-reservoirs
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Quantified fracture (joint) clustering in Archean basement, Wyoming: application of the normalized correlation count method
Authors Qiqi Wang, S. E. Laubach, J. F. W. Gale and M. J. RamosWe demonstrate statistically significant self-organized clustering over a length scale range from 10−2 to 101 m for north-striking opening-mode fractures (joints) in Late Archean Mount Owen Quartz Monzonite. Spatial arrangement is a critical fracture network attribute that until recently has only been assessed qualitatively. We use normalized fracture intensity plots and the normalized correlation count (NCC) method of Marrett et al. to discriminate clustered from randomly placed or evenly spaced patterns quantitatively over a wide range of length scales and to test the statistical significance of the resulting patterns. We propose a procedure for interpreting cluster patterns on NCC diagrams generated by the freely available spatial analysis software CorrCount. Results illustrate the efficacy of NCC to measure fracture clustering patterns in texturally homogeneous Archean granitic rock in a setting distant (>2 km) from folds or faults. In their current geological setting, these regional fractures are conduits for water flow and their patterns – and the NCC approach to defining clusters – may be useful guides to the spatial arrangement style and clustering magnitude of conductive fractures in other, less accessible fractured basement rocks.
Thematic collection: This article is part of the Naturally Fractured Reservoirs collection available at: https://www.lyellcollection.org/cc/naturally-fractured-reservoirs
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Multiscale fracture length analysis in carbonate reservoir units, Kurdistan, NE Iraq
Fracture scaling parameters are an important input for modelling of naturally fractured reservoirs, but are very difficult to derive from subsurface data. Extensive areas of exposure in the northern Kurdistan Region of Iraq provide useful outcrop analogues for nearby producing and potential hydrocarbon fields. A variety of data acquisition methods are used to analyse fracture systems in carbonates of the Upper Cretaceous Aqra–Bekhme Formation across a wide range of scales. When plotted on length–intensity graphs, the collated data lie below an upper envelope that follows a power-law distribution over five orders of magnitude between 0.1 and 3000 m, and which defines the maximum likely intensity of background fracturing across the region. Contouring the length–intensity data shows the distribution of intensities below the upper envelope, and allows modal and minimum likely intensities to be estimated. Likely causes for the observed variation in fracture intensities include the domainal nature of deformation, the proximity to high strain zones including faults, second-order effects such as ladder fractures, and variations in the thickness of mechanical layering.
Thematic collection: This article is part of the Naturally Fractured Reservoirs collection available at: https://www.lyellcollection.org/cc/naturally-fractured-reservoirs
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Deciphering background fractures from damage fractures in fault zones and their effect on reservoir properties in microporous carbonates (Urgonian limestones, SE France)
Authors Irène Aubert, J. Lamarche and P. LeonideMost carbonates have a dual porosity and permeability (matrix and fracture). As fractures are preferential conduits for fluid flows, fracture networks strongly impact reservoir hydraulic properties. Two fracture patterns can affect reservoirs: random background fractures in the host rock; and damage-zone-clustered fractures in fault zones. This study identifies the structural and diagenetic attributes of both fracture patterns and determined their respective impact on reservoir properties. The study focuses on the eastern part of La Fare Anticlinal (SE France). Lower Cretaceous, Urgonian facies carbonates underwent a polyphase tectonic history. Faults were set up as normal and were later reactivated as strike-slip. We made a 290 m scanline along the outcrop to characterize the fracture network in and outside the fault zones. The diagenetic analysis of 45 thin sections in polarized light microscopy with scanning electron microscopy and cathodoluminescence evidenced three cementation phases and two micrite recrystallization phases. This study shows that fault-zone structural properties and deformation are dependent of the initial host-rock background fracture network. The fault-zone structure with a damage-zone fracture network encouraged fluid flow and the cementation of S2 phase. This fluid flow, absent in the host rock, strongly modified the reservoir properties of the studied zone.
Thematic collection: This article is part of the Naturally Fractured Reservoirs collection available at: https://www.lyellcollection.org/cc/naturally-fractured-reservoirs
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Linking natural fractures to karst cave development: a case study combining drone imagery, a natural cave network and numerical modelling
More LessIn carbonate rocks, channelized fluid flow through fracture conduits can result in the development of large and connected karst networks. These cavity systems have been found in multiple hydrocarbon and geothermal reservoirs, and are often associated with high-permeability zones, but also pose significant challenges in drilling and reservoir management. Here, we expand on the observed interplay between fractures, fluid flow and large cave systems, using outcrop analysis, drone imagery and fluid-flow modelling. The studied carbonate rocks are heavily fractured and are part of the Salitre Formation (750–650 Ma), located in central Bahia (NE Brazil). Firstly, the fracture and cave network data show a similar geometry, and both systems depict three main orientations, namely; NNE–SSW, NW–SE and ESE–WNW. Moreover, the two datasets are dominated by the longer NNE–SSW features. These observed similarities suggest that the fractures and caves are related. The presented numerical results further acknowledge this observed correlation. These results show that open fractures act as the main fluid-flow conduits, with the aperture model defining the fracture-controlled flow contribution. Furthermore, the performed modelling highlights that geometrical features such as length, orientation and connectivity play an important role in the preferred flow orientations.
Thematic collection: This article is part of the Naturally Fractured Reservoirs collection available at: https://www.lyellcollection.org/cc/naturally-fractured-reservoirs
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Influence of fracture nucleation and propagation rates on fracture geometry: insights from geomechanical modelling
Authors Michael J. Welch, Mikael Luthje and Aslaug C. GladWe combine a power-law microfracture size distribution function with an expression for fracture propagation rate derived from subcritical fracture propagation theory and linear elastic fracture mechanics, to derive a geomechanically based deterministic model for the growth of a network of layer-bound fractures. This model also simulates fracture termination due to intersection with perpendicular fractures or stress-shadow interaction. We use this model to examine key controls on the emergent geometry of the fracture network.
First, we examine the effect of fracture propagation rates. We show that at subcritical fracture propagation rates, the fracture nucleation rate increases with time; this generates a very dense network of very small fractures, similar to the deformation bands generated by compaction in unconsolidated sediments. By contrast, at critical propagation rates, the fracture nucleation rate decreases with time; this generates fewer but much larger fractures, similar to the brittle open fractures generated by tectonic deformation in lithified sediments. We then examine the controls on the rate of growth of the fracture network. A fracture set will start to grow when the stress acting on it reaches a threshold value, and it will continue to grow until all the fractures have stopped propagating and no new fractures can nucleate. The relative timing and rate of growth of the different fracture sets will control the anisotropy of the resulting fracture network: if the sets start to grow at the same time and rate, the result is a fully isotropic fracture network; if the primary fracture set stops growing before the secondary set starts growing, the result is a fully anisotropic fracture network; and if there is some overlap but the secondary set grows more slowly than the primary set, the result is a partially anisotropic fracture network. Although the applied horizontal strain rates are the key control on the relative growth rates of the two fracture sets, we show that the vertical effective stress, the initial horizontal stress, the elastic properties of the rock and the inelastic deformation processes, such as creep, grain sliding and pressure solution, all exert a control on the fracture growth rates, and that more isotropic fracture networks will tend to develop if the vertical effective stress is low or if the fractures are critically stressed prior to the onset of deformation.
Thematic collection: This article is part of the Naturally Fractured Reservoirs collection available at: https://www.lyellcollection.org/cc/naturally-fractured-reservoirs
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Flow diagnostics for naturally fractured reservoirs
Authors Victoria Spooner, Sebastian Geiger and Dan ArnoldReliable production forecasting for fractured carbonate reservoirs is a challenge. Natural fractures, adverse wettability and complex matrix heterogeneity are all uncertain and can all negatively impact upon recovery. Ideally, we should consider different reservoir concepts encapsulated in a large ensemble of reservoir models to quantify the impact of these and other geological uncertainties on reservoir performance. However, the computational cost of considering many scenarios can be significant, especially for dual porosity/permeability models, rendering robust uncertainty quantification impractical for most asset teams.
Flow diagnostics provide a complement to full-physics simulations for comparing models. Flow diagnostics approximate the dynamic response of the reservoir in seconds. In this paper we describe the extension of flow diagnostics to dual porosity models for naturally fractured reservoirs. Our new diagnostic tools link the advective time of flight in the fractures to the transfer from the matrix, identifying regions where transfer and flux are not in balance leading to poor matrix oil sweep and early breakthrough. Our new diagnostics tools have been applied to a real field case and are shown to compare well with full-physics simulation results.
Thematic collection: This article is part of the Naturally Fractured Reservoirs collection available at: https://www.lyellcollection.org/cc/naturally-fractured-reservoirs
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Geoscience and decarbonization: current status and future directions
At the 2015 United Nations International Climate Change Conference in Paris (COP21), 197 national parties committed to limit global warming to well below 2°C. But current plans and pace of progress are still far from sufficient to achieve this objective. Here we review the role that geoscience and the subsurface could play in decarbonizing electricity production, industry, transport and heating to meet UK and international climate change targets, based on contributions to the 2019 Bryan Lovell meeting held at the Geological Society of London. Technologies discussed at the meeting involved decarbonization of electricity production via renewable sources of power generation, substitution of domestic heating using geothermal energy, use of carbon capture and storage (CCS), and more ambitious technologies such as bioenergy and carbon capture and storage (BECCS) that target negative emissions. It was noted also that growth in renewable energy supply will lead to increased demand for geological materials to sustain the electrification of the vehicle fleet and other low-carbon technologies. The overall conclusion reached at the 2019 Bryan Lovell meeting was that geoscience is critical to decarbonization, but that the geoscience community must influence decision-makers so that the value of the subsurface to decarbonization is understood.
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A feasibility study for detection thresholds of CO2 at shallow depths at the CaMI Field Research Station, Newell County, Alberta, Canada
Authors Marie Macquet, Donald C. Lawton, Amin Saeedfar and Kirk G. OsadetzWe present the results of a feasibility study for seismic monitoring using conventional surface seismic experiments at the CaMI Field Research Station, Alberta, Canada, where a small volume of gas-phase CO2 is being injected into a sandstone reservoir at a depth of 300 m. We first apply a careful fluid substitution procedure to the results of reservoir gas saturation and pressure responses obtained from fluid flow simulations. We test different methods to compute the bulk modulus of the fluid for different fluid saturation models. Assuming a semi-patchy model and considering only the replacement of brine with a maximum saturation of 50% CO2, we estimate the reduction in P-wave velocity to be 20%. Adding an increase in pore pressure of 2.7 MPa increases the P-wave velocity reduction to 32%. After including a field-based signal-to-noise ratio of 5% to the synthetic seismic data, the time-lapse seismic anomaly should be detectable after one year of injection (266 tonnes of CO2).
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Characterization of effective permeability in heterolithic, distal lower-shoreface sandstone reservoirs: Rannoch Formation, Brent Group, UK North Sea
More LessThe reservoir properties of distal lower-shoreface and distal wave-dominated delta-front deposits, which consist of sandstone beds with locally scoured bases and mudstone interbeds, are poorly understood. The lower Rannoch Formation (Middle Jurassic Brent Group) forms an interval of such heterolithic sandstones in many North Sea reservoirs, and is used to illustrate a workflow for rapid estimation of reservoir properties and their sensitivity to key parameters. Mudstone-interbed thickness distributions in cored reservoir successions are compared to the thickness distribution of sandstone scour-fills in an outcrop analogue(s) in order to identify mudstones with the potential to form laterally extensive barriers to vertical flow. Effective k v/k h at the scale of several typical reservoir-model grid cells (200 × 100 × 20 m) is estimated in intervals bounded by these mudstone barriers via a simple analytical technique that is calibrated to previously documented reservoir-modelling experiments, using values of sandstone proportion measured in cored reservoir successions. Using data from the G2 parasequence (Grassy Member, Blackhawk Formation, east-central Utah, USA) outcrop analogue, mudstones bounding 3–8 m-thick, upwards-coarsening successions in the lower Rannoch Formation may define separate stratigraphic compartments in which grid-cell-scale effective k v/k h is estimated to be 0.0001–0.001 using a streamline-based analytical method.
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Volumes & issues
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Volume 30 (2024)
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Volume 29 (2023)
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Volume 28 (2022)
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Volume 27 (2021)
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Volume 26 (2020)
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Volume 25 (2019)
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Volume 24 (2018)
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Volume 23 (2017)
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Volume 22 (2016)
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Volume 21 (2015)
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Volume 20 (2014)
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Volume 19 (2013)
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Volume 18 (2012)
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Volume 17 (2011)
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Volume 16 (2010)
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Volume 15 (2009)
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Volume 14 (2008)
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Volume 13 (2007)
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Volume 12 (2006)
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Volume 11 (2005)
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Volume 10 (2004)
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Volume 9 (2003)
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Volume 8 (2002)
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Volume 7 (2001)
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Volume 6 (2000)
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Volume 5 (1999)
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Volume 4 (1998)
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Volume 3 (1997)
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Volume 2 (1996)
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Volume 1 (1995)