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- Volume 25, Issue 3, 2019
Petroleum Geoscience - Volume 25, Issue 3, 2019
Volume 25, Issue 3, 2019
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Simulation of salt-cavity healing based on a micro–macro model of pressure solution
Authors Xianda Shen and Chloé ArsonCO2 storage in salt rock is simulated with the finite element method (FEM), assuming constant gas pressure. The initial state is determined by simulating cavity excavation with a continuum damage mechanics (CDM) model. A micro–macro healing mechanics model is proposed to understand the time-dependent behaviour of halite during the storage phase. Salt is viewed as an assembly of porous spherical inclusions that contain three orthogonal planes of discontinuity. Eshelby's self-consistent theory is employed to homogenize the distribution of stresses and strains of the inclusions at the scale of a representative elementary volume (REV). Pressure solution results in inclusion deformation, considered as eigenstrain, and in inclusion stiffness changes. The micro–macro healing model is calibrated against Spiers’ oedometer test results, with uniformly distributed contact plane orientations. FEM simulations show that independent of salt diffusion properties, healing is limited by stress redistributions that occur around the cavity during pressure solution. In standard geological storage conditions, the displacements at the cavity wall occur within the first 5 days of storage and the damage is reduced by only 2%. These conclusions still need to be confirmed by simulations that account for changes in gas temperature and pressure over time. For now, the proposed modelling framework can be applied to optimize crushed salt back-filling materials and can be extended to other self-healing materials.
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Investigating controls on salt movement in extensional settings using finite-element modelling
Authors James Hamilton-Wright, Stephen Dee, Christina von Nicolai and Howard JohnsonSalt structures present numerous challenges for targeting reservoirs. Salt movement within the subsurface can follow complex pathways, producing deformation patterns in surrounding strata which are often difficult to decipher. Consequently, the relative role of key salt-flow drivers and geological sensitivities on salt-structure evolution are often poorly understood. To address this, we have developed 2D geomechanical models using the finite-element method to simulate salt diapir and pillow development in two extensional tectonic settings. We conducted model sensitivity analyses to examine the influence of geological parameters on field-scale salt structures and their corresponding deformation pattern. Modelled diapirs developing in thin-skinned extensional settings closely resemble published analogue experiments; however, active and passive stages of diapir growth are seldom or never reached, respectively, thus challenging existing ideas that diapir evolution is dominated by passive growth. In all modelled cases, highly strained domains bound the diapir flanks where extensive small-scale faulting and fracturing can be expected. Asymmetrical diapirs are prone to flank collapse and are observed in models with fast extension or sedimentation rates, thin roof sections or salt layers, or initially short or triangular-shaped diapirs. In modelled thick-skinned extensional settings, salt pillows and suprasalt overburden faults can be laterally offset (decoupled) from a reactivating basement fault. This decoupling increases with increased salt-layer thickness, overburden thickness, sedimentation rate and fault angle, and decreased fault slip rates. Contrary to existing consensus, overburden grounding onto the basement fault scarp does not appear to halt development of salt structures above the footwall basement block.
Supplementary material: Animations for all model runs are available at https://doi.org/10.6084/m9.figshare.c.4446272
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How do stress perturbations near salt bodies induce difficulty in salt imaging? Insights from a geomechanical model and salt imaging
Authors Yaxing Li, Yunqiang Sun, Xiaofeng Jia and Gang LuoTraditional methods for imaging salt bodies seldom consider near-salt stress perturbations caused by salt, and the associated velocity perturbations of seismic waves in the sediments near the salt. To demonstrate the importance of stress changes caused by the salt on accurately imaging salt bodies, in this study we develop and apply a combined method of geomechanical stress modelling and salt imaging. We simulate the stress perturbations in sediments induced by a salt sphere using a static geomechanical model, and calculate the associated velocity changes of seismic waves in the sediments by using our model stress perturbations. We use the reverse time migration and imaging method to image the salt sphere, and then analyse the imaging results of two cases including and excluding the effects of stress perturbations by the salt sphere on velocity changes of seismic waves. The results show that the near-salt velocity changes of seismic waves induced by stress perturbations near salt bodies can have a significant impact on the salt imaging. We find that when the effects of near-salt stress perturbations are ignored, the imaging of the salt sphere is clearly distorted: the salt sphere is extended vertically and becomes a salt ellipse with a vertical major axis. In contrast, when we include the effects of near-salt stress perturbations, the imaging of this salt sphere accurately matches the salt geometry and position. Thus, the near-salt stress perturbations should not be ignored in salt imaging. This study provides scientific insights for petroleum geologists and exploration geophysicists on the relationship between near-salt stress perturbations and accurate imaging of salt structures.
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Influence of a reservoir bed on diapirism and drilling hazards near a salt diapir: a geomechanical approach
Authors Mahdi Heidari, Maria A. Nikolinakou, Michael R. Hudec and Peter B. FlemingsWe use a 2D forward finite-element model to explore how a laterally continuous permeable bed impacts the geological evolution and the geomechanical properties of a salt basin. We show that a permeable bed tilted by rise of a salt diapir substantially increases pore pressure in sediments near the diapir through hydraulically connecting these sediments to deep, high-overpressure sediments far from the diapir. The pore-pressure increase near the diapir has the following significant consequences: it causes a faster rise of the diapir; brings sediments near the diapir close to shear failure in situ; causes unloading of sediments around the crest of the permeable bed; and reduces the margin of appropriate mud weights for drilling near the diapir. The rise of the salt diapir induces concentrated lateral deformation and thereby overpressure in mudrocks encasing the permeable bed in an area near the bottom of the basin. This anomalously high overpressure is in marked contrast with the overpressure in the permeable bed, resulting in a large pore-pressure gradient between the permeable bed and encasing mudrocks. Our study provides insight into the importance of permeable beds to the structural evolution of a salt basin and to the exploration and production of hydrocarbon near salt diapirs.
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The geochemistry of oil in Cornish granites
Authors Mas'ud Baba, John Parnell and Stephen BowdenOil residues in Variscan granites in Cornwall, SW England, preserve biomarker data which indicate an origin from marine source rocks. The biomarkers also indicate a thermal maturity that excludes an origin from the Devono-Carboniferous rocks intruded by the granites, but is similar to that of Jurassic-sourced oil to the east in the Wessex Basin. A suite of five different samples from the South Crofty tin mine are variably biodegraded, implying alteration after emplacement of oil in the granite. These characteristics are compatible with models for updip flow of fluids from offshore Mesozoic sediments into older granite topographical highs.
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Mapping the bathymetric evolution of the Northern North Sea: from Jurassic synrift archipelago through Cretaceous–Tertiary post-rift subsidence
Authors Alan M. Roberts, Nick J. Kusznir, Graham Yielding and Hugh BeeleyThe post-rift history of the North Viking Graben has been backstripped in 3D, producing a sequence of palaeobathymetric maps that culminates at the Late Jurassic synrift stage. The backstripping takes into account the three main processes which drive post-rift basin development: thermal subsidence, flexural-isostatic loading and sediment compaction. Before backstripping was performed, the Norwegian Trench, a bathymetric feature within the present-day seabed, was smoothed in order to remove associated decompaction artefacts within the backstripping results.
Palaeobathymetric restorations at the top and base of the Paleocene take into account regional transient dynamic uplift, probably related to the Iceland Plume. 350 m of uplift is incorporated at the Base Tertiary (65 Ma) and 300 m at the Top Balder Formation (54 Ma), followed by rapid collapse of this same uplift.
At the top of the Lower Cretaceous (98.9 Ma), very localized fault-block topography, inherited from the Jurassic rift, is predicted to have remained emergent within the basin. At the Base Cretaceous (140 Ma), the fault-block topography is much more prominent and numerous isolated footwall islands are shown to have been present. At the Late Jurassic synrift stage (155 Ma), these islands are linked to form emergent island chains along the footwalls of all of the major faults. This is the Jurassic archipelago, the islands of which were the products of synrift footwall uplift. The predicted magnitude and distribution of footwall emergence calibrates well against available well data and published stratigraphic information, providing important constraints on the reliability of the results.
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Comparing simulations of hydrogen storage in a sandstone formation using heterogeneous and homogenous flow property models
Authors Wolf Tilmann Pfeiffer and Sebastian BauerHydrogen storage in porous geological formations is a potential option to mitigate offsets between power demand and generation in an energy system largely based on renewables. Incorporating hydrogen storage into the energy network requires the consideration of multiple scenarios for storage settings and potential loading cycles, causing a high computational effort. Therefore, homogenous replacement models are constructed by applying different spatial averaging methods for permeability and linearized relative permeability to an ensemble of heterogeneous reservoir representations of a potential hydrogen storage site. The applicability of these replacement models for approximating storage characteristics, such as well flow rates, pressure changes and power rates, is investigated by comparing their results to the results of the full heterogeneous ensemble. It is found that using the arithmetic mean to estimate the lateral and the harmonic mean for the vertical permeability in the homogeneous replacement models provides an approximation to the median of the heterogeneous ensemble for pressure changes, storage flow rate, gas in place and power output. Basic time-dependent effects of reducing well flow, and thus the power rates, during an extraction cycle can also be represented by these homogeneous replacement models. Using geometric means is found not to yield a valid representation of the storage behaviour.
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Controlling parameters of a mono-well high-temperature aquifer thermal energy storage in porous media, northern Oman
Authors Christian Wenzlaff, Gerd Winterleitner and Felina SchützAquifer thermal energy storage (ATES) as a complement to fluctuating renewable energy systems is a reliable technology to guarantee continuous energy supply for heating and air conditioning. We investigated a high-temperature (HT) mono-well system (c. 100°C), where the well screens are separated vertically within the aquifer, as an alternative to conventional doublet ATES systems for an underground storage in northern Oman. We analysed the impact of thermal inference between injection and extraction well screens on the heat recovery factor (HRF) in order to define the optimal screen-to-screen distance for best possible systems efficiency. Two controlling interference parameters were considered: the vertical screen-to-screen distance and aquifer heterogeneities. The sensitivity study shows that with decreasing screen-to-screen distances, thermal interference increases storage performance. A turning point is reached if the screen distance is too close, causing either water breakthrough or negative thermal interference between the screens. Our simulations show that a combined heat plume with spherical geometry results in the highest heat recovery factors due to the lowest surface area to volume ratios. Thick aquifers for mono-well HT-ATES are thus not mandatory. Our study shows that a HT-ATES mono-well system is a feasible storage design with high heat recovery factors for continuous cooling or heating purposes.
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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)