Layer | Fill | Outline |
---|
Map layers
Theme | Visible | Selectable | Appearance | Zoom Range (now: 0) |
---|
Fill | Stroke |
---|---|
Collaborating Authors
Rockfield Software
ABSTRACT Large-scale folding of sedimentary rock is generally considered to be a response to horizontal tectonic shortening. We test an alternative hypothesis where we propose that in basins with high sedimentation rates where folds are cored by mechanically weak mobile shale, fold growth can be amplified by the gravitational loading of the weak underlying shale. We use two-dimensional plane-strain, finite element code to investigate the mechanics of growth of a shale-cored fold in the South Caspian Sea Basin, where c.10 km of sediment was deposited in the last 6 Myr. The overburden and syn-kinematic sediments are modelled as poro-elastoplastic materials using a modified Cam-Clay critical state model and the mobile shale is modelled as visco-plastic Herschell-Bulkley material, at critical state. The results show that the atypical geometries of the fold strata can be explained by the application of horizontal shortening and simultaneous sediment loading of the visco-plastic layer. The viscosity of the shale determines whether differential loading will cause fold growth and its density controls the magnitude of fold amplification, with a lower density causing greater fold amplification. Results demonstrate that the magnitude of shale inflation is controlled by complex interaction of the relative amounts of shortening and sedimentation rate. INTRODUCTION Mobile shale tectonics has been documented in 65 areas across the world, including the Niger Delta, the Gulf of Mexico, the Caribbean Basin and the South Caspian Basin (Soto et al., 2021a). However, unlike salt tectonics, very few studies which investigate the role of sediment loading on the deformation history within these regions have been published. Although both salt and mobile shale can produce thin-skinned deformation through extension, shortening and loading (Morley and Guerin, 1996), the intrinsic (material) properties of both mediums mean they act and respond differently depending on the local conditions (Jackson and Vendeville, 1994). Whist properties of salt remain relatively constant, both the composition of shale and its properties can vary through time, depending on compaction and depth (Ewy et al., 2020), with shale movement dependent primarily on the degree of overpressure within the pore fluids (Morley and Guerin, 1996). The effect of sediment load in salt tectonics has been demonstrated frequently (Waltham, 1997, Gemmer et al., 2004, Hudec and Jackson, 2007) and is well understood, however, deformation of mobile shale is relatively poorly understood. It is generally agreed that shale can behave as a visco-plastic solid (Dean et al., 2015, Albertz et al., 2010, Ings and Beaumont, 2010, Soto et al., 2021a) but can also behave as a suspension fluid as demonstrated by the wide-spread occurrence of mud volcanoes in shale provinces such as Trinidad, Nigeria and both on and offshore Azerbaijan (Barboza and Boettcher, 2000, Boettcher et al., 2000, Fowler et al., 2000, Graue, 2000, Hudec and Soto, 2021). Several large-scale numerical models have attempted to model mobile shale tectonics, for example the effect of delta propagation on mobile shales in the Niger Delta (Albertz et al., 2010, Ings and Beaumont, 2010, Dean et al., 2015). Here we examine the growth of a single, large km-scale, fold and conduct numerical models to test whether sediment loading above a thick mobile shale layer can contribute to the growth of such structures.
- North America > United States (0.88)
- Asia > Middle East (0.67)
- Africa > Nigeria > Niger Delta (0.44)
- Europe > United Kingdom > Wales (0.28)
- Research Report > New Finding (1.00)
- Research Report > Experimental Study (0.86)
- Asia > Kazakhstan > Caspian Depression > Caspian Basin (0.99)
- Asia > Georgia > Black Sea Basin (0.99)
- Asia > Azerbaijan > Caspian Sea > Apsheron-Pribalkhan Ridge > South Caspian Basin > Azeri-Chirag-Guneshli Field (0.99)
- Asia > Middle East > Iran > Central Iran Basin (0.98)
Effect of Interbeds on Hydraulic Fracture Characteristics and Formation Pressure Response
Profit, Matthew (Rockfield Software) | Dutko, Martin (Rockfield Software) | Bere, Adam (Rockfield Software) | Mutlu, Uno (Rockfield Global Technologies America LLC)
Abstract This paper presents geomechanical models which are used to simulate hydraulic fracture propagation in interbedded and laminated rocks. The models integrate routinely obtained reservoir and geomechanical log/core data and mechanical stratigraphy with interbed properties to quantify hydraulic fracture, complexity and conductivity. The primary objective of this study is to gain an understanding of the physical and operational controls that result in the observed hydraulic fracture patterns. The models attempt to provide guidelines for well placement and stimulation design parameters. The approach is based on finite discrete element methodology with flow and geomechanical coupling. This coupling allows the realization of the complex interactions between fracture, mechanical stratigraphy, interbeds and laminations. The rock matrix is represented by a poro-elasto-plastic model that can honor mixed mode rock failure. Interbeds can be modelled as bonded layers or discrete contacts (i.e. where flow and strength properties are assigned). Pore fluid coupling is single phase and flow is controlled by conductivity changes due to applied mechanical and hydraulic loads. Simultaneous fracture propagation from multi-clusters with stress shadows can also be simulated. Simulations quantify the impact of key parameters on fracture characteristics and formation pressure response while taking into account the interaction between hydraulic fractures and interbeds. Formation pressure response and fracture networks emerge from the models as dictated by the interbeds, stratigraphy, stress state and stimulation parameters. Sensitivity analysis show that interbed properties, e.g. elasto-plastic properties, hydraulic conductivity and frictional characteristics, can dictate the mechanical and flow behavior of the resulting fracture height and aperture. Results, where interbeds are assigned discrete contact properties, highlight the need for new experimental techniques to quantify interbed properties. These properties include both strength and flow properties. Introduction Hydraulic fracturing is a general engineering procedure which is aimed at improving the productivity of hydrocarbon reservoirs (Jones et al. 2005 and King 2010). When unconventional plays are considered, this process becomes extremely important as it is one of the few procedures known that can make stimulation of a target reservoir economically feasible (Bai 2011). Although much effort has been spent in trying to understand the key factors which determine the final fracture geometry resulting from stimulation, there are still many unanswered questions. To gain an idea of these issues, a few are stated here:a method of defining and quantifying โfracture complexityโ in a meaningful way (Soliman 2010), the expected final fracture length and by association the fracture width along its length (Davies et al. 2012); the influence of heterogeneity, whether it be largely material property or in-situ stress based, on the final fracture geometry; the role of boundary conditions in hydraulic fracturing; an example here would be the flow conditions at the fracture tip, the outcome of assuming single or multi-phase fluid flow during stimulation, flowback and production, the assumed fracture mechanics theory, e.g. linear elastic or nonlinear elastic fracture mechanics, and impact of near wellbore stress state/perforation architecture (Ferguson et al. 2018).
- Europe (1.00)
- North America > United States > Texas > Harris County > Houston (0.28)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (0.34)
Compaction- and Shear-Induced Well Deformation in Tyra: Geomechanics for Impact on Production
Schutjens, P. M. T. M. (Shell Global Solutions International B.V.) | Fokker, P. (Shell Global Solutions International B.V.) | Rai, B. B. (Shell Global Solutions International B.V.) | Kandpal, J. (Shell Global Solutions International B.V.) | Cid Alfaro, M. V. (Shell Global Solutions International B.V.) | Hummel, N. D. (Shell Global Solutions International B.V.) | Yuan, R. (Shell Global Solutions International B.V.) | Klever, F. (Shell Global Solutions International B.V.) | De Gennaro, S. (Shell Global Solutions International B.V.) | Vaibav, J. (Shell Global Solutions International B.V.) | Bourgeois, F. (Mรฆrsk Oil) | Calvert, M. (Mรฆrsk Oil) | Ditlevsen, F. (Mรฆrsk Oil) | Hendriksen, P. (Mรฆrsk Oil) | Derer, C. (Mรฆrsk Oil) | Richards, G. (Rockfield Software) | Price, J. (Rockfield Software) | Bere, A. (Rockfield Software) | Cain, J. (Rockfield Software)
ABSTRACT: Multi-scale numerical geomechanical models for reservoir and overburden deformation in the Tyra chalk field (Denmark) were made, and calibrated by laboratory deformation tests and field data. The mechanical interaction between the compacting and deforming formation, cement and casing was 1) modeled as a function of well orientation, cement distribution, and mechanical properties, 2) followed by probabilistic analysis of the model results in well-failure risking models to gain insight in the effects of rock deformation on well failure, both in space and time, and then 3) used as input in fluid-flow models to forecast the impact of well-failure on production. The risk analysis revealed that, whilst further Tyra compaction will probably lead to more well failure, its impact on production is probably low. Our geomechanical modeling helped to reduce uncertainty in the high-cost multi-year Tyra Future field upgrade planned for the next years to support Tyra production over the next decades.
- North America > United States (1.00)
- Asia (0.93)
- Europe > Norway > North Sea > Central North Sea (0.46)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock > Limestone (0.34)
- Geophysics > Seismic Surveying (0.93)
- Geophysics > Time-Lapse Surveying > Time-Lapse Seismic Surveying (0.67)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Block 2/4 > Greater Ekofisk Field > Ekofisk Field > Tor Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Block 2/4 > Greater Ekofisk Field > Ekofisk Field > Ekofisk Formation (0.99)
- Europe > Denmark > North Sea > Danish Sector > Central Graben > Block 5504/12 > Tyra Field (0.99)
- (6 more...)
Modelling Near-Wellbore Hydraulic Fracture Branching, Complexity and Tortuosity: A Case Study Based on a Fully Coupled Geomechanical Modelling Approach
Ferguson, W.. (Rockfield Software) | Richards, G.. (Rockfield Software) | Bere, A.. (Rockfield Software) | Mutlu, U.. (Rockfield Global Technologies) | Paw, F.. (Rockfield Software)
Abstract This paper presents a 3D advanced near-wellbore coupled flow-geomechanical model that simulates all phases of the wellbore construction and stimulation in order to quantify near-wellbore hydraulic fracture branching, complexity and tortuosity. The model integrates wellbore drilling, completion system installation, perforation and stimulation stages in a single simulation. The approach is based on the finite element methodology that allows coupling between the injection fluid flow and the geomechanical behaviour. The rock formation is represented by a poro-elasto-plastic model that can honour mixed mode fracturing through the utilization of an advanced constitutive material model. This includes a unified compaction, tensile and shear failure envelope that is calibrated against supplied laboratory data. Fluid flow coupling is single phase where the flow path is governed by localised damage and associated conductivity changes. Hydraulic fracture itinerary is controlled entirely by the material and stress state and can follow any arbitrary path with potential branching as dictated by the combined material and stress states. Simultaneous fracture propagation from multiple perforations with stress shadowing can therefore be achieved. Prior to stimulation, drilling of the wellbore and subsequent creation of the perforations leads to a complex near-wellbore stress state due to the redistribution and reorientation of stress. Upon stimulation, models demonstrate significant fracture branching complexity, due to factors such as near-wellbore stress perturbation, mixed-mode shear and tensile damage, in-situ stress anisotropy and cement bond strength as the fractures propagate from individual perforations. For multiple perforation cases and during the early stages of stimulation, stress shadowing suppresses tensile stresses at the inner perforations, leading to preferential propagation from the outer perforations. In particular, dominant, transverse, elliptical fractures initially propagate from the outer perforations and some curving/tortuosity of the fractures is observed. Longitudinal fractures, oriented perpendicular to the outer fractures, propagate from the inner perforations and coalesce, forming an "H-shaped morphology". Fractures also spread from the base of the perforations and travel along the wellbore axis further contributing to the complexity. Sensitivity simulations demonstrate that near-wellbore fracture complexity and tortuosity increases with both a near-isotropic in-situ stress state and with a weak cement bond. The novelty of this fully coupled advanced hydraulic fracture model is in the ability to (i) incorporate all stages of wellbore construction (from drilling to perforation to cementing), (ii) take into account mixed-mode fracturing (iii) include near-wellbore and perforation stress perturbations within the framework of an advanced poro-elasto-plastic constitutive material model to simulate fracture coalescence, complexity, tortuosity and branching from multiple perforations. The simulation presented can contribute to a fuller understanding of the pressure drop between well and advancing fracture, and also the shape, size and orientation of the initial propagating fracture. In terms of operational benefits, this technology allows operators to design optimum perforation patterns based on the stress and material state to ensure pump pressures are kept to a minimum and fractures propagate along the desired path.
- North America > United States (0.28)
- Europe > Norway > Norwegian Sea (0.26)
Influence of Fault Transmissibility On Seismic Attributes Based On Coupled Fluid-flow And Geomechanical Simulation
Angus, D.A. (University of Bristol) | Verdon, J.P. (University of Bristol) | Kendall, J.M. (University of Bristol) | Fisher, Q.J. (University of Leeds) | Skachov, S. (University of Leeds) | Segura, J. (University of Leeds) | Dutko, M. (Rockfield Software) | Crook, A.J.L. (Rockfield Software)
INTRODUCTION SUMMARY In this study, we present results from linked fluid-flow, geomechanical and seismic modeling to examine the influence of fault transmissibility on seismic attributes. The model is a graben structure with two normal faults subdividing a sandstone reservoir into three compartments. The predicted seismic traveltime differences are consistentwith reservoir compaction and overburden extension. For the case of high transmissibility we observe a large spatial extent in traveltime anomalies as well as a fault related stress guide effect. For lower transmissibilities, the influence of production on seismic attributes becomes more localized around the well reservoir compartment. Anisotropy predictions show perturbations associated with the faults as well as the production induced stress redistribution in the overburden. Over the past few decades seismic monitoring has been used to image areas of bypassed oil, the geometry and nature of reservoir flow compartments, and regions of high stress and fracturing. The success of time-lapse seismic monitoring is heavily influenced by the overall complexity of the reservoir system (e.g., geometry of the reservoir and behaviour of faults), which can alter the the relationship between seismic velocities and the rock physical properties as well as the stress and strain fields. Of particular interest is understanding the impact of faults on fluid flow. Although the link between fluid flow and faults has been known for over 100 years (see Hickman et al., 1995), fluid motion in fault zones is often difficult to understand. Some fault systems act as seals whilst others as flow conduits (e.g., Hooper, 1991). One of the main difficulties in using time-lapse seismic data to interpret fluid migration is relating changes in seismic attributes (e.g., traveltimes and reflection amplitudes) to changes not only in fluid saturation and pressure, but also to the reservoir physical properties, for example faults. Thus there is a need to improve our understanding of the relationship between seismic attributes, fluid effects and mechanical deformation. Recent work in reservoir monitoring has focused on applying coupled fluid-flow and geomechanical modeling to improve our understanding of subsurface response to hydrocarbon production. The coupling of fluid mechanics with mechanical elastoplastic deformation has shown potential in improving reservoir physics models (e.g., Minkoff et al., 2003,Herwanger & Horne, 2005), where the integrated influence of deviatoric stress and strain, and multi-phase fluid flow dictate the spatial and temporal behaviour of various rock attributes. Studies such as these have helped improve our understanding of how seismic attributes are related to changes in fluid properties and reservoir structure. In this study, we present results from linking coupled fluid flow and geomechanical simulation with seismic model building to study the influence of fault transmissibility on various seismic attributes. The results stem from the work being carried out as part of the IPEGG (Integrated Petroleum Engineering, Geomechanics and Geophysics) consortium by the Universities of Bristol and Leeds and Rockfield Software Ltd.
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Structural Geology > Fault > Dip-Slip Fault > Normal Fault (0.69)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.57)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock (0.50)
- Geophysics > Time-Lapse Surveying > Time-Lapse Seismic Surveying (1.00)
- Geophysics > Seismic Surveying > Seismic Interpretation (1.00)
- Geophysics > Seismic Surveying > Seismic Modeling > Velocity Modeling (0.36)