Modelling and Simulation of Heterogeneous and Anisotropic Formations using Advanced Fractal Reservoir Models

2020 ◽  
Author(s):  
Piroska Lorinczi ◽  
Paul Glover ◽  
Al-Zainaldin Saud ◽  
Saddam Sinan ◽  
George Daniel
Keyword(s):  
Fluid Flow ◽  
Production Rate ◽  
Water Saturation ◽  
Modelling And Simulation ◽  
Core Material ◽  
Reference Case ◽  
Hydrocarbon Production ◽  
Fractal Approach ◽  
Reservoir Models ◽  
Wide Range

<p>Energy and carbon-efficient exploitation, management, and remediation of subsurface aquifers, gas and oil resources, CO<sub>2</sub>-disposal sites, and energy storage reservoirs all require high quality modelling and simulation. The heterogeneity and anisotropy of such subsurface formations has always been a challenge to modellers, with the best current technology not being able to deal with variations at scales of less than about 30-50 m. Most formations exhibit heterogeneities and anisotropy which result in variations of the petrophysical properties controlling fluid flow down to millimetre scale and below. These variations are apparent in well-logs and core material, but cannot be characterised in the inter-well volume which makes up the great majority of the formation.</p><p>This paper describes a new fractal approach to the modelling and simulation of heterogeneous and anisotropic aquifers and reservoirs. This approach includes data at all scales such that it can represent the heterogeneity of the reservoir correctly at each scale.</p><p>Advanced Fractal Reservoir Models (AFRMs) in 3D can be produced using our code. These AFRMs can be used to model fluid flow in formations generically to understand the effects of an imposed degree of heterogeneity and anisotropy, or can be conditioned to match the characteristics of real aquifers and reservoirs. This paper will show how 3D AFRMs can be created such that they represent critical petrophysical parameters, as well as how fractal 3D porosity and permeability maps, synthetic poro-perm cross-plots, water saturation maps and relative permeability curves can all be calculated. It will also show how quantitative controlled variation of heterogeneity and anisotropy of generic models affects fluid flow. We also show how AFRMs can be conditioned to represent real reservoirs, and how they provide a much better simulated fluid flow than the current best technology.</p><p>Results of generic modelling and simulation with AFRMs show how total hydrocarbon production, hydrocarbon production rate, water cut and the time to water breakthrough all depend strongly on heterogeneity, and also depend upon anisotropy. Modelling with different degrees and directions of anisotropy shows how critical hydrocarbon production data depends on the direction of the anisotropy, and how that changes over the lifetime of the reservoir.</p><p>Advanced fractal reservoir models are of greatest utility if they can be conditioned to represent individual reservoirs. We have developed a method for matching AFRMs to aquifer and reservoir data across a wide range of scales that exceeds the range of scales currently used in such modelling. We show a hydrocarbon production case study which compares the hydrocarbon production characteristics of such an approach to a conventional krigging approach. The comparison shows that modelling of hydrocarbon production is appreciably improved when AFRMs are used, especially if heterogeneity and anisotropy are high. In this study AFRMs in moderate to high heterogeneity reservoirs always provided results within 5% of the reference case, while the conventional approach resulted in massive systematic underestimations of production rate by over 70%.</p>

A Fractal Approach to the Modelling and Simulation of Heterogeneous and Anisotropic Reservoirs

2019 ◽  
Author(s):  
Paul W. J. Glover ◽  
Piroska Lorinczi ◽  
Saud Al-Zainaldin ◽  
Hassan Al-Ramadhan ◽  
Saddam Sinan ◽  
...  
Keyword(s):  
Modelling And Simulation ◽  
Fractal Approach ◽  
Anisotropic Reservoirs

Time Domain Simulation of the Vibration of a Steam Generator Tube Subjected to Fluidelastic Forces Induced by Two-Phase Cross-Flow

2013 ◽  
Vol 135 (3) ◽  
Author(s):  
Téguewindé Sawadogo ◽  
Njuki Mureithi
Keyword(s):  
Steam Generator ◽  
Two Phase Flow ◽  
Work Rate ◽  
Fretting Wear ◽  
Phase Flow ◽  
Reference Case ◽  
Two Phase ◽  
Steam Generator Tube ◽  
Wide Range ◽  
Instability Regime

Having previously verified the quasi-steady model under two-phase flow laboratory conditions, the present work investigates the feasibility of practical application of the model to a prototypical steam generator (SG) tube subjected to a nonuniform two-phase flow. The SG tube vibration response and normal work-rate induced by tube-support interaction are computed for a range of flow conditions. Similar computations are performed using the Connors model as a reference case. In the quasi-steady model, the fluid forces are expressed in terms of the quasi-static drag and lift force coefficients and their derivatives. These forces have been measured in two-phase flow over a wide range of void fractions making it possible to model the effect of void fraction variation along the tube span. A full steam generator tube subjected to a nonuniform two-phase flow was considered in the simulations. The nonuniform flow distribution corresponds to that along a prototypical steam-generator tube based on thermal-hydraulic computations. Computation results show significant and important differences between the Connors model and the two-phase flow based quasi-steady model. While both models predict the occurrence of fluidelastic instability, the predicted pre-instability and post instability behavior is very different in the two models. The Connors model underestimates the flow-induced negative damping in the pre-instability regime and vastly overestimates it in the post instability velocity range. As a result the Connors model is found to underestimate the work-rate used in the fretting wear assessment at normal operating velocities, rendering the model potentially nonconservative under these practically important conditions. Above the critical velocity, this model largely overestimates the work-rate. The quasi-steady model on the other hand predicts a more moderately increasing work-rate with the flow velocity. The work-rates predicted by the model are found to be within the range of experimental results, giving further confidence to the predictive ability of the model. Finally, the two-phase flow based quasi-steady model shows that fluidelastic forces may reduce the effective tube damping in the pre-instability regime, leading to higher than expected work-rates at prototypical operating velocities.

Simulation of Miscible Displacement in Full-Diameter Carbonate Cores

1982 ◽  
Vol 22 (05) ◽  
pp. 647-657 ◽  
Author(s):  
J.P. Batycky ◽  
B.B. Maini ◽  
D.B. Fisher
Keyword(s):  
Oil Recovery ◽  
Water Saturation ◽  
Accurate Determination ◽  
Miscible Displacement ◽  
Carbonate Reservoir ◽  
Core Material ◽  
Immiscible Fluid ◽  
Displacement Efficiency ◽  
Carbonate Cores ◽  
Capacitance Model

Abstract Miscible gas displacement data obtained from full-diameter carbonate reservoir cores have been fitted to a modified miscible flow dispersion-capacitance model. Starting with earlier approaches, we have synthesized an algorithm that provides rapid and accurate determination of the three parameters included in the model: the dispersion coefficient, the flowing fraction of displaceable volume, and the rate constant for mass transfer between flowing and stagnant volumes. Quality of fit is verified with a finite-difference simulation. The dependencies of the three parameters have been evaluated as functions of the displacement velocity and of the water saturation within four carbonate cores composed of various amounts of matrix, vug, and fracture porosity. Numerical simulation of a composite core made by stacking three of the individual cores has been compared with the experimental data. For comparison, an analysis of Berea sandstone gas displacement also has been provided. Although the sandstone displays a minor dependence of gas recovery on water saturation, we found that the carbonate cores are strongly affected by water content. Such behavior would not be measurable if small carbonate samples that can reflect only matrix properties were used. This study therefore represents a significant assessment of the dispersion-capacitance model for carbonate cores and its ability to reflect changes in pore interconnectivity that accompany water saturation alteration. Introduction Miscible displacement processes are used widely in various aspects of oil recovery. A solvent slug injected into a reservoir can be used to displace miscibly either oil or gas. The necessary slug size is determined by the rate at which deterioration can occur as the slug is Another commonly used miscible process involves addition of a small slug within the injected fluids or gases to determine the nature and extent of inter well communication. The quantity of tracer material used is dictated by analytical detection capabilities and by an understanding of the miscible displacement properties of the reservoir. We can develop such understanding by performing one-dimensional (1D) step-change miscible displacement experiments within the laboratory with selected reservoir core material. The effluent profiles derived from the experiments then are fitted to a suitable mathematical model to express the behavior of each rock type through the use of a relatively small number of parameters. This paper illustrates the efficient application of the three-parameter, dispersion-capacitance model. Its application previously has been limited to use with small homogeneous plugs normally composed of intergranular and intencrystalline porosity, and its suitability for use with cores displaying macroscopic heterogeneity has been questioned. Consequently, in addition to illustrating its use with a homogeneous sandstone, we fit data derived from previously reported full-diameter carbonate cores. As noted earlier, these cores were heterogeneous, and each of them displayed different dual or multiple types of porosity characteristic of vugular and fractured carbonate rocks. Dispersion-Capacitance Model The displacement efficiency of one fluid by a second immiscible fluid within a porous medium depends on the complexity of rock and fluid properties. SPEJ P. 647^

Design of Laboratory Studies to Develop the Chemical Formulation for Surfactant-Polymer Flooding

2021 ◽  
Author(s):  
Dmitry Gospodarev ◽  
Igor Lymar ◽  
Aleksandra Rakutko ◽  
Anastasia Antuseva ◽  
Dmitry Tkachev
Keyword(s):  
Thermal Stability ◽  
Physical Simulation ◽  
Research Work ◽  
Polymer Flooding ◽  
Core Material ◽  
Chemical Components ◽  
Laboratory Studies ◽  
Static Adsorption ◽  
Reservoir Models ◽  
Surfactant Solutions

Abstract Nowadays, chemical EOR methods are becoming more and more relevant, among which the alkali-surfactant-polymer flooding is of particular interest. The efficiency of this technology largely depends on the correct choice of the components of chemical formulation, which should be based on a set of laboratory experiments carried out in a given sequence. This paper presents a methodological approach to laboratory studies in order to develop an optimal surfactant-polymer formulation, taking into account the geological and physical characteristics of the target field and the properties of reservoir fluids. The experimental part of the research work was carried out in several stages, involving the analysis of the physicochemical characteristics of reservoir oil, the screening studies of surfactant and polymer samples, as well as a series of coreflood tests with a selected chemical formulation on the terrigenous reservoir models. During screening studies, the solubility and compatibility of the chemical components, the phase behavior of surfactant solutions with oil at different salinity values and water-oil ratios, static adsorption of chemicals on the rock and their thermal stability at reservoir temperature were investigated. Optimization of the chemical formulation was based on the results of IFT measurements of the surfactant solutions and rheological studies of the polymer solutions. At the stage of coreflood tests, physical simulation of the surfactant-polymer flooding was carried out on reservoir models using natural core material in order to optimize the composition and slug size of the developed chemical formulation. The obtained results of the displacement experiment were matched by numerical 1D simulation. Based on the results of the studies performed, an effective surfactant-polymer formulation has been designed, which provides the ultra-low IFT (2.8·10−4 mN/m) values and the ability to form stable middle-phase microemulsions when interacting with oil. The findings of thermal stability and static adsorption experiments confirmed a feasibility of selected chemicals for practical application. Within the framework of the study, the key technical parameters of proposed formulation were determined, which are required for up-scaled simulation study of the chemical flooding process at pilot site.

Relating Acoustic Anisotropy to Kerogen Content in Unconventional Formations - A Case Study in A Kerogen-Rich Unconventional Carbonate

2021 ◽  
Author(s):  
Yair Gordin ◽  
Thomas Bradley ◽  
Yoav O. Rosenberg ◽  
Anat Canning ◽  
Yossef H. Hatzor ◽  
...  
Keyword(s):  
Wave Velocity ◽  
Water Saturation ◽  
Well Logs ◽  
Rock Properties ◽  
Thermal Maturity ◽  
Burial Diagenesis ◽  
S Wave ◽  
Velocity Anisotropy ◽  
Thermal Maturation ◽  
Wide Range

Abstract The mechanical and petrophysical behavior of organic-rich carbonates (ORC) is affected significantly by burial diagenesis and the thermal maturation of their organic matter. Therefore, establishing Rock Physics (RP) relations and appropriate models can be valuable in delineating the spatial distribution of key rock properties such as the total organic carbon (TOC), porosity, water saturation, and thermal maturity in the petroleum system. These key rock properties are of most importance to evaluate during hydrocarbon exploration and production operations when establishing a detailed subsurface model is critical. High-resolution reservoir models are typically based on the inversion of seismic data to calculate the seismic layer properties such as P- and S-wave impedances (or velocities), density, Poisson's ratio, Vp/Vs ratio, etc. If velocity anisotropy data are also available, then another layer of data can be used as input for the subsurface model leading to a better understanding of the geological section. The challenge is to establish reliable geostatistical relations between these seismic layer measurements and petrophysical/geomechanical properties using well logs and laboratory measurements. In this study, we developed RP models to predict the organic richness (TOC of 1-15 wt%), porosity (7-35 %), water saturation, and thermal maturity (Tmax of 420-435⁰C) of the organic-rich carbonate sections using well logs and laboratory core measurements derived from the Ness 5 well drilled in the Golan Basin (950-1350 m). The RP models are based primarily on the modified lower Hashin-Shtrikman bounds (MLHS) and Gassmann's fluid substitution equations. These organic-rich carbonate sections are unique in their relatively low burial diagenetic stage characterized by a wide range of porosity which decreases with depth, and thermal maturation which increases with depth (from immature up to the oil window). As confirmation of the method, the levels of organic content and maturity were confirmed using Rock-Eval pyrolysis data. Following the RP analysis, horizontal (HTI) and vertical (VTI) S-wave velocity anisotropy were analyzed using cross-dipole shear well logs (based on Stoneley waves response). It was found that anisotropy, in addition to the RP analysis, can assist in delineating the organic-rich sections, microfractures, and changes in gas saturation due to thermal maturation. Specifically, increasing thermal maturation enhances VTI and azimuthal HTI S-wave velocity anisotropies, in the ductile and brittle sections, respectively. The observed relationships are quite robust based on the high-quality laboratory and log data. However, our conclusions may be limited to the early stages of maturation and burial diagenesis, as at higher maturation and diagenesis the changes in physical properties can vary significantly.

Internal heat generation/or absorption phenomena in three-dimensional natural convection flow within enclosure filled with different working fluids

2018 ◽  
Vol 28 (4) ◽  
pp. 878-908
Author(s):  
Najib Hdhiri ◽  
Brahim Ben Beya
Keyword(s):  
Fluid Flow ◽  
Heat Generation ◽  
Average Nusselt Number ◽  
Thermal Field ◽  
Three Dimensional ◽  
Grashof Number ◽  
Content Type ◽  
Wide Range ◽  
Heat Generation Or Absorption ◽  
2D Model

Purpose The purpose of this study is to investigate the effects of heat generation or absorption on heat transfer and fluid flow within two- and three-dimensional enclosure for homogeneous medium filled with different metal liquid. Numerical results are presented and analyzed in terms of fluid flow, thermal field structures, as well as average Nusselt number profiles over a wide range of dimensionless quantities, Grashof number (Gr) (104 and 105), SQ (varied between −500 to 500) and Prandtl number (Pr = 0.015, 0.024 and 0.0321). The results indicate that when the conductive regime is established for a Grashof number Gr = 104, the 2D model is valid and predicts all three-dimensional results with negligible difference. This was not the case in the convective regime (Gr = 105) where the effect of the third direction becomes important, where a 2D-3D difference was seen with about 37 per cent. Also, in most cases, the authors find that the heat absorption phenomena have the opposite effect with respect to the heat generation. Design/methodology/approach Numerical results are presented and analyzed in terms of fluid flow, thermal field structures, as well as average Nusselt number profiles over a wide range of dimensionless quantities. Findings Grashof number (Gr) (104 and 105), SQ (varied between −500 to 500) and Prandtl number (Pr = 0.015, 0.024 and 0.0321). Originality/value The results indicate that when the conductive regime is established for a Grashof number Gr = 104, the 2D model is valid and predicts all three-dimensional results with negligible difference.

Fluvial architecture of the Burro Canyon Formation using unmanned aerial vehicle-based photogrammetry and outcrop-based modeling: Implications for reservoir performance, Escalante Canyon, southwestern Piceance Basin, Colorado

2018 ◽  
Vol 6 (4) ◽  
pp. T1117-T1139
Author(s):  
Sarah A. Clark ◽  
Matthew J. Pranter ◽  
Rex D. Cole ◽  
Zulfiquar A. Reza
Keyword(s):  
Fluid Flow ◽  
Unmanned Aerial Vehicle ◽  
Geometric Mean ◽  
Piceance Basin ◽  
Sweep Efficiency ◽  
Flow Simulations ◽  
Reservoir Performance ◽  
Reservoir Models ◽  
Sandstone Body ◽  
Aerial Vehicle

The Cretaceous Burro Canyon Formation in the southern Piceance Basin, Colorado, represents low sinuosity to sinuous braided fluvial deposits that consist of amalgamated channel complexes, amalgamated and isolated fluvial-bar channel fills, and floodplain deposits. Lithofacies primarily include granule-cobble conglomerates, conglomeratic sandstones, cross-stratified sandstones, upward-fining sandstones, and gray-green mudstones. To assess the effects of variable sandstone-body geometry and internal lithofacies and petrophysical heterogeneity on reservoir performance, conventional field methods are combined with unmanned aerial vehicle-based photogrammetry to create representative outcrop-based reservoir models. Outcrop reservoir models and fluid-flow simulations compare three reservoir scenarios of the Burro Canyon Formation based on stratigraphic variability, sandstone-body geometry, and lithofacies heterogeneity. Simulation results indicate that lithofacies variability can account for an almost 50% variation in breakthrough time (BTT). Internal channel-bounding surfaces reduce the BTT by 2%, volumetric sweep efficiency by 8%, and recovery efficiency by 10%. Three lateral grid resolutions and two permeability-upscaling methods for each reservoir scenario are explored in fluid-flow simulations to investigate how upscaling impacts reservoir performance. Our results indicate that coarsely resolved grids experience delayed breakthrough by as much as 40% and greater volumetric sweep efficiency by an average of 10%. Permeability models that are upscaled using a geometric mean preserve slightly higher values than those using a harmonic mean. For upscaling based on a geometric mean, BTTs are delayed by an average of 17% and the volumetric sweep efficiency is reduced by as much as 10%. Results of the study highlight the importance of properly incorporating stratigraphic details into 3D reservoir models and preserving those details through proper upscaling methods.

Numerical Investigation on Multiphase Erosion-Corrosion Problem of Steel of Apparatus at a Well Outlet in Natural Gas Production

2018 ◽  
Vol 140 (12) ◽  
Author(s):  
Zhang Jianwen ◽  
Jiang Aiguo ◽  
Xin Yanan ◽  
He Jianyun
Keyword(s):  
Fluid Flow ◽  
Natural Gas ◽  
Production Rate ◽  
Gas Production ◽  
Two Phase ◽  
Gas Well ◽  
Chemical Corrosion ◽  
High Production Rate ◽  
Erosion Corrosion ◽  
Corrosion Problem

The erosion-corrosion problem of gas well pipeline under gas–liquid two-phase fluid flow is crucial for the natural gas well production, where multiphase transport phenomena expose great influences on the feature of erosion-corrosion. A Eulerian–Eulerian two-fluid flow model is applied to deal with the three-dimensional gas–liquid two-phase erosion-corrosion problem and the chemical corrosion effects of the liquid droplets dissolved with CO2 on the wall are taken into consideration. The amount of erosion and chemical corrosion is predicted. The erosion-corrosion feature at different parts including expansion, contraction, step, screw sections, and bends along the well pipeline is numerically studied in detail. For dilute droplet flow, the interaction between flexible water droplets and pipeline walls under different operations is treated by different correlations according to the liquid droplet Reynolds numbers. An erosion-corrosion model is set up to address the local corrosion and erosion induced by the droplets impinging on the pipe surfaces. Three typical cases are studied and the mechanism of erosion-corrosion for different positions is investigated. It is explored by the numerical simulation that the erosion-corrosion changes with the practical production conditions: Under lower production rate, chemical corrosion is the main cause for erosion-corrosion; under higher production rate, erosion predominates greatly; and under very high production rate, erosion becomes the main cause. It is clarified that the parts including connection site of oil pipe, oil pipe set, and valve are the places where erosion-corrosion origins and becomes serious. The failure mechanism is explored and good comparison with field measurement is achieved.

scholarly journals The Relationship between Fluid Flow, Structures, and Depositional Architecture in Sedimentary Rocks: An Example-Based Overview

Geofluids ◽  
2020 ◽  
Vol 2020 ◽  
pp. 1-19 ◽  
Author(s):  
Vilde Dimmen ◽  
Atle Rotevatn ◽  
Casey W. Nixon
Keyword(s):  
Fluid Flow ◽  
Sedimentary Rocks ◽  
Structure Type ◽  
Mineral Dissolution ◽  
Rock Properties ◽  
Hydrocarbon Migration ◽  
Geological Processes ◽  
Wide Range ◽  
Depositional Architecture ◽  
The Relationship

Fluid flow in the subsurface is fundamental in a variety of geological processes including volcanism, metamorphism, and mineral dissolution and precipitation. It is also of economic and societal significance given its relevance, for example, within groundwater and contaminant transport, hydrocarbon migration, and precipitation of ore-forming minerals. In this example-based overview, we use the distribution of iron oxide precipitates as a proxy for palaeofluid flow to investigate the relationship between fluid flow, geological structures, and depositional architecture in sedimentary rocks. We analyse and discuss a number of outcrop examples from sandstones and carbonate rocks in New Zealand, Malta, and Utah (USA), showing controls on fluid flow ranging from simple geological heterogeneities to more complex networks of structures. Based on our observations and review of a wide range of the published literature, we conclude that flow within structures and networks is primarily controlled by structure type (e.g., joint and deformation band), geometry (e.g., length and orientation), connectivity (i.e., number of connections in a network), kinematics (e.g., dilation and compaction), and interactions (e.g., relays and intersections) within the network. Additionally, host rock properties and depositional architecture represent important controls on flow and may interfere to create hybrid networks, which are networks of combined structural and stratal conduits for flow.

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