Understanding Fluid Flow Behavior in Fractured Reservoir using Dual Porosity Dual Permeability and Discretized Fracture Model

2019 ◽  
Author(s):  
Sarwesh Kumar ◽  
Alvaro Rey ◽  
Gaelle Dufour ◽  
Babafemi Ogunyomi
Keyword(s):  
Fluid Flow ◽  
Flow Behavior ◽  
Fracture Model ◽  
Dual Porosity ◽  
Fractured Reservoir

Numerical Simulation of Coning Behavior of a Single Well in a Naturally Fractured Reservoir

1983 ◽  
Vol 23 (06) ◽  
pp. 879-884 ◽  
Author(s):  
Huan-Zhang Chen
Keyword(s):  
Mass Transfer ◽  
Fluid Flow ◽  
History Matching ◽  
Petroleum Exploration ◽  
Dual Porosity ◽  
Fractured Reservoir ◽  
Axially Symmetric ◽  
Drainage Radius ◽  
Water Zone ◽  
Insight Into

Chen, Huan-Zhang; Scientific Research Inst. of Petroleum Exploration and Development Abstract The history matching and predicting of an actual well in a reservoir with double porosity is performed with a new coning simulation model that gives satisfactory results. A discussion of the parameters used for matching provides some insight into the structure and parameters of provides some insight into the structure and parameters of the reservoir. Other points discussed includebottomwater rising characteristics,a comparison between the dual porosity and the single porosity (assuming that the mass transfer between the fracture and matrix is equal to zero), andthe imbibition characteristics of matrix. Introduction The mathematical equations describing fluid flow in the dual-porosity medium were presented in the 1960's. Kazemi et al. obtained the numerical solution of this problem in 1976 but did not present the solution of problem in 1976 but did not present the solution of coning, and the flow terms of matrix in the equations were neglected. Since 1977, Wu Wan-yi of Beijing U. has done extensive research on this aspect. His work-the axially symmetric water coning problem-is based on a dual-porosity-medium model and equations presented by Barenblatt and Jeltov. All the terms that should appear in the equations are included-i.e., the fluid flow between the matrix blocks has not been neglected. The harmonic average value of mobility of fissure and matrix is used as the imbibition coefficient. All nonlinear coefficients are linearized, and the semi-implicit scheme is used in the difference equations. These equations are solved by the direct solution method. We performed a further study based on these works, using an improved program to give a good history matching with an actual program to give a good history matching with an actual well behavior. Our results are discussed in detail in this paper. This method may be used to solve the problems of paper. This method may be used to solve the problems of multidimensional, two-phase fluid flow. Model Structure The structure of the model is shown in Fig. 1. It is a cylinder, which represents a part of the reservoir controlled by the well. Its axis coincides with the axis of the well, and the radius of the cylinder represents the drainage radius of the well. The top and flank of this cylinder are impervious. The bottomwater is supplied from the lower surface of the cylinder, and the pressure on this surface is maintained at a constant value. The upper part of the cylinder is oil zone, the middle is transition zone, and the lower is water zone. The well may be perforated in both oil zone and water zone or in only one of the two zones. In any given depth, there may be a horizontal thin impervious break with a changeable radius. Fluid-Flow Equations Assume that the fluids are immiscible, and that both the medium and fluids are slightly compressible. In addition to the continuous flow in fracture and matrix, there is the mass transfer between the fracture and matrix. Under these assumptions, the flow of fluids satisfies the following equations. ..........................................(1) SPEJ p. 879

Capturing the Effect of Fracture Heterogeneity on Multiphase Flow During Fluid Injection

2013 ◽  
Vol 16 (02) ◽  
pp. 194-208 ◽  
Author(s):  
S.. Jonoud ◽  
O.P.. P. Wennberg ◽  
G.. Casini ◽  
J.A.. A. Larsen
Keyword(s):  
Fluid Flow ◽  
Multiphase Flow ◽  
Oil Recovery ◽  
Large Scale ◽  
Flow Behavior ◽  
Fractured Reservoirs ◽  
Scale Up ◽  
Carbonate Reservoir ◽  
Fracture Model ◽  
Dynamic Simulations

Summary Carbonate fractured reservoirs introduce a tremendous challenge to the upscaling of both single- and multiphase flow. The complexity comes from both heterogeneous matrix and fracture systems in which the separation of scales is very difficult. The mathematical upscaling techniques, derived from representative elementary volume (REV), must therefore be replaced by a more realistic geology-based approach. In the case of multiphase flow, an evaluation of the main forces acting during oil recovery must also be performed. A matrix-sector model from a highly heterogeneous carbonate reservoir is linked to different fracture realizations in dual-continuum simulations. An integrated iterative workflow between the geology-based static modeling and the dynamic simulations is used to investigate the effect of fracture heterogeneity on multiphase fluid flow. Heterogeneities at various scales (i.e., diffuse fractures and subseismic faults) are considered. The diffuse-fracture model is built on the basis of facies and porosity from the matrix model together with core data, image-log data, and data from outcrop-analogs. Because of poor seismic data, the subseismic-fault model is mainly conceptual and is based on the analysis of outcrop-analog data. Fluid-flow simulations are run for both single-phase and multiphase flow and gas and water injections. A better understanding of fractured-reservoirs behavior is achieved by incorporating realistic fracture heterogeneity into the geological model and analyzing the dynamic impact of fractures at various scales. In the case of diffuse fractures, the heterogeneity effect can be captured in the upscaled model. The subseismic faults, however, must be explicitly represented, unless the sigma (shape) factor is included in the upscaling process. A local grid-refinement approach is applied to demonstrate explicit fractures in large-scale simulation grids. This study provides guidelines on how to effectively scale up a heterogeneous fracture model and still capture the heterogeneous flow behavior.

An Integrated Geologic and Engineering Assessment of Fracture-Flow Potential in the Ratawi Reservoir of the Wafra Field, Partitioned Neutral Zone

2008 ◽  
Vol 11 (06) ◽  
pp. 1071-1081 ◽  
Author(s):  
Amy Whitaker ◽  
C. Shah Kabir ◽  
Wayne Narr
Keyword(s):  
Transient Analysis ◽  
Water Injection ◽  
Flow Simulation ◽  
Simulation Models ◽  
Dual Porosity ◽  
Fracture Flow ◽  
Fractured Reservoir ◽  
Horizontal Drilling ◽  
Rate Transient Analysis ◽  
Production Characteristics

Summary The extent to which fractures affect fluid pathways is a vital component of understanding and modeling fluid flow in any reservoir. We examined the Wafra Ratawi grainstone for which production extending for 50 years, including recent horizontal drilling, has provided some clues about fractures, but their exact locations, intensity, and overall effect have been elusive. In this study, we find that a limited number of total fractures affect production characteristics of the Ratawi reservoir. Although fractures occur throughout the Wafra field, fracture-influenced reservoir behavior is confined to the periphery of the field where the matrix permeability is low. This work suggests that for the largest part of the field, explicit fractures are not necessary in the next-generation Earth and flow-simulation models. The geologic fracture assessment included seismic fault mapping and fracture interpretation of image logs and cores. Fracture trends are in the northeast and southwest quadrants, and fractures are mineralized toward the south and west of the field. Pressure-falloff tests on some peripheral injectors indicate partial barriers, and most of these wells lie on seismic-scale faults in the reservoir, suggesting partial sealing. A few wells show fractured-reservoir production characteristics, and rate-transient analysis on a few producers indicates localized dual-porosity behavior. Producers proximal to dual-porosity wells display single-porosity behavior, however, to attest to the notion of localized fracture response. The spatially restricted fracture-flow characteristics appear to correlate with fracture or vug zones in a low-permeability reservoir. Presence of fracture-flow behavior was tested by constructing the so-called flow-capacity index (FCI), the ratio of khwell (well test-derived value) to khmatrix (core-derived property). Data from 80 wells showed khmatrix to be consistently higher than khwell, a relationship that suggests insignificant fracture production in these wells. Introduction The Wafra field is in the Partitioned Neutral Zone (PNZ) between Kuwait and Saudi Arabia, as shown in Fig. 1. The field has been producing since the 1950s and has seen renewed drilling activity since the late 1990s, including horizontal drilling and implementation of peripheral water injection (Davis and Habib 1999). The Lower Cretaceous Ratawi formation contains the most reserves of the producing intervals at Wafra. The Ratawi oolite (a misnomer--it is a grainstone) reservoir has variable porosity (5 to 35%) and permeability that ranges from tens to hundreds of md (Longacre and Ginger 1988). The main Wafra structure is a gentle (i.e., interlimb angle >170°), doubly plunging anticline trending north-northwest to south-southeast, which culminates near its northern end. The East Wafra spur is a north-trending branch that extends from the center of the main Wafra structure. As seen in Fig. 1, relief on the Main Wafra structure exceeds that on East Wafra. The Ratawi oolite in the Wafra field has been studied at length, and various authors have reported geologic and engineering elements, leading to reservoir characterization and understanding of reservoir performance. Geologic studies are those of Waite et al. (2000) and Sibley et al. (1997). In contrast, Davis and Habib (1999) presented implementation of peripheral water injection, whereas Chawathé et al. (2006) discussed realignment of injection pattern owing to lack of pressure support in the reservoir interior. Previous studies considered the reservoir to behave like a single-porosity system. But recent image-log fracture interpretations indicate high fracture densities, suggesting that the implementation of a dual-porosity model may be necessary because the high impact of fractures during field development has been recognized in some Middle East reservoirs for more than 50 years (Daniel 1954). Static and dynamic data are required to characterize fracture reservoir behavior accurately (Narr et al. 2006). Geologic description of the fracture system, by use of cores, borehole images, seismic data, and well logs, does not in itself determine whether fractures affect reservoir behavior. While seismic and some image logs were available to locate fractures in the Wafra Ratawi reservoir, no dynamic testing with the specific objective of understanding fracture impact has occurred. So, to determine whether fractures influence oil productivity significantly, we used diagnostic analyses of production data and well tests of available injectors. The assessment of fracture effects in the Ratawi reservoir will be used to guide the next generation of geologic and flow-simulation models. Dynamic data involving pressure and rate have the potential to reveal the influence of open fractures in production performance. Unfortunately, pressure-transient testing on single wells does not always provide conclusive evidence about the presence of fractures with the characteristic dual-porosity dip on the pressure-derivative signature (Bourdet et al. 1989). That is because a correct mixture of matrix/fracture storativity must be present for the characteristic signature to appear (Serra et al. 1983). In practice, interference testing (Beliveau 1989) between wells appears to provide more-definitive clues about interwell connectivity, leading to inference about fractures. In contrast to pressure-transient testing, rate-transient analysis offers the potential to provide the same information without dedicated testing. In this field, all wells are currently on submersible pumps. Consequently, the pump-intake pressure and measured rate provided the necessary data for pressure/rate convolution or rate-transient analysis. We provide the Ratawi-reservoir case study primarily as an example of the integration of diverse geologic and engineering data to develop an assessment of fracture influence on reservoir behavior. It illustrates the use of production-data diagnostic tests to determine fracture influence in the absence of targeted fracture-analysis testing. The workflow can be applied to similar static/dynamic problems, such as fault-transmissivity determination. Secondly, this analysis illustrates the process of deciding that fractures, although present throughout the reservoir, may not lead to widespread fractured-reservoir characteristics (e.g., Allan and Sun 2003).

Effects of Nano-Nozzles Cross-Sectional Geometry on Fluid Flow: Molecular Dynamic Simulation

2017 ◽  
Vol 34 (5) ◽  
pp. 667-678 ◽  
Author(s):  
H. Nowruzi ◽  
H. Ghassemi
Keyword(s):  
Fluid Flow ◽  
Velocity Profile ◽  
Cross Sections ◽  
Md Simulation ◽  
Flow Behavior ◽  
Water Model ◽  
Physical Parameters ◽  
Cross Sectional ◽  
Behavior Characteristics ◽  
Fanning Friction Factor

AbstractNano-nozzles are an essential part of the nano electromechanical systems (NEMS). Cross-sectional geometry of nano-nozzles has a significant role on the fluid flow inside them. So, main purpose of the present study is related to the effects of different symmetrical cross-sections on the fluid flow behavior inside of nano-nozzles. To this accomplishment, five different cross-sectional geometries (equilateral triangle, square, regular hexagon, elliptical and circular) are investigated by using molecular dynamics (MD) simulation. In addition, TIP4P is used for atomistic water model. In order to evaluate the fluid flow behavior, non-dimensional physical parameters such as Fanning friction factor, velocity profile and density number are analyzed. Obtained results are shown that the flow behavior characteristics appreciably depend on the geometry of nano-nozzle's cross-section. Velocity profile and density number for five different cross sections of nano-nozzle at three various measurement gauges are presented and discussed.

In Vitro Stain Transport in Canaliculi of Rat Femora Under Cyclic Loading

2000 ◽  
Author(s):  
Bixia Li ◽  
Timothy L. Norman
Keyword(s):  
Fluid Flow ◽  
Cyclic Loading ◽  
Confocal Microscopy ◽  
Mechanical Loading ◽  
Cyclic Load ◽  
Flow Behavior ◽  
Load Level ◽  
Static Conditions ◽  
Rat Bone

Abstract In this study, rat femurs were used to test the diffusion and mechanical transport properties of a fluroscein stain tracer in microvessels of bone. Fluroscein was used as a tracer to visualize the fluid flow behavior using confocal microscopy. It was found that stain transport occurs due to diffusion under static conditions and due to mechanical loading. The transport increased with cyclic load level and frequency. Our results also show that stain transport at the canaliculi level occurs rapidly in rat bone.

Pressure-Transient Tests and Flow Regimes in Fractured Reservoirs

2015 ◽  
Vol 18 (02) ◽  
pp. 187-204 ◽  
Author(s):  
Fikri Kuchuk ◽  
Denis Biryukov
Keyword(s):  
History Matching ◽  
Fractured Reservoirs ◽  
Flow Regimes ◽  
Naturally Fractured Reservoirs ◽  
Dual Porosity ◽  
Hydraulic Fractures ◽  
Fractured Reservoir ◽  
Pressure Transient ◽  
Matrix Block ◽  
Naturally Fractured

Summary Fractures are common features in many well-known reservoirs. Naturally fractured reservoirs include fractured igneous, metamorphic, and sedimentary rocks (matrix). Faults in many naturally fractured carbonate reservoirs often have high-permeability zones, and are connected to numerous fractures that have varying conductivities. Furthermore, in many naturally fractured reservoirs, faults and fractures can be discrete (rather than connected-network dual-porosity systems). In this paper, we investigate the pressure-transient behavior of continuously and discretely naturally fractured reservoirs with semianalytical solutions. These fractured reservoirs can contain periodically or arbitrarily distributed finite- and/or infinite-conductivity fractures with different lengths and orientations. Unlike the single-derivative shape of the Warren and Root (1963) model, fractured reservoirs exhibit diverse pressure behaviors as well as more than 10 flow regimes. There are seven important factors that dominate the pressure-transient test as well as flow-regime behaviors of fractured reservoirs: (1) fractures intersect the wellbore parallel to its axis, with a dipping angle of 90° (vertical fractures), including hydraulic fractures; (2) fractures intersect the wellbore with dipping angles from 0° to less than 90°; (3) fractures are in the vicinity of the wellbore; (4) fractures have extremely high or low fracture and fault conductivities; (5) fractures have various sizes and distributions; (6) fractures have high and low matrix block permeabilities; and (7) fractures are damaged (skin zone) as a result of drilling and completion operations and fluids. All flow regimes associated with these factors are shown for a number of continuously and discretely fractured reservoirs with different well and fracture configurations. For a few cases, these flow regimes were compared with those from the field data. We performed history matching of the pressure-transient data generated from our discretely and continuously fractured reservoir models with the Warren and Root (1963) dual-porosity-type models, and it is shown that they yield incorrect reservoir parameters.

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