Dual Permeability Simulation - reservoirengineering.org.uk by dandanhuanghuang

VIEWS: 26 PAGES: 15

									  Nov-09
NOTES:

           The papers listed here have been obtained by search SPE and IPTC papers post 2005 on the SPE's OnePetro
           The papers relating to reservoir engineering have been catergorised for inclusion on the   reservoirengineering.org.uk website
           The affiiations searched were;

                                                                    Total No Papers     Reservoir Engineering Related
                      BP                                                   551                      175
                      Shell                                                575                      279
                      Chevron                                              482                      238
                      ConocoPhillips                                       191                       68
                      Marathon                                             55                        37
                      Total                                                255                      129
                      Schlumberger                                        1130                      563
                      Imperial College, London                             95                        53
                      Heriot Watt University, Edinburgh                    235                      175
                      (Anywhere in Article)
                                                      Total               3569                          1717



                      Total number of papers published post 2005 =             10,000

                                                                   35% of papers published categorised
                                Paper
Organisation             Source No.          Chapter                     Section
BP                         SPE   102542   Reservoir Modelling    Dual Permeability Simulation
Imperial College           SPE    93144   Reservoir Modelling    Dual Permeability Simulation
MARATHON                  IPTC    11778   Reservoir Modelling    Dual Permeability Simulation
SHELL                      SPE   104580   Reservoir Modelling    Dual Permeability Simulation
TOTAL                      SPE   113890   Reservoir Modelling    Dual Permeability Simulation
TOTAL                      SPE   121244   Reservoir Modelling    Dual Permeability Simulation
Imperial College           SPE   101113   Reservoir Modelling    Dual Permeability Simulation
Heriot Watt University     SPE   107485   Reservoir Modelling   Naturally Fractured Reservoirs
BP                         SPE   100079   Reservoir Modelling   Naturally Fractured Reservoirs
TOTAL                      SPE   102165   Reservoir Modelling   Naturally Fractured Reservoirs
SCHLUMBERGER               SPE   117370   Reservoir Modelling   Naturally Fractured Reservoirs

CHEVRON                    SPE   103901   Reservoir Modelling   Naturally Fractured Reservoirs
SCHLUMBERGER               SPE   101674   Reservoir Modelling   Naturally Fractured Reservoirs
SCHLUMBERGER               SPE    95498   Reservoir Modelling   Naturally Fractured Reservoirs
SHELL                      SPE    95498   Reservoir Modelling   Naturally Fractured Reservoirs
SHELL                      SPE    88761   Reservoir Modelling   Naturally Fractured Reservoirs
SCHLUMBERGER               SPE   115881   Reservoir Modelling   Naturally Fractured Reservoirs
MARATHON                   SPE   113651   Reservoir Modelling   Naturally Fractured Reservoirs
TOTAL                      SPE   107525   Reservoir Modelling   Naturally Fractured Reservoirs
TOTAL                     IPTC    11320   Reservoir Modelling   Naturally Fractured Reservoirs
SHELL                      SPE   102471   Reservoir Modelling   Naturally Fractured Reservoirs
SCHLUMBERGER               SPE   102549   Reservoir Modelling   Naturally Fractured Reservoirs
SCHLUMBERGER               SPE   107471   Reservoir Modelling   Naturally Fractured Reservoirs
SCHLUMBERGER               SPE   119132   Reservoir Modelling   Naturally Fractured Reservoirs
MARATHON                   SPE   109821   Reservoir Modelling   Naturally Fractured Reservoirs
MARATHON                   SPE   124213   Reservoir Modelling   Naturally Fractured Reservoirs

CHEVRON                   SPE    102491   Reservoir Modelling   Naturally Fractured Reservoirs


CHEVRON                   SPE    109686   Reservoir Modelling   Naturally Fractured Reservoirs

Imperial College          SPE     98108   Reservoir Modelling   Naturally Fractured Reservoirs
Heriot Watt University    SPE     99920   Reservoir Modelling   Naturally Fractured Reservoirs
Heriot Watt University    SPE    118924   Reservoir Modelling   Naturally Fractured Reservoirs
          Subject
      Transfer Functions
      Transfer Functions
      Transfer Functions
      Transfer Functions
      Transfer Functions
      Transfer Functions
  With Adsorption Behaviour
        3 Phase Model
   Compositional Modelling
  Discrete Fracture Modelling
Dual Porosity Model Applicability

   Finite Volume Formulation
     Gas Oil Displacement
        History Matching
        History Matching
 History Matching - Case Study
       Multiple Reservoirs
 Multiscale Compositional Moel
      Pragmatic Modelling
         Respresentation
          Shape Factor
           Streamlines
           Streamlines
           Streamlines
       Transfer Functions
       Transfer Functions

           Upscaling


           Upscaling

          Waterflood
                                              Title
General Transfer Functions for Multiphase Flow in Fractured Reservoirs
Multirate-Transfer Dual-Porosity Modeling of Gravity Drainage and Imbibition
A Critical Review for Proper Use of Water-Oil-Gas Transfer Functions in Dual-Porosity Naturally Fractured Reservoirs – Part
Verification and Proper Use of Water-Oil Transfer Function for Dual-Porosity and Dual-Permeability Reservoirs
Matrix-Fracture Transfer Function in Dual-Medium Flow Simulation: Review, Comparison, and Validation
SubFace Matrix-Fracture Transfer Function: Improved Model of Gravity Drainage/ Imbibition
A Multicomponent Dual-Porosity Model for Gas Reservoir Flow With Adsorption Behaviour
Black-Oil Simulations for Three-Component, Three-Phase Flow in Fractured Porous Media
A Fully Implicit, Compositional, Parallel Simulator for IOR Processes in Fractured Reservoirs
Characterisation and Modelling of a Fractured Reservoir Using a Novel DFN Approach
Why Dual Porosity Models are not Applicable for Simulation of the Near-Wellbore Zone of Gas Condensate Well for Naturally F
Efficient Field-Scale Simulation for Black Oil in a Naturally Fractured Reservoir via Discrete Fracture
Networks and Homogenized Media
Simulation of Gas/Oil Displacements in Vuggy and Fractured Reservoirs
History Matching of Naturally Fractured Reservoirs Using Elastic Stress Simulation and Probability Perturbation Method
History Matching of Naturally Fractured Reservoirs Using Elastic Stress Simulation and Probability Perturbation Method
Practical Flow-Simulation Method for a Naturally Fractured Reservoir: A Field Study
Multiple Reservoir Simulations Integration: An Alternative to Full Field Simulation in the North Kuwait Jurassic Complex
Multiscale Compositional Simulation of Naturally Fractured Resevoirs
Fast and Efficient Modeling and Conditioning of Naturally Fractured Reservoir Models Using Static and Dynamic Data
Simulating Karstic Conduits as Wells in a Commercial Reservoir Simulator
Thermal and Hydraulic Matrix-Fracture Interaction in Dual-Permeability Simulation
A Three-Phase Compressible Dual-Porosity Model for Streamline Simulation
Implicit 1-D Transport Solvers For a Streamline Simulator For Fractured Reservoirs
Multiscale Mimetic Solvers for Efficient Streamline Simulation of Fractured Reservoirs
A Critical Review for Proper Use of Water/Oil/Gas Transfer Functions in Dual-Porosity Naturally Fractured Reservoirs: Part I
A Critical Review for Proper Use of Water/Oil/Gas Transfer Functions in Dual-Porosity Naturally Fractured Reservoirs: Part II
Upscaling Discrete Fracture Characterizations to Dual-Porosity, Dual-Permeability Models for
Efficient Simulation of Flow With Strong Gravitational Effects

Development and Application of New Computational Procedures for Modeling Miscible Gas Injection
in Fractured Reservoirs
Control-Volume Model for Simulation of Water Injection in Fractured Media: Incorporating Matrix
Heterogeneity and Reservoir Wettability Effects
Experimental and Simulation Studies of SAGD Process in Fractured Reservoirs
Massively Parallel Sector Scale Discrete Fracture and Matrix Simulations
                                Author                                     Abstract
                                                                            Summary We propose a physically motivated form
Huiyun Lu, SPE, Sasol Petroleum; Ginevra Di Donato, SPE, BP; and Martin J. Blunt, SPE, Imperial College London
                                                                            Summary We develop a physically
Ginevra Di Donato, SPE, Huiyun Lu, SPE, Zohreh Tavassoli, SPE, and Martin J. Blunt, SPE, Imperial College motivated appr
                                                                                       Porosity is Part Company
                                                                             and S. This paper Naturally Fractured Reservoirs
M. Al-Kobaisi , H. Kazemi, B. Ramirez, E. Ozkan, Colorado School of Mines,AbstractAtan, Marathon Oil II of SPE 109821. In Pa
                                                                            Summary Permeability SPE, Colorado School of
                                                                                       B. Ramirez, Reservoirs
A. Balogun, SPE, Shell E&P, H. Kazemi, SPE, E. Ozkan, SPE, M. Al-Kobaisi, SPE, andAccurate calculation of multiphase fluidM
Ahmad S. A. Abushaikha1, SPE, and Olivier R. Gosselin, SPE, TOTAL S.A. Abstract Most of porous naturally fractured reservo
                                                                            Abstract Gravity
Ahmad S. A. Abushaikha, SPE, Qatar Petroleum, and Olivier R. Gosselin, SPE, TOTAL S.A. is a major recovery mechanism of
M. Lu, SPE, and L.D. Connell, SPE, CSIRO Petroleum                          Abstract This study presents a modified dual-poro
                                                                            Summary Phase Flow in R. Helmig,Porous Media
                                                                                        Niessner and Fractured and simulati
S. Geiger, SPE, Heriot-Watt University; S. Matth�i, SPE, University of Leoben; and J.Discrete-fracture modelingUniversity of
                                                                            Summary Naturally fractured reservoirs contain
Reza Naimi-Tajdar, SPE, Choongyong Han, SPE, Kamy Sepehrnoori, SPE, Todd J. Arbogast, SPE, and Mark A. Miller, SPE,aU
F. Gouth and A. Toublanc, Total, and M. Mresah, CPTL                        Abstract Characterising and modelling of naturally
D.Rudenko, A.Shandrygin and A.Zyryanova, SPE, Schlumberger                  Abstract The peculiarities of retrograde condensati

Liyong Li and Seong H. Lee, Chevron Energy Technology Co.                 Abstract This paper describes a hybrid finite volum
C.A. Kossack, SPE, Schlumberger                                           Abstract The presence of vugs in a naturally fractu
                                                                          Summary The U.; and Dietmar Mueller, SPE, Sh
Satomi Suzuki, SPE, Stanford U.; Colin Daly, SPE, Schlumberger; Jef Caers, SPE, Stanfordapplication of elastic stress simulat
                                                                          Summary The U.; and Dietmar Mueller, SPE, Sh
Satomi Suzuki, SPE, Stanford U.; Colin Daly, SPE, Schlumberger; Jef Caers, SPE, Stanfordapplication of elastic stress simulat
                                                                          Summary This paper presents the methodology im
S.E. Salem, SPE, M. Al-Deeb, SPE, M. Abdou, SPE, and S. Linthorst, SPE, ADCO; A. Bahar, SPE, Kelkar and Assocs. Inc.; an
                                                                          Abstract The North Kuwait Jurassic Complex cons
Kassem Ghorayeb, SPE, Manoch Limsukhon, SPE, Schlumberger, Qasem Dashti, SPE, Rafi Mohammad Aziz, SPE, Kuwait O
                                                                          Abstract To and Hossein Kazemi, SPE, of fluid flo
B. Ramirez, SPE, Colorado School of Mines; Safian Atan, SPE, Marathon Oil Company; obtain accurate descriptionsColorado S
M. Garcia, FSS Intl., and F. Gouth and O. Gosselin, Total                 Abstract A large proportion of petroleum reservoirs
Monia Herriou and John W. Barker, SPE, Total SA                           Abstract Karst is a generic term for the effects of m
                                                                          Boerrigter, Shell Technology Oman, originally intr
A.P.G. van Heel, Shell Technology Oman, Muscat, Sultanate of Oman; P.M.Summary The shape factor concept Muscat, Sulta
                                                                          Abstract Streamline methods as a reservoir simula
A. Kozlova, Schlumberger Moscow Research; F. Bratvedt, Schlumberger Information Solutions, Oslo; and K. Bratvedt and A. M
Nikolay Andrianov, Kyrre Bratvedt, and Artyom Myasnikov, Schlumberger Abstract Naturally fractured reservoirs can be seen
                                                                          Abstract Advances Lie, SINTEF ICT; and V. Lapt
J.R. Natvig and B. Skaflestad, SINTEF�ICT; F. Bratvedt and K. Bratvedt, Schlumberger; K.-A.in reservoir characterization an
                                                                          Colorado Accurate calculation S. Atan, SPE, Mar
B. Ramirez, SPE, H. Kazemi, SPE, M. Al-Kobaisi, SPE, and E. Ozkan, SPE, Summary School of Mines; and of multiphase-fluid
                                                                           Colorado This paper continues the work presente
M. Al-Kobaisi , SPE, H. Kazemi, SPE, B. Ramirez, SPE, and E. Ozkan, SPE,Summary School of Mines; and S. Atan, SPE, Ma
B. Gong, SPE, M. Karimi-Fard, SPE, and L.J. Durlofsky, SPE, Stanford
University                                                                Summary The geological complexity of fractured r
Mun-Hong Hui,�SPE, and Bin Gong, SPE, Chevron Energy Technology
Company, and Mohammad Karimi-Fard, SPE, and Louis J. Durlofsky,
SPE, Stanford University                                                  Abstract Detailed geological characterizations of na

                                                                         Summary
J.E.P. Monteagudo and A. Firoozabadi, SPE, Reservoir Engineering Research Institute The control-volume discrete-fracture (C
A.S. Bagci, SPE, Heriot-Watt U.                                          ABSTRACT Experimental studies present the eff
                                                                         Abstract Edinburgh; S. able to SPE, Montan Univ
S. Geiger, SPE, Heriot-Watt University; Q. Huangfu and�F. Reid, The University of We have beenMatthai, solve a reservoir s
se a physically motivated formulation for the matrix/fracture transfer function in dual-porosity and dual-permeability reservoir simulation. The
op a physically motivated approach to modeling displacement processes in fractured reservoirs. To find matrix/fracture transfer functions in a
Naturally Fractured Reservoirs – Part II
 lity Reservoirs
  us naturally fractured reservoirs present a two-timescale flow-system due to a two-scale heterogeneity which cannot be modelled explicitly
major recovery mechanism of naturally fractured reservoirs where fracture gas drains matrix oil until equilibrium is reached with the capillary
presents a modified dual-porosity model for multi-species gas flow with adsorption behaviour which is formulated from an exact formal soluti
ow in Fractured Porous Media
 ractured reservoirs contain a significant amount of the world oil reserves. A number of these reservoirs contain several billion barrels of oil. A
ng and modelling of naturally fractured reservoirs (NFR) with fracturing at different scales is usually a challenging task as the specific respon
 ities of retrograde condensation in the near wellbore region in naturally fractured formation were studied with the use of dual-porosity/dual pe

describes a hybrid finite volume method designed to simulate multi-phase flow in a field-scale naturally fractured reservoir. Lee et al. (WRR
ce of vugs in a naturally fractured reservoir can be a significant source of reserves.� These vugs can be connected to the fracture system
 ation of elastic stress simulation for fracture modeling provides a more realistic description of fracture distribution than conventional statistica
 ation of elastic stress simulation for fracture modeling provides a more realistic description of fracture distribution than conventional statistica
r presents the methodology implementation and results of the dynamic modeling of a naturally fractured carbonate reservoir which consists
 uwait Jurassic Complex consists of five fields each with three identified reservoirs within the naturally fractured Jurassic carbonate formation
 curate descriptions of fluid flow in the reservoir it is necessary to include detailed geological information on the scale of geocellular models.
 ortion of petroleum reservoirs is known to be naturally fractured with consequences on their flow behavior hence on reservoir performance. T
 neric term for the effects of meteoric (rain) water on carbonate rocks. Resulting features include rock dissolution conduits sink-holes etc w
e factor concept originally introduced by Barenblatt in 1960 provides an elegant and powerful upscaling method for fractured reservoir simul
methods as a reservoir simulation tool have generated a great deal of interest in petroleum engineering because of the capability to calculate
 ctured reservoirs can be seen as a set of low permeability matrix rock blocks and a high permeability network of fracture channels. This repr
n reservoir characterization and modeling have given the industry improved ability to build detailed geological models of petroleum reservoirs
calculation of multiphase-fluid transfer between the fracture and matrix in naturally fractured reservoirs is a crucial issue. In this paper we wil
r continues the work presented in Ramirez et al. (2009). In Part I we discussed the viability of the use of simple transfer functions to accurate

gical complexity of fractured reservoirs requires the use of simplified models for flow simulation. This is often addressed in practice by using


 logical characterizations of naturally fractured reservoirs are commonly in the form of discrete fracture models in which each fracture is defi

ol-volume discrete-fracture (CVDF) model is extended to incorporate heterogeneity in rock and in rock-fluid properties. A novel algorithm is p
mental studies present the effect of horizontal and vertical fractures and well configurations on the SAGD process in a three-dimensional mo
een able to solve a reservoir simulation problem which was previously thought of as intractable:�We simulated multiphase displacement in
ermeability reservoir simulation. The approach currently applied in commercial simulators (Barenblatt et al. 1960; Kazemi et al. 1976) uses a
matrix/fracture transfer functions in a dual-porosity model we use analytical expressions for the average recovery as a function of time for ga


which cannot be modelled explicitly nor homogenised in reservoir simulation models. When the only flowing domain is the fracture network
                                                    fluid densities matrix gas capillary pressure and block height). The challenge of modelling g
uilibrium is reached with the capillary forces (wrt OnePetro
rmulated from an exact formal solution of a linear multi-component gas diffusion process within a porous matrix block. Therefore the couplin

contain several billion barrels of oil. Accurate and efficient reservoir simulation of naturally fractured reservoirs is one of the most important c
allenging task as the specific response from each scale is difficult to isolate. We focus on a carbonate reservoir in North Africa in productio
 with the use of dual-porosity/dual permeability models and the direct numerical simulation based on the “Sugar Cube19 representation o

                                                                                        OnePetro
fractured reservoir. Lee et al. (WRR 37:443-455 2001) developed a hierarchical approach in which the permeability contribution from short f
be connected to the fracture system or be isolated in matrix material which constitutes a triple porosity system.� The modeling of the disp
stribution than conventional statistical and geostatistical techniques allowing the integration of geomechanical data and models into reservo
stribution than conventional statistical and geostatistical techniques allowing the integration of geomechanical data and models into reservo
d carbonate reservoir which consists of a fracture swarm system and high matrix permeability. The focus of this paper is on the description o
                                                                                         at near critical conditions with flow properties ranging from
actured Jurassic carbonate formation. These reservoirs contain multiple fluid typesOnePetro OnePetro
 on the scale of geocellular models. However computation resources are often overwhelmed by the vast amount of information that geocellu
or hence on reservoir performance. Though the modeling of such reservoirs has been the purpose of many research works it remains a cha
ssolution conduits sink-holes etc which may have extremely high permeability. Fluid flow simulations in such environments are therefore v
 method for fractured reservoir simulation. The shape factor determines the fluid and heat transfer between matrix and fractures when there
because of the capability to calculate fluid flow in multi-million cell geological models with reasonable CPU times. Recently streamline simul
twork of fracture channels. This representation is conventionally described by a dual porosity model which is the one used in the present wo
gical models of petroleum reservoirs. These models are characterized by complex shapes and structures with discontinuous material proper
 a crucial issue. In this paper we will present the viability of the use of simple transfer functions to account accurately for fluid exchange resu
                                                   for fluid exchange as the result of capillary gravity and diffusion mass transfer for immiscibl
 simple transfer functions to accurately account OnePetro

often addressed in practice by using flow modeling procedures based on the dual-porosity dual-permeability concept. However in most exis


models in which each fracture is defined explicitly. The efficient simulation of flow processes in such models poses a great challenge. In rece

uid properties. A novel algorithm is proposed to model strong water-wetting with zero capillary pressure in the fractures. The extended metho
D process in a three-dimensional model using 12.4 � and 18 �API gravity crude oils. A total of eleven runs were conducted using a 30
imulated multiphase displacement including viscous capillary and gravitational forces for highly resolved and geologically realistic models
 al. 1960; Kazemi et al. 1976) uses a Darcy-like flux from matrix to fracture assuming a quasisteady state between the two domains that doe
e recovery as a function of time for gas gravity drainage and countercurrent imbibition. For capillary-controlled displacement the recovery ten


wing domain is the fracture network and when the accumulation lies in porous and low permeable matrix blocks the rate of exchanges betw

s matrix block. Therefore the coupling effects of mutual-diffusion are included in the representation. This new respresentation in its first ord

 rvoirs is one of the most important challenging and computationally intensive problems in reservoir engineering. Parallel reservoir simulator
 eservoir in North Africa in production for two years. There is evidence of fracturing at different scales (from diffuse fractures to conductive fa
e “Sugar Cube19 representation of the fractured porous media. Serious spatial inhomogeneity of the saturation distribution in porous mat


 ystem.� The modeling of the displacement of oil from the vugs can not be made with conventional dual porosity reservoir simulators since
hanical data and models into reservoir characterization. The geomechanical prediction of the fracture distribution accounts for the propagatio
hanical data and models into reservoir characterization. The geomechanical prediction of the fracture distribution accounts for the propagatio
 s of this paper is on the description of the dynamic single-media model that was used to history match the production. The challenges in pro

st amount of information that geocellular models contain. The multiscale approach presented in this paper is designed to include the detailed
any research works it remains a challenging task. Too simplistic reservoir models do not allow capturing essential features like large-scale f
 n such environments are therefore very challenging – conventional reservoir simulators often experience convergence problems and run t
een matrix and fractures when there is a difference in pressure or temperature between matrix blocks and the surrounding fractures. An app
PU times. Recently streamline simulation has been applied to fractured reservoirs at the geo-scale. However these simulations have been li
 ich is the one used in the present work. More precisely the porosities and absolute permeabilities at each point of a reservoir are considered
es with discontinuous material properties that span many orders of magnitude. Models that represent fractures explicitly as volumetric objects
unt accurately for fluid exchange resulting from capillary gravity and diffusion mass transfer for immiscible flow between fracture and matrix


bility concept. However in most existing approaches there is not a systematic and quantitative link between the underlying geological mode


dels poses a great challenge. In recent work we developed systematic procedures for upscaling discrete fracture models to coarsescale con

 n the fractures. The extended method is used to simulate: (1) oil production in a layered faulted reservoir (2) laboratory displacement tests i
ven runs were conducted using a 30 cm x 30 cm x 10 cm rectangular-shaped box model. Temperature distributions the rise and growth of
 ed and geologically realistic models of naturally fractured reservoirs (NFR) at the sector i.e. kilometre scale with very reasonable runtime. T
 e between the two domains that does not correctly represent the average transfer rate in a dynamic displacement. On the basis of 1D analys
rolled displacement the recovery tends to its ultimate value with an approximately exponential decay (Barenblatt et al. 1990). When gravity d


ix blocks the rate of exchanges between the two domains drives the recovery of such reservoirs. So called dual-porosity simulation models

 s new respresentation in its first order form exhibits to be a simple algebraic expression that is of an equivalent computational efficiency in

gineering. Parallel reservoir simulators developed for naturally fractured reservoirs can effectively address the computational problem. A new
rom diffuse fractures to conductive faults) �with significant implications for oil production. We first present the way fractures have been fu
 saturation distribution in porous matrix blocks was demonstrated. Dual porosity/permeability models are obviously unable to reproduce spat


ual porosity reservoir simulators since triple porosity system “isolated vugs are not part of the formulation. The simulation of oil productio
 tribution accounts for the propagation of fracture caused by stress perturbation associated with faults. However the challenge lies in estimat
 tribution accounts for the propagation of fracture caused by stress perturbation associated with faults. However the challenge lies in estimat
he production. The challenges in properly quantifying the separate effects of matrix and fracture within the framework of a single-media mod

 er is designed to include the detailed geological information into the flow calculations while making computations less expensive. The disting
g essential features like large-scale fracturing trends or non-linear multivariate relationships between the equivalent (generally anisotropic) p
nce convergence problems and run times of several days are not uncommon even for models with a modest number of grid cells. We propo
nd the surrounding fractures. An appropriate specification of the shape factor is therefore critical for accurate modeling. Since its introduction
wever these simulations have been limited to two-phase incompressible systems. Commercial application of streamline methods to fractured
ch point of a reservoir are considered to be those of two interpenetrating continua the matrix and the fractures one. It is also assumed that th
 ctures explicitly as volumetric objects pose a particular challenge to standard simulation technology with regard to accuracy and computation
ble flow between fracture and matrix in dual-porosity numerical models. The transfer functions are designed for sugar-cube or match-stick id


ween the underlying geological model [in this case a discrete fracture model (DFM)] and the parameters appearing in the flow model. In this


e fracture models to coarsescale continuum descriptions referred to as multiple subregion (MSR) models. In this work we extend these form

 ir (2) laboratory displacement tests in a stack of matrix blocks with a large contrast in fracture and matrix capillary pressure functions and (3
   distributions the rise and growth of the initial steam chamber were observed by using 25 thermocouples. Three different well configuration
 scale with very reasonable runtime. This has been possible because we used massive parallelisation and hierarchical solvers in conjunction
placement. On the basis of 1D analyses in the literature we find expressions for the transfer rate accounting for both displacement and fluid
arenblatt et al. 1990). When gravity dominates the approach to ultimate recovery is slower and varies as a power law with time (Hagoort 198


 led dual-porosity simulation models must incorporate an adequate transfer function between fracture and matrix in order to predict the recov

quivalent computational efficiency in comparison with the traditional Warren and Root. Yet the mutual-diffusion effect is not present in the lat

ss the computational problem. A new accurate parallel simulator for large-scale naturally fractured reservoirs capable of modeling fluid flow
esent the way fractures have been fully characterised using an extensive integration of static (FMI) and dynamic (Well test Pressure Build Up
e obviously unable to reproduce spatial condensate distribution in near wellbore zone of the reservoir but after proper tuning these models ca


ation. The simulation of oil production from triple porosity reservoirs requires the development of composite porosity composite relative perm
However the challenge lies in estimating the past remote stress conditions which induced structural deformation and fracturing the limited ap
However the challenge lies in estimating the past remote stress conditions which induced structural deformation and fracturing the limited ap
 he framework of a single-media model become the major objective of the study. A brief description of the static model (which consists of the

 putations less expensive. The distinguishing characteristic of this paper lies on the procedure used to carry out the computations. The proce
e equivalent (generally anisotropic) permeability of the fracture system and fracture densities and properties to be characterized on a directio
 dest number of grid cells. We propose a method in which the conduits are represented as long horizontal wells with no net production to the
urate modeling. Since its introduction many different values for the shape factor have been proposed in the literature among which the well
on of streamline methods to fractured reservoirs often requires the modeling of at least three compressible fluid phases. Flow simulation of f
 ctures one. It is also assumed that the flow occurs in fractures only i.e. the matrix permeability is equal to zero. Mass transfer between mat
  regard to accuracy and computational efficiency. We present a new simulation approach based on streamlines in combination with a new m
 ned for sugar-cube or match-stick idealizations of matrix blocks. The study relies on numerical experiments involving fine-grid simulation of


  appearing in the flow model. In this work a systematic upscaling procedure is presented to construct a dual-porosity dual-permeability mo


 s. In this work we extend these formulations to generate full dual-porosity dual-permeability MSR models and additionally introduce the use

 x capillary pressure functions and (3) water injection in 2D and 3D fractured media with mixed-wettability state. Our results show that the alg
es. Three different well configurations were investigated – a horizontal injection and production well pair a vertical injection – vertical pr
nd hierarchical solvers in conjunction with a new discrete fracture and matrix modelling (DFM) technique that is based on mixed-dimensional
nting for both displacement and fluid expansion at early and late times. The resultant transfer function is a sum of two terms: a saturation-dep
s a power law with time (Hagoort 1980). We apply transfer functions based on these expressions for core-scale recovery in field-scale simula


 d matrix in order to predict the recovery mechanisms for an optimal reservoir management. This is still true for dual-porosity / dual-permeab

 ffusion effect is not present in the latter one. A numerical algorithm is also developed for this model when the full form of it which is of an in

 rvoirs capable of modeling fluid flow in both rock matrix and fractures has been developed. The simulator is a parallel 3D fully implicit equ
dynamic (Well test Pressure Build Up Mud losses) data. The advanced use of well test signatures in understanding the main flow mechanis
  after proper tuning these models can be used for the simulation of the well production profile in naturally fractured reservoir and of the flow


site porosity composite relative permeabilities and composite capillary pressure relationships. These composite curves can be generated fro
rmation and fracturing the limited applicability of the elasticity assumption and the latent uncertainty in the structural geometry of faults. The
rmation and fracturing the limited applicability of the elasticity assumption and the latent uncertainty in the structural geometry of faults. The
e static model (which consists of the development of matrix and fracture models as well as the method to integrate them) is also presented.

arry out the computations. The procedure splits the computation into pressure solution on a coarser grid and the saturations and compostion
 rties to be characterized on a directional fracture-set basis. Conversely too complex reservoir models intended to be more realistic require
tal wells with no net production to the surface but in which cross-flow can occur. We present tests that demonstrate the efficiency of the met
  the literature among which the well-known Warren-Root and Kazemi shape factors. The aim of this paper is to show that the selection of th
ble fluid phases. Flow simulation of fractured reservoirs is commonly performed using a dual porosity model. The dual porosity system is mo
  to zero. Mass transfer between matrix and fractures is modeled by empirically determined transfer functions. Fracture permeabilities can di
eamlines in combination with a new multiscale mimetic pressure solver with improved capabilities for complex fractured reservoirs. The multi
 ents involving fine-grid simulation of oil recovery from a typical matrix block by water or gas in an adjacent fracture. The fine-grid results for w


a dual-porosity dual-permeability model from detailed discrete fracture characterizations. The technique referred to as a multiple subregion


els and additionally introduce the use of global single-phase flow information in the computation of the upscaled interblock transmissibilities r

ty state. Our results show that the algorithm is suitable for the simulation of water injection in heterogeneous porous media both in water-wet
air a vertical injection – vertical production well pair and a vertical injection – horizontal production well pair with and without fractures th
 that is based on mixed-dimensional unstructured hybrid-element discretisations. High-resolution DFM simulations are important to resolve
a sum of two terms: a saturation-dependent term representing displacement and a pressure-dependent term to model fluid expansion. The
e-scale recovery in field-scale simulation. To account for heterogeneity in wettability matrix permeability and fracture geometry within a sing


 rue for dual-porosity / dual-permeability models where the matrix domain is also flowing but at lower velocity. During the past 40 years until

en the full form of it which is of an integral form with history-dependency is incorporated into a set of multi-phase and multi-species flow equ

tor is a parallel 3D fully implicit equation-of-state compositional model that solves very large sparse linear systems arising from discretizat
derstanding the main flow mechanisms occurring within the reservoir is emphasized. Then we detail the way the dynamic model was build
y fractured reservoir and of the flow picture in the near wellbore zone in general. Introduction Near wellbore zones are very important areas


 mposite curves can be generated from properly designed laboratory experiments on representative cores or by history matching fine grid sin
the structural geometry of faults. The integration of historical production data and well-test permeability into geomechanical fracture modeling
the structural geometry of faults. The integration of historical production data and well-test permeability into geomechanical fracture modeling
to integrate them) is also presented. Both matrix and fracture systems play an important role in the production mechanism of the reservoir. H

 and the saturations and compostions calculations on a very fine scale. This is based the physical and theoretical evidence that pressure effe
 ntended to be more realistic require computationally intensive and memory consuming algorithms. They also involve numerous parameters
demonstrate the efficiency of the method first on a conceptual model then on a full field model of a particular carbonate reservoir. The result
 per is to show that the selection of the appropriate shape factor should not only depend on the shape" and dimensions of matrix blocks but s
 odel. The dual porosity system is modeled by using two coupled grids: one for matrix and one for fracture. The interaction between the two c
 tions. Fracture permeabilities can differ in orders of magnitude which results in very different flow velocities in different parts of the reservoi
mplex fractured reservoirs. The multiscale solver approximates the flux as a linear combination of numerically computed basis functions defin
ent fracture. The fine-grid results for water/oil and gas/oil systems were compared with results obtained with transfer functions. In both water


  referred to as a multiple subregion (MSR) model represents an extension of an earlier method that did not account for gravitational effects


pscaled interblock transmissibilities required by the method. The resulting models are used for waterflood simulations and more interestingly

eous porous media both in water-wet and mixed-wettability states. The novel approach with zero fracture capillary and nonzero matrix capilla
 well pair with and without fractures that provided a vertical path through the horizontal producer for 12.4 �API gravity crude oil. The effec
simulations are important to resolve the non-linear coupling of small scale capillary - viscous and large scale gravitational - viscous processe
 term to model fluid expansion. The transfer function is validated through comparison with 1D and 2D fine-grid simulations and is compared
y and fracture geometry within a single gridblock we propose a multirate model (Ponting 2004). We allow the matrix to be composed of a se


locity. During the past 40 years until recently several formulations have been proposed. In order to review compare and validate some of th

ulti-phase and multi-species flow equations. A numerical example with the proposed model for a two-phase and three gas-species flow is pe

near systems arising from discretization of the governing partial differential equations. A generalized dual-porosity model the multiple-interac
 e way the dynamic model was build using a novel discrete fracture network (DFN) approach developed internally. The method populates the
bore zones are very important areas of the formation because they account for well deliverability. So the ability of precise and reliable simula


es or by history matching fine grid single porosity simulations.� Kossack et al1 discussed this for water-oil systems.� Since the displace
nto geomechanical fracture modeling is a practical way to reduce such uncertainty. We propose to combine geostatistical algorithms for histo
nto geomechanical fracture modeling is a practical way to reduce such uncertainty. We propose to combine geostatistical algorithms for histo
duction mechanism of the reservoir. History matching for 20 years of production was done successfully in a single-media model through an it

heoretical evidence that pressure effects travel at much higher velocities than saturation and composition fronts – thus different scales on
y also involve numerous parameters a large part of which cannot be estimated from available data. In-between there is a need for reasona
cular carbonate reservoir. The results obtained with the conceptual model confirm that a substantial (3-fold) reduction in CPU time could be
 nd dimensions of matrix blocks but should also take into consideration the character of the dominant underlying physical recovery mechanis
 e. The interaction between the two continua is modeled using matrix-fracture transfer functions. Until now there were no mathematical mod
cities in different parts of the reservoir. This circumstance is advantageous for simulating the reservoir numerically with the streamline method
 rically computed basis functions defined over a coarsened simulation grid consisting of collections of cells from the geological model. Here w
with transfer functions. In both water and gas injection the simulations emphasize the interaction of capillary and gravity forces to produce oi


d not account for gravitational effects. The subregions (or subgrid) are constructed for each coarse block using the iso-pressure curves obtai


 d simulations and more interestingly for compositional simulations of first-contactmiscible gas injection. In a series of flow simulations invol

e capillary and nonzero matrix capillary pressure allows the proper prediction of sharp fronts in the fractures. Introduction This work is focus
4 �API gravity crude oil. The effect of fracture orientation (vertical or horizontal) on steam-oil ratio (SOR) and oil recovery was studied usi
 cale gravitational - viscous processes adequately for sector scale NFR. Cross-scale process coupling in NFR controls oil recovery and NFR
ne-grid simulations and is compared to predictions using the traditional Kazemi et al. (1976) formulation. Our method captures the dynamics
ow the matrix to be composed of a series of separate domains in communication with different fracture sets with different rate constants in th


ew compare and validate some of them this work first analyse the main recovery drivers in two-phase systems like drainage and imbibition

ase and three gas-species flow is performed in light of a parametric study demonstrating that multi-component gas species interactions have

l-porosity model the multiple-interacting-continua (MINC) has been implemented in this simulator. The matrix blocks are discretized into su
internally. The method populates the static parameters at the full field scale using a geo-statistical process guided by a geological driver. Usi
 ability of precise and reliable simulation of the fluids flow inside of these zones is very important to forecast the production profile and field d


er-oil systems.� Since the displacement of oil from vugs by gas involves very different mechanisms from water-oil systems and is very com
bine geostatistical algorithms for history matching with geomechanical elastic simulation models for developing an integrated yet efficient frac
bine geostatistical algorithms for history matching with geomechanical elastic simulation models for developing an integrated yet efficient frac
n a single-media model through an iterative process between static and dynamic models to ensure the consistency between the two models

n fronts – thus different scales on computation. Splitting up the computations through appropriate physical rules the multiscale approach d
between there is a need for reasonably complex models and methods to generate them in a consistent way with various fracturing and dyna
  old) reduction in CPU time could be achieved compared to a conventional approach using high permeability values to represent the conduit
nderlying physical recovery mechanisms. We will show that by taking into account the dominant physical recovery mechanism the apparent
ow there were no mathematical models of dual porosity three-phase compressible flow for streamline simulators. To realize this model it was
umerically with the streamline method [1 4 6 7 8 9 11 17 18 21]. Indeed in the streamline method the transport part is solved along a set of o
 ls from the geological model. Here we use a mimetic multipoint flux approximation to compute the multiscale basis functions. This method h
 llary and gravity forces to produce oil depending on the wettability of the matrix. In gas injection the thermodynamic phase equilibrium aide


k using the iso-pressure curves obtained from local pressure solutions of a discrete fracture model over the block. The subregions thus acco


 . In a series of flow simulations involving both connected and disconnected fracture systems it is shown that the MSR method provides resu

 res. Introduction This work is focused on the numerical treatment of two main physical aspects of multiphase flow in fractured porous medi
OR) and oil recovery was studied using horizontal well pair scheme. The experimental results indicated that vertical fractures improved SAG
n NFR controls oil recovery and NFR often exhibit power-law fracture length distributions i.e. they do not possess an REV and highly permea
 Our method captures the dynamics of expansion and displacement more
sets with different rate constants in the transfer function. We use


 ystems like drainage and imbibition under capillary and gravity forces

ponent gas species interactions have significant influ

 matrix blocks are discretized into subgrids in
ess guided by a geological driver. Using an innovative
cast the production profile and field development manage


om water-oil systems and is very complex the simulation of this pro
eloping an integrated yet efficient fracture modelin
eloping an integrated yet efficient fracture modelin
consistency between the two models. Different sets of relative permeability

 sical rules the multiscale approach divides the computation o
 way with various fracturing and dynamic data in order to produce conditio
ability values to represent the conduits. The full field model was built
 l recovery mechanism the apparent discrepancies in the shape factor value
mulators. To realize this model it was necessary to reformulate the mat
  nsport part is solved along a set of one-dimensio
 iscale basis functions. This method has limited sensitivity to grid distorti
ermodynamic phase equilibrium aided by g


the block. The subregions thus account for the fracture distributi


n that the MSR method provides results of reasonable accuracy

iphase flow in fractured porous media: heterogeneity in
 that vertical fractures improved SAGD. Maximum oil re
 possess an REV and highly permeable fractures can extend over

								
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