METHOD FOR CHARACTERIZING THE NETWORK OF FRACTURES OF A FRACTURE SLOT AND METHOD FOR OPERATING IT

专利摘要:
A method for operating a fluid within an underground formation comprising a layer traversed by a fracture network and a well. From measurements of properties relating to the layer, the fracture network is characterized by statistical parameters and a discrete fracture network model is constructed. For each well, three zones of simplification are defined surrounding the well. From the statistical parameters, we determine for each zone a tensor of equivalent permeability and a parameter characterizing the orientation and the vertical continuity of the fractures. For each zone, a simplification of the discrete fracture network model is determined as a function of the zone, the equivalent permeability tensor and the parameter value. From the simplified fracture network model and a flow simulator, an optimal exploitation scheme of the formation fluid is defined. Application in particular to the exploration and the oil exploitation.
公开号:FR3041026A1
申请号:FR1558653
申请日:2015-09-15
公开日:2017-03-17
发明作者:Andre Fourno；Bernard Bourbiaux
申请人:IFP Energies Nouvelles IFPEN；
IPC主号:

专利说明:

The present invention relates to the field of the petroleum industry, and more particularly to the exploration and exploitation of hydrocarbon deposits or geological gas storage sites.
In particular, the invention relates to a method for constructing a representation of an underground formation traversed by any fracture network, and the use of this representation for the simulation of fluid flows in the formation in question. Exploration and exploitation of deposits, particularly oil, require the acquisition of the best possible knowledge of underground geology, in order to effectively provide a reserve assessment, a production model, or farm management. Indeed, the determination of the location of a production well or an injection well within a hydrocarbon reservoir, the constitution of the drilling mud, the completion characteristics, the choice of a hydrocarbon recovery process (such as water injection for example) and the parameters necessary for the implementation of this process (such as the injection pressure, the production rate, etc.) require know the deposit well. The knowledge of a deposit means to have as precise a description as possible of the structure, the petrophysical properties, the properties of the fluids, etc., of the deposit studied.
To acquire this knowledge, the oil industry combines field measurements (made in situ, during seismic surveys, measurements in wells, coring, etc.) with experimental modeling (carried out in the laboratory) as well as with numerical simulations (performed using software).
The formalization of this knowledge then goes through the establishment of a model of the subsoil, known as the "geological model", which allows to account for these aspects in an approximate way. Generally, this type of model is represented on a computer, and one speaks then of numerical model. A reservoir model has a mesh representation (in the form of a regular grid, or in the form of a mesh more generally), generally three-dimensional, at least one petrophysical property (porosity, permeability, saturation ...) being assigned to each mesh of the mesh representation.
In order to reproduce or predict (i.e. "simulate") the actual hydrocarbon production, the tank engineering specialist implements a calculation software, called "tank simulator". The reservoir simulator is a flow simulator, which calculates the flows and pressure evolution within the reservoir represented by a "reservoir model". If the computing power available to perform the flow simulations allows, the reservoir model can be confused with the geological model. In the opposite case, the reservoir model can be obtained after an "upscaling" technique, which makes it possible to go from the geological model (model with finer meshes) to the reservoir model. (model with coarser mesh). This upscaling step is well known to the tank engineering specialist and can be performed for example using the CobraFlow software (IFP Energies nouvelles, France).
The results of these calculations then make it possible to predict and optimize exploitation plans (definition of the number of wells to be implanted, their position, the assisted recovery mode, etc.) of the deposit studied in order to improve flows and / or the quantities of hydrocarbons recovered. The calculation of the behavior of the reservoir according to a given production scenario constitutes a reservoir simulation.
The following documents will be quoted during the description:
Bourbiaux, B., Cacas, M.C., Sarda, S. and Sabathier J.C., 1998, "A Rapid and Efficient Methodology to Convert Fractured Reservoir Images into a Dual-Porosity Model," Oil & Gas Science and Technology, Vol. 53, No. 6, Nov.-Dec. 1998, 785-799.
Delorme, M., Atfeh, B., Allken, V. and Bourbiaux, B., 2008, Upscaling Improvement for Heterogeneous Fractured Reservoir Using a Geostatistical Connectivity Index, edited in Geostatistics 2008, VIII International Geostatistics Congress, Santiago, Chile.
Oda, M., 1985, Permeability Tensorfor Discontinuous Rock Masses, Geotechnical Vol 35, Issue 4, 483-495.
Warren, J.E. and Root, P.J., "The Behavior of Naturally Fractured Reservoirs", SPE Journal (September 1963), 245-255.
Fourno, A., Grenier, C., Benabderrahmane, A., Delay, F., 2013, A continuum voxel approach to model flow in 3D fault networks: A new way to obtain up-scaled hydraulic conductivity tensors of grid cells, Journal of Hydrology, 493, 68-80.
Fractured reservoirs are an extreme type of heterogeneous geological reservoirs, with two contrasting media: a matrix medium containing most of the oil in place and having a low permeability, and a fractured medium representing less than 1% of the oil in place and highly conductive. The fractured environment itself can be complex, composed of different families of fractures characterized by their density, and distributions relating to the length of the fractures of each family, their orientation in space and their opening. A "fracture" is a plane discontinuity, very thin in relation to its extension, which represents a plane of rupture of a rock in the deposit.
The specialists in charge of the operation of fractured reservoirs, need to know perfectly the role of the fractures. On the one hand, knowledge of the distribution and behavior of these fractures makes it possible to optimize the production patterns of a hydrocarbon deposit, ie the number of wells to be drilled, their location, their geometry, the type of recovery fluid injected etc. On the other hand, the geometry of the fracture network conditions the movement of the fluids, both at the reservoir scale and at the local scale, where it determines elementary matrix blocks in which the oil is trapped. Knowing the distribution of fractures is also very useful for the tank engineer who seeks to calibrate the models he builds, so that the models built reproduce the past production curves, in order to predict future productions. reliably. For these purposes, geoscientists have three-dimensional images of the deposits, making it possible to locate a large number of fractures.
Faced with the complexity of fractured media, specialists often use a "double medium" approach to represent this type of environment. This approach, described for example in (Warren J.E. et al., 1963), consists of considering the fractured medium as two continuums exchanging fluids with each other: matrix blocks and fractures. This is called the "double medium" or "double porosity" model. Thus, the "double medium" modeling of a fractured deposit consists in discretizing this deposit into two superimposed sets of meshes (called grids) constituting the "crack" grid and the "matrix" grid. Each elementary volume of the fractured deposit is thus conceptually represented by two meshes, one "crack" and the other "matrix", coupled together (that is to say, exchanging fluids). In the reality of the fractured field, these two meshes represent all the matrix blocks delimited by fractures present in this place of the reservoir. Indeed, most often, meshes have lateral dimensions MF (commonly 100 or 200 m) given the size of the fields and limited possibilities of simulation software in terms of capacity and calculation time. As a result, for most fractured fields, the fracture reservoir elemental volume (mesh) contains innumerable fractures forming a complex network delimiting multiple matrix blocks of variable size and shape depending on the geological context. Each of the constituent real blocks exchanges fluids with the fractures that surround it at a rate (flow) that is specific to it because of the size and shape of this particular block.
Faced with such a geometrical complexity of the real environment, the approach of the reservoir engineering specialist consists, for each elementary volume (mesh) of reservoir, to represent the real fractured medium as a set of matricial blocks all identical, parallelepipedic, delimited by a orthogonal and regular network of fractures oriented along the main directions of flow: for each mesh, the so-called "equivalent" permeabilities of this network of fractures are thus determined and a matrix block, called "representative" (of the actual distribution ( geological) blocks), unique and of parallelepipedic shape. It is then possible to formulate and calculate the matrix-crack exchange fluxes for this "representative" block, and to multiply the result by the number of such blocks in the elementary volume (mesh) to obtain the flow at the scale of this mesh.
It should be noted, however, that the calculation of equivalent permeabilities requires knowledge of the flow properties (i.e., conductivities) of the discrete fractures of the reservoir model. This is why, prior to the construction of this equivalent reservoir model (called the "double-medium tank model") as described above, it is first necessary to simulate the flow responses of a few wells (test results). transient or pseudo-permanent flows also called well tests, interference tests, flow tests, etc.) on models extracted from the reservoir model giving a discrete (realistic) representation of the fractures feeding these wells. Adjusting the simulated pressure / flow responses on the field measurements calibrates the conductivities of the families of fractures. Although only covering a limited area (drainage area) around the well, such a well testing simulation model still has a large number of computational nodes if the fracture network is dense. As a result, the size of the systems to be solved and / or the duration of the calculations often remain prohibitive.
State of the art
Patent application FR 2967200 (US 8983818) is known which describes a method allowing a simplification of the fracture networks at the local scale of the drainage area of the well, in order to be able to simulate, in a reasonable calculation time, the wells tests of fractured reservoirs and thus calibrate the conductivities of families of fractures. This hydraulic calibration of fractures results in a set of parameters characterizing the fracture network (or fracture model). This fracture model is then used to construct a dual-scale flow model at the reservoir scale. However, this method is only suitable for fracture networks that are substantially orthogonal to the layers and continuous from one layer to another, that is to say to fracture networks whose flow behavior is comparable to a 2D behavior. (cf in particular the patent applications EP 2530493 (US 9103194) and EP 2581767 (US 13 / 644,479), as well as the document (Fourno et al., 2013)). An example of such a fracture network is given in FIG. 2a. In this example, the formation has two layers, the fracture network is continuous from one layer to another (thus ensuring connectivity from one layer to another) and the fractures are substantially orthogonal to the boundaries of the layers.
Patent applications EP 2530493 (US 9103194) and EP 2581767 (US 2013/0096889) are also known which make it possible to take into account networks of fractures which are not necessarily suborthogonal and / or continuous from one layer to one other, while limiting the number of computing nodes. To achieve this, the application EP 2530493 (US 9103194) is based on the use of a Voronoi diagram on each fracture plane, in order to construct a mesh of the fractured medium which gives a good estimate of the volumes present at each node. and current lines representing the movement of fluids from node nodes. For example, meshes have only 3 or 4 nodes at intersections, making it possible to treat millions of fractures in a reasonable calculation time. The application EP 2581767 (US 2013/0096889) makes it possible to dispense with the restrictive hypothesis of having as many fracture nodes as matrix nodes while preserving the volumes in place and the flow physics by means of an off-center scheme. The use of tree-type structures (and in particular of the octree) makes it possible to accelerate the construction of the meshing of the fracture medium (limitation of the number of intersections calculation), to simplify the calculations of matrix / fracture exchange terms. as well as to estimate the matrix volumes associated with the fracture nodes. This method, applied here to the mesh of a dual medium in 3D, applies to any dual problem involving strong heterogeneities. Thus, applications EP 2530493 (US 9103194) and EP 2581767 (US 2013/0096889) making it possible to represent fracture networks that are not necessarily sub-orthogonal and / or continuous from one layer to another, 3D flow simulations on these 3D fracture networks, made using a 3D flow simulator, provided access to a better understanding of the 3D flows in the studied deposits. However, these methods are still prohibitive in terms of computation time, especially when a large number of flow simulations (on the scale of the reservoir or on the scale of a zone of influence of one or more several wells) is necessary (in the case of the optimization of the production scheme, the calibration of production history, or the calibration of the statistical parameters of fracture families by parameter sensitivity procedures).
One of the objects of the present invention relates to a method for suitably representing a subterranean formation comprising a fracture network of which at least one family may be characterized by any dip and / or by a variable continuity of the fractures of a layer to a other. In particular, the present invention establishes a parameter for qualifying the type of fractures and adapts, as a function of this parameter, the simplification of the fractured medium. In addition, this simplification is not localized at the local level of the well drainage area, but can be directly performed at the reservoir scale. This simplified fracture model, adapted to the new generation of 3D tank simulator, is then used to optimize fluid production patterns in the studied formation, in an affordable calculation time.
The process according to the invention
Thus, the present invention relates to a method for the exploitation of a fluid within an underground formation comprising at least one layer traversed by a network of fractures and by at least one well, in which a mesh representation of said structure is constructed. at least one layer from measurements of properties relating to said at least one layer, and at least for said layer is defined a zone of interest comprising a set of meshes of said meshed representation relating to said layer and comprising at least said well. The method comprises at least the following steps for each of said layers: A. from said measurements, said fracture network is characterized by statistical parameters, and a discrete fracture network model is constructed from said parameters; B. for each of said wells contained in said zone of interest, at least three simplification zones (ZS1, ZS2, ZS3) are defined, a first simplification zone (ZS1) containing said well, a second simplification zone (ZS2). having as an internal boundary the outer boundary of said first zone (ZS1), and a third zone of simplification (ZS3) having as an internal boundary the outer boundary of said second zone (ZS2), all of said simplification zones of the whole said wells covering all the stitches of said area of interest; C. from at least said statistical parameters, for at least each of said simplification zones (ZS1, ZS2, ZS3) of said zone of interest, an equivalent permeability tensor and a value of a parameter P are determined. characterizing the orientation and continuity towards the other layers of the fractures of said network; D. a simplification of said model is determined in each of said simplification zones, as a function of said zone, of said equivalent permeability tensor and of said value of said parameter P;
Then, from said mesh representation, of said model of simplified fracture network, and of a flow simulator, an optimal exploitation scheme of said fluid of said formation is defined and said fluid of said formation is exploited as a function of said optimal operating scheme.
Advantageously, said statistical parameters can be chosen from the following parameters: fracture density, fracture length, orientation of fractures in space, opening of fractures, and distribution of fractures within said layer.
Preferably, said simplification zones may be cylinders of vertical axis and elliptical section, centered around said well.
According to an embodiment of the present invention, the major axis of one of said simplification zones may be oriented in a preferential direction of flow, said preferential direction being determined from a diagonalization of said equivalent permeability tensor.
Advantageously, the distance separating two of said zones can be determined according to a geometric progression of constant reason.
According to one embodiment of the present invention, it is possible to perform no simplification of said fracture network model in said first simplification zone (ZS1), to carry out a first simplification in said second zone (ZS2), and a second simplification in said third zone (ZS3), said second simplification being greater than said first simplification.
According to an embodiment of the invention, said second and / or third simplification zones (ZS2, ZS3) can be cut into annular simplification sub-zones.
Advantageously, said second simplification zones (ZS2) can be divided into column simplification sub-zones.
Preferably, said third simplification zones (ZS3) can be divided into locally homogeneous sub-zones of simplification.
According to an embodiment of the invention, said parameter P can be determined for at least each of said simplification zones (ZS1, ZS2, ZS3), by means of: a value of a parameter PO measuring the orientation in the space of said fractures of said layer according to a formula of the type:
and / or - a value of a parameter PC measuring the continuity of said fractures of said layer towards the other layers according to a formula of the type:
where k-ι, k2, and k3 are the eigenvalues of said permeability tensor after diagonalization.
According to an embodiment of the present invention, said simplification can consist of the calculation of at least one spacing value between said fractures, an opening of said fractures, and a permeability value.
According to one embodiment of the invention, said simplification of said model can be carried out according to three directions of space if the parameter P characterizes fractures not substantially orthogonal to the layers and / or continuous towards the other layers.
According to another embodiment of the invention, said simplification of said model can be performed in two directions of space if the parameter P characterizes fractures substantially orthogonal to the layers and continuous to the other layers.
Preferably, said optimal exploitation scheme can be defined by determining a recovery process of said fluid, as well as a number, an implantation and a geometry of injectors and producers wells to meet predefined technical-economic criteria.
Advantageously, said exploitation of said fluid according to said optimal exploitation scheme may consist at least in drilling said injectors and producers wells and in producing said fluid according to said recovery method.
Furthermore, the invention relates to a computer program product downloadable from a communication network and / or recorded on a computer readable medium and / or executable by a processor, comprising program code instructions for the implementation of the method as described above, when said program is run on a computer. Other features and advantages of the method according to the invention will become apparent on reading the following description of nonlimiting examples of embodiments, with reference to the appended figures and described below.
Brief presentation of the figures - Figure 1 shows an example of fracture network in a horizontal section made in a layer of a subterranean formation. FIG. 2a illustrates an example of a 2.5D fracture network in the case of a two-layer underground formation. FIG. 2b shows an example of a 3D fracture network in the case of a four-layer underground formation. FIG. 2c illustrates an example of a 3D fracture network in the case of a subterranean formation composed of a single layer. FIG. 3 illustrates the creation of simplification zones and sub-zones around a well crossing a layer of a subterranean formation.
Figure 4 illustrates a simplified fracture network DFNs on a fine grid. FIG. 5 illustrates a model of simplified fracture network DFNs according to the invention. FIG. 6 shows the overlap between model of simplified fracture networks DFNs of neighboring simplification sub-zones. FIG. 7 illustrates a simplified fracture network model DFNs resulting from the implementation of the present invention in the case of a layer of an underground formation traversed by five wells.
Detailed description of the process
The following definitions are used during the description of the invention:
Well testing: This is an injection or production of a fluid in the subsoil at a given well. The well test is characterized by a production curve (quantity of fluid injected or produced) and a pressure curve (curve which characterizes the evolution of the pressure in the structure as a function of the production curve). Well tests are useful for calibrating the flow / reservoir models used for flow simulations. - Interference tests: this is an association of several well tests. Each well is characterized by its production curve and its pressure curve. The difference with a single well test per well is that each well may be disturbed by the operation of another. ... i
The method according to the invention relates to the exploitation of a fluid within an underground formation comprising at least one layer traversed by a network of fractures and by at least one well. In a nonlimiting manner, the subterranean formation consists of at least one layer of reservoir rock (that is to say at least one porous and preferably permeable rock). The exploitation of the fluid is then called resource exploitation, and aims at extracting the fluid from this reservoir rock. Without limitation, the fluid in question is of hydrocarbon type (oil, gas, bitumen etc.).
An underground formation may consist of several geological layers, each geological layer may comprise a clean fracture network, and each network may consist of several families of fractures. For the sake of simplification, a "fracture network 3D" will be called a fracture network consisting of at least one family of dip fractures (orientations) of any kind (FIG. 2c) and / or characterized by a variable continuity of fractures from one layer to another (Figure 2b); and called "2.5D fracture networks" a fracture network consisting of families of fractures substantially perpendicular to the layers and whose fractures are continuous from one layer to another (Figure 2a).
The present invention relates to taking into account arbitrary fracture networks in a flow simulation, and this in reasonable computing times, even in the case of a 3D fracture network. To do this, the present invention consists in modeling the network of fractures of the considered layer (see step 1 described below), then in simplifying it (see step 2 described below), in order to allow numerical flow simulations (see Step 3 described below) at reasonable computation times.
The present invention requires the provision of: - measurements of properties relative to at least the studied layer: it can be measurements of petrophysical properties realized in situ, at various points of the formation studied, such as porosity, permeability, and lithology (that is, rock type), relative permeability, or capillary pressure. These measurements may have been obtained for example by coring, via logs made in wells, by seismic acquisition campaigns. But these are also measurements (oil flow rates, water flow rates, pressure variations, for example) related to the flows in the layer studied, obtained for example by putting into production the fluid in some wells passing through the formation, during well tests or interference tests; a representative mesh representation of at least the studied layer: also called "reservoir model", it is a kind of mock-up of the subsoil constructed in order to describe as precisely as possible the structure, the petrophysical properties, the properties of the fluids, the formation studied, and at least the studied layer. This model is generally represented on a computer, and consists of a mesh or grid, each mesh of this grid comprising one or more values of properties relating to the formation studied (porosity, permeability, saturation, etc.). A reservoir model should verify as much as possible the properties of the studied layer collected in the field: the logging data measured along the wells, the measurements made on rock samples taken from the wells, the data deduced from Seismic acquisition campaigns, production data like oil flow, water flow, pressure changes etc. The tank simulation specialist has full knowledge of methods for constructing such a mesh representation of a formation. Note that the reservoir model can be confused with the geological model when the computer power is sufficient to allow numerical computations of flow simulation on a fine mesh grid. In other cases, the specialist may use an "upscaling" technique to change from a fine-meshed model (the geological model) to a coarser mesh model (the model). tank). This upscaling step can be performed for example using the CobraFlow software (IFP Energies nouvelles, France). an area of interest (ZOI), comprising a set of meshes of said meshed representation relating to the studied layer and comprising at least the well passing through the layer concerned: the dimensions and the geometry of this zone may be variable according to the mode of implementation of the present invention. In the most general case, that is to say during simulations of production of the fluid studied studied implemented to test different operating patterns, the ZOI can correspond to the entire reservoir, and can include at least two wells, and preferably all the wells. In the case where prior to this simulation, a calibration of the model used for the simulation, via well tests, the ZOI considered will advantageously correspond to a portion of the reservoir, a kilometer, including a single well. In the case of interference tests, the ZOI can then correspond to a portion of the reservoir, and comprises several wells. Note that the ZOI can be discontinuous and be formed for example of a sum of subfields of interest defined locally around a number of well data. - A flow simulator: A flow simulator is a digital program, run on a computer, which is used to predict the flow of fluids within the different layers of a formation. Simulation of flow, also called reservoir simulation, consists in predicting numerically the production of a fluid trapped in one or more layers of an underground formation, the production requiring the existence of at least one injection well (in which another fluid is injected, which will expel the trapped fluid) and a producing well (towards which the entrapped fluid will be displaced and from which it can be extracted). Advantageously, use will be made of a so-called "double medium" flow simulator, which makes it possible to model the exchanges between the non-fractured rock blocks and the fracture network, without requiring the discretization of these blocks. An example of such a simulator is the PUMAFLOW software (IFP Energies nouvelles, France).
The method according to the invention comprises at least the following steps, steps 1 and 2 being repeated for each of the layers of the formation studied: 1. Modeling the fracture network 1.1. Determination of statistical parameters 1.2. Construction of a Discrete Fracture Network Model 2. Simplification of the Fracture Network Model 2.1. Definition of simplification areas 2.2. Determination of a tensor of equivalent permeability 2.3. Determination of a parameter P characterizing fracture geometry 2.4. Simplification of the Discrete Fracture Network Model 3- Exploitation of Formation Fluid
The main steps of the present invention are detailed below. Steps 1 and 2 will be used for a single layer of the training studied and are to be repeated for all the layers of the formation. The implementation of the invention requires the existence of at least one well passing through each of the considered layers, but the implementation of the invention does not require taking into account all the wells passing through a given layer. 1. Modeling the fracture network
During this step, it is necessary to determine a model of the fracture network of the studied layer, respecting the measurements of properties related to the layer realized in situ.
The realization of this step can comprise at least the following substeps: 1.1. Determination of statistical parameters
During this sub-step, it is necessary to determine statistical parameters making it possible to characterize the network of fractures of the studied layer. This substep requires measurements, allowing a direct or indirect characterization of the fracturing.
Information on the fracturing of a geological layer can be obtained via: cores, extracted from the formation studied, and from which a statistical study of the intersected fractures can be carried out; - outcrops, which have the advantage of providing a large-scale view of the fracture network; seismic images, to identify large geological events.
According to the invention, statistical parameters (noted PSF thereafter) are used to characterize the fractures observed during the measurements. According to one embodiment of the invention, the density of the fractures observed, their length, their orientation in space, their opening, and their distribution within the studied layer are characterized.
Statistical parameters (PSF) are thus available describing the fracture network of the studied layer, from which a model of this network can be constructed, on the scale of each of the meshes of the mesh representation. 1.2. Construction of a discrete fracture network model
According to the invention, a realistic image of the fracture network characterized by the statistical parameters (PSF) determined in the previous substep is then constructed, via a discrete fracture network model (known by the acronym DFN, for "Discrete Fracture Network").
To do this, from a grid representation of the studied formation (and at least of the considered layer), we associate in each mesh, a detailed representation (DFN) of the internal complexity of the network of fractures, as faithful as possible direct and indirect observations of the reservoir. Figure 1 shows a horizontal section taken in a layer of a formation, and the fracture network, observable at the scale of formation, for this section. FIG. 2 presents the discrete network of visible fractures at the scale of the three-dimensional mesh whose 2D boundaries are presented by the square in FIG. 1. A set of porous matrix blocks of irregular shapes and sizes can be observed in FIG. delimited by fractures. This discrete fracture network constitutes a representative image of the real network of fractures delimiting the matrix blocks.
To construct a discrete fracture network (DFN) model in each mesh of the mesh representation, it is possible to use modeling software, well known to specialists, such as the FRACAFlow® software (IFP Energies nouvelles, France). These programs use the statistical parameters (PSF) determined previously. 2. Simplification of the fracture network model
Due to its extreme geometric complexity, the fracture network model (DFN) obtained in the previous step and representative of the real fractured reservoir, can not be used to simulate, reproduce and / or predict, local flows around wells . Indeed, the DFN obtained in the previous step often has a large number of fractures and many points of intersection between fractures. The mesh will be too complex or will have too many compute nodes, making the simulations unaffordable in computing time. The objective of this step is to determine a simplified fracture network model, while respecting in situ flow measurements.
Thus, during this step, it is a question of simplifying the discrete fracture network model determined in the previous step for the layer in question. According to the invention, this simplification is different according to the simplification zones described around each of the wells considered for the layer in question (see step 2.1). Each simplification zone is characterized by 2 parameters that are specific to it: an equivalent permeability tensor (see step 2.2) and a parameter (P) characterizing both the orientation and the continuity (towards the other layers of the formation studied) of the fracture network of this layer (see step 2.3). 2.1. Definition of simplification zones
During this sub-step, it is necessary to define zones of simplification for each well considered. According to the invention, at least three simplification zones (ZS1, ZS2, ZS3) are defined around each well, the first of said simplification zones (ZS1) containing said well, the second of said simplification zones (ZS2) having as internal boundary the outer boundary of said first zone (ZS1), and the third of said simplification zones (ZS3) having as internal boundary the outer boundary of said second zone (ZS2).
In addition, according to the invention, all the simplification zones for all the wells considered must cover all the meshes of the ZOI, regardless of the number of wells. The invention is not limited to the definition of three zones of simplification for each of the wells considered, and an implementation of the invention can be carried out for NZ simplification zones, with NZ> 3.
According to a preferred mode of implementation of the invention, the zones of simplification correspond to cylinders of elliptical section, the axis of revolution of the cylinders being able to be oriented according to a vertical axis (see for example the horizontal sections of the zones ZS1, ZS2 and ZS3 created around a well W in Figure 3). The sections in a horizontal plane of the simplification zones are then concentric ellipses (ZS1) or elliptical crowns (ZS2 and ZS3), centered around a well. According to another embodiment of the invention, the zones of simplification correspond to cylinders of elliptical section, the axis of revolution of the cylinders being able to be oriented along an axis defined by the perpendicular to the dip (line of greatest slope) of the considered layer, or an axis defined by the axis of the well considered.
According to an embodiment of the invention, a simplification zone ZS2 and / or a zone ZS3 is divided into N simplification sub-zones by adding, between the internal and external boundaries of the zone considered, N-1 boundaries. intermediate, the geometry of the intermediate boundary n (with n between 1 and N-1) that can result from a linear combination (eg function of n and N) curves describing the internal and external boundaries of the simplification area considered . For example, in the case of a cylindrical simplification zone of elliptical section, the division of this simplification zone into two simplification sub-zones amounts to adding an intermediate cylindrical boundary (see, for example, the boundary ann_ZS3 in FIG. 3), of elliptical section. We will speak later of "annular subfield" for this type of sub-areas of simplification. This mode of implementation will be preferred in the case of relatively homogeneous flow properties.
According to an embodiment in which the simplification zones or simplification sub-zones are cylinders of horizontal section with elliptical geometry, it is very preferable to orient the ellipses (direction of the major axis of each ellipse) as a function of the flow directions. preferential values deduced from a calculation of equivalent permeabilities. Such a calculation is precisely described in the following sub-step. Similarly, the aspect ratio of the ellipse (noting Lmax the half-length of the major axis of the ellipse, and Lmin the half-length of the minor axis of the ellipse, this form ratio is defined by Lmax ^ l-min) and the distance between concentric ellipses (distance separating the inner and outer elliptic limits of a given concentric ring) can be determined according to the flow anisotropy in the studied layer.
According to a particular mode of implementation of the invention, the shape ratio can be defined according to a formula of the type:
where ki and k2 are the eigenvalues, respectively, obtained after diagonalisation of the equivalent permeability tensor, in the principal directions closest to a horizontal plane.
According to another particular mode of implementation of the invention, in order to define the distance between concentric ellipses (boundaries between zones), one opts for a dimensioning criterion conforming to a uniformly distributed modeling precision on the simulation domain, which consists in fixing the half-lengths of the major axis (or the minor axis Lmin) of two successive ellipses i and i + 1 (with i varying from 1 to I, and I at least equal to 3) to values in geometric progression of reason r constant (equal to 2 for example), according to a formula of the type:
This rule makes it possible to give equal weight to each zone i (i = 1 to I, l 3) in terms of the pressure difference observed on each ring in steady-state flow.
According to a preferred embodiment of the invention, a simplification zone ZS2 is divided into a number of sub-zones equal to the number of mesh columns present in the zone ZS2. The term "column of meshes" is used to designate a "stacking" of vertical meshes of the mesh representation. These sub-zones will then be quadrilaterals whose lengths of sides correspond to the discretization according to the axes x and y of the meshed representation ( subfields ss_ZS2 in Figure 3). We shall speak later of "column simplification subfield" for this type of simplification subfields.
According to a preferred embodiment of the invention, a simplification zone ZS3 is divided into simplification sub-zones, taking into account the heterogeneities of the flow properties. For example, it is possible, without limitation, to delimit simplification sub-zones of a zone ZS3 by grouping subsets of meshes having neighboring flow properties. For example, in the case of a zone ZS3 corresponding to a cylinder of vertical axis and of elliptical section, an angular sweep, centered on the well, is carried out. The meshes contained by sampled degree are grouped in a column of meshes. Thus, the zone ZS3 is characterized by at most 360 mesh columns. For each of these mesh columns, a calculation of the equivalent fracture permeability tensor is performed (see next step). This tensor makes it possible to characterize the dynamic properties of the fracture network of the studied mesh column. The permeability values and the flow orientation obtained are then compared between neighboring mesh columns. If the equivalent properties of two neighboring mesh columns are close, these two columns of cells will be considered as belonging to the same sub-zone. In the opposite case (difference of 20% on the main permeability values or 10 degrees on the main directions of permeability for example), the two columns of meshes are assigned to different sub-zones. In this way, the outer limit, in a horizontal plane, of the area ZS3 considered is divided into arcs of elliptical shape (see Figure 3). The limits in a horizontal plane of the sub-areas are then obtained by connecting the end-points of each of these arcs in the center (well W) of the ellipse (dashed lines ss_ann_ZS3 and ss_ZS3 in Figure 3): each sub-area to simplify is thus defined as the union of the subsets of meshes constituting the area between the intra-zone radial partitioning (dashed lines ss_ann_ZS3 and ss_ZS3) and the elliptic interzone boundaries (solid lines ann_ZS3 and ZS3). In this way, ZS3 zone simplification subzones are substantially homogeneous with respect to the flow properties, each being characterized by its own equivalent permeability. This will be referred to as a "locally homogenous sub-zone" for this type of simplification sub-area.
According to one embodiment of the invention, a division into locally homogeneous sub-zones of simplification can be applied, in addition, to annular-type sub-zones for a simplification zone ZS3 (sub-zones ss_ann_ZS3 and ss_ZS3 in Figure 3).
According to an embodiment of the invention, a division into column simplification sub-zones can be applied, in addition, to annular-type sub-zones for a simplification zone ZS2. 2.2. Determination of a tensor of equivalent permeability
During this sub-step, it is necessary to calculate an equivalent permeability tensor for at least each of the simplification zones determined in the preceding substep, the objective being, in the following substep, to replace the fracture network of each simplification zone by a simplified network having the same flow properties as the original network.
Very preferably, in the case where simplification sub-zones have been defined for a simplification zone given in the preceding substep, an equivalent permeability tensor is calculated in each of these simplification sub-zones.
Computation of equivalent permeabilities is performed from the DFN fracture network model, or directly from the PSFs. This type of calculation of equivalent permeabilities is well known to those skilled in the art. One can for example use the numerical method for calculating equivalent properties of fractured media, implemented in the FracaFlow software (IFP Energies nouvelles, France) and recalled hereinafter.
According to one embodiment of the invention, a permeability tensor representative of the flow properties of the discretized fracture network (DFN) can be obtained for example by one of two scaling methods ( so-called upscaling methods): - a first method, analytical, called "local analytical upscaling", is based on an analytical approach described for example in the document (Oda, 1985) or in the patent application FR 2918179 (US 8078405). This method has the advantage of being very fast. Its scope is, however, limited to well-connected fracture networks. Otherwise, significant errors on the permeability tensor can be found. - A second method, digital, called "local numerical upscaling", is described in the document (Bourbiaux, et al., 1998), or in the patent application FR 2757947 (US 6023656) for the calculation of equivalent permeabilities. This method is based on the numerical resolution of the flow equations on a discrete mesh of the fracture network for different boundary conditions applied to the column of computation mesh considered. The tensor of equivalent permeabilities is obtained by identifying the ratios between flow rate and pressure drop at the limits of the calculation domain. This approach, more expensive than the previous one, has the advantage of well characterizing a given network (even if it is not connected).
According to one embodiment of the present invention, in order to make the most of the advantages of the two scaling methods, the permeability tensor is determined by one or other of these two methods, for example, following the selection procedure described in document FR 2918179 (US 8078405), based on the value of the connectivity index of the fracture network. This index, representative of the ratio between the number of intersections between fractures and the number of fractures, is calculated for each unit of the column of mesh considered. Its value makes it possible to consider the network as very well connected, little / badly connected or not connected. The choice of the scaling method is then made, as described in (Delorme, et al., 2008), and summarized below: - Well connected network: for this case characterized by a connectivity index close to 3 or more than 3 (at least 3 intersections per network fracture on average), the analytical upscaling method is chosen because its accuracy is guaranteed given the good connectivity of the network, with the essential additional advantage of speed. - Network little / badly connected: in this case, the connectivity index is between 1 and 3 (which corresponds to a number of fracture intersections between one and three times the number of fractures) and the method of Digital upscaling is used to reliably calculate the permeability tensor. - When the network is very little or not connected (number of intersections close to or less than the number of fractures), the original fractures (few) are preserved, and there is no need to simplify the network of fractures.
According to one embodiment of the invention, the equivalent permeability tensor thus calculated is diagonalized so as to determine the three main directions of the flow, which will be noted subsequently by din, dir2 and dir3, the din direction. (respectively dir2, and dir3) being chosen so that its angle with the abscissa axis (respectively the ordinate axis, the vertical axis) is the lowest. We will then denote by k2, k3 the eigenvalues of this tensor, respectively associated with the three main directions din, dir2 and dir3.
According to an embodiment of the invention, a fracture porosity representative of the volume of fractures of the zone or sub-zone is also calculated. This porosity φί is obtained via a formula of the type:
where the volume of fractures present in the volume in question can be obtained from the PSF or DFN determined in step 1, and total volume is the total volume of the zone or sub-area of simpification.
According to an embodiment of the invention, the characteristic dimensions of a representative matrix block (said equivalent) for each simplification zone are also calculated, and preferably for each simplification sub-zone. Note a, b and c the characteristic dimensions of this matrix block respectively in the directions din, dir2 and dir3. Such a calculation can be performed according to the technique described in patent applications FR 2757957 (US 6064944) or FR2923930 (US 8688424). 2.3. Determination of a Parameter P Characterizing the Geometry of Fractures From at least the statistical parameters (PSF) determined in the previous step, a value of a parameter, denoted P, is determined; characterizing both the orientation in the space and the continuity towards the other layers of the fractures of the network of fractures contained at least in each of the simplification zones determined in the sub-step 2.1. Thus, the value of this parameter P will make it possible to determine whether the fracture network of interest is of type 2.5D or of type 3D in each of the simplification zones.
According to a preferred embodiment of the invention, a parameter P is determined, where appropriate, for each simplification sub-zone defined in step 2.1, in particular in the case of heterogeneities of the flow properties. and most preferably in the case where so-called locally homogenous sub-zones have been predefined.
According to an embodiment of the present invention, a binary parameter P equal to 0 or 1 is defined for each (sub) zone of simplification. The value 1 of the parameter P indicates that the families of fractures of the fracture network contained in a given subzone of simplification are both substantially orthogonal to the limits of the layer considered and substantially continuous towards the other layers of the formation (FIG. ). The value 0 indicates that the fracture network of the (sub) zone of simplification considered comprises at least one family of any dip fractures (FIG. 2c) and / or characterized by a variable continuity of fractures from one layer to another (Figure 2b). In other words, the value 1 of the parameter P indicates that the fracture network of the (sub) zone of simplification considered is 2.5D, whereas the value 0 of the parameter P indicates that the fracture network of the (sub) zone of simplification considered is 3D
According to one embodiment of the invention, a PC parameter is determined which qualifies the continuity of the fracturing of a given layer towards the other layers of the formation. The calculation of this parameter can be carried out by simplification zone or by simplification sub-zone. To do this, we consider an equivalent permeability tensor calculated on the height of the considered layer for the (sub) zone of simplification considered (see sub-step 2.2), and diagonalized this tensor. If k3 (sub-vertical permeability) is very different from k-i + k2 (sum of subhorizontal permeabilities), then the fracturing is not continuous over the height of the layer considered for the (sub) zone considered. More precisely, a PC parameter can be defined according to a formula of the type:
When PC <where is a threshold predefined by the specialist, then we can consider that the network of fractures is not continuous from one layer to another in the (sub) zone of simplification considered. Preferably, choose ec = 0.8. This very restrictive criterion implies that most natural fracture networks will be treated as 3D fracture networks.
According to one embodiment of the invention, a parameter PO qualifying the orientation in space of the fracturing of a given layer is determined. The calculation of this parameter can be carried out by simplification zone or by simplification sub-zone. More precisely, consider a tensor of equivalent permeability calculated on the height of the layer considered by (sub) zone of simplification (cf sub-step 2.2), and one diagonalizes this tensor. If the principal direction associated with the component k 3 of this tensor is characterized by a deviation from the normal to the layer below a certain threshold predefined by the specialist, it will be considered that the fractures are not substantially orthogonal for the ) simplification area considered. For example, a parameter PO of the form can be defined:
arccos providing an angle in radians between [0, PI] converted to degrees to get dev.
When PO <ε0 where ε0 is a threshold predefined by the specialist, then we consider that the fracture network of the considered layer, for the (sub) zone considered, is not substantially orthogonal to the limits of the considered layer. Preferentially, we choose εο = 0.81 (which corresponds to a deviation from the normal at the 9 ° layer).
According to one embodiment, the value of the parameter P is defined as follows: the parameter P is equal to 1 if both the parameter PC and the parameter PO are greater than or equal to 0.8. In this case, it is considered that the fracture network of the layer considered, for the (sub) zone considered, is (substantially) 2.5D. the parameter P is 0 if at least one of the parameters PC or PO is strictly lower than 0.8. In this case, it is considered that the fracture network of the layer considered, for the (sub) zone considered, is (substantially) 3D. 2A. Simplification of the fracture network
During this step, it is a question of simplifying the network of fractures in each of the meshes of the zones of simplification defined previously (which amounts to a simplification in each meshes of the zone of interest ZOI since all the meshes of the set of simplification zones corresponds to the set of meshes of the zone of interest ZOI), said simplification being a function of the zone of simplification considered, the tensor of equivalent permeability determined previously and the value of the parameter (P ) characterizing the orientation and the continuity towards the other layers of the fractures of the fracture network of the considered layer.
Thus according to the invention, the simplification of the fracture network model is carried out differently from one simplification zone to another.
According to a preferred embodiment of the invention, the simplification is carried out as follows: no simplification of said fracture network model is carried out in the first simplification zone ZS1. In fact, since the simplification zone ZS1 is closest to the well, it is highly desirable not to simplify the fracture network model, so as to correctly model the transient flow phenomena occurring around the well; a first simplification, moderate, is applied in the second zone ZS2. Indeed, since the simplification zone ZS2 is further away from the considered well than the zone ZS1, a simplification of the fracture network model is possible, but it is preferable that the local variations of the flow properties in this zone are respected. According to a very preferred embodiment of the invention, a zone ZS2 is simplified by sub-areas of simplification. Preferably, the simplification sub-zones of a zone ZS2 are of column type (cf the substep 2.2). a second, important simplification is carried out in the third zone ZS3. Being further away from the well considered, it is acceptable to be less precise in detecting heterogeneities than in the case of ZS2 type zones. According to a preferred embodiment of the invention, a zone ZS3 is simplified by sub-areas of simplification. Preferably, the simplification sub-zones of a zone ZS3 are of locally homogeneous type (cf. substep 2.2). Advantageously, a simplification zone ZS3 can be previously cut into annular simplification sub-zones before cutting the annular-type sub-zones into sub-zones of locally homogeneous type. From the division into simplification zones (preferentially into simplification sub-zones in the case of a heterogeneous fracture network), an equivalent permeability value and a value of a parameter P assigned to each zone of simplification (preferentially to each simplification sub-zone), we create a simplified fracture network model (DFNs), equivalent to the original fracture network model (DFN) in terms of flow by (sub) simplification zone. The calculations that follow will be indifferently applied to a simplification zone or a simplification sub-zone. We then note keqm'ik the equivalent permeability of a matrix block m of dimension (a, b, c), and km'ik the real permeability of the rock (also called matrix) in a mesh ijk.
According to the invention, at least one spacing value between fractures, a fracture opening, and a permeability value, or any combination between these parameters, is determined during this step.
According to one embodiment of the invention, a s-i9r0S fracture spacing of the simplified fracture network model (DFNs) is determined in the main flow direction dir, according to a formula of the type:
(1) where NG is an integer controlling connectivity. It represents the minimum number of simplified fractures to intersect the smallest side of the (sub-) area to be simplified to provide connectivity between simplified (sub) areas; preferentially, NG = 6 is chosen. and DC is a characteristic dimension of the (sub) zone considered. According to one embodiment of the invention, the characteristic dimension of a (sub) zone is the smallest length of a quadrilateral inscribed in the (sub) zone.
According to one embodiment of the invention, if Si9ros is greater than a threshold s-imax predefined by the specialist, then Sigros is fixed at s 3 *. Advantageously, Simax will be used equal to DC / 6.
According to one embodiment of the invention, the fracture spacing of the simplified fracture network model (DFNs) is then determined in the other main directions of flow dir2 and dir3 by posing:
(2) (3)
According to an embodiment of the invention for which a matrix block characteristic dimension (a, b, c) has been calculated (see step 2.2), a magnification parameter G (fracture spacing) is determined by a formula of the type:
(4)
According to another embodiment of the invention for which a matrix block characteristic dimension (a, b, c) has not been calculated, G is equal to 1.
According to an embodiment of the invention, the fracture spacing of the simplified fracture network model (DFNs) is determined in the other main directions of flow dir2 and dir3 according to formulas of the type:
(5) (6)
According to a particular mode of implementation of the invention, it is possible to determine conductivities of fractures Cf19ras, Cf29ros and Cf39ros, the values of which make it possible to preserve the fluxes, that is to say also the equivalent permeabilities, that is to say:
(7) (8) (9)
The numbers of the indices f 1, f 2, f 3 of the conductivities indicate the direction of the normal of the simplified fracture. For example Cf19ros is the conductivity to be assigned to fractures of the coarse network whose normal is oriented in the direction dir ^ principal direction of the flow close to the abscissa axis of the mesh representation of the considered layer.
According to one embodiment of the invention, an e9ras fracture aperture is calculated that makes it possible to maintain the fracture porosity φτ of the initial network, according to a formula of the type:
(10) the computation of the pore fracture pore given in step 2.2.
According to an embodiment of the invention for which a matrix block characteristic dimension (a, b, c) has been calculated (see step 2.2), an equivalent matrix permeability keqm'jk is calculated in the ijk mesh retaining the value of the matrix-crack exchange parameter as follows:
(11)
According to the invention, if the value of the parameter P associated with the (sub) simplification zone under consideration indicates that all the families of the considered fracture network are at the same time substantially orthogonal to the considered layer and substantially continuous towards the others. layers of the formation, the values of the parameters defined above in the main direction 3 (that is to say dir3) are not considered or are canceled. Indeed, in this case, c being very large, this implies the non-existence of the family 3 of simplified fractures, fractures whose normal is oriented in the dir3 direction. In this case, only two families of vertical fractures are generated, with normal flow directions 1 and 2 in the case of a 2.5D fracture network. In all other cases, the equivalent parameters described above are calculated in the 3 directions. Three families of fractures will be generated with normal flow directions 1, 2 and 3.
Preferably, the fractures of the simplified networks obtained as described above are extended, if necessary, beyond the limits of the (sub) zones of simplification in order to guarantee a sufficient partial "overlap" and thus a sufficient connectivity of the simplified networks of the subsystems. neighboring areas. For this purpose, and following a test-proven procedure, the simplified network fractures DFNs can thus be extended by a length equal to 60% of the maximum spacing (Sigros, s29r0S, s39r0S) of the fractures of this network. Such a recovery image between (sub) zones of simplification is for example represented in FIG.
The families of fractures constituting the network of fractures of a simplification zone or subzone of simplification of a layer of the subterranean formation studied, are at this stage simplified respectively by zone or subzone of simplification. More specifically, each zone or subzone of simplification of a layer of the formation studied comprises a simplified fracture network DFNs characterized by at least a gap spacing between fractures, a fracture opening, and a permeability value. In addition, this simplified fracture network model is calculated taking into account the orientation and continuity of fracture families in each simplification zone or subzone, by determining a parameter P. This network model simplified fracture DFNs can then be advantageously (in terms of calculation time, but also in terms of accuracy) used for flow simulations, whether at the scale of the deposit or at the scale of an area of influence of one or more wells.
The steps 1 and 2 defined above are repeated for each layer of the underground formation of interest, prior to the implementation of step 3. 3. Operation of the formation fluid
Once the preceding steps 1 and 2 have been repeated for each layer of interest of the formation studied, it is, from the mesh representation for each of the layers, the simplified fracture network model for each of the layers, and a flow simulator, to define an optimal operating scheme of the fluid of the formation studied. By optimal operating scheme is meant an operating scheme for optimal use of a fluid considered according to technico-economic criteria predefined by the specialist. It can be a scenario with a high fluid recovery rate over a long operating life and requiring a limited number of wells. Then, according to the invention, the fluid of the studied formation is exploited according to this optimal exploitation scheme.
According to one embodiment of the invention, the tank engineer first constructs a reservoir scale flow model, the flow model taking into account the simplified fracture network model. According to one embodiment of the invention in which a flow simulation based on a "double medium" approach (also called "double porosity") is used, two approaches can be implemented to construct the model. flow: 1. approach based on classical double porosity
Proposed for example by (Warren and Root, 1963), this approach assumes that any elementary volume (mesh of the reservoir model) of the fractured reservoir is modeled as a set of identical parallelepipedal blocks, called equivalent blocks, delimited by a orthogonal system of continuous uniform fractures oriented along the main directions of flow. The flow of the fluids, at the reservoir scale, is carried out through the fractures for the most part, and fluid exchanges occur locally between the fractures and the matrix blocks. For example, it is possible to use the methods described in the following documents, applied to the entire tank this time: FR 2757947 (US 6023656), FR 2757957 (US 6064944) and FR 2918179 (US 8078405). These methods make it possible to calculate the equivalent fracture permeabilities and the equivalent block dimensions for each of the cells of the reservoir model. The result is then a grid filled with equivalent fracture and matrix properties and equivalent block size. The resolution of the flow is then carried out on a mesh which is based on that of the meshed representation of the formation studied, with a dual medium simulator such as PumaFlow software (IFP Energies nouvelles, France). 2. Approach using a simplified network on the entire tank
We can also directly mesh the simplified fracture network. For this, we can rely on patent applications EP 2530493 (US 9103194) and EP 2581767 (US 2013/009688913). This mesh can then be provided to a flow simulator based on a representation of the "double medium" type and able to process unstructured meshes, such as the PumaFlow software (IFP Energies nouvelles, France). Although more expensive, this simulation will be more accurate especially in cases where the meshes of the flow model are not oriented in the flow directions.
The definition of a fluid exploitation scheme of the studied formation may consist of choosing a type of recovery process (for example a water injection recovery method) and then determining, for this type of process, the number , geometry and implantation (position and spacing) of injectors and producers to better take into account the impact of fractures on the progression of fluids within the reservoir. In order to define an optimal exploitation scheme, different tests of different production scenarios can be carried out using a flow simulator. The operating scheme offering the best fluid recovery rate for the lowest cost will for example be preferred.
According to a dual-medium model, a so-called dual-medium flow simulator can be used to simulate the production of fluid for a given operating scheme. At any instant t of the simulation, the flow simulator solves the set of flow equations specific to each cell of each of the two grids of the model (equations involving the matrix-crack exchange formula described above) and thus delivers the solution values of the unknowns (saturations, pressures, concentrations, temperature, ...) predicted at this instant t. From this resolution, comes the knowledge of the quantities of oil produced and the state of the deposit (distribution of pressures, saturations, etc ...) at the moment considered. From a given exploitation scenario, from the double representation of the deposit, and from the formula linking the mass and / or energy exchange flux to the matrix-fracture potential difference, we are then able to to simulate expected hydrocarbon production using the so-called dual medium flow simulator.
By selecting various scenarios, characterized for example by various respective locations of injectors and producers, and by simulating the production of fluid for each of them, one can select the scenario to optimize the production of the training considered according to technical criteria. -economic predefined by the specialist.
The specialists then use the fluid of the formation considered according to the scenario making it possible to optimize the production of the deposit, in particular by drilling the injectors and producers defined by this optimal exploitation scheme, and to produce the fluid according to the recovery method defined. by said optimal operating scheme.
variants
Calculation of a simplified fracture network model on a fine grid
According to one embodiment of the invention, during the simplification step 2.4, a first simplified fracture network model is calculated on a fine grid (sugar box network), directly derived from the permeability calculation. equivalent. This network (FIG. 4) is characterized by fracture spacings corresponding to the dimensions of matrix blocks identified in the zone or sub-zone, ie s1fln = a, s2fin = b, s3fin = c in the 3 main directions of permeability 1, 2 , 3.
In case, we define an additional parameter of equivalent opening of the fractures (efin), characterizing the fractures of this fine network (all the fractures of this fine network are supposed to have the same opening). Assuming the equality of the porosities φτ of the initial DFN discrete fracture network model and the fine equivalent network, efin is deduced from the fracture volume of the initial DFN network, Vf, nit, and the total VT rock volume as follows:
For the record, the equivalent main fracture permeabilities, derived from the calculations described above, are worth k1t k2and k3 along the main directions 1, 2 and 3. We deduce the fracture conductivities of the fine equivalent network, Cf / ", Cf2fin and Cf3fin following these three directions of flow, by writing the conservation of flows per unit area of fractured medium:
The numbers of the indices f1, f2, f3 of the conductivities indicate the direction of the normal of the simplified fracture. For example Cf / "is the conductivity to be assigned to the fractures of the fine network in the dir1 direction, main direction of the flow close to the x-axis of the reservoir grid.
Finally, the matrix medium between fractures has a permeability km'jk.
Then we proceed to the replacement of this fine equivalent network (Figure 4) by the so-called "coarse" equivalent network (Figure 5), because with more spaced fractures to increase the degree of simplification for subsequent flow simulations. The geometric and flow properties of this coarse network are the following: o S! 9 ™ 3, s29ros and sbrros fracture spacings such as:
where G is a coefficient of magnification (of the separation of the fractures) of the network whose value can be determined as presented in step 2.4 o of the fracture conductivities Cf19ros, Cf29ros and Cf39ros, whose values make it possible to preserve the fluxes per unit area of fractured medium, that is to say also the equivalent permeabilities, that is:
or,
The numbers of the indices f 1, f 2, f 3 of the conductivities indicate the direction of the normal of the simplified fracture. For example Cf19r0S is the conductivity to be assigned to the fractures of the coarse network in the direction dir1, main direction of the flow close to the x-axis of the reservoir grid. o an opening of fracture e9ros making it possible to preserve again the fracture porosity of the initial network (equal to that of the coarse equivalent network):
from where :
a matrix permeability keqmljk retaining the value of the matrix-crack exchange parameter, that is to say:
where gold is a constant and where the equivalent fracture permeabilities of fine and coarse, equal networks are here denoted kf and kfos. We obtain then a formula of the type:
According to this variant embodiment of the invention, if the value of the parameter P associated with the simplification (sub) zone under consideration indicates that all the families of the considered fracture network are, at the same time, substantially orthogonal to the layer considered. and substantially continuous to the other layers of the formation, the components along the main direction 3 (i.e., dir3) of the parameters defined above are ignored. Thus, only two families of vertical fractures are generated, according to the flow directions 1 and 2 in the case of a 2.5D fracture network. In all other cases, the equivalent parameters described above are calculated in the 3 directions and three families of fractures will be generated, according to the flow directions 1, 2 and 3.
Calibration of fracture flow properties
Prior to simulating the fluid production of the studied formation for different exploitation schemes, it may be advantageous to calibrate the fracture flow properties (conductivity and opening of fractures), locally around the wells. Such a step requires the implementation of a well test simulation, from a well test simulator and a flow model. The flow model advantageously takes into account the simplified fracture network model determined at the end of step 2.
This type of calibration is well known to specialists. For example, the process described in patent FR 2787219 (US 6842725) may be used. The flow responses of a few wells (transient or pseudo-permanent flow tests, interferences, flow metering, etc.) are simulated on these models extracted from the reservoir model giving a discrete (realistic) representation of the fractures feeding these wells. Then, we compare the result of the simulation with the actual measurements made at the wells. If the results diverge, the statistical parameters (PSF) describing the fracture networks are modified, then steps 1 to 2 described above are re-applied before performing a new well test simulation. The operation is repeated until the well test simulation results and the measurements converge.
The results of these simulations make it possible to calibrate (estimate) the geometry and the fracture flow properties, such as the conductivities of the fracture networks of the studied reservoir and the openings.
This optional step makes it possible to determine a more reliable simplified fracture network model, since it makes it possible to construct a flow model that makes it possible to explain the existing measurements. Such a model can then be advantageously used to develop a flow model at the scale of the formation, and to test different exploitation schemes by reservoir simulation.
Computer program product The invention further relates to a computer program product downloadable from a communication network and / or recorded on a computer-readable and / or executable medium by a processor, including program code instructions for the implementation of the method according to one of the preceding characteristics, when said program is executed on a computer.
Application example
The characteristics and advantages of the method according to the invention will appear more clearly on reading the application example below.
The present invention has been applied to an underground formation composed of a single layer traversed by five wells, the hydrocarbon-type fluid-containing layer and a fracture network of which at least the orientation of a family leads to a parameter value. P equal to 0 (3D type fracture network). The objective of this application is to determine the optimal exploitation scheme, that is to say, an exploitation scheme allowing an optimal recovery of the hydrocarbons, while respecting technico-economic constraints. Among the exploitation schemes evaluated by flow simulation, a typical "five-spot injection" exploitation scheme, with an injector well at the center of the formation to be exploited and four wells at the periphery, was tested. Three zones of simplification ZS1, ZS2, ZS3 of circular geometry were defined around each of the wells and for each layer of the formation. Simplification areas ZS2 were then cut into column-like simplification sub-areas. And simplification areas ZS3 have been cut into simplification sub-zones of locally homogeneous type.
FIG. 7 shows, for a layer of the formation, the limits of the simplification subzones of the simplified fracture network model resulting from the implementation of the invention according to the characteristics defined above. In this figure, we can notably observe the zones ZS1 for which the mesh is the thinnest (no simplification realized in the zone ZS1), the zones ZS2 for which the mesh is of average size (division into simplification subzones of type column), and the zones ZS3 for which the mesh size is coarser (cutting into simplification subfields of locally homogeneous type). Each of these simplification sub-zones comprises a fracture opening, a fracture spacing, a permeability tensor, as well as a conductivity tensor, as determined according to the invention.
A flow simulation performed on an unstructured fracture network DNF (characterized by 350000 fractures, with 2560000 intersections) proved impractical in practice since only 1% of the production time was simulated in two weeks) on a station Precision 5810 workstation. With a simplified fracture network model DFNs realized according to the method according to the invention, the same simulation was completed in 12 hours on the same workstation.
Thus, the simplification according to the invention of a flow model, in the case of any fractured medium, allows a significant saving of computation time, while at the same time preserving the flow properties around the wells. This gain in computation time can potentially make it possible to test more scenarios (exploitation plans) for the exploitation of the fluid contained in the fractured medium, and thus make it possible to determine an optimal exploitation scheme of the fluid of the formation, satisfying at best technical and economic criteria.

权利要求:
Claims (16)
[1" id="c-fr-0001]
A method for the exploitation of a fluid within an underground formation comprising at least one layer traversed by a fracture network and by at least one well, in which a meshed representation of said at least one layer is constructed from measurements of properties relating to said at least one layer, and at least for said layer, a zone of interest comprising a set of meshes of said meshed representation relating to said layer and comprising at least said well, characterized in that at least the following steps are carried out for each of said layers: A. from said measurements, said fracture network is characterized by statistical parameters, and a discrete fracture network model is constructed from said parameters; ; B. for each of said wells contained in said zone of interest, at least three simplification zones (ZS1, ZS2, ZS3) are defined, a first simplification zone (ZS1) containing said well, a second simplification zone (ZS2). having as an internal boundary the outer boundary of said first zone (ZS1), and a third zone of simplification (ZS3) having as an internal boundary the outer boundary of said second zone (ZS2), all of said simplification zones of the whole said wells covering all the stitches of said area of interest; C. from at least said statistical parameters, for at least each of said simplification zones (ZS1, ZS2, ZS3) of said zone of interest, an equivalent permeability tensor and a value of a parameter are determined; P characterizing the orientation and continuity towards the other layers of the fractures of said network; D. a simplification of said model is determined in each of said simplification zones, as a function of said zone, of said equivalent permeability tensor and of said value of said parameter P; and in that, from said mesh representation, of said simplified fracture network model, and a flow simulator, an optimum exploitation scheme of said fluid of said formation is defined and said fluid of said formation is exploited according to said optimal operating scheme.
[2" id="c-fr-0002]
2. The method of claim 1, wherein said statistical parameters are selected from the following parameters: fracture density, fracture length, orientation of fractures in space, opening of fractures, and distribution of fractures within said layer.
[3" id="c-fr-0003]
3. Method according to one of the preceding claims, wherein said simplification zones are cylinders of vertical axis and elliptical section, centered around said well.
[4" id="c-fr-0004]
4. The method of claim 3, wherein the major axis of one of said simplification areas is oriented in a preferred direction of flow, said preferred direction being determined from a diagonalization of said equivalent permeability tensor.
[5" id="c-fr-0005]
5. Method according to one of the preceding claims 3 or 4, wherein the distance separating two of said zones is determined according to a geometric progression of constant reason.
[6" id="c-fr-0006]
6. Method according to one of the preceding claims, wherein no simplification of said fracture network model is carried out in said first simplification zone (ZS1), a first simplification is carried out in said second zone (ZS2), and a second simplification is carried out in said third zone (ZS3), said second simplification being greater than said first simplification.
[7" id="c-fr-0007]
7. Method according to one of the preceding claims, wherein said second and / or third simplification zones (ZS2, ZS3) are cut into annular simplification sub-zones.
[8" id="c-fr-0008]
The method according to one of the preceding claims, wherein said second simplification areas (ZS2) are cut into column simplification sub-areas.
[9" id="c-fr-0009]
9- Method according to one of the preceding claims, wherein said third simplification areas (ZS3) are cut into sub-areas of simplification locally homogeneous.
[10" id="c-fr-0010]
10- Method according to one of the preceding claims, wherein said parameter P is determined for at least each of said simplification areas (ZS1, ZS2, ZS3), by means of: - a value of a parameter PO measuring the orientation in the space of said fractures of said layer according to a formula of the type:

, and / or - a value of a parameter PC measuring the continuity of said fractures of said layer towards the other layers according to a formula of the type:

where ki, k2, and k3 are the eigenvalues of said permeability tensor after diagonalization.
[11" id="c-fr-0011]
11- Method according to one of the preceding claims, wherein said simplification consists of the calculation of at least one spacing value between said fractures, an opening of said fractures, and a permeability value.
[12" id="c-fr-0012]
12- Method according to one of the preceding claims, wherein said simplification of said model is performed in three directions of space if the parameter P characterizes fractures not substantially orthogonal to the layers and / or continuous to the other layers.
[13" id="c-fr-0013]
13- Method according to one of claims 1 to 11, wherein said simplification of said model is performed along two directions of space if the parameter P characterizes fractures substantially orthogonal to the layers and continuous to the other layers.
[14" id="c-fr-0014]
14- Method according to one of the preceding claims, wherein said optimal operating scheme is defined by determining a recovery process of said fluid, and a number, an implantation and a geometry of wells injectors and producers to satisfy predefined technical and economic criteria.
[15" id="c-fr-0015]
15. The method of claim 14, wherein said exploitation of said fluid according to said optimal exploitation scheme consists at least in drilling said injectors and producing wells and producing said fluid according to said recovery method.
[16" id="c-fr-0016]
16- Computer program product downloadable from a communication network and / or recorded on a computer readable medium and / or executable by a processor, comprising program code instructions for the implementation of the method according to one of the preceding claims, when said program is executed on a computer.

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公开号 | 公开日

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EP3144468B1|2019-03-27|

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FR3041026B1|2017-10-20|

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优先权:

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申请号 | 申请日 | 专利标题

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FR1558653A|FR3041026B1|2015-09-15|2015-09-15|METHOD FOR CHARACTERIZING THE NETWORK OF FRACTURES OF A FRACTURE SLOT AND METHOD FOR OPERATING IT|FR1558653A| FR3041026B1|2015-09-15|2015-09-15|METHOD FOR CHARACTERIZING THE NETWORK OF FRACTURES OF A FRACTURE SLOT AND METHOD FOR OPERATING IT|

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EP16187472.2A| EP3144468B1|2015-09-15|2016-09-06|Method for characterising the network of fractures of a fractured deposit and method for exploiting same|

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US15/265,665| US10288544B2|2015-09-15|2016-09-14|Method for characterizing the fracture network of a fractured reservoir and method for exploiting it|