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    • 专利摘要:
    The present invention relates to a method for optimizing a reservoir of fluid traversed by a fracture network. For this process, the deposit is discretized in a mesh representation, a "double-medium" approach is used, and the exchange flux between the meshes is determined, as well as corrective factors. The corrective factors are dependent on the initial pressure and the minimum production pressure of the deposit. By means of these fluxes and these corrective factors, the flows of fluid (s) in the deposit are simulated.
    公开号:FR3047039A1
    申请号:FR1650582
    申请日:2016-01-26
    公开日:2017-07-28
    发明作者:Bernard Bourbiaux；Didier Yu Ding
    申请人:IFP Energies Nouvelles IFPEN；
    IPC主号:
    专利说明:

    The present invention relates to the field of the exploitation of underground deposits, such as hydrocarbon deposits, especially when they include a network of fractures.
    The method according to the invention is particularly suitable for the study of the hydraulic properties of fractured terrains, and in particular to study hydrocarbon displacements in underground deposits.
    In particular, the invention relates to a method for predicting the flow of fluids that may occur through this medium, to simulate hydrocarbon production under various production scenarios. The oil industry, and more specifically the exploration and exploitation of deposits, especially oil, require the acquisition of the best possible knowledge of the underground geology to efficiently provide an assessment of reserves, a modeling of production , or the management of the operation. In fact, the determination of the location of a production well or an injection well, the constitution of the drilling mud, the completion characteristics, the choice of a hydrocarbon recovery process (such as the injection of water for example) and the parameters necessary for the implementation of this process (such as the injection pressure, the production flow, etc.) require a good knowledge of the deposit. Knowing the deposit means knowing the petrophysical properties of the subsoil at any point in space.
    To do this, the oil industry has for a long time been combining on-field measurements (in situ) with experimental (laboratory-generated) and / or digital (software-based) models. Modeling oil fields is therefore a technical step essential to any exploration or exploitation of deposits. These models are intended to provide a description of the deposit.
    Cracked reservoirs are an extreme type of heterogeneous reservoirs with two contrasting media, a matrix medium containing most of the oil in place and having a low permeability, and a cracked medium representing less than 1% of the oil in place. and highly conductive. The cracked medium itself can be complex, with different sets of cracks characterized by their respective density, length, orientation, inclination and aperture.
    The engineers in charge of the exploitation of fractured tanks, need to know perfectly the role of the fractures. 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, on the one hand, the knowledge of the distribution and behavior of these fractures. optimizes the location and spacing between the wells that are to be drilled through the oil field, and the geometry of the fracture network conditions the movement of the fluids both on the reservoir scale and on the at the local scale where it determines elementary matrix blocks in which the oil is trapped, knowing the distribution of fractures, is therefore very useful, also, at a later stage, for the tank engineer who seeks to calibrate the models that it constructs to simulate the deposits to reproduce or predict past or future production curves.For these purposes, geoscientists have three-dimensional images the deposits, allowing to locate a large number of fractures.
    Thus, to reproduce or predict (ie "simulate") the production of hydrocarbons during the production of a deposit according to a given production scenario (characterized by the position of the wells, the recovery method, ...) , the tank engineering specialist implements a computation software, called "reservoir simulator" (or "flow simulator"), which calculates the flows and the evolution of the pressures within the tank, the results of these calculations allowing it to predict and optimize the deposit in terms of flow and / or quantity of recovered hydrocarbons. The calculation of the behavior of the reservoir according to a given production scenario constitutes a "reservoir simulation". State of the art
    A method is known for optimizing the exploitation of a fluid reservoir traversed by a fracture network, in which fluid flows in the reservoir are simulated by means of a simplified but realistic modeling of the deposit. This simplified representation is called the "double-medium approach", it is proposed by Warren J.E. et al. in "The Behavior of Naturally Fractured Reservoirs", SPE Journal (September 1963), 245-255. This technique consists in considering the fractured medium as two continua exchanging fluids between them: 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 sets of meshes (called grids) superimposed, constituting the grid "crack" and the grid "matrix". 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 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 an orthogonal and regular network of fractures oriented along the main directions of flow: for each mesh, one thus defines a block matrix, said "representative" (of the real distribution (geological) blocks), unique and of parallelepipedic form. 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 flux at the scale of this mesh.
    In the "simple permeability" version of the double-medium model, the fluid flow at the reservoir scale is supposed to be carried out only via fractures (ie via the single fracture grid), fluid exchanges occurring locally between fractures and matrix blocks (ie between the two meshes of a given couple of meshes "fracture" and "matrix" representing the porous reservoir fractured at a given location of the field). In the "double permeability" version of the same model, the flow of fluids takes place within the two "fracture" and "matrix" media at the reservoir scale, with fracture-matrix exchanges always occurring between fluids. locally between fractures and matrix blocks.
    Such a representation (modeling) of the real (geological) fractured reservoir is used to reproduce, i.e. "simulate", the response (the behavior) of the field when it is put into production. To do this, flow or transfer equations are formulated, explained and solved for each of the meshes constituting the model according to the method summarized below: the set of mathematical equations applied to the double medium representing the fractured reservoir constitutes the simulator of double middle tank, well known specialists.
    A reservoir simulator makes it possible, from input data concerning both the two media (matrix and fracture), and the fluids that this double medium contains, to determine, at various times ("no time ") and in each cell, the values of various parameters quantifying the state of these two media such as saturations (oil, gas, water), pressures, concentrations, temperatures, ... This simulator solves two sets of equations, one relating to the matrix medium, and the other relating to the fractured medium. As a reminder, these equations express the mass (per constituent) and energy balances for each pair of "fracture" and "matrix" meshes representing an elementary volume of the real porous fractured reservoir: these mass balances involve exchange flux between cells of the same medium (fracture or matrix) neighboring in space, the matrix-crack exchange term object of the present invention, a possible injection term or production if a well passes through the elementary volume considered , the set of previous flow terms being equal to the term of accumulation of matter or energy of the mesh considered. Thus, the equations relating to the "matrix" medium and the "fracture" medium at each point of the reservoir are coupled, via an exchange term, describing the exchange fluxes (mass or energy) between the rock (matrix ) porous and the fractures which cross it: this modelization of matrix - fracture exchanges is essential, because the matrix contains most of the essential reserves to produce.
    The method adopted up to this day, to formulate these matrix-fracture exchanges (or matrix-crack), consists, for each pair of fracture meshes and matrix discretizing the double-medium model: on the one hand to determine the dimensions of blocks identical matrices (in dimensions and shape) supposed to represent the complex real distribution of the blocks present in this elementary volume of reservoir; and then to formulate and calculate the matrix-crack exchange flux as a function of the dimensions of this representative block thus calculated (this flux is then equal to the flux expressed for such a representative block multiplied by the number of such blocks in the mesh considered) .
    Thus, the exchange formulations adopted to date in fractured reservoir simulators, which rely on a very simplified representation of this type of reservoir, prove to be very approximate and incapable of faithfully accounting for all the mechanisms involved. exchange media that may be involved, which include pressure diffusivity, capillarity, gravity, molecular diffusion, conduction, and viscous forces.
    Indeed, on the one hand, the exchange between matrix blocks and cracks is expressed at the mesh scale (hectometric) of the simulation model considering that a matrix block of fixed dimensions and shape is representative of (" equivalent to (a) the set of real (geological) blocks of the mesh. On the other hand, the exchange is assumed to be pseudo-permanent, ie the exchange flux at the limits of this equivalent block is proportional to the potential difference (ex .: the difference in pressure, the difference temperature, ...) between the two matrix and fissure media. For each medium, this potential (temperature for example) is supposed to be uniform within a given medium, therefore in the present uniform case (constant) within the representative block of the mesh considered at the moment of simulation considered. However, the exchanges between cracks and blocks, especially if they involve several fluid phases, are not instantaneous. Moreover, apart from the gravitational and viscous entrainment effects (by the fracture flow), these exchanges concern first the periphery of the blocks before spreading towards their center. This spatial non-uniformity of the change of state of the matrix blocks also induces a temporal evolution (i.e. non-stationary or transient), since the fluid of the fracture accesses much faster to the borders of the block than to its center. A faithful reproduction of the change of state of the blocks would thus need to discretize the block in order to simulate displacements on a local scale (intra-block), the resultant of these flows on the block-fracture boundary then constituting a much larger estimate. precise exchange matrix - fracture over time.
    For example, it should be remembered that multiple expressions of this constant form factor σ (ie only dependent on the dimensions a, b, c of the block and independent of the variable solved by the simulator, such as water saturation for example) have been proposed in recent decades: for example, the first of these, proposed by Kazemi et al. in 1976 (ref .: Kazemi, H., Merrill, LS, Porterfield, KL and Zeman, PR: "Numerical Simulation of Water-Oil Flow in Naturally Fractured Reservoirs", SPE Journal (Dec. 1976) 317, defines the factor of constant form as follows:
    In order to take into account the transient nature of the exchange flux, the patent applications FR 2 925 726 A (US Pat. No. 8,386,225) and FR 3,007,165 A (US 2014-0372042 A1) describe a method, in which the Transient exchange flux between porous blocks and fractures is determined by means of a form function (also called form factor) transient. This method is suitable, in particular for two-phase exchanges of slightly compressible fluids such as exchanges by water-oil imbibition for example.
    However, in the case of very low permeability matrix environments, the forecast of the exchanges between matrix and fractures during the so-called short-time or transient period (period during which the so-called transient exchanges are not yet pseudo
    permanent) is very imprecise, and the duration of this transitional period is long. However, the usual models simulate the production at both short and long times, while the short-term flow behavior is not the same, which induces important errors for the fields whose very little permeable matrix blocks remain long in this transitional state of production. With the methods of the prior art, it proved impossible to reproduce the reference forecasts (ie to reproduce the simulations carried out by means of a so-called reference model, that is to say finely mesh the matrix blocks ) using a conventional dual medium simulator for gas fractured fields. In addition, it was also not possible to reproduce them using the same simulator incorporating improvements in the calculation of transient exchanges at short times.
    To overcome these disadvantages, the present invention relates to a method for optimizing a fluid deposit traversed by a fracture network. For this process, the deposit is discretized into a mesh representation, and a "double-medium" approach, and the exchange flux between the meshes is determined, as well as corrective factors. The corrective factors are dependent on the initial pressure and the minimum production pressure of the deposit. By means of these fluxes and these corrective factors, the flows of fluid (s) in the deposit are simulated. Thus, it is possible to simulate, in a representative manner, the flows of any type of fluid (compressible or not), including in matrices that are not very permeable.
    The method according to the invention relates to a method for the exploitation of a fluid reservoir traversed by a fracture network, in which, from measurements of properties relating to said deposit, a meshed representation of said deposit is constructed, each cell of said representation comprising a matrix medium and a fractured medium, and in which the initial pressure of said deposit and the minimum production pressure of said deposit are known. For this method, the following steps are carried out: a) determining in each mesh an exchange flux intervening between said matrix medium and said fractured medium; b) determining a corrective factor of said exchange flow by means of said initial pressure of said deposit and said minimum production pressure of said deposit; c) the flows of said fluid in said deposit are simulated by means of a flow simulator, said exchange flux and said corrective factor; and d) optimizing the exploitation of said deposit by means of said simulation of said flows.
    According to one embodiment of the invention, said steps a) and b) are performed in this order, simultaneously or in reverse order.
    Advantageously, said corrective factor of said exchange flux is obtained by means of a pseudo-pressure formulation of the fluid flow equations in the deposit.
    In accordance with one embodiment of the invention, said correction factor is determined for the transient exchange regimes.
    According to one variant, said corrective factor for one-dimensional transient exchange regimes β ^ _ΙΒ (Ρ) is written by a formula of the type:
    - Pref a reference pressure, - pref the viscosity at the reference pressure, - Zref the compressibility factor of said fluid at said reference pressure, P the average pressure of a matrix block of said matrix medium, - μ the viscosity of said fluid at a pressure p - Z the compressibility factor of said fluid at said pressure P, - mf the pseudo-pressure at the final state - mi the pseudo-pressure at the initial state of the reservoir, - Pf the pressure of the reservoir at the final state, and m (P) an average pseudo pressure of said matrix block defined as:
    As a variant, said corrective factor for the two-dimensional transient exchange regimes J3SJ_2D (P) can be written with a formula of the following type: βΙΤ-2ο (Ρ) = ^ · βίΤ-ΙΒ (Ρ) with
    with - Pref a reference pressure, - pref the viscosity at said reference pressure,
    - Zref the compressibility factor of said fluid at said reference pressure, P the average pressure of a matrix block of said matrix medium, - μ the viscosity of said fluid at a pressure p - Z the compressibility factor of the fluid at said pressure P, - mf the pseudo-pressure in the final state - mi the pseudo-pressure in the initial state of the reservoir, - Pf the reservoir pressure in the final state, m (P) an average pseudopressure of the said matrix block defined as:
    - L ° eq an equivalent length of a one-dimensional matrix block at the initial time of the transient regime, and - Lfg an equivalent length of a one-dimensional matrix block at the final transient time.
    According to an implementation of the invention, said correction factor is determined for the pseudo-permanent exchange regimes.
    According to one variant, said corrective factor for the pseudo-permanent one-dimensional diagrams β ^ _ιο (Ρ) or two-dimensional diagrams β ^ _2Β (Ρ) can be written using a formula such as:
    - Pref a reference pressure, - μΓ6 / the viscosity at said reference pressure, - Zref the compressibility factor of said fluid at said reference pressure, P the average pressure of a matrix block of said matrix medium, - μ the viscosity of said fluid pressure p - Z the compressibility factor of said fluid at the pressure p, - mf the pseudo-pressure in the final state - mi the pseudo-pressure at the initial state of the reservoir, - Pf the pressure of the reservoir at the final state, and m (P) the mean pseudo pressure of said matrix block defined as:
    According to one characteristic of the invention, prior to step a) a plurality of corrective factor values are determined and stored, and in step b), said corrective factor is determined among said stored values.
    Preferably, said exchange flux fp is calculated by means of a relation of the type: fp = CPmpAΦp, with C a geometric coefficient defined by C-AA-AB AC Iv {x), with AA, AB, AC the dimensions of said mesh, / y (x) a shape factor, ΔΦ ^ the potential difference and Pmp a property relating to the fluids and the matrix medium.
    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 according to one of the preceding features, when said program is executed on a computer.
    BRIEF DESCRIPTION OF THE DRAWINGS Other features and advantages of the method according to the invention will become apparent on reading the following description and nonlimiting examples of embodiments, with reference to the appended figures and described below.
    Figure 1 illustrates a horizontal projection of a block for a first example.
    For this first example, FIG. 2 illustrates curves of the production of gas P as a function of time T, according to a reference (ie according to the reference model finely waving the block), according to two methods according to FIG. prior art, and according to the method according to the invention.
    Figure 3 illustrates a horizontal projection of a gas tank for a second example.
    FIG. 4 illustrates curves of the production of gas P as a function of time T for the second example, for a reference, for a method according to the prior art, and for the method according to the invention.
    Detailed description of the invention
    The method according to the invention makes it possible to optimize the exploitation of a hydrocarbon deposit, especially when it comprises a network of fractures. From seismic data, well data, and sedimentary and lithological data, a geological model, ie a mesh representation, of the deposit studied is constructed, consisting of a detailed representation of its real internal complexity. This model comprises a set of meshes, each mesh of this representation comprising one or more property values relating to the deposit studied. In addition, each cell contains an image of the fracture network. This model forms a complex porous medium composed of a set of porous matrix blocks of irregular shapes and sizes. Each of the blocks is delimited by fractures.
    Given its geometric complexity, such a model, although representative, can not be used to make production forecasts for the deposit. It is essential to simplify it into an "equivalent" model. The term "equivalent medium" refers to a medium for which the estimation of oil recovery during a displacement process, such as capillary imbibition, is substantially the same as the oil recovery estimate made on the oil. complex porous medium, ie representative of the various shapes and dimensions of the matrix blocks constituting the considered deposit.
    Thus, from this geological model, according to the prior art, a simplified model is constructed (simplification by equivalence to a model of the Warren & Root type), called "equivalent", consisting of blocks of identical dimensions and shapes that possess the same petrophysical properties and behave in an equivalent way in terms of oil recovery. For example, the equivalence criterion is based on the recovery of oil during the capillary imbibing process of the blocks involved during a water injection (according to the patent application FR 2,757,957 (US 6,064. 944)).
    According to the invention, this same simplified model is used to simulate reliably and accurately the production of fluids, both compressible and incompressible, resulting from the blocks over time. Flow simulations are then performed to calculate more representative, more reliable, more accurate, and more numerous production forecasts. The method according to the invention makes it possible to make less risky development decisions and more quickly.
    The present invention requires the provision of: - measurements of properties relating to the studied formation: it can be measurements of petrophysical properties realized in situ, at various points of the studied formation, such as the porosity, the permeability, and the lithology (ie the type of rock), the relative permeability or the capillary pressure. These measurements may have been obtained for example by coring, via logs made in wells, by seismic acquisition campaigns. But it can also be measurements (oil flow rates, water flow rates, pressure variations for example) related to the flows in the studied layer, obtained for example by putting into production of the fluid in some wells passing through the formation. , during well tests or interference tests. These properties can in particular be used to construct a mesh representation of the formation studied. In order to better characterize the fracture network present in said formation, it may also be measures concerning the orientation, the dip or the extension of the fractures present in the formation studied, this information being determined for example from logs or outcrops. - a mesh representation representative of the studied formation: also called "model of reservoir", it is about a kind of model of the subsoil built in order to describe as precisely as possible the structure, the properties petrophysics of the studied formation, or the properties of the fluids present in the formation. 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 related to the studied formation 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). - A flow simulator: A flow simulator is a digital program, run on a computer, that is used to predict the flow of fluids within 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 "double medium" flow simulator, which makes it possible to model the exchanges between the non-fractured rock blocks (matrix 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 process according to the invention comprises four steps: 1- Discretization of the deposit in a set of meshes 2- Modeling of the fracture network 3- Simulation of the flows of fluids 4- Optimization of the conditions of production of the deposit 1 - Discretization of the deposit in one mesh set
    During this step, the deposit is discretized into a set of meshes, in order to have a representation of the deposit.
    For a long time, the oil industry has combined on-field measurements (in situ) with experimental (laboratory-generated) and / or digital (software-based) models.
    The modeling of the oil fields, therefore constitute a technical step essential to any exploration or exploitation of deposits. These modelizations are intended to provide a description of the deposit, characterized by the structure / geometry and the petrophysical properties of the deposits or geological formations that constitute it.
    These modelizations are based on a representation of the deposit in a set of meshes. Each of these meshes represents a given volume of the deposit, and constitutes an elementary volume of the deposit. The set of meshes constitutes a meshed representation (or discrete) of the deposit, called geological model. 2- Modeling the fracture network
    During this step, we model the fracture network of the deposit, in order to have a representation of the deposit traversed by the fractures.
    To take into account the role of the fracture network in the simulation of the flows within the deposit, it is necessary to associate with each of these elementary volumes (meshes) a fracture modeling.
    Thus, according to the invention, one starts from a geological model of the studied deposit, that is to say from a more or less detailed representation of the network of fractures, as faithful as possible of the direct and indirect observations of the reservoir made by specialists in charge of reservoir characterization. This model is a complex porous medium composed of a set of porous matrix blocks of irregular shapes and sizes delimited by fractures. This complex porous medium constitutes a representative image of the real network of fractures delimiting the matrix blocks.
    To implement such a method, it is possible to use modeling software, well known to specialists, such as the FRACAFlow® software (IFP Energies nouvelles, France).
    Because of its extreme geometric complexity, the previous geological model, representative of the real fractured reservoir, can not be used directly to simulate, reproduce and / or predict, the production of the deposit during the implementation of a recovery process. , such as water injection for example.
    To circumvent this obstacle, this model of the complex complex porous medium is simplified. A "double-medium" approach, also called "double porosity approach", proposed for example by Warren J.E. et al. (Ref .: "The Behavior of Naturally Fractured Tanks", SPE Journal (September 1963), 245-255). The "double porosity" approach consists in considering the fractured medium as two continua of contrasting properties and exchanging fluids between them: the "fracture" continuum (or "crack") constituted by the network of fractures and the "matrix" continuum consisting of Matrix blocks, the meeting of the two continued constituting a "double medium". Reservoir simulators based on this approach are known as "double porosity" or "dual medium" simulators.
    The implementation of a "double medium" simulator uses the calculation of exchanges between each of the two fracture and matrix meshes representing the so-called "double medium" in any volume element (or mesh) of the reservoir. Classically, this calculation is based on the equivalent simplified representation (of the Warren & Root type), according to which the distribution of geological blocks is represented by a set of identical "equivalent" blocks of parallelepipedal shape, of dimensions (Lx, Ly). , Lz). Obtaining this simplified representation is the subject of patent application FR 2 757 957 (US 6,064,944). The method according to the invention is based on this simplified representation commonly used by fractured tank simulators. 3- Simulation of fluid flows
    Principle At this stage, the reservoir engineer has a geological representation of the fractured hydrocarbon deposit, from which he wishes to extract the hydrocarbons.
    A tool well known to specialists is then used: a dual-medium reservoir simulator. Each of the two grids (set of meshes) of this reservoir simulator is indicated by input data E (t) which can concern on the one hand the properties (for example lithological facies, permeabilities of matrix and crack (Km, Kf), matrix and crack porosities (Φ ™, <Pf), ...) related to each of the two "matrix" media (for the so-called "matrix" grid) and "fracture" (for the so-called "crack" grid "), and secondly properties related to the fluids enclosed by these two media (for example densities, viscosities, ...). For this representation, we consider the exchanges within the fracture medium, the exchanges within the matrix medium, and the exchanges between the matrix medium and the fracture medium for a given pair of meshes.
    Using this information, the simulator can determine, in each mesh, and for each time step t, various parameters S (i), such as the saturation (Sm, Sf) of phase (water or oil for example) in each of the two matrix and crack media, the corresponding fluid pressure (Pm, Pf) in each of the two media, possibly the concentration, the temperature, etc., depending on the nature of the recovery process (injection of water, gas, etc. ...). To do this, the simulator solves two sets of coupled equations, a first set relating to the matrix medium, and a second set relating to the fractured medium. These two sets of equations are coupled, via a flux term, expressing mass and / or energy transfers (called "matrix-crack exchanges") between the porous rock (matrix blocks) and the fractures that cross it. . This matrix-fracture exchange flux (f) depends on the potential difference (ΛΦ) between these two media, which is expressed as a difference in pressure, temperature, etc. depending on the nature of the physical process. of exchange put into play by the recovery process applied.
    According to one embodiment of the method according to the invention, the proportionality factor C, called the exchange factor, can be calculated from a known solution of the pseudo-permanent exchange flux and which indicates that: 2 C = - + - + - (in the general case operating in the 3 x, y, z directions) T1 T1 T1 L / x L ^ y L ^ z
    With Lx, Ly, Lz the dimensions according to the directions of exchange x, y and z.
    In order to increase the reliability and the precision of the flow simulations of various fluids (liquid or gaseous), the method of the invention takes into account a corrective factor of the exchange fluxes which corrects the important errors on these flows related to the compressibility of the fluid and the low permeability of the matrix. Determination of a correction factor of the exchange flow
    During this operation, a corrective factor of the exchange flux is determined. This operation can be performed before, simultaneously with or after the exchange flux determination operation, since these two values are determined independently. The corrective factor is intended to correct the flow of exchange for a more accurate simulation.
    According to the invention, the corrective factor of the exchange flux is dependent on the initial pressure of the deposit and the minimum production pressure imposed on producing wells.
    Thus, the corrective factor makes it possible to take into account, during the simulation, the flows of compressible fluids, such as gases. In addition, the corrective factor makes it possible to take into account the permeability of the matrix medium.
    According to one embodiment of the invention, the corrective factor of the exchange flux is obtained by means of a pseudo-pressure formulation of the fluid flow equations in the deposit. This pseudo-pressure formulation is conventionally used for the interpretation of gas well tests (compressible fluids), which requires a particular treatment consisting in transforming the data / pressure measurements into pseudopression according to a transformation intended to integrate the significant variations of the properties of the fluid as a function of pressure (an example of such a pseudo-pressure formulation is described in particular in the book Hagoort, J. (1988) Fundamentals of Gas Tank Engineering, Developments in Petroleum Science, 23, Elsevier).
    According to one embodiment of the invention, a correction factor of the exchange flux can be calculated for the transient regime, also called "short time", and another corrective factor can be calculated for the pseudo-permanent regime , also says "long time". The transient regime corresponds to the initial phases of invasion of the mesh by the fluid. The pseudo-permanent regime starts when the exchange flux becomes proportional to the difference of potential (eg the difference of the pressures or pseudopressions, the difference of temperature, ...) between the two media matrix and crack, with a factor of proportionality independent of time. The method according to the invention then applies the corrective factor as a function of the regime in which the flow of the fluid is located.
    According to an alternative embodiment of the invention, the corrective factor of the exchange flux, variable as a function of the pressure described during the operation of the reservoir in question, can be determined by means of the following steps: • the corrective factor in question comes from a pseudo-pressure formulation of the flow equations (as used by the industry to interpret gas well tests): it is thus written as a function of common pseudopressure and pressure; However, because of the known correspondence between the variables of pseudo-pressure and pressure for the fluid considered (knowing the evolution of the viscosity and the compressibility of this fluid as a function of pressure), we can finally calculate this factor. as a simple function of pressure. • account is taken of the succession over time of a transient exchange regime (at "short times", which in reality can be long in the case of very low permeability matrix fields), and a at the so-called "pseudo-permanent" long times: consequently, the value of the corrective factor comes from different formulas depending on whether one is in one or the other of the two regimes. • the transition between the two regimes (therefore between the two calculation modes) is carried out for a value of the pseudo-pressure equal to the average value of the interval of the values. pseudo-pressure described during the operation (mi and mf being the pseudo-pressure values corresponding to the initial pressure of the reservoir on the one hand and the final pressure imposed via the wells in the other fractures). • the corrective factor can be formulated for one-way or multi-directional exchanges, given the knowledge of exact flows at initial times and "pseudo-permanent" flows at long times.
    According to one implementation of the invention, the values of this corrective function of the exchange flux as a function of the pressure can be determined beforehand and then stored in a memory (notably a computer memory), for example in tabular form. These values can then be read as input data (for example in the form of a simple table giving the pressure in the first column, and the pre-calculated value of the corrective coefficient of flux in the second column).
    According to an alternative embodiment, the corrective factor for the one-dimensional transient exchange regime (1D) can be written by a formula of the type:
    - Pref a reference pressure, - μνβί the viscosity at the reference pressure, - Zref the compressibility factor of the fluid at the reference pressure, - P the average pressure of the matrix block,
    - μ the viscosity of the fluid at the pressure P - Z the compressibility factor of the fluid at the pressure p, - mf the pseudo-pressure in the final state (state when the pressure of the reservoir is equal to the minimum pressure imposed at the bottom of the well) - mi the pseudo-pressure at the initial state of the reservoir, - Pf the pressure of the reservoir at the final state (equal to the minimum pressure imposed in the fractures via the production well (s)), and - m (P) the pseudo average pressure of the matrix block defined as:
    According to an alternative embodiment, the corrective factor for the two-dimensional transient exchange regimes (ie in 2 x and y directions of the parallelepipedal block of the matrix medium), β ^ _2Β (Ρ), can be written in a formula of type: β ^ 2Β (Ρ) = sc.psJ_lD (P)
    with the preceding definitions as well as the following ones: - m = m (P) the mean pseudo pressure of the matrix block, - L ° eq the equivalent dimension of the matrix block at the beginning of the transient regime (when m = m), which is equal to the equivalent length of the block for a 1D exchange:
    for a block whose dimensions according to the exchange directions x and y are equal to Lx and Ly - Üfq the equivalent length of the matrix block at the end of the transient regime and during the pseudo-permanent regime defined as follows:
    According to an alternative embodiment, the corrective factor for the pseudo-permanent one-dimensional regimes pL ^ _w {P) or two-dimensional β ^ _2Β (Ρ) is written by a formula of the type:
    with the notations previously used, especially taking into account LLJq.
    It should be noted that the method according to the invention also applies to slightly compressible fluids but with correction factors that can be determined more simply according to the pressure alone (and not the pseudo-pressures).
    Simulation of flows
    During this step, the flow of fluid (s) in the deposit is simulated using the double-medium model, the exchange fluxes and the corrective factors determined. The reservoir engineer can choose a production process, for example the water injection recovery process, the optimal implementation scenario for the field in question. The definition of an optimal water injection scenario may consist, for example, in determining the number and location (position and spacing) of the injection and production wells in order to best take into account the impact of fractures on the progression of fluids within the reservoir.
    Depending on the chosen scenario, the double-medium representation of the deposit, the formula linking the mass and / or energy exchange flux to the matrix-fracture potential difference, and the corrective factor of the exchange flux, it is then possible to simulate the expected hydrocarbon production, by means of the so-called dual medium flow simulator. The simulator then makes use of this correction factor to calculate a precise value of the exchange flux at each time step of the simulation characterized by a given value of the pressure. At any instant t of the simulated production, from the input data E {t) (fixed or variable data as the simulated time), the formula connecting the flow (/) of exchange to the difference of potential (ΑΦ), and the corrective factor of the exchange flux, the simulator solves the set of equations specific to each cell and 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 S (f) (saturations, pressures, concentrations, temperatures, ...) at this instant t. From this resolution comes knowledge of the quantities of oil produced and the state of the deposit (distribution of
    pressures, saturations, etc ...) at the moment considered. However, the exchange flow as currently calculated under the pseudo-permanent exchange regime and low compressibility fluids must be multiplied by the corrective factor
    during the transitional period of exchange (1D or 2D respectively), then by the corrective factor
    during the transitional period of pseudo-permanent exchange beginning when the pseudo-pressure is equal to
    . For a matrix-crack exchange governed by the pressure, one recalls the current expression of the mass flow of exchange pseudopermanent:
    where p is the density of the fluid, μ the density of the fluid, km the permeability of the matrix medium. L is the exchange length equal to the block size in the exchange direction for a 1D exchange, or the equivalent length Leq such that:
    (where SC is as defined above) for an exchange in two directions of the parallelepiped block. 4- Optimization of the production conditions of the deposit (EXP) From the simulations carried out during the preceding stages, the specialists can determine several exploitation plans corresponding to different possible configurations of exploitation of the underground reservoir: location of the producing wells and / or injectors, target values for flows per well and / or for the reservoir, the type of tools used, the fluids used, injected and / or recovered ... For each of these schemes, their production forecasts should be determined. These probabilistic production forecasts are obtained by means of flow simulation software as well as by means of the fractured reservoir numerical model. A reservoir simulation is a technique for simulating fluid flows within a reservoir using software called flow simulator and reservoir model. For example, the PumaFlow® software (IFP Énergies nouvelles, France) is a flow simulator.
    One or more possible exploitation schemes are defined for the fractured reservoir model (also called geological model). For each of these schemes, responses are determined by simulation. From the predictions of probabilistic productions defined for each exploitation scheme, the specialists can by comparison choose the exploitation scheme which seems to them the most relevant. For example: by comparing the maximum volume of oil recovered, one can determine the production scheme that can provide the maximum recovery or be the most profitable. by comparing the standard deviation of the volume of oil recovered, the least risky production scheme can be determined.
    The reservoir is then exploited according to the exploitation scheme defined for example by drilling new wells (producer or injector), by modifying the tools used, by modifying the flow rates and / or the nature of injected fluids.
    The process according to the invention is particularly suitable for the production of compressible fluids (gases) in very low permeability reservoirs. Indeed, it allows to take into account the compressibility of the fluids and the permeability of the reservoir. However, the method according to the invention can be used for any type of fluid and any type of tank. The invention also 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. This program includes program code instructions for implementing the method as described above, when the program is run on a computer.
    In general, the invention makes it possible to predict the hydrodynamic behavior (flow, pressure, etc.) of the fractured fields (or considered and modeled as such) in response to external stresses imposed via wells during the production of hydrocarbons.
    The engineers in charge of the exploitation of the deposit then have a tool allowing them to quickly and accurately evaluate the performance of different production scenarios, and thus, to select the one that optimizes the exploitation according to the criteria selected by the operator, for example to ensure optimum hydrocarbon production in terms of flow and recovery.
    Thus, the invention finds an industrial application in the exploitation of any type of underground deposit traversed by a network of fractures. It may be, for example, a hydrocarbon reservoir for which it is desired to optimize production, or a gas storage reservoir for example, for which it is desired to optimize the injection or the storage conditions.
    Application examples
    Two examples are given by way of illustration of the advantages of the present invention.
    Example 1: Production at the scale of a matrix block
    It is sought to predict the output from a parallelepipedal matrix block by two of its opposite faces. Figure 1 shows a horizontal projection of the parallelepiped block 1. The block is limited by two fractures F, by which the production of the block is solicited. The block is initially assumed to be saturated with gas and interstitial (immobile) water, and at a pressure of 3800 psi (262 bar). A pressure of 1000 psi (70 bar) is imposed and maintained constant in both fractures from this initial moment. The other boundaries of the block are supposed to be impermeable. In the simulated example, the two very thin fractures (0.01 feet of aperture or about 3 mm) are spaced apart by a length A of 200 feet (ie about 61 m) and the matrix has a permeability of 100 nanoDarcy (0.0001 mD ).
    For this example, the reference production REF is determined, that is to say the exact solution calculated by means of a model very finely discretizing the matrix block and the two fractures which limit it. In addition, the production is evaluated by applying to this example different double-medium models, which comprise only one double-medium mesh, that is to say a crack mesh and a mesh matrix. The first model according to the prior art AA1, with a constant form factor ("constant shape factor") corresponds to the production forecast of a conventional dual-medium tank simulator, which does not take account of the exchanges short-time transients, nor the effects of fluid compressibility on the calculation of exchanges between matrix and fracture meshes of a double-medium model. The second model according to the prior art AA2, with variable form factor ("variable shape factor"), corresponds to the production forecast with correction of flows at short times but according to a formalism in pressure, it is that is to say without taking into account the exchange flow errors related to the strong modification of gas properties as a function of the pressure. The third model according to the invention INV, corresponds to the determination of the exchange flux with a correction of this flow based on a formalism of exchanges in pseudo-pressure.
    Figure 2 illustrates the production of P gas in MMcf (million cubic feet, one cubic foot worth substantially 28.3 liters) versus time T in days, for REF reference production, for model evaluations according to prior art AA1 and AA2, and according to the invention INV. Note that the model according to the prior art AA1 does not reproduce the reference production curve, because it underestimates production at short times, and overestimates at long times. In addition, the model according to prior art AA2 is not satisfactory because it overestimates production. On the other hand, the model according to the invention INV gives a production forecast very close to the reference solution REF, whatever the instant of production considered.
    Example 2: Scale production of a tank volume
    In the same way, we try to predict the output from a reservoir portion. FIG. 3 illustrates the reservoir portion put into production by means of a horizontal W well which intersects a bidirectional fracture network F consisting of two families of orthogonal vertical fractures, generated by stimulation of the well. These F fractures are expected to delineate matrix blocks of 100 feet per 100 feet (about 30.5 m) along the X and Y directions in the SVA stimulated zone surrounding the well. The matrix-fracture exchanges are bi-directional this time, that is to say that they take place along the X and Y directions. Beyond the VS stimulated zone (1400 feet x 1000 feet x 300 feet, ie approximately 427 mx 305 mx 91.5 m), the reservoir is not fractured and behaves like a simple medium with the properties of the matrix identical to those of the previous case.
    For this example, the reference production REF is determined, that is to say the exact solution calculated by means of a model very discretely discretizing each of the matrix blocks and each of the fractures F of the stimulated zone VS around the well. In addition, the production is evaluated by applying to this example different double-middle models, which have mesh sizes of 200 feet x 200 feet x 300 feet (approximately 61m x 61m x 91.5m). The first model according to the prior art AA1, with a constant form factor ("constant shape factor") corresponds to the production forecast of a conventional dual-medium tank simulator, which does not take account of the exchanges short-time transients, nor the effects of fluid compressibility on the calculation of exchanges between matrix and fracture meshes of a double-medium model. The second model according to the invention INV, corresponds to the determination of the exchange flux and a corrective term of the exchange flux. The corrective term of the exchange flux depends on the initial and minimum pressures of the deposit.
    FIG. 4 illustrates the production of the P gas in Tcf (1012 cubic feet) as a function of the time T in days, for the reference production REF, for the evaluations with the models according to the prior art AA1, and according to the invention INV . Note that the model according to the prior art AA1 does not reproduce the reference production curve, because it underestimates production at short times. On the other hand, the model according to the invention INV faithfully reproduces the forecasts of the reference model REF.
    权利要求:
    Claims (11)
    [1" id="c-fr-0001]
    1) Process for the exploitation of a fluid reservoir traversed by a fracture network, in which, from measurements of properties relating to said deposit, a meshed representation of said deposit is constructed, each cell of said representation comprising a medium. matrix and a fractured medium, and in which the initial pressure of said deposit and the minimum production pressure of said deposit are known, characterized in that the following steps are carried out: a) a flow of exchange occurring between each mesh is determined between each mesh; said matrix medium and said fractured medium; b) determining a corrective factor of said exchange flow by means of said initial pressure of said deposit and said minimum production pressure of said deposit; c) the flows of said fluid in said deposit are simulated by means of a flow simulator, said exchange flux and said corrective factor; and d) optimizing the exploitation of said deposit by means of said simulation of said flows.
    [0002]
    2) Method according to claim 1, wherein said steps a) and b) are performed in this order, simultaneously or in reverse order.
    [0003]
    3) Method according to one of the preceding claims, wherein said corrective factor of said exchange flux is obtained by means of a pseudo-pressure formulation of fluid flow equations in the deposit.
    [0004]
    4) Method according to one of the preceding claims, wherein said corrective factor is determined for the transient exchange regimes.
    [0005]
    5) Method according to claim 4, wherein said corrective factor for one-dimensional transient exchange regimes β ^ _ιο (Ρ) is written by a formula of the type:

    with - Pref a reference pressure, - μ ·, · ^ the viscosity at the reference pressure, - Zref the compressibility factor of said fluid at said reference pressure, - P the average pressure of a matrix block of said matrix medium,

    μ the viscosity of said fluid at a pressure p - Z the compressibility factor of said fluid at said pressure p, - mf the pseudo-pressure at the final state - and the pseudo-pressure at the initial state of the reservoir, - Pf la reservoir pressure in the final state, and - m (P) an average pseudo pressure of said matrix block defined as:

    [0006]
    6) Method according to claim 4, wherein said corrective factor for two-dimensional transient exchange regimes fisJ_2D (P) is written by a formula of the type:

    and

    with - Pref a reference pressure, - μΓβί the viscosity at said reference pressure, - Zref the compressibility factor of said fluid at said reference pressure, - F the average pressure of a matrix block of said matrix medium, - μ the viscosity of said fluid at a pressure p - Z the compressibility factor of the fluid at said pressure p, - mf the pseudo-pressure at the final state - mi the pseudo-pressure at the initial state of the reservoir, - Pf the pressure of the reservoir at the final state, - m (P) an average pseudo pressure of said matrix block defined as:

    an equivalent length of a one-dimensional matrix block at the initial time of the transient regime, and







    - Lfg an equivalent length of a one-dimensional matrix block at the final time of the transient regime.
    [0007]
    7) Method according to one of the preceding claims, wherein said corrective factor is determined for pseudo-permanent exchange regimes.
    [0008]
    8) The method of claim 7, wherein said corrective factor for one-dimensional pseudo-permanent diets β ^ _ιο (Ρ) or two-dimensional fi ^ _2D (P) is written by a formula of the type:

    with - Pref a reference pressure, - μΓ6 / the viscosity at said reference pressure,% ref the compressibility factor of said fluid at said reference pressure, - P the mean pressure of a matrix block of said matrix medium, - μ la viscosity of said fluid at the pressure p - Z the compressibility factor of said fluid at the pressure p, - mf the pseudo-pressure at the final state - mi the pseudo-pressure at the initial state of the reservoir, - Pf the pressure of the reservoir in the final state, and m (P) the mean pseudo pressure of said matrix block defined as:

    [0009]
    9) Method according to one of the preceding claims, wherein prior to step a) is determined and stores a plurality of corrective factor values, and in step b), said corrective factor is determined among said stored values .
    [0010]
    10) Method according to one of the preceding claims, wherein said exchange flux fp is calculated by means of a relation of the type: fp = CPmpAΦ p, with C a geometric coefficient defined by C-AA-ABACIv {x) with AA, AB, AC the dimensions of said mesh, Iv {x) a form factor, ΔΦ the potential difference and Pmp a property relating to the fluids and the matrix medium.



    [0011]
    11) Computer program product downloadable from a communication network and / or recorded on a computer-readable and / or executable medium by a processor, comprising program code instructions for carrying out the method according to one of the preceding claims, when said program is executed on a computer.
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    同族专利:
    公开号 | 公开日
    US10872182B2|2020-12-22|
    US20170212973A1|2017-07-27|
    FR3047039B1|2018-01-26|
    CA2956285A1|2017-07-26|
    EP3199749A1|2017-08-02|
    引用文献:
    公开号 | 申请日 | 公开日 | 申请人 | 专利标题
    EP2813668A1|2013-06-13|2014-12-17|IFP Energies nouvelles|Method for optimising the exploitation of a fluid reservoir by taking into consideration a geological and transitional exchange term between matrix blocks and cracks|
    FR2757957B1|1996-12-30|1999-01-29|Inst Francais Du Petrole|METHOD FOR SIMPLIFYING THE MODELING OF A POROUS GEOLOGICAL ENVIRONMENT CROSSED BY AN IRREGULAR FRACTURE NETWORK|
    US7565278B2|2006-12-04|2009-07-21|Chevron U.S.A. Inc.|Method, system and apparatus for simulating fluid flow in a fractured reservoir utilizing a combination of discrete fracture networks and homogenization of small fractures|
    FR2925726B1|2007-12-20|2010-04-23|Inst Francais Du Petrole|METHOD FOR OPTIMIZING THE OPERATION OF A FLUID DEPOSITION BY TAKING INTO ACCOUNT A TERM OF GEOLOGICAL AND TRANSIENT EXCHANGE BETWEEN MATRIX BLOCKS AND FRACTURES|US10060241B2|2009-06-05|2018-08-28|Schlumberger Technology Corporation|Method for performing wellbore fracture operations using fluid temperature predictions|
    CN110529105A|2018-05-23|2019-12-03|中国石油天然气股份有限公司|Multi-dielectric has the design method and design device of Gas Reservoirs horizontal well development|
    CN112651190A|2020-12-21|2021-04-13|中国石油大学|Method for representing dual-medium seepage flow rate through fracture density|
    法律状态:
    2017-01-16| PLFP| Fee payment|Year of fee payment: 2 |
    2017-07-28| PLSC| Publication of the preliminary search report|Effective date: 20170728 |
    2018-01-26| PLFP| Fee payment|Year of fee payment: 3 |
    2020-01-28| PLFP| Fee payment|Year of fee payment: 5 |
    2021-01-27| PLFP| Fee payment|Year of fee payment: 6 |
    优先权:
    申请号 | 申请日 | 专利标题
    FR1650582|2016-01-26|
    FR1650582A|FR3047039B1|2016-01-26|2016-01-26|METHOD FOR OPERATING A FRACTURE-CROSS-FLUID FLOW BY MEANS OF FLOW SIMULATION BASED ON AN EXCHANGE FLOW AND A CORRECTIVE FACTOR|FR1650582A| FR3047039B1|2016-01-26|2016-01-26|METHOD FOR OPERATING A FRACTURE-CROSS-FLUID FLOW BY MEANS OF FLOW SIMULATION BASED ON AN EXCHANGE FLOW AND A CORRECTIVE FACTOR|
    EP16306687.1A| EP3199749A1|2016-01-26|2016-12-15|Method for exploiting a fluid reservoir having fractures passing through same by means of a flow simulation based on an exchange flow and a corrective factor|
    CA2956285A| CA2956285A1|2016-01-26|2017-01-25|Exploration process for a fluid deposit crossed by fractures by means of a flow simulation based on flow exchange and a corrective factor|
    US15/416,646| US10872182B2|2016-01-26|2017-01-26|Method for the development of a fluid deposit traversed by fractures by means of a flow simulation based on an exchange flow and a corrective factor|
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