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    • 专利摘要:
    Process for operating a hydrocarbon reservoir by gas injection in the form of a foam, comprising a step of determining a foam displacement model, this model being a function of an optimal gas mobility reduction factor and at least one interpolation function dependent on a parameter and constants to be calibrated. The gas mobility reduction factor is determined and the constants of at least one interpolation function are calibrated from experimental measurements including gas injections in non-foaming and foam form in a sample of the deposit for different values of the parameter relating to the function in question, and measurements of the pressure drop corresponding to each value of the parameter of the interpolation function considered. The calibration of the constants is performed according to interpolation by interpolation function. Application in particular to the exploration and the oil exploitation.
    公开号:FR3054594A1
    申请号:FR1657393
    申请日:2016-07-29
    公开日:2018-02-02
    发明作者:Bernard Bourbiaux；Christophe PREUX；Lahcen NABZAR；Benjamin BRACONNIER
    申请人:IFP Energies Nouvelles IFPEN；
    IPC主号:
    专利说明:

    ® FRENCH REPUBLIC
    NATIONAL INSTITUTE OF INDUSTRIAL PROPERTY © Publication number: 3,054,594 (to be used only for reproduction orders)
    ©) National registration number: 16 57393
    COURBEVOIE © Int Cl 8 : E 21 B 43/16 (2017.01), E 21 B 43/20
    A1 PATENT APPLICATION
    ©) Date of filing: 07.29.16. © Applicant (s): IFP ENERGIES NOUVELLES Etablis- (© Priority: public education - FR. @ Inventor (s): BOURBIAUX BERNARD, PREUX CHRISTOPHE, NABZAR LAHCEN and BRACONNIER (43) Date of public availability of the BENJAMIN. request: 02.02.18 Bulletin 18/05. ©) List of documents cited in the report preliminary research: Refer to end of present booklet (© References to other national documents ® Holder (s): IFP ENERGIES NOUVELLES Etablisse- related: public. ©) Extension request (s): © Agent (s): IFP ENERGIES NOUVELLES.
    PROCESS FOR THE EXPLOITATION OF A OIL DEPOSIT BY INJECTION OF A GAS IN THE FORM OF FOAM.
    FR 3 054 594 - A1 (6 /) Process for exploiting a hydrocarbon deposit by injecting gas in the form of foam, comprising a step of determining a model for displacement of the foam, this model being a function of '' an optimal gas mobility reduction factor and at least one interpolation function dependent on a parameter and constants to be calibrated.
    The reduction factor of mobility of the gas is determined and the constants of at least one interpolation function are calibrated from experimental measurements comprising injections of gas in non-foaming form and in the form of foam in a sample of the deposit for different values of the parameter relating to the function considered, and pressure drop measurements corresponding to each value of the parameter of the interpolation function considered. The constants are calibrated by interpolation function by interpolation function.
    Application in particular to oil exploration and exploitation.

    Q (cm3 / h)
    The present invention relates to the field of the exploitation of a fluid contained in an underground formation, more particularly the assisted recovery of a fluid, such as a hydrocarbon fluid, by injection of foam.
    The exploitation of an oil reservoir by primary recovery consists in extracting, via a so-called production well, the oil present from the reservoir by the overpressure effect prevailing naturally within the reservoir. This primary recovery only gives access to a small quantity of the oil contained in the reservoir, of the order of 10 to 15% at most.
    To allow further extraction of the oil, secondary production methods are used, when the reservoir pressure becomes insufficient to move the oil still in place. In particular, a fluid is injected (re-injection of the water produced diluted or not, injection of sea or river water, or injection of gas, for example) within the hydrocarbon tank, with a view to exerting within the tank an overpressure capable of entraining the oil towards the production well or wells. A common technique in this context is the injection of water (also known by the English term "waterflooding"), in which large volumes of water are injected under pressure into the reservoir via injector wells. The injected water entrains part of the oil it encounters and pushes it towards one or more producing wells. Secondary production methods such as water injection, however, only extract a relatively small part of the hydrocarbons in place (typically around 30%). This partial sweeping is due in particular to the trapping of the oil by capillary forces, to the differences in viscosity and density existing between the injected fluid and the hydrocarbons in place, as well as to heterogeneities on micro- or macroscopic scales (scale pores and also tank scale).
    To try to recover the rest of the oil, which remains in the underground formations at the end of the implementation of the primary and secondary methods of production, there are different techniques known as assisted recovery (known by the acronym "EOR >> , corresponding to "Enhanced Oil Recovery"). Among these techniques, mention may be made of techniques akin to the aforementioned injection of water, but employing water comprising additives such as, for example, water-soluble surfactants (we then speak of "surfactant flooding "). The use of such surfactants in particular induces a reduction in the water / oil interfacial tension, which is capable of ensuring a more effective entrainment of the trapped oil at the level of the pore constrictions.
    Also known is assisted recovery by injection of gases, miscible or not (natural gas, nitrogen or CO 2 ). This technique makes it possible to maintain the pressure in the petroleum tank during its exploitation, but can also make it possible, in the case of miscible gases, to mobilize the hydrocarbons in place and thus to improve the flow thereof. A commonly used gas is carbon dioxide when it is available at low cost.
    Alternative techniques are also known based on an injection of foam into the oil tank. Due to its high apparent viscosity, foam is considered an alternative to gas as an injection fluid in hydrocarbon tanks. The mobility of the foam is thus reduced compared to the gas which, on the other hand, tends to segregate and rapidly pierce in producing wells, in particular in heterogeneous and / or thick reservoirs. The assisted recovery by injection of foam is particularly attractive because it requires the injection of smaller volumes than for other assisted recovery processes based on non-foaming fluids.
    State of the art
    The following documents will be cited in the following description:
    Ma, K., Lopez-Salinas, J.L., Puerto, M.C., Miller, C.A., Biswal, S.L., Hirasaki, G.J., 2013. Estimation of Parameters for the Simulation of Foam Flowthrough Porous Media. Part 1: The Dry-Out Effect. Energy & Fuels 27, 2363-2375 (ACS Publications).
    Farajzadeh, R., Lotfollahi, M., Eftekhari, A.A., Rossen, W.R. and Hirasaki, G.J., 2015. Effect of Permeability on Implicit-Texture Foam Model Parameters and the Limiting Capillary Pressure. Energy Fuels 29, 3011-3018 (ACS Publications).
    Kapetas, L., Vincent-Bonnieu, S., Farajzadeh, R., Eftekhari, A.A., Mohd-Shafian, S.R., Kamarul Bahrim, R.Z. and Rossen, W.R., 2015. Effect of Permeability on Foam-Model Parameters - An Integrated Approach from Coreflood Experiments through to Foam Diversion Calculations. 18th European Symposium on IOR, Dresden, 14-16 April.
    The oil exploitation of a deposit consists in selecting the zones of the deposit presenting the best petroleum potential, in defining optimal exploitation schemes for these zones (using notably a numerical simulation of the flows in the deposit, in order to to define the type of recovery, the number and positions of the exploitation wells allowing an optimal recovery of hydrocarbons), to drill exploitation wells and, in general, to set up the production infrastructures necessary for the development of the deposit.
    The definition of an operating plan for an oil tank including a recovery step assisted by foam injection may require simulating numerically, as realistically as possible, the flows in the presence of foam in the tank considered. Such a simulation is carried out using a flow simulator comprising a foam displacement model.
    Such a model may need to assess the performance of the foam in terms of reduced mobility. In general, this estimate involves carrying out laboratory experiments consisting in measuring the pressure losses during displacement of foam on the one hand, of water and non-foaming gas on the other hand in a sample of the oil tank. Then this model of displacement of the foam, representative of the flows on the laboratory scale, is calibrated on the tank scale before carrying out the numerical simulations of the flows, in order to predict the benefit obtained by the injection of the foam in terms of improving the efficiency of displacement of the fluids in place.
    The foam displacement models used by the industry are relatively simple models which, under the conditions of existence of the foam, simulate only the effects of the foam in terms of reduced mobility and not the generation-destruction processes. foam. In general, the foam displacement models depend non-linearly on many parameters (calibration constants). Determining the parameters of this model therefore requires solving a non-linear inverse problem. However, the complexity of moving a foam in a confined medium that constitutes any natural porous medium makes modeling difficult because the large number of parameters influencing the foam can lead to indeterminacies (multiple solutions).
    We know the approach proposed in the document (Ma et al., 2013) which consists in simultaneously determining certain parameters of the foam displacement model by a graphical approach, supplemented by a numerical adjustment.
    We also know the technique proposed in the document (Farajzadeh et al. 2015) which proceeds to the determination of the unknown parameters (calibration constants) of the foam displacement model by an iterative least squares approach. However, the problem posed being non-linear vis-à-vis these unknowns, there is no uniqueness of the solution, or in other words, the parameters thus determined are one solution among others possible (cf. for example Kapetas et al ., 2015).
    The method according to the invention aims to pragmatically determine the parameters of the foam displacement model. Unlike the existing methods, the method according to the invention consists, from experimental data, in a sequential adjustment of the parameters of the foam model, and not in an overall adjustment. Thus, the method according to the invention makes it possible to minimize the numerical adjustments, by trying to extract the maximum amount of information on the dynamic behavior of the foam from experimental data.
    The method according to the invention
    Thus, the present invention relates to a method of operating an underground formation comprising hydrocarbons, by means of an injection of an aqueous solution comprising a gas in the form of foam and of a flow simulator based on a model. of displacement of said gas in the form of foam, said displacement model being a function of a factor of reduction of mobility of said optimal gas and of at least one function of interpolation of said factor of reduction of optimal mobility, said function of interpolation being function of at least one parameter relating to at least one characteristic of the foam and at least one constant. The method according to the invention is implemented from at least a sample of said formation, from conventional relative permeability measurements to said gas in non-foaming form and from relative relative permeability measurements from said aqueous phase, and comprises at least the following steps:
    A. said displacement model of said simulator is determined according to at least the following steps:
    i. a plurality of values of said parameter relating to at least one of said interpolation functions are defined, an injection is made into said sample of said gas in non-foaming form and of said gas in the form of foam according to said values of said parameter relating to said function, and a pressure drop with foam and a pressure drop without foam are measured respectively for each of said values of said parameter relating to said function;
    ii. from said pressure drop measurements relating to said interpolation function, an optimal value of said parameter relating to said function is determined, said optimal value making it possible to maximize a ratio between said pressure drops without foam and said pressure drops with foam measured for said function;
    iii. from said pressure drop measurements carried out at said optimal value determined for at least said interpolation function, from said conventional relative permeability measurements to said gas in non-foaming form and from said conventional relative permeability measurements to said aqueous phase, said optimal mobility reduction factor;
    iv. for at least said interpolation function, on the basis of said optimal mobility reduction factor, said pressure drop measurements relating to said interpolation function, said conventional relative permeability measurements to said gas in non-foaming form and said permeability measurements conventional relating to said aqueous phase, said constants of said interpolation function are calibrated;
    B- from said displacement model and from said flow simulator, an optimal exploitation scheme for said deposit is determined and said hydrocarbons are exploited.
    According to an embodiment of the invention, said model of displacement of the foam can be expressed in the form:
    k F rg {S g ^ FMkr g {Si>
    i Ç λ where Krg Vdg7 is the permeability relative to said gas in the form of foam for a given gas saturation value S 9 , ^ rg ^ g) es t | has permeability relative to said non-foaming gas for said gas saturation value Sg , and FM is a functional expressed in the form:
    FM = 1 + (Μ Οί, ί -ΐ) * Π ^ k
    where MP is said mobility reduction factor of said optimal gas and Fk is one of said interpolation functions, with k> 1.
    According to one embodiment of the invention, said interpolation functions can be four in number and said parameters of said functions can be a foaming agent concentration, water saturation, oil saturation, and a gas flow rate.
    Advantageously, said interpolation function Fk of a parameter Vk can be written in the form:
    F / VÙ
    M opt -l
    ΛΑ op 'ΛΑ op ' where 1V1 is said optimal mobility reduction factor and 1V1 k is an optimal mobility reduction factor for said parameter Vk .
    According to an embodiment of the invention, before step iii), optimal conditions can be defined as corresponding to said optimal values determined for each of said interpolation functions, said gas can be injected into said sample in the form non-foaming and said gas in the form of foam according to said optimal conditions, and it is possible to measure respectively a pressure drop with foam and a pressure drop without foam.
    Advantageously, it is possible to calibrate said constants of at least one of said interpolation functions by a method of least squares, such as an inverse method based on the iterative minimization of a functional.
    Other characteristics and advantages of the method according to the invention will appear on reading the description below of nonlimiting examples of embodiments, with reference to the appended Figure and described below.
    Brief presentation of the figures
    Figure 1 shows an example of the evolution of the mobility reduction factor R as a function of the gas flow rate Q.
    Detailed description of the process
    In general, one of the objects of the invention relates to a method of operating an underground formation comprising hydrocarbons, by means of an injection of an aqueous solution comprising a gas in the form of foam, and in particular the determination of an optimal exploitation scheme for the underground formation studied. In particular, the method according to the invention aims to determine the parameters of a displacement model of the gas in the form of foam. In the following, a phase dispersed in another phase is called foam by the addition of a foaming agent in one of the two phases. One of the phases can be water and the other phase is a gas, such as natural gas, nitrogen or CO 2 .
    The method according to the invention requires having:
    - a sample of the underground formation studied, taken by coring in situ for example;
    - a flow simulator based on a gas displacement model in the form of foam (see below);
    - measurements of conventional relative permeabilities to the gas in non-foaming form and measurements of conventional relative permeabilities to the aqueous phase: these may be measurements made expressly for the need of the process according to the invention (the specialist is fully aware of the manner of conducting such laboratory experiments), but it can also be analytical functions calibrated on the basis of correlations well known to the specialist.
    Thus, the method according to the invention requires having a flow simulator comprising a foam displacement model. According to the invention, the foam displacement model is based on the assumption that the gas present in the form of foam has its mobility reduced by a given factor under fixed conditions of formation and flow of the foam. The formulation of such a model, used by many flow simulators, consists of a modification of the gas permeabilities when the gas is present in the form of foam, which, for a given gas saturation S g , s' expresses according to a formula of the type:
    k F ° (Sg) = FMk r g (Sg) (1) where Krg is the permeability relative to gas in the form of foam, which is expressed as the product of an FM function by the permeability relative to non-foaming gas for the same gas saturation value s g (noted below sg 0 ) · An underlying assumption in current foam models is that the permeability relative to water (or liquid by extension) is assumed to be unchanged, as gas either present as a continuous phase or as a foam. In this hypothesis, the gas mobility reduction functional, denoted FM thereafter, is expressed according to a formula of the type:
    FM = -i- (2) + (ΜΧ, -ΐ) * Π ^ ( ν *) where:
    - MXiest optimal factor of reduction of mobility, that is to say the ratio of the permeabilities relative to the gas (k rg ) and to the foam [k ™) under optimal conditions to reduce the mobility of the gas, that is to say i.e. the conditions under which the terms Fk (V ^ defined below are equal to 1, ie:
    opt _ mod krg (s F g ° 0P jFOlçFO) Λrg i ~> g, opt)
    FM opt (3)
    - the terms Fk (V (with k equal to or greater than 1) are the values of the functions Fk of interpolation of the mobility reduction factor between the value mZî and l, which each depend on a parameter y k relating to at least a characteristic of the foam, and which involve a certain number of calibration constants to be calibrated as explained below.
    In order to provide a foam displacement model to the simulator representative of reality, the method according to the invention aims to determine, reliably from representative displacement measurements, the following modeling data:
    - the optimal gas mobility reduction factor defined by equation (3);
    - the calibration constants of each of the functions Fk considered in the definition of the foam displacement model according to equations (1) and (2).
    According to an implementation of the invention, the parameter y k can in particular be the concentration of foaming agent c w s, the water saturation s w , the oil saturation s a , or even the gas flow rate u g ..
    According to one embodiment of the invention, the gas mobility reduction functional, denoted FM, comprises four interpolation functions F ^ CVJet each of these functions comprises two constants to be calibrated from experimental data. According to an embodiment of the invention in which the gas mobility reduction functional comprises four interpolation functions Fk (V />' we define:
    - the interpolation function F 7 relating to the parameter Vi = C (concentration of foaming agent c ) by a formula of the type:
    <Mm (c ;, cr ef ) T (4) and for which the constants to be calibrated are the exponent e ,, and the constant c ref which corresponds to the concentration of foaming agent under optimal reference conditions;
    - the interpolation function F 2 relating to the parameter V 2 = S, (water saturation), by a formula of the type:
    F 2 = Q5 ! arctanE / ,,, π (5) and for which the constants to be determined are the constant / w which governs the transition (as a function of water saturation) between the foaming and non-foaming states and the constant si, which represents the saturation in transition water between stable and unstable foaming states;
    the interpolation function F 3 relating to the parameter y 3 = S 0 (oil saturation) by a formula of the type:
    (6)
    where s * 0 is the oil saturation beyond which the foam loses all its faculties to reduce the mobility of the gas, and the exponent e „is a constant to be determined;
    - the interpolation function F 4 relating to the parameter y 4 = u g (gas flow rate) by a 5 formula of the type:
    _fs_avec N - ^ s u n (7)
    Max (N c , N c ) J c </ xr w / C7) where / y * is the reference value of the capillary number N c calculated for the optimal reference flow. The variables involved in the calculation of N c are the speed of the gas u g , the porosity φ of the formation considered, the water-gas interfacial tension a gw (which is a function of the concentration of foaming agent c)), as well as the viscosity of the gas μ.
    The exponent e is also a constant to calibrate.
    In general, it can be shown that any interpolation function F k of the parameter y k can be written in the form:
    Fk (V k )
    FM (8)
    FM op t where Λ / ,,,,,,! (VJ is the reduction in mobility for a value V k of the parameter k impacting the foam (and for optimal values of the other parameters VÇ, j being different from k) and where MmÔd = MmodCE ^) is the mobility reduction obtained for the optimal value y ° k pt of the parameter y k . The method according to the invention thus consists, for each parameter y k impacting the foam, in determining the factors M mO d (y k ) for various values of this parameter, as well as, then in determining, from these factors, the constants of the interpolation function F k considered.
    According to an embodiment of the invention in which the FM functional defined in equation (2) involves the interpolation functions F ,, F 2 , F 3 and F 4 defined in equations (4) to ( 7), determining the foam displacement model requires calibrating the 8 constants: c w s ~ ref , e ,, fw, sl, S * 0, e „, N r c ef , e c
    According to the invention, the constants of the interpolation functions F k involved in equation (2) are determined by calibrating the interpolation function by the interpolation function (and not globally, for all the functions ), from experimental measurements relating to each of the interpolation functions, carried out under the optimal conditions established for the other interpolation functions.
    The method according to the invention comprises at least the following steps, step 1 being able to be repeated for each of the interpolation functions of the foam displacement model, and step 2 being optional:
    1. Laboratory measurements relating to an interpolation function
    1.1. Definition of values of the parameter relating to the interpolation function
    1.2. Injections with / without foam and pressure drop measurements
    1.3. Determination of an optimal parameter value
    2. Laboratory measurements under optimal conditions
    3. Determination of the foam displacement model
    3.1. Determination of the optimal mobility reduction factor
    3.2. Calibration of the constants of the interpolation functions
    4. Exploitation of hydrocarbons from the formation
    The various stages of the process according to the invention are detailed below.
    1. Laboratory measurements relating to an interpolation function
    During this step, laboratory experiments are carried out relating to a given interpolation function F k of the foam displacement model defined according to equations (1) and (2). According to an embodiment of the invention, this step is repeated for each of the interpolation functions involved in the displacement model of the foam defined according to equations (1) and (2). Note that the foam displacement model may, however, have only one interpolation function (case for which k = 1). Optimal values are adopted for the other parameters impacting the foam so that the other interpolation functions F y , j different from k, are equal to 1 or are invariant during these experiments relating to the interpolation function F k .
    During this step, applied to each interpolation function independently of one another, a plurality of values of the parameter relating to the interpolation function considered is defined, then an injection is made into said sample of the gas under non-foaming form and gas in the form of foam according to the values of the parameter relating to the interpolation function considered, and a pressure drop with foam and a pressure drop without foam are measured respectively for each of the values of the parameter relating to this function. This step is detailed below for a given interpolation function F k .
    1.1. Definition of values of the parameter relating to the interpolation function
    During this sub-step, it is a question of defining a plurality of values (with i ranging between 1 and I, and I> 1) of the characteristic parameter V k of the interpolation function F considered.
    According to an embodiment of the invention, it is a question of defining a range of values for this parameter and a sampling step of this range.
    According to one embodiment of the invention, the plurality of values of the parameter V k relating to the interpolation function F k considered are defined among the possible or realistic values of the parameter considered (for example, a mass concentration of foaming agent less than 1% in all cases) and so as to sample ad hoc the curve representative of the interpolation function considered (an interpolation function having a linear behavior does not need a high number unlike other types of function). The specialist in recovery assisted by injection of foam has perfect knowledge of how to define a plurality of ad hoc values of the parameters of each of the interpolation functions F k .
    According to an embodiment of the invention in which the interpolation function considered relates to the fluid flow rate (parameter V 4 of the function F 4 of equation (7)), a flow rate d is chosen for example. injection on carrot between 10 and 40 cm 3 / h, with a step of 10 cm 3 / h.
    1.2. Injections with / without foam and pressure drop measurements
    During this sub-step, at least two series of experiments are carried out on at least one sample of the underground formation for the interpolation function F k considered:
    injection of gas in non-foaming form (more precisely a co-injection of water and gas in non-foaming form) into the sample considered for each of the values y k , i of the parameter y k relating to the function F k considered .
    The gas and water flow rates adopted for each of these co-injections are the same as the gas and water flow rates injected in the form of foam in the tests which follow these co-injections. For example, in the case of the interpolation function F 4 of equation (7), only the flow rate is varied in the sample considered, the parameters of the other interpolation functions P 7 , F 2 , f 3 (for example, the foaming agent concentration, the quality of the foam and the oil saturation) being fixed. During each of the experiments in this first series, a pressure drop is measured (that is to say a pressure difference), which is noted Δρ * ° Ρ0 , for each value y ki ;
    - foam injection: the same experiment is repeated, for the same values of the parameter considered (for example the flow rate for the interpolation function F 4 according to equation (7)), but this time by injecting the water and the gas in the form of foam. During each of the experiments in this second series, a pressure drop (that is to say a pressure difference), which we denote Δρ ™, is measured for each value y k4 ;
    According to one embodiment of the invention, the injections of gas in non-foaming form and in the form of foam are carried out on samples of the formation initially saturated with a liquid phase (such as water and / or oil), which can be mobile or residual depending on the history of the core and the measurement objectives (mobility control of the gas in secondary or tertiary injection, after water injection). The displacements studied are then drainage processes in which the saturation of the gas phase increases in all cases.
    According to a variant implementation of the invention, it is possible to measure, in addition to pressure losses, the productions of liquid phase (water and / or oil) and of gas, and possibly, the gas saturation profiles during the transitory period of displacement and in the stationary state. These optional measurements make it possible to validate the model once the interpolation functions F k have been calibrated.
    1.3. Determination of an optimal parameter value
    During this sub-step, it is a question of determining the value y ° k pl - which will be called optimal value in the following, maximizing the ratio between the pressure drops without foam & pk ° FO and the pressure drops with Δρ ™ foam relating to the interpolation function Fk considered and measured during the previous substep. Thus, if we note Mu, the ratio of the pressure drops measured in the presence and in the absence of foam for the value y k4 of the parameter y k , that is
    Λ Λ & j
    M lab
    ΔΡ ™ pl ° F0 , ( c N0F0
    Krg g (k, F)), FO ( e FO)
    Krg bg (k, i ') J, we can then define the optimal value V k ^ pt as the value y ki which maximizes Mm whose value is then noted as follows:
    M ^ pt ^ MÏT ^ MaxMÏj, l
    (9)
    According to a preferred embodiment of the invention, step 1 as described above is repeated for each of the parameters y k relating to each of the interpolation functions ρ λ taken into consideration for the implementation of the method according to the invention. Thus at the end of such a repetition, an optimal value y ° k p 'is obtained for each parameter y k .
    Thereafter, the term “optimal conditions” is used to denote the set of values y k p ′ determined at the end of step 1, the latter being if necessary repeated for each of the interpolation functions taken into account for the implementation of the method according to the invention.
    2. Laboratory measurements under optimal conditions
    During this stage, it involves carrying out two types of experiments on at least one sample of the underground formation, by injecting gas in non-foaming form, and gas in the form of foam, similarly to the sub-stage. 1.2, but this time under the optimal conditions determined at the end of sub-step 1.3, this sub-step being repeated if necessary for each of the interpolation functions taken into account for the definition of the foam displacement model according to equations (1) and (2)). In other words, the following measurements are carried out:
    injection of gas in non-foaming form (more precisely a co-injection of water and gas in non-foaming form) into the sample considered, this injection being carried out under optimal conditions (defined by the set of optimal values vT determined for each parameter v k ) determined at the end of step 1. During this first experiment, a pressure drop (that is to say a pressure difference) is measured, which is noted Δρ ™ Ρ0 thereafter;
    injection of foam (that is to say an injection of gas and water, with the addition of a foaming agent in one of the water or gas phases) into the sample considered, this injection being carried out in the optimal conditions (defined by the set of optimal values y 0 / 'determined for each parameter v k ) determined at the end of step 1. During this second experiment, a pressure drop is measured (c' i.e. a pressure difference), which we denote by Δρ ™ later.
    Thereafter, we will denote m ° S, the optimal mobility reduction factor relating to laboratory measurements, defined by a formula of the type:
    AP F0 L · (e N0F0 ) _ ΙΛΓ opt _ Krg àg, opt / ~~ .pNOFO ~ jF0 („F0 A 2ΛΙ opt K, rg g, opt / (10).
    This step is not necessary in practice if we have taken the precaution of carrying out the experiments of step 1 relating to each of the parameters V k by adopting optimal values V 0 ^ of the other parameters Vj impacting the foam. This step nevertheless makes it possible to refine the value of Mu, if the supposedly optimal conditions of the parameters Vj, j * k were not entirely satisfied.
    3. Determination of the foam displacement model
    3.1. Determination of the optimal mobility reduction factor
    During this sub-step, it is, on the basis of the pressure drop measurements carried out under the optimal conditions, conventional relative permeability measurements for gas in non-foaming form and conventional relative permeability measurements for the aqueous phase , to determine an optimal mobility reduction factor, that is to say the reduction factor of the gas permeabilities when, present at a given saturation in the porous medium, it circulates in the form of foam or in the form of continuous phase (in the presence of water).
    According to an embodiment of the invention, the optimal mobility reduction factor is determined according to at least the following steps:
    - from the conventional relative permeabilities to gas k rg and to the aqueous phase k m , the gas saturation in steady flow of gas and non-foaming water s N g 0F0 is calculated according to a formula of the type:
    NOFO
    (11) where f g is the fractional gas flow (ratio of gas flow to total flow), μ and μ κ are the viscosity of gas and water respectively;
    - from the pressure drop ratio measured under the optimal conditions as defined at the end of step 1 (step 1 can be repeated if necessary for each of the interpolation functions F k considered), the gas saturation in steady flow of gas and non-foaming water S N g 0F0 , the gas saturation in the presence of foam s F0 is calculated according to a formula of the type:
    (12)
    N O FO
    N O FO
    This relationship follows from the known assumption of invariance of the permeability functions relating to water flowing in the form of foam films or in conventional continuous form.
    - from the gas saturation in steady flow of gas and non-foaming water s N g 0F0 , from the gas saturation in the presence of foam S F g ° op , under optimal conditions, by the factor mS determined under optimal conditions (and step 2), the mobility reduction factor Mmod is determined according to a formula of the type:
    (13)
    3.2. Calibration of the constants of the interpolation functions
    During this sub-step, the constants of each of the interpolation functions F k considered are calibrated, on the basis of the optimal mobility reduction factor Mm O d, of the pressure drop measurements relating to the interpolation function considered , conventional relative permeability measurements for gas in non-foaming form and conventional relative permeability measurements for the aqueous phase.
    According to one mode of implementation of the invention, the procedure described in sub-step 3.1 is applied beforehand to the ratios of the load losses / measured in the presence and in the absence of foam for the different values y *, · of the Vk parameter
    Thus, mobility reduction factors relating to the values ^ ki of the parameter are determined according to a formula of the type:
    (14), where the gas saturation in the presence of foam for the Vki values of the parameter is obtained according to a formula of the type:
    (15) krw (..S iNOFO lab
    Advantageously, this operation is repeated for each of the interpolation functions Fk . Then we calibrate the constants of each of the interpolation functions Fk considered,
    Ajf opt from the optimal mobility reduction factor 1V1 mod and the values of the mobility reduction factors relating to each interpolation function determined as described above. In the case of the function F 4 for example, a value of the exponent e c is determined which adjusts as closely as possible the values of Mmod corresponding to the values of the parameter studied (bit rate in this example), which is formulated as follows:
    Born
    F2VJ = ^ Max (Nc, i, Nc))
    According to an embodiment of _mX-i 'Æ-l the invention, this calibration, interpolation function by interpolation function, can be carried out by a method of least squares, such as for example an inverse method based on the iterative minimization of a functional. The specialist has perfect knowledge of such methods. Advantageously, the implementation of a least squares method, and in particular the iterative minimization of a functional, is carried out by means of a computer.
    According to another embodiment of the invention, such a calibration is carried out, interpolation function by interpolation function, graphically. The specialist is fully aware of such methods for calibrating constants of a function from a series of values of said function.
    Thus, at the end of this step, there is a calibrated foam displacement model capable of being used by an ad hoc flow simulator.
    4. Exploitation of hydrocarbons
    During this step, it is a question of defining at least one diagram of optimal exploitation of the fluid contained in the formation, that is to say a diagram of exploitation allowing an optimal exploitation of a fluid considered according to technical and economic criteria predefined by the specialist. It can be a scenario offering a high recovery rate of the fluid, over a long operating life, and requiring a limited number of wells. Then, according to the invention, the fluid of the formation studied is exploited as a function of this optimal operating scheme.
    According to the invention, the determination of said operating diagram is carried out using a flow simulation exploiting the foam displacement model established during the previous steps. An example of a flow simulator allowing the consideration of a foam displacement model is the PumaFlow software (IFP Energies nouvelles, France).
    According to the invention, at any time t of the simulation, the flow simulator solves all of the flow equations specific to each cell and delivers solution values of the unknowns (saturations, pressures, concentrations, temperature, etc. ) predicted at this time 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 instant considered. According to one embodiment of the invention, different operating diagrams of the fluid of the formation studied are defined and it is estimated, using the flow simulator integrating the foam displacement model determined with the from step 3, the quantity of hydrocarbons produced according to each of the different operating patterns.
    An operating scheme relating to recovery assisted by foam injection can in particular be defined by a type of gas injected in the formation studied and / or by the type of foaming agent added to this gas, by the quantity of foaming agent etc. An operating diagram is also defined by the number, geometry and location (position and spacing) of the injector and producer wells in order to best 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. For example, the operating scheme offering the best fluid recovery rate at the lowest cost will be preferred. By selecting various scenarios, characterized for example by various respective locations of the injector and producer wells, and by simulating the production of fluid for each of them, one can select the scenario making it possible to optimize the production of the training considered according to technical criteria. -economic predefined by the specialist. The operating scheme offering the best recovery rate of fluid at the lowest cost will for example be considered as the optimal operating scheme.
    The specialists then exploit 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 injector and producer wells defined by said optimal exploitation scheme, and in producing the fluid according to the defined recovery process. by said optimal exploitation scheme.
    Example of realization
    The characteristics and advantages of the process according to the invention will appear more clearly on reading the example of application below.
    More specifically, the present invention has been applied to an underground formation whose reservoir rock consists of sandstone of the Berea sandstone type. An enhanced recovery of the hydrocarbons contained in the tank based on an injection of foaming CO2 is being tested.
    For this example, we use a functional FM of the foam displacement model according to equation (2) defined by the four interpolation functions according to equations (4) to (7). As prescribed in the method according to the invention, the calibration of the constants of the interpolation functions is carried out interpolation function by interpolation function. Only the calibration of the interpolation function F 4 (see equation (7)) is detailed below, but the same principle can be applied to the other interpolation functions.
    In accordance with step 1.2 described above, a series of gas and water co-injections and foam injections were carried out in the laboratory, on a sample of the reservoir rock from the formation studied. The characteristics of this sample as well as the measurement conditions are presented in Table 1. A sparse gas mixture consisting of 62% CO2 and 38% methane at a temperature of 100 ° C and a pressure of 100 bars was injected . These displacements were carried out with a fixed fractional gas flow (equal to 0.8) and for different successive total flows (10, 20, 30 and 40 cm 3 / h). The oil is absent for this series of tests and the pressure drops under steady flow conditions for water and gas on the one hand, and foam on the other hand, were measured under the same conditions.
    The conventional relative permeabilities required for the resolution of equations (11) and (12) are analytical functions defined as power functions (called Corey) of exponents equal to about 2.5 for gas and 3.9 for water with saturation irreducible in drainage water equal to 0.15, and limit points equal to 0.2 for gas and 1 for water, ie:
    k rg is N g 0F0 ^^ - 'A- r
    NOFO
    2.5
    NOFO) =
    3.9
    These relative permeability curves have been estimated a priori from literature data and verified a posteriori by comparison of the pressure drop values calculated and measured during the gas and water co-injections. In this way, the model of permeability relative to the foam well restores the reductions in mobility of the gas, ie the ratios of relative permeability in the absence and in the presence of foam, without however necessarily reproducing well the real two-phase behavior (transient states in particular ).
    Table 1 presents the pressure drops (pressure gradient) with and without foam for four values of the parameter y 4 = u g of equation (7). From these values, we deduce the value of m® = MaxMtt, This value (mIT in this example), equal to i
    83, was obtained for a flow rate vT equal to 20 cm 3 / h (see sub-step 1.3). These laboratory experiments are repeated for the other parameters of the other interpolation functions F ,, F 2 , and F 3 . We then determine the optimal conditions for all the interpolation functions.
    In accordance with step 2, measurements are made with and without foam under the optimal conditions thus determined. Then, in accordance with step 3.1, the optimal mobility reduction factor mZi is determined as well as the values of the mobility reduction factors, v / 2d relative to the sampled values y, 3 of the parameter y k , in accordance with step 3.2. We then proceed to the calibration of each of the interpolation functions. In particular, the constant e c of the function F 4 has been calibrated and a value close to 0.6 has been determined.
    Figure 1 shows in solid lines the evolution of the mobility reduction factor R as a function of the parameter V 4 of the function F 4 (flow rate Q) deduced from the method according to the invention. The comparison with the mobility reduction factor from the flow simulation (dotted line curve) shows good consistency with the foam displacement model according to the invention.
    Thus the method according to the invention allows a reliable determination of the displacement model of the foam from experimental data produced and processed according to a sequential and systematic approach, parameter by parameter, and not by the global adjustment of a set of measurements. varying one or more parameters simultaneously. Furthermore, taking into account the parametric complexity of the behavior of the foams, the experiments according to the method according to the invention are carried out under conditions as close as possible to the reservoir conditions.
    Table 1
    Berea sandstoneP = 100 barT = 100 ° CL = 15 cmA = 12.56 cm2Φ = 0.19Kw = 120mDpw = 0.28cppg = 0.02cppg = 0.125g / cm3 Total flow [cm3 / h] 10 20 30 40 Δρ £ 5.2 10.3 11.9 13.6 ΔΡ, Τ ° 0.07 0.124 0.18 0.235 , „_ ΔΕ, Τ ° ΔΡ, ” 74 83 66 58
    权利要求:
    Claims (6)
    [1" id="c-fr-0001]
    1. Method of operating an underground formation comprising hydrocarbons, by means of an injection of an aqueous solution comprising a gas in the form of foam and a flow simulator based on a displacement model of said gas under foam form, said displacement model being a function of an optimal mobility reduction factor of said gas and at least one interpolation function of said optimal mobility reduction factor, said interpolation function being a function of at least a parameter relating to at least one characteristic of the foam and at least one constant, characterized in that, from at least one sample of said formation, measurements of conventional relative permeabilities to said gas in non-foaming form and conventional relative permeability measurements to said aqueous phase:
    A. said displacement model of said simulator is determined according to at least the following steps:
    i. a plurality of values of said parameter relating to at least one of said interpolation functions are defined, an injection is made into said sample of said gas in non-foaming form and of said gas in the form of foam according to said values of said parameter relating to said function, and a pressure drop with foam and a pressure drop without foam are measured respectively for each of said values of said parameter relating to said function;
    ii. from said pressure drop measurements relating to said interpolation function, an optimal value of said parameter relating to said function is determined, said optimal value making it possible to maximize a ratio between said pressure drops without foam and said pressure drops with foam measured for said function;
    iii. from said pressure drop measurements carried out at said optimal value determined for at least said interpolation function, from said conventional relative permeability measurements to said gas in non-foaming form and from said conventional relative permeability measurements to said aqueous phase, said optimal mobility reduction factor;
    iv. for at least said interpolation function, on the basis of said optimal mobility reduction factor, said pressure drop measurements relating to said interpolation function, said conventional relative permeability measurements to said gas in non-foaming form and said permeability measurements conventional relating to said aqueous phase, said constants of said interpolation function are calibrated;
    B- from said displacement model and from said flow simulator, an optimal exploitation scheme for said deposit is determined and said hydrocarbons are exploited.
    [2" id="c-fr-0002]
    2. Method according to claim 1, in which said model of displacement of the foam is expressed in the form:
    k ^ ÇS / ^ FMkr ^ S / where xrg | a relative permeability to said gas foamed to a gas saturation value S 9 given, kr g (Sg) is the permeability relative to said non-foaming gas to said saturation value gas s g, and FM is a functional s' expressing in the form:
    FM = -iι + (α ,,! -Ι) ϊ! Πε k
    where m is said mobility reduction factor of said optimal gas and Fk is one of said interpolation functions, with k> 1.
    [3" id="c-fr-0003]
    3. Method according to one of the preceding claims, in which said interpolation functions are four in number and said parameters of said functions are a concentration of foaming agent, water saturation, oil saturation, and a gas flow rate. .
    [4" id="c-fr-0004]
    4. Method according to one of the preceding claims, in which said interpolation function Fk of a parameter y k is written in the form:
    F / Vk)
    M ° k p, ~ l
    M opt -l where m is said optimal mobility reduction factor and mT is an optimal mobility reduction factor for said parameter y k .
    [5" id="c-fr-0005]
    5. Method according to one of the preceding claims, wherein, prior to
    Step iii), optimal conditions are defined as corresponding to said optimal values determined for each of said interpolation functions, said gas is injected into said sample in non-foaming form and said gas in the form of foam according to said optimal conditions, and a pressure drop with foam and a pressure drop without foam are measured respectively.
    [6" id="c-fr-0006]
    6. Method according to one of the preceding claims, wherein said constants are calibrated for at least one of said interpolation functions by a least squares method, such as an inverse method based on the iterative minimization of a functional.
    3054
    1/1
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    同族专利:
    公开号 | 公开日
    US20180030817A1|2018-02-01|
    CA2974549A1|2018-01-29|
    US10669818B2|2020-06-02|
    FR3054594B1|2020-07-17|
    EP3276124B1|2020-03-18|
    EP3276124A1|2018-01-31|
    引用文献:
    公开号 | 申请日 | 公开日 | 申请人 | 专利标题
    US3937283A|1974-10-17|1976-02-10|The Dow Chemical Company|Formation fracturing with stable foam|
    US7680640B2|2007-12-07|2010-03-16|Landmark Graphics Corporation|Systems and methods for utilizing cell based flow simulation results to calculate streamline trajectories|
    US9322263B2|2013-01-29|2016-04-26|Landmark Graphics Corporation|Systems and methods for dynamic visualization of fluid velocity in subsurface reservoirs|
    US20150337631A1|2014-05-23|2015-11-26|QRI Group, LLC|Integrated production simulator based on capacitance-resistance model|CN110894782B|2018-08-24|2021-09-28|中国石油天然气股份有限公司|Method and device for determining gas storage capacity of oil reservoir and storage medium|
    US10845322B2|2019-01-31|2020-11-24|King Fahd University Of Petroleum And Minerals|Method and apparatus for measuring capillary pressure and foam transport in porous media|
    EP3763913A1|2019-07-12|2021-01-13|IFP Energies nouvelles|Method for operating a hydrocarbon reservoir by injecting a gas in foam form|
    法律状态:
    2017-07-31| PLFP| Fee payment|Year of fee payment: 2 |
    2018-02-02| PLSC| Publication of the preliminary search report|Effective date: 20180202 |
    2018-07-25| PLFP| Fee payment|Year of fee payment: 3 |
    2019-07-25| PLFP| Fee payment|Year of fee payment: 4 |
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    2021-07-26| PLFP| Fee payment|Year of fee payment: 6 |
    优先权:
    申请号 | 申请日 | 专利标题
    FR1657393A|FR3054594B1|2016-07-29|2016-07-29|PROCESS FOR THE EXPLOITATION OF A HYDROCARBON DEPOSIT BY INJECTION OF A GAS IN THE FORM OF FOAM|
    FR1657393|2016-07-29|FR1657393A| FR3054594B1|2016-07-29|2016-07-29|PROCESS FOR THE EXPLOITATION OF A HYDROCARBON DEPOSIT BY INJECTION OF A GAS IN THE FORM OF FOAM|
    EP17305816.5A| EP3276124B1|2016-07-29|2017-06-29|Method for operating a hydrocarbon reservoir by injecting a gas in foam form|
    CA2974549A| CA2974549A1|2016-07-29|2017-07-24|Exploration process for a hydrocarbon deposit by injection of a gas in the form of foam|
    US15/663,959| US10669818B2|2016-07-29|2017-07-31|Method for operating a hydrocarbon deposit by injection of a gas in foam form|
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