EP2253797B1 - Verfahren zur Förderung in einem porösen Medium mittels einer Modellierung der Flüssigkeitsströme - Google Patents

Verfahren zur Förderung in einem porösen Medium mittels einer Modellierung der Flüssigkeitsströme Download PDF

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EP2253797B1
EP2253797B1 EP10290174.1A EP10290174A EP2253797B1 EP 2253797 B1 EP2253797 B1 EP 2253797B1 EP 10290174 A EP10290174 A EP 10290174A EP 2253797 B1 EP2253797 B1 EP 2253797B1
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well
mesh
reservoir
simulator
fluids
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EP2253797A1 (de
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Didier Yu Ding
Gérard Renard
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IFP Energies Nouvelles IFPEN
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IFP Energies Nouvelles IFPEN
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    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/12—Methods or apparatus for controlling the flow of the obtained fluid to or in wells

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  • the present invention relates to the field of the exploitation of underground environments.
  • the invention makes it possible in particular to improve the injectivity and the productivity of wells drilled through a porous medium, such as a hydrocarbon deposit or a geological CO 2 storage tank.
  • the numerical methods which make it possible to model the flow of fluids within a well involve the construction of two distinct models: the model of reservoir (“ reservoir model ”) and the model d ' near-wellbore model'.
  • domain decomposition techniques have been developed, described for example in GAIFFE, S. "Hybrid Meshes and Domain Decomposition for the Modeling of Petroleum Reservoirs", Doctoral Thesis, University of Paris 6, 2000 And windowing techniques ( “windowing") as described for example in the following document: MLACNIK, MJ and HEINEMANN, ZE "Using well windows in full field reservoir simulation ", paper SPE 66371 presented at the SPE Reservoir Simulation Symposium, Houston, TX, USA, February 2001 .
  • each successive time interval can have a length which is a function of a time step of calculation of the first flow simulator and of a time step of the second flow simulator.
  • each successive time interval can have a length equal to a time step of the first flow simulator.
  • the fluid flows within the medium are simulated by means of the first simulator on a first mesh discretizing the porous medium into a set of meshes
  • the fluid flows around the well are simulated by means of the second simulator on a second mesh discretizing the well and its surroundings into a set of meshes.
  • This second mesh is generated by constraining meshes situated on the edge of the second mesh, so that their interfaces coincide with the interfaces of the meshes of the first mesh.
  • digital productivity index multipliers are updated, instead of the digital productivity indices themselves, for each phase, by comparing flow rates per phase calculated by the first simulator and flow rates per phase calculated by the second simulator.
  • damage to the well can be taken into account by a drilling fluid by modeling an invasion of the porous reservoir by the drilling fluid in steps d and e.
  • the operating scenario can include an injection of a polymer solution through the well, and we can then model the flows to prevent water coming in.
  • the operating scenario can also include an injection of an acid solution into the well, and we can then model the flows to assess the impact of acid stimulation.
  • the invention relates to a method for exploiting an underground porous medium, by injecting a fluid into the medium via at least one well, and / or by producing a fluid present in the medium by means of at least one well.
  • the method includes a modeling of the flows of fluids in the system constituted by the porous medium (reservoir and surroundings of the wells) and the well. It is therefore, in particular, to model the injectivity or the productivity of wells passing through a porous medium.
  • a scenario can be a scenario of production of hydrocarbons contained in the porous medium (reservoir), or a scenario of injection of acid gas, such as CO2, in an underground reservoir for the storage of acid gas .
  • a scenario is characterized by the position of the wells, the recovery or injection method, the injection and / or production flow rates and duration, the operating conditions in these wells such as the flow rate or the bottom pressure.
  • the reservoir engineer chooses a production process, for example the recovery process by water injection, of which it then remains to specify the optimal implementation scenario for the reservoir considered.
  • the definition of an optimal scenario consists, for example, in fixing the number and the location (position and spacing) of the injector and producer wells in order to best take into account the impact of heterogeneities within the reservoir, for example permeability channels, fractures, etc., on the progression of fluids within the reservoir.
  • the flow simulator we are then able to simulate the expected production of hydrocarbons, using the tool well known to specialists: the flow simulator.
  • the “reservoir mesh” consists of a set of meshes spatially discretizing the reservoir (porous medium + well).
  • An example of a tank mesh is illustrated on the figure 3 , this mesh is coarse. Some meshes correspond to the “porous medium” part, others correspond to the part where the well is drilled. One speaks for these last of meshs of well of the mesh of reservoir.
  • the “well access grid” consists of a set of meshes spatially discretizing the well and its surroundings.
  • An example of first well mesh is illustrated on the figure 4 , this mesh is fine to simulate the detailed phenomena around the well. Its surroundings therefore belong to the porous medium in which the well is drilled. Some meshes correspond to the “porous medium” part, others correspond to the “well” part.
  • an object of the invention relates to a coupling method, which makes it possible to couple in a very simple way a reservoir model, for the simulation of the reservoir, and a well model first, which is an autonomous model for simulating the phenomena detailed around the well.
  • tank model simulator it can be the Puma Flow ® software (IFP, France) for example.
  • the technique used here consists in coupling between the two flow simulators.
  • a coarse mesh is often used for the reservoir model, and a fine mesh is usually necessary to simulate the detailed phenomena around the well.
  • the figure 5 shows the two meshes used in the coupling.
  • the figure on the left represents the reservoir mesh for the field simulation, and the figure on the right represents the mesh in the vicinity of wells in the approach well model.
  • the meshes at the edges (in gray) in the well approach model coincide with the meshes of the same color in the reservoir mesh.
  • the cross indicates the location of the well.
  • the time steps used in the first well model are generally much smaller than those of the reservoir model.
  • the reservoir model is mainly used to simulate flows in the entire reservoir.
  • the digital productivity index IP takes into account: the geometric effect of the well mesh i of the mesh, the permeability of the porous medium in the well mesh and a skin coefficient.
  • a skin coefficient is a coefficient, well known to those skilled in the art, used to represent the damage of a well in a mesh.
  • the variables IP i , P nw, p, j , P r, p, i and P wf, j are a function of time T.
  • the optimal scenario can be selected.
  • the optimal scenario is the scenario allowing to obtain an optimal production of the deposit within the framework of the production of a reservoir, or the scenario allowing to obtain the optimal injectivity in the deposit within the framework of injection of fluid in the tank (injection of water for improved production, or injection of acid gases).
  • the scenario selected in step 1 is modified ( ⁇ SCE ), for example by modifying the location of a well.
  • step 2 during which the meshes are constructed, is modified.
  • the simulation carried out using the reservoir model in step 3c, provides dynamic properties of fluids such as pressure or saturation in the period from T 0 to T 1 on all coarse meshes.
  • the determination of the boundary conditions in step 3b requires the interpolation of the pressure or the flow on the edges of the well approach model.
  • the edge meshes in the approach well model are also constrained so that they coincide with meshes of the reservoir model ( figure 3 ). In this way, the transfer of dynamic data from the reservoir model to the approach well model is direct on these meshes.
  • the boundary conditions are of zero flux. In order to maintain the dynamic properties at the edges of the model, very high porosities
  • M p, i is the multiplier of the productivity index for phase p in the mesh of wells i .
  • the coupling method according to the invention can be used to model various detailed phenomena around the well, such as, damage by drilling or completion fluid, acid stimulation, non-Darcean flow around the well, the problem of condensate gas, asphaltene deposition, damage by injection of CO 2 , prevention of water or gas, sand, mineral deposits, the impact of completions, etc.
  • damage by drilling or completion fluid acid stimulation, non-Darcean flow around the well
  • the problem of condensate gas asphaltene deposition
  • damage by injection of CO 2 prevention of water or gas, sand, mineral deposits
  • the impact of completions etc.
  • we present in particular an example of application for the damage of the oil formation by the drilling fluid during the drilling of the well and an example of application for the prevention of water coming when a well in production produces a significant amount of water, and we are trying to reduce this production of water.
  • a standard reservoir model is used for the field simulation.
  • a 1000m x 1000m x 10m tank is considered.
  • a Cartesian mesh with 20 meshes in the x direction, 20 meshes in the y direction and 1 mesh in the z direction is used for the simulation of the field ( figure 6 ).
  • the mesh sizes are therefore 50m x 50m x 10m.
  • the initial tank pressure is 200 bar.
  • a producing well must be drilled in the block (15, 15, 1). It is represented by a black circle on the figure 6 . The damage to this well by the drilling fluid is studied with the method according to the invention.
  • the tank is homogeneous with permeability 200 mD and porosity 0.15.
  • the boundary conditions of this reservoir are zero flows, except on the edge ⁇ x- ( figure 6 ), where the pressure is constant (200 bars).
  • the mesh is refined around the well ( figure 7 ).
  • a specific model which takes into account the advanced physics of the damage, is used on this mesh to simulate the reference solution. Since damage by drilling fluid is generally limited to a few centimeters or a few tens of centimeters around wells, we need very small meshes in the refined zone (Table 1).
  • the diameter of the well is 21.6 cm.
  • the size of the well mesh is 22 cm.
  • the other meshes around the well are much smaller with a size of 2 cm.
  • the meshes used for the coupling are illustrated on the Figures 8A and 8B .
  • the mesh of the well approach model ( figure 8B ) corresponds to the refined zone and to the meshes around in the reference mesh.
  • the meshes at the edges of the approaching well model coincide with meshes of the reservoir model.
  • the contact time between the drilling fluid and the reservoir is 2 days.
  • the pressure during drilling at the bottom of the well is 250 bars.
  • the permeability and the thickness of the external “cake” formed by the drilling mud are equal to 0.001 mD and 0.2 cm.
  • the thickness of the internal cake is 2 cm with an average permeability reduced to 20 mD during the drilling period and 40 mD in the production period.
  • the viscosity of the drilling fluid is 30 cPo.
  • the hysteresis of the relative permeability between the drilling and production periods is presented in the figure 9 . An irreducible water saturation of 30% linked to the filtrate (drilling fluid) which will invade the formation during the drilling phase will remain blocked in the porous medium when the well is returned to production.
  • the drilling fluid invasion volumes are compared to the figure 10 for the simulation with the coupling method and the reference solution obtained using the mesh with local refinement ( figure 7 ).
  • the time steps for updating the data in the coupling are presented in Table 2.
  • the figure 10 shows that the volume of fluid invasion is correctly simulated with the coupling method.
  • the small difference between the coupling solution and the reference solution in the period between 0.1 and 0.3 days can be improved by using small iteration steps in time to exchange the data in the coupling.
  • the well After the 2 days of drilling, the well is closed for 1 day for the establishment of its completion, then it is put into production. The coupling is effected until 10 th day. Beyond 10 days, the effect of damage around wells becomes stable and the digital IPs in the reservoir model hardly change any more. We no longer need coupling to continue simulating the field with the reservoir model.
  • the oil production curve simulated by the reservoir model, which is coupled with the first well model for the first 10 days, is presented in the figure 11 . This curve is very close to the reference solution.
  • a polymer solution is injected into a producing well for a short time in order to reduce the large amount of water produced together with the oil. Part of the polymer is absorbed on the rock, and another part is dispersed in water.
  • the injected polymer has the effect of reducing the mobility of the water phase by increasing its viscosity and by reducing the relative permeability of this phase. Therefore, in the coupling method, the most suitable approach is to update the digital IP multiplier for the water phase.
  • a 1000m x 1000m x 25m tank is considered as an example.
  • a Cartesian mesh with 20 meshes in the x direction, 20 meshes in the y direction and 5 meshes in the z direction is used for the simulation of the field.
  • the mesh size is 50m x 50m x 5m.
  • the reservoir is heterogeneous. Permeability is presented to the figure 12 .
  • the ratio of permeabilities in the vertical and horizontal directions is 0.1.
  • the initial tank pressure is 200 bar.
  • the pressure at the injector well is imposed at 300 bars, and the pressure at the producing well is constrained to 150 bars during production.
  • the water-cut (water flow compared to the total flow) of the producing well reaches 85%.
  • the water ingress prevention procedure is then applied to reduce the amount of water produced.
  • a polymer solution with a concentration of 2500 ppm is injected into the producer with a bottom pressure of 300 bars for 2 days. Then, the well is put back into production. This water prevention procedure is simulated with the method according to the invention.
  • a local refinement around the producing well is used ( figure 13 ).
  • the mesh size around the well is 0.617 m in the x direction.
  • the mesh for coupling is presented in the figure 14 .
  • Meshes at the edges of the first well model coincide with meshes in the reservoir model.
  • the physics of the polymer can be considered in both models (first well model and reservoir model).
  • Table 3 No time during coupling Period (day) No time (day) 0 - 950 - 950-970 2 970 - 1000 28 1000 - 1000.1 0.01 1000.1 - 1005 0.1 1005 - 1030 1 1030 - 1100 2 1100 - 3000 -
  • the coupling begins at 950 days and ends at 1100 days, a period of 150 days in total.
  • the time steps for exchanging data in the coupling method are presented in Table 3.
  • the global digital IPs are updated at the start of the coupling (from 950 to 970 days) to take into account the effects of the meshes between the reservoir model and the approaching well model.
  • the global digital IPs are further recalculated to integrate the effect induced by the injected polymer (we could also update the digital IP multipliers for the water phase ).
  • the digital IP multipliers for the water phase are updated.
  • the figure 15 compare the injection rates of polymer in the well for the different simulations: the reference solution, the simulation on the reservoir mesh with coupling, the direct simulation on the reservoir mesh without coupling and the simulation with the well approach model (with coupling).
  • the Figures 16A to 16E show the same layer-by-layer comparisons.
  • the volume of polymer injected is greatly overestimated.
  • the results are significantly improved.
  • the injection rate is high, but it is quickly corrected by the update of the IP due to the coupling. If we want to have more precision on the polymer injection rate, it is enough to refer to the simulation results with the first model of well. With this model, the volume injected and the distribution of the polymer around the well are both correctly simulated.
  • the figures 17, 18 and 19 show the oil, water and water-cut flow curves for the tank model with coupling, the tank model without coupling and the reference solution.
  • the results of the coupled reservoir model are generally satisfactory.
  • the figure 20 presents the water saturation card at the end of the coupling (1100 days), and the figure 21 shows the pressure card at 1100 days. Compared to the reference solutions, the coupling gives globally satisfactory results.

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Claims (9)

  1. Verfahren, das von einem Computer eingesetzt wird, um Fluidabflüsse innerhalb eines unterirdischen porösen Mediums, das von mindestens einem Bohrloch durchquert wird, im Hinblick auf die Ausbeutung des Mediums zu modellieren, das durchgeführt wird, wobei eines der Fluide in das Medium über mindestens eines der Bohrlöcher injiziert wird, und/oder wobei eines der in dem Medium vorhandenen Fluide mit Hilfe mindestens eines der Bohrlöcher produziert wird, wobei ein erster Flusssimulator verwendet wird, der es ermöglicht, den Abfluss der Fluide innerhalb des porösen Mediums auf Basis von digitalen Produktivitätsindizes, die Fluiddruckwerte mit Fluidmengen verbinden, zu simulieren, und wobei ein zweiter Flusssimulator verwendet wird, um den Abfluss der Fluide in der Umgebung des Bohrlochs auf Basis von Grenzbedingungen zu simulieren, dadurch gekennzeichnet, dass:
    a- die Fluidabflüsse innerhalb des Mediums mit Hilfe des ersten Simulators über ein definiertes Zeitintervall zwischen Zeiten T0 und T1 simuliert werden, und aktualisierte Grenzbedingungen für den zweiten Simulator durch eine lineare Interpolation der Resultate des ersten Simulators zwischen den Zeiten T0 und T1 abgeleitet werden;
    b- die Fluidabflüsse in der Umgebung der Bohrlöcher mit Hilfe des zweiten Simulators über dasselbe Zeitintervall simuliert werden, wobei die aktualisierten Grenzbedingungen verwendet werden, und davon aktualisierte digitale Produktivitätsindizes für den ersten Simulator abgeleitet werden, wobei vom ersten Simulator berechnete Mengen und vom zweiten Simulator berechnete Mengen verglichen werden; und
    c- die Fluidabflüsse innerhalb des porösen Mediums während einer Zeitdauer zwischen T0 und Tn, wobei Tn>T1, modelliert werden, wobei die Schritte a und b für aufeinanderfolgende Zeitintervalle zwischen T0 und Tn reiteriert werden.
  2. Verfahren nach Anspruch 1, bei dem jedes aufeinanderfolgende Zeitintervall eine Länge hat, die von einem Berechnungszeitschritt des ersten Flusssimulators und einem Zeitschritt des zweiten Flusssimulators abhängt.
  3. Verfahren nach Anspruch 1, bei dem jedes aufeinanderfolgende Zeitintervall eine Länge gleich einem Zeitschritt des ersten Flusssimulators hat.
  4. Verfahren nach einem der vorhergehenden Ansprüche, bei dem die Fluidabflüsse innerhalb des Mediums mit Hilfe des ersten Simulators auf einem ersten Netzwerk simuliert werden, das das poröse Medium in eine Gesamtheit von Maschen unterteilt, und die Fluidabflüsse in der Umgebung des Bohrlochs mit Hilfe des zweiten Simulators auf einem zweiten Netzwerk, das das Bohrloch und seine Umgebung in eine Gesamtheit von Maschen unterteilt, simuliert werden, wobei das zweite Netzwerk erzeugt wird, wobei Maschen, die sich am Rand des zweiten Netzwerks befinden, so gedrückt werden, dass ihre Schnittstellen mit den Schnittstellen der Maschen des ersten Netzwerks zusammenfallen.
  5. Verfahren nach einem der vorhergehenden Ansprüche, bei dem Mehrphasenabflüsse modelliert werden, und Multiplikatoren von digitalen Produktivitätsindizes anstatt der digitalen Produktivitätsindizes selbst für jede Phase aktualisiert werden, wobei von dem ersten Simulator berechnete Mengen pro Phase und von dem zweiten Simulator berechnete Mengen pro Phase verglichen werden.
  6. Verfahren nach einem der Ansprüche 1 bis 5, um ein unterirdisches poröses Reservoir mit Hilfe mindestens eines das Reservoir durchquerenden Bohrlochs auszubeuten, wobei mindestens ein Fluid zwischen dem Reservoir und dem Bohrloch zirkuliert, wobei Daten zur Geometrie des porösen Reservoirs erfasst werden, aus denen eine Aufteilung des Reservoirs in eine Gesamtheit von Maschen, Reservoir-Netzwerk genannt, konstruiert wird, und eine Aufteilung des Bohrlochs und seiner Umgebung in eine Gesamtheit von Maschen, Bohrlochumgebung-Netzwerk genannt, konstruiert wird, dadurch gekennzeichnet, dass die folgenden Schritte durchgeführt werden:
    a- Auswahl eines Ausbeutungsszenarios des porösen Reservoirs;
    b- zu dem Reservoir-Netzwerk Zuordnung eines ersten Flusssimulators, der es ermöglicht, den Abfluss der fluide innerhalb des Reservoirs aus mindestens den folgenden Daten zu simulieren: Produktionsszenario, Eingangsdaten im Zusammenhang mit dem Fluid und dem Reservoir, digitale Produktivitätsindizes, die es ermöglichen, Druckwerte mit Mengen zu verbinden, Grenzbedingungen;
    c- zu dem Bohrlochumgebung-Netzwerk Zuordnung eines zweiten Flusssimulators, um den Abfluss der Fluide in der Umgebung des Bohrlochs aus mindestens den folgenden Daten zu simulieren: Eingangsdaten im Zusammenhang mit dem Fluid und dem Reservoir, Grenzbedingungen;
    d- Modellieren der Fluidabflüsse innerhalb des Reservoirs und in der Umgebung des Bohrlochs mit Hilfe des Verfahrens nach einem der Ansprüche 1 bis 5; und
    e- Verändern des Ausbeutungsszenarios und Wiederholen des Schritts d bis zum Erhalt eines optimalen Ausbeutungsszenarios.
  7. Verfahren nach Anspruch 6, bei dem eine Beschädigung des Bohrlochs durch ein Bohrfluid berücksichtigt wird, wobei eine Invasion des porösen Reservoirs durch das Bohrfluid in den Schritten d und e modelliert wird.
  8. Verfahren nach Anspruch 6, bei dem das Ausbeutungsszenario eine Injektion einer Polymerlösung durch das Bohrloch umfasst, und die Abflüsse modelliert werden, um einem Wassereintritt vorzubeugen.
  9. Verfahren nach Anspruch 6, bei dem das Ausbeutungsszenario eine Injektion einer sauren Lösung in das Bohrloch umfasst, und die Abflüsse modelliert werden, um die Auswirkung einer sauren Stimulation zu bewerten.
EP10290174.1A 2009-05-20 2010-04-01 Verfahren zur Förderung in einem porösen Medium mittels einer Modellierung der Flüssigkeitsströme Active EP2253797B1 (de)

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FR0902533A FR2945879B1 (fr) 2009-05-20 2009-05-20 Methode d'exploitation de milieu poreux au moyen d'une modelisation d'ecoulements de fluide

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CA2704060A1 (fr) 2010-11-20
FR2945879A1 (fr) 2010-11-26
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