EP2253797A1 - 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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EP2253797A1
EP2253797A1 EP10290174A EP10290174A EP2253797A1 EP 2253797 A1 EP2253797 A1 EP 2253797A1 EP 10290174 A EP10290174 A EP 10290174A EP 10290174 A EP10290174 A EP 10290174A EP 2253797 A1 EP2253797 A1 EP 2253797A1
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Prior art keywords
well
reservoir
simulator
mesh
flow
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French (fr)
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EP2253797B1 (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

Definitions

  • the present invention relates to the field of the exploitation of underground environments.
  • the invention notably makes it possible 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.
  • Numerical methods for modeling the flow of fluids within a well involve the construction of two distinct models: the reservoir model and the water model. ' near-wellbore model '.
  • domain decomposition techniques have been developed, described for example in GAIFFE, S. "Hybrid Hybrids and Domain Decomposition for the Modeling of Petroleum Reservoirs", Ph.D. Thesis, University Paris 6, 2000 And windowing techniques ( “windowing") as described for example in the following document: MLACNIK, MJ and HEINEMANN, ZE "Using well simulation of SPE 66371 at SPE Reservoir Simulation Symposium, Houston, TX, USA, February 2001 .
  • each successive time interval may have a length which is a function of a computation time step of the first flow simulator and a time step of the second flow simulator.
  • each successive time interval may have a length equal to one time step of the first flow simulator.
  • the boundary conditions can be deduced by linear interpolation of the results of the first simulator between the start and end times of the successive time intervals.
  • the numerical productivity indices they can be deduced by comparing flow rates calculated by the first simulator and flows calculated by the second simulator.
  • fluid flows within the medium are simulated by means of the first simulator on a first mesh discretizing the porous medium in a set of meshes, and fluid flows are simulated near the well by means of the second simulator on a second mesh discretizing the well and its surroundings in a set of meshes.
  • This second mesh is generated by constraining meshes located on the edge of the second mesh, so that their interfaces coincide with the mesh interfaces of the first mesh.
  • numerical productivity index multipliers are updated, instead of the numerical productivity indices themselves, for each phase, by comparing phase flows calculated by the first one. simulator and phase flow rates 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 may include an injection of a polymer solution through the well, and then the flows can be modeled to prevent water coming in.
  • the operating scenario may also include an injection of an acidic solution into the well, and the flows can then be modeled to evaluate the impact of acid stimulation.
  • the invention relates to a method for operating 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 as well.
  • the method involves a modeling of fluid flows in the system consisting of the porous medium (reservoir and surrounding wells) and the well. It is therefore, in particular, to model the injectivity or productivity of wells passing through a porous medium.
  • a scenario can be a hydrocarbon production scenario contained in the porous medium (reservoir), or an acid gas injection scenario, 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 rates and duration of injection and / or production, 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 process of recovery by water injection, which then remains to specify the optimal scenario of implementation for the tank in question.
  • the definition of an optimal scenario consists, 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 heterogeneities within the reservoir, for example permeability channels, fractures, etc., on the progression of fluids within the reservoir.
  • the flow simulator is then able to simulate expected hydrocarbon production, 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 reservoir mesh is shown on the figure 3 , this mesh is rude. Some meshes correspond to the part "porous medium”, others correspond to the part where the well is drilled. We speak for the latter mesh well of the reservoir mesh.
  • the "well edge mesh” consists of a set of meshes spatially discretizing the well and its surroundings.
  • An example of first well meshing 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 part "porous medium”, others correspond to the part "well”. For the latter, we speak of well meshes of the mesh around wells.
  • an object of the invention relates to a coupling method, which makes it possible to very simply couple a reservoir model, for reservoir simulation, and a well-first model, which is an autonomous model for simulating detailed phenomena around the well.
  • the reservoir model simulator it may be Puma Flow® software (IFP, France) for example.
  • the technique used here consists of coupling between the two flow simulators.
  • a coarse mesh is often used for the reservoir model, and a fine mesh is usually required 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 near wells in the well approach model.
  • the meshes at the edges (in gray) in the first well 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 tank model is mainly used to simulate flows in the tank as a whole.
  • the IP numerical productivity index takes into account: the geometric effect of the mesh of wells i of the mesh, the permeability of the porous medium in the mesh of the well and a coefficient of skin.
  • 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 the time T.
  • the optimal scenario is the scenario allowing to obtain an optimal production of the deposit as part of the production of a reservoir, or the scenario making it possible to obtain the optimal injectivity in the deposit in the framework of fluid injection into the reservoir.
  • reservoir 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, performed using the reservoir model in step 3c, provides dynamic properties of fluids such as pressure or saturations 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 flux at the edges of the wellhead model.
  • the edge meshes in the well approach 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 wellhead model is direct on these meshes.
  • the boundary conditions are zero flow. In order to maintain dynamic properties at the edges of the model, very valuable porosities (1,000,000, for example) are assigned to the dots. This type of boundary conditions is consistent with most flow models, and its implementation is easy.
  • M p , i is the multiplier of the productivity index for phase p in well mesh i .
  • the coupling method according to the invention can be used to model various detailed phenomena around the well, for example, damage by drilling or completion fluid, acid stimulation, non-Darcean flow around the well, gas-to-condensate problem, asphaltene deposition, damage by CO 2 injection, prevention of the arrival of water or gas, the arrival of sand, mineral deposits, the impact of completions, etc.
  • damage by drilling or completion fluid for example, damage by drilling or completion fluid, acid stimulation, non-Darcean flow around the well, gas-to-condensate problem, asphaltene deposition, damage by CO 2 injection, prevention of the arrival of water or gas, the arrival of sand, mineral deposits, the impact of completions, etc.
  • 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 that one seeks to reduce this production of water.
  • a standard tank model is used for field simulation.
  • a tank of size 1000m x 1000m x 10m 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 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 of this well by the drilling fluid is studied with the method according to the invention.
  • the reservoir is homogeneous with a permeability of 200 mD and a porosity of 0.15.
  • the boundary conditions of this reservoir are zero flows, except on the edge ⁇ x - ( figure 6 ), where the pressure is constant (200 bar).
  • 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 mesh well is 22 cm.
  • the other stitches 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 first well model corresponds to the refined zone and to the meshes around in the reference mesh.
  • the meshes at the edges of the well approach model coincide with mesh 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 outer cake formed by the drilling mud are 0.001 mD and 0.2 cm.
  • the thickness of the inner cake is 2 cm with a mean 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 at figure 9 . An irreducible water saturation of 30% bound to the filtrate (drilling fluid) that will invade the formation during the drilling phase will remain locked in the porous medium when the well will be returned to production.
  • the volumes of drilling fluid invasion are compared to the figure 10 for the simulation with the coupling method and the reference solution obtained using 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 gap 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.
  • Table 2-No time for updating the data in the coupling Period (day) No time (day) 0 - 0.01 0001 0.01 - 0.1 0.01 0.1 - 3 0.1 3 -10 1 10 - 200 10
  • a polymer solution is injected into a producing well for a short time in order to reduce the large amount of water produced at the same time as the oil. Part of the polymer is absorbed on the rock, and another part is dispersed in the 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. So, in the coupling method, the most appropriate 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 at figure 12 .
  • the ratio of permeabilities in the vertical and horizontal directions is 0.1.
  • the initial pressure of the tank is 200 bars.
  • 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 rate at total flow) of the producing well reaches 85%.
  • the water intake 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 bar for 2 days. Then, the well is returned to production. This water intake 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 the coupling is presented to 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 pairing 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 pairing starts at 950 days and ends at 1100 days, for a total of 150 days.
  • the time steps for the exchange of data in the coupling method are shown in Table 3.
  • the global digital IPs are updated at the beginning of the coupling (from 950 to 970 days) to take into account the effects of the meshes between the reservoir model and the first well model.
  • the global numerical IPs are again recalculated to integrate the effect induced by the injected polymer (one could also update the numerical IP multipliers for the water phase ). But when the well is returned to production (at 1003 days), the digital IP multipliers for the water phase are updated.
  • the figure 15 compares the polymer injection rates 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 first well model (with coupling).
  • the Figures 16A to 16E show the same comparisons layer by layer.
  • For direct simulation with the reservoir mesh without coupling the volume of injected polymer is largely overestimated.
  • the results are significantly improved.
  • the injection rate is large, but it is quickly corrected by the update of the IP due to the coupling. If one wants to have more precision on the injection rate of polymer, it is enough to refer to the results of simulation with the model first of well. With this model, the injected volume and the distribution of the polymer around the well are both correctly simulated.
  • the Figures 17, 18 and 19 present the oil, water and water-cut flow curves for the coupled tank model, the non-coupled tank model and the reference solution.
  • the results of the coupled reservoir model are generally satisfactory.
  • the figure 20 presents the water saturation map at the end of the coupling (1100 days), and the figure 21 shows the pressure map at 1100 days. Compared to the reference solutions, the coupling gives globally satisfactory results.

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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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FR2989200A1 (fr) * 2012-04-10 2013-10-11 IFP Energies Nouvelles Procede de selection des positions de puits a forer pour l'exploitation d'un gisement petrolier
EP2650471A1 (de) * 2012-04-10 2013-10-16 IFP Energies nouvelles Verfahren zur Auswahl der Position von Bohrbrunnen zur Förderung eines Erdöllagers
US9411915B2 (en) 2012-04-10 2016-08-09 Ipf Energies Nouvelles Method of selecting positions of wells to be drilled for petroleum reservoir development
CN104981585A (zh) * 2012-11-08 2015-10-14 斯多恩吉公司 确定开发贮藏和储藏可压缩流体的井生产率曲线的新方法
WO2014072627A1 (fr) * 2012-11-08 2014-05-15 Storengy Nouvelle methodologie de determination des courbes de productivite des puits d'exploitation de stockages et gisements de fluides compressibles
FR2997721A1 (fr) * 2012-11-08 2014-05-09 Storengy Radonip : nouvelle methodologie de determination des courbes de productivite des puits d'exploitation de stockages et gisements de fluides compressibles
CN104981585B (zh) * 2012-11-08 2018-09-21 斯多恩吉公司 确定开发贮藏和储藏可压缩流体的井生产率曲线的新方法
FR3002270A1 (fr) * 2013-02-21 2014-08-22 IFP Energies Nouvelles Procede d'exploitation d'un reservoir geologique au moyen d'un modele de reservoir cale et coherent vis a vis des proprietes d'ecoulement
EP2770162A1 (de) * 2013-02-21 2014-08-27 IFP Energies nouvelles Verfahren zur Ausbeutung eines geologischen Speichers mit Hilfe eines intelligenten und kohärenten Speichermodells in Bezug auf die Ablaufeigenschaften
WO2021118714A1 (en) * 2019-12-11 2021-06-17 Exxonmobil Upstream Research Company Semi-elimination methodology for simulating high flow features in a reservoir
CN114839130A (zh) * 2022-05-12 2022-08-02 西南石油大学 一种高温高压大尺度剖面模型束缚水实验条件的建立方法
CN117828732A (zh) * 2024-01-02 2024-04-05 中国恩菲工程技术有限公司 基于数字孪生的边坡稳定性确定方法及系统、介质、终端
CN117828732B (zh) * 2024-01-02 2024-05-31 中国恩菲工程技术有限公司 基于数字孪生的边坡稳定性确定方法及系统、介质、终端

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FR2945879A1 (fr) 2010-11-26
CA2704060C (fr) 2018-02-27
US8694297B2 (en) 2014-04-08
FR2945879B1 (fr) 2011-06-24
US20100299125A1 (en) 2010-11-25
CA2704060A1 (fr) 2010-11-20

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