High-water-cut-period injection-production allocation method in water-flooding development oil reservoir

Abstract

The invention relates to the technical field of oil-gas field development, and provides a high-water-cut-period injection-production allocation method in a water-injection development oil reservoir. Comprising the steps of establishing an oil reservoir geologic model and an oil reservoir dynamic model; carrying out fine fitting on the direct simulation model of the oil reservoir, and outputting small-layer data; effective oil wells are determined, and an injection-production well group is formed; the injection output and benefit conditions of each layer of well group are quantified; dividing the layer well group into six types of allocation feature units through water content comparison; quantitatively calculating layered injection allocation of the layer well group; scheme optimization is conducted from the five aspects of water injection well conditions, stratum energy, interval allocation amount, plane allocation scale and allocation oil increasing benefits; the method for determining the layered injection allocation quantity is scientific, reasonable, simple, practical, convenient and fast, and has good application and popularization value for offshore large-section sand prevention multi-layer commingling production and oil fields in medium and high water content stages.

Description

TECHNICAL FIELD

[0001] The present application relates to the technical field of oil and gas field development, and provides a method for injection-production matching in high water cut period of water injection development reservoir. BACKGROUND

[0002] In the process of oilfield development, water injection is an important measure to supplement the formation energy and achieve stable production of oilfield. For the oilfield with complex reservoir properties and large interlayer differences, general water injection cannot obtain high yield, but will exacerbate interlayer contradictions and seriously affect the yield of the oilfield. Therefore, separate layer water injection is a good means to alleviate interlayer contradictions, and the calculation of water injection volume of each layer is the key problem of separate layer water injection. The properties of water injection layers are analyzed, the layers are divided into several layers for water injection with different injection allocation, the water injection volume of each layer is reasonably calculated, and the actual production situation is dynamically analyzed to timely and reasonably adjust the injection allocation of the water injection layer, which is beneficial to further improve the water injection development of the oil reservoir and has important significance for improving the recovery of the oil reservoir.

[0003] This paper investigates the commonly used separate layer water injection injection allocation calculation methods at home and abroad, points out the applicability and limitations of each method, selects the comprehensive use of reservoir numerical simulation remaining oil method as the calculation method of this paper. And the separate layer injection allocation scheme is optimized and adjusted.

[0004] In the process of separate layer water injection development of oilfield, there are four methods commonly used for separate layer injection allocation of each layer: (1) formation thickness method: the essence of thickness method for separate layer injection allocation is the original reserve method. With the increase of water cut of oilfield, interlayer interference is intensified, the producing degree of each layer is uneven, and the distribution of remaining oil changes greatly, and the water drive effect gradually deteriorates. (2) Formation coefficient method: the essence of formation coefficient method is flow capacity method. This injection allocation method allocates large amount of water injection to high permeability and thick oil layers with strong flow capacity. The injected water quickly breaks through along the small layer with strong flow capacity, and the subsequent water injection is ineffective circulation, and the water drive effect gradually deteriorates. (3) Formation remaining reserve method: when the water cut is low, the producing degree is low, and the difference between the original reserve and the remaining reserve is small. Therefore, when the water cut is less than 50%, the effect of reserve method for separate layer injection allocation is slightly better than that of thickness method, but the difference is not large. (4) Reservoir numerical simulation method: for the oilfield in the initial stage of medium and high water cut development, the high permeability layer has not only individual layer water breakthrough, but also general water breakthrough, and the distribution rule of remaining oil has changed greatly. However, due to interlayer interference, the water absorption of medium and low permeability layer is very small, even no water absorption, so the remaining oil in most medium and low permeability layers is still in the state of continuous distribution. At this time, according to the distribution rule of remaining recoverable reserves of small layer, the water injection intensity of remaining oil rich reservoir is increased, which can improve the utilization rate of injected water and expand the water injection swept volume. Therefore, when the water cut is 50%-80%, the effect of remaining oil method for separate layer injection allocation is obviously better than that of thickness method.

[0005] The methods (1)-(3) are simple and convenient to calculate, and can be quickly completed by using current office software. SUMMARY

[0006] The present application aims at solving the defects of the prior art and provides a water injection development reservoir injection-production allocation method in a high water cut period.

[0007] The method can realize rapid and effective injection-production allocation, fully considers the reservoir development law, adjusts injection-production flow lines, balances injection-production, expands water injection swept volume, coordinates plane interlayer contradictions, controls the water cut rising speed of the oilfield, and maintains good development effect.

[0008] In order to achieve the above purpose, the present application adopts the following technical scheme:

[0009] A water injection development reservoir injection-production allocation method in a high water cut period comprises the following steps:

[0010] Step one, establishing a reservoir geological model and a reservoir dynamic model;

[0011] Step two, performing fine fitting of the reservoir direct simulation model, and outputting small layer data;

[0012] Step three, determining effective oil wells according to step one and step two, and forming injection-production well groups;

[0013] Step four, quantifying injection-production and benefit conditions of each layer well group;

[0014] Step five, dividing the layer well group into six types of allocation characteristic units through water cut comparison;

[0015] Step six, quantitatively calculating the layered injection allocation of the layer well group;

[0016] Step seven, performing scheme optimization from five aspects of injection well conditions, formation energy, layer allocation amount, plane allocation scale, and allocation oil increment benefit.

[0017] Further, the reservoir geological model comprises the following establishment steps:

[0018] a1: obtaining drilling, seismic, logging and geological data;

[0019] a2: establishing a structure model;

[0020] a3: establishing a reservoir skeleton model;

[0021] a4: performing a reservoir attribute model;

[0022] a5: establishing a reservoir geological model.

[0023] Furthermore, the reservoir geological model requires at least 3 grids between 2 production wells and at least 5 grids between a production well and an injection well.

[0024] Furthermore, the reservoir attribute model includes a porosity model and a permeability model. The porosity model is established by: firstly, based on the reservoir development characteristics and provenance direction of the work area, performing variogram analysis on each sand body to determine the principal direction, principal range, secondary range, and vertical range; then, under the control of the variogram, selecting an appropriate algorithm to simulate porosity for each sand body to obtain the porosity model. The permeability model is established by: determining the correlation between permeability and porosity through core analysis; using porosity as a co-constraint condition for permeability during permeability simulation; and applying the co-kriging method to simulate reservoir permeability under the control of the variogram to obtain the reservoir permeability model.

[0025] Furthermore, step five specifically includes: comparing the water cut at three levels: "block, sub-layer, and well layer"; identifying low-water-cut layers within high-water-cut wells; identifying weakly flooded areas within high-water-cut layers; and dividing the well group into six types of regulatory characteristic units.

[0026] Table 1

[0027]

[0028] Furthermore, step seven includes the following allocation scheme:

[0029] Table 2

[0030]

[0031] Furthermore, the establishment of the reservoir geological model also includes establishing a sand body model through the top surface structure and inversion thickness of the sand body inversion, wherein the well attribute parameters are the porosity, permeability and net-to-gross ratio attributes interpreted by a single well using a well logging interpretation model.

[0032] Furthermore, the original well data is discretized and assigned to a grid.

[0033] Furthermore, the well data includes porosity and permeability, wherein the porosity is discretized using the arithmetic mean method and the permeability is discretized using the RMS mean method.

[0034] Furthermore, the reservoir dynamic model is established using reservoir numerical simulation software Eclipse or RMsimple.

[0035] The beneficial effects of this invention are as follows:

[0036] The method for determining the stratified injection volume using the residual oil method in reservoir numerical simulation is scientific, reasonable, simple, practical, convenient, and quick. It has great application value for offshore oilfields with large-scale sand control and multi-layer combined production, as well as oilfields in the medium and high water-cut stages. The adaptability analysis results of the stratified injection method to the oilfield development stage provide guidance for the selection of stratified injection methods for similar new oilfields and the optimization and adjustment of stratified injection in old oilfields. Attached Figure Description

[0037] Figure 1 This is a schematic diagram of the 3D modeling process;

[0038] Figure 2 It is a three-level water content map;

[0039] Figure 3 This is a diagram showing the comparison of water content at three levels. Detailed Implementation

[0040] The technical solutions of the present invention will be clearly and completely described below with reference to the accompanying drawings in the embodiments of the present invention. Obviously, the described embodiments are only some embodiments of the present invention, and not all embodiments.

[0041] Example 1:

[0042] A water injection and production blending method for high-permeability reservoirs during the high water-cut stage in water injection development includes the following steps:

[0043] 1) Use reservoir modeling software such as Petrel or Direct to establish a reservoir geological model; based on the comprehensive use of drilling, seismic, logging and geological data, first establish a structural model, including a bedding plane model and a fault model, then establish a reservoir skeleton model, and then establish a reservoir property model (porosity, permeability) under the control of the skeleton model, and finally optimize the model and output it to numerical simulation.

[0044] Data preparation is fundamental to reservoir modeling, which utilizes Petrel software. According to the software requirements, 3D reservoir modeling necessitates the preparation of four types of data: fault files, structural bedding plane files, well attribute parameter files, and well trajectory files.

[0045] Structural modeling comprises two main parts: the establishment of fault models and sand body bedding models. Sand body bedding models control the spatial location of the simulated sand bodies, while fault models control the boundaries and configurations of fault blocks within the region. The structural model primarily relies on well logging data and seismic interpretation results. Through well-point sand body stratification data, inter-well stratigraphic correlation, and inversion of the sand body top surface structure, the morphology of sand bodies and fault development in this area can be effectively controlled.

[0046] 2) Use reservoir numerical simulation software such as Eclipse or RMsimple to establish a dynamic reservoir model. Reservoir numerical simulation is a process of comprehensively evaluating and analyzing the development history and future of a reservoir using mathematical equations and numerical solutions with the aid of computers. Reservoir geological modeling and numerical simulation are important research contents in reservoir description, an important means of finding remaining oil, and an important manifestation of digital reservoirs. Its research results can not only provide a basis for tapping the current remaining oil potential of the reservoir, but also provide a continuously improving foundation for the subsequent development and management of the reservoir. The reservoir model is based on petroleum geology and reservoir engineering research. Through the establishment of reservoir geological models and numerical simulation models, the process of reservoir production history is reproduced. That is, by fitting dynamic production indicators, contradictions between dynamic and static data are found. Dynamic data is used to correct static data. After repeated simulations and corrections of the two models, a four-dimensional reservoir model reflecting the reservoir development process is established. To date, reservoir numerical simulation is still the most scientific, economical, and convenient technical means to study the laws of reservoir development from a macroscopic perspective. It is applicable to reservoir development research of different reservoir types, different development methods, and different research objectives. Practice has proven that reservoir modeling studies have played a crucial guiding role throughout the entire development process of an oilfield.

[0047] 3) Based on the fine fitting of the reservoir numerical simulation model, output the oil saturation, reserve abundance, injection-production ratio, reservoir pressure distribution, and cumulative production and injection data for each sub-layer of the reservoir. Historical fitting is the process of reproducing the reservoir development history on a computer. It is a correct analysis of the reservoir geology and development history, making the reservoir description closer to the actual underground situation. By repeatedly adjusting parameters and correcting the static model, from the whole reservoir to the oil layer and then to the single well, parameters such as pressure and water cut are fitted. The fitting process is also a process of continuous understanding of the reservoir. Overall index fitting adjustment parameters: ① relative permeability; ② capillary pressure; ③ rock compressibility; ④ hydrocarbon properties; ⑤ formation water properties. Local index fitting adjustment parameters: ① water zone conductivity coefficient; ② water zone reservoir coefficient; ③ oil zone conductivity coefficient; ④ structure; ⑤ original oil-water interface.

[0048] Historical data fitting metrics mainly include fitting of reserves, pressure, cumulative oil production, and water cut under constant liquid conditions. To improve prediction accuracy, the fitting of metrics at the end of the period should meet the highest possible precision requirements.

[0049] 4) Based on new understandings of reservoir structure, reservoir, fluids, and reservoir dynamic analysis results, take the water injection well as the effective oil well as the injection well as the water injection well as the water injection well as the water injection well to determine the effective oil well and form an injection-production well group; the injection-production well group is further subdivided into single layers, the injection production is quantified, and the current injection-production ratio is determined.

[0050] 5) Quantify the distribution of remaining oil in a single layer, the utilization status of each layer, the injection status of well groups, and the production status of well groups. Due to differences in reservoir lithology and physical properties and the contradiction of uneven long-term exploitation, there are still certain differences in the degree of reservoir utilization between oil reservoir layers, and the distribution pattern of remaining oil between layers is also different.

[0051] 6) Analyze the dynamic change patterns and, combined with the characteristics of differential enrichment of remaining oil, deepen the understanding of the flow field. High water cut in the overall reservoir does not mean high water cut in every part of the reservoir; high water cut in a certain part of the reservoir does not mean high water cut in every well in that part; high water cut in a well does not mean high water cut in every layer produced by the well; high water cut in a certain oil layer does not mean high water cut in every rhythmic layer; and high water cut in a single direction on a plane does not mean high water cut in every direction. Refine the classification to clarify the allocation direction, conduct water cut comparisons at three levels: "block, small layer, and well layer," identify low water-cut layers in high water-cut wells, and identify weak water-flooded areas in high water-cut layers, dividing the well group into "six types" of characteristic units. For each of the "six types" of characteristic units, develop plans to adjust the injection-production ratio upwards or downwards.

[0052] 7) Calculate the effective injection allocation for well groups by combining the distribution of remaining oil and the production status of adjacent well groups. For old oilfields with large heterogeneity differences and fixed injection-production flow lines, optimize production and injection allocation to adjust the underground injection-production flow field and achieve injection-production balance. For injection-production well groups with one injection and one production well, the injection-production method can be optimized by adopting unstable water injection, injection-production coupling, etc., to widen the water jet and expand the water drive reach. For injection-production well groups with one injection and multiple production wells, multiple injections and one production wells, and multiple injections and multiple production wells, the adjustment of production and injection allocation should be combined with the adjustment of reservoir flow lines: based on the reservoir seepage mechanism, reduce the pressure difference in the direction of the strong flow line where water flooding is aggravated, increase the pressure difference in the direction of the weak flow line where the remaining oil is relatively rich, and stabilize the pressure difference in the direction of the balanced flow line. Through the interaction between oil wells and water wells, the pressure difference between injection and production wells can be reasonably adjusted to achieve the purpose of reversing the strong and weak flow lines, expanding the water drive reach, and improving the reservoir recovery rate.

[0053] 8) Optimize the injection scheme based on five aspects: well conditions, formation energy, inter-layer allocation volume, horizontal allocation scale, and oil production enhancement benefits, to achieve the best scheme and the greatest benefits. The overall principles are: grasp the reservoir development law and rationally allocate production and injection; maintain reasonable formation energy; coordinate horizontal and inter-layer contradictions and control the rate of water cut increase in the oilfield; adjust the injection and production flow lines, balance injection and production, and expand the water injection swept volume.

[0054] Example 2:

[0055] A method for injection and production blending in the high water-cut stage of water-injection oil reservoir development.

[0056] 1) Based on the comprehensive use of drilling, seismic, logging, and geological data:

[0057] First, establish a structural model, including a bedding plane model and a fault model; second, establish a reservoir skeleton model; then, under the control of the skeleton model, establish a reservoir property model (porosity, permeability); use reservoir modeling software such as Petrel or Direct to establish a reservoir geological model; the model principle requires at least 3 grids between 2 production wells and at least 5 grids between production wells and injection wells.

[0058] The planar grid division of Block A offshore in Shengli Oilfield: The work area is defined by three faults. The distance between every two production wells should be at least three grids, and the distance between production wells and water injection wells should be at least six grids. The planar grid design is 50m×50m.

[0059] Vertical grid division of Block A offshore area in Shengli Oilfield: Vertically, the sand bodies are subdivided into smaller grids, with each interlayer between sand bodies assigned a separate grid. The subdivision of the internal grids primarily considers the sand body thickness and its heterogeneous characteristics. The goal is to ensure that the sand body grid can represent interlayers up to 1 meter in diameter.

[0060] To accurately establish a three-dimensional geological model of the proposed area and eliminate boundary effects, the modeling area was expanded outward from the proposed area. The sand body model was established using the top surface structure and inversion thickness derived from sand body inversion. Well attribute parameters were obtained by interpreting porosity, permeability, and net-to-gross ratio from a single well using a well logging interpretation model.

[0061] The lithofacies types interpreted by well logging are sandstone and mudstone facies, with a sampling rate of 0.125m. To ensure accurate assignment of the raw well data to the grid, the well data should first be discretized. For lithofacies data, the most-of method should be selected for discretization.

[0062] Well data discretization: Since the original well data sampling rate is 0.125m, the well data should be discretized (scaled up) first in order to accurately assign the original well data to the grid.

[0063] For attribute data, Petrel software provides eight discretization methods: grid center value method, arithmetic mean method, geometric mean method, harmonic mean method, maximum value method, minimum value method, random value method, and RMS average method. After analysis and comparison, the arithmetic mean method was used for porosity, and the RMS average method was used for permeability to discretize the well data.

[0064] Porosity model establishment: First, based on the reservoir development characteristics and provenance direction of the study area, variogram analysis was performed on each sand body to determine the principal direction, principal range, secondary range, and vertical range. Then, under the control of the variogram, an appropriate algorithm was selected for porosity simulation of each sand body. Due to the dense well network in the study area, the Kriging interpolation method was used to simulate the porosity of each sublayer, thus obtaining the porosity model.

[0065] Permeability model establishment: Through core analysis, permeability and porosity showed a good correlation. In permeability simulation, porosity was used as a co-constraint condition for permeability. Under the control of the variogram function, the co-kriging method was applied to simulate reservoir permeability, and the reservoir permeability model was obtained.

[0066] 2) Use reservoir numerical simulation software such as Eclipse or RMsimple to build a dynamic reservoir model and perform history fitting. History fitting is the process of reproducing the reservoir development history on a computer. It is a correct analysis of the reservoir geology and development history, making the reservoir description closer to the actual underground situation. By repeatedly adjusting parameters and correcting the static model, from the whole reservoir to the oil layer and then to a single well, parameters such as pressure and water cut are fitted. The fitting process is also a process of continuous understanding of the reservoir.

[0067] 3) Based on the fine fitting of the reservoir numerical simulation model, output the oil saturation, reserve abundance, injection-production ratio, reservoir pressure distribution, and cumulative production and injection data for each sub-layer of the reservoir. Perform big data mining on the data files of the Eclipse or RMsimple model to extract and calculate the layered production and water absorption data, which can quickly and quantitatively analyze the effectiveness of production wells and evaluate the water injection efficiency of the well group.

[0068] Simulations show that the average oil saturation in Block A of Shengli Oilfield is 0.57 in the upper strata, 0.50 in the lower strata, and 0.51 across the entire area. Within the lower strata, areas with an average oil saturation between 0.4 and 0.45 account for 2.4%, areas between 0.45 and 0.55 account for 6.7%, areas between 0.55 and 0.6 account for 8.6%, and areas with a saturation greater than 0.6 account for 54.4%. Remaining oil is generally enriched, with the areas between production wells being the main enrichment zones.

[0069] The reservoir is relatively homogeneous between layers, and the differences in the distribution of remaining oil layers are mainly influenced by the completeness of the well network and the original material basis. The main oil-producing layer is the primary location for remaining oil enrichment. The remaining reserves of each sub-layer account for an average of 75.3% of the original reserves.

[0070] 4) Based on new understandings of reservoir structure, reservoirs, fluids, and reservoir dynamic analysis results, injection and production well groups are formed with water injection wells as the center and effective oil wells as the core.

[0071] 5) Subdivide injection-production well groups into individual layers, quantify injection output, and determine the current injection-production ratio. Evaluate the water flooding dynamics and development indicators of the entire area, layers, well groups, and individual wells, and use this as a basis to determine target areas and well groups.

[0072] 6) Quantify the distribution of remaining oil in a single layer, the utilization status of each layer, the injection status of each well group, and the production status of each well group to accurately describe the injection output and benefits of each well group.

[0073] 7) Refine the classification and clarify the allocation direction. Conduct water cut comparisons at three levels: "block, small layer, and well layer". Find low water-bearing layers in high water-bearing wells and weak water-flooded areas in high water-bearing layers. Divide the well groups into six types of allocation characteristic units.

[0074] 8) Based on the distribution of remaining oil and the production status of adjacent well groups, quantitatively calculate the layered injection allocation of the well group.

[0075] 9) Optimize the scheme from five aspects: well conditions, formation energy, layer allocation amount, scale of horizontal allocation, and oil enhancement benefits of allocation, so as to achieve the best scheme and the best benefits.

[0076] Table 1 Six Types of Allocation Characteristic Units

[0077]

[0078] Table 2 Optimization Directions for Allocation Scheme

[0079]

[0080] The above description is only a preferred embodiment of the present invention, but the scope of protection of the present invention is not limited thereto. Any equivalent substitutions or modifications made by those skilled in the art within the scope of the technology disclosed in the present invention, based on the technical solution and inventive concept of the present invention, should be covered within the scope of protection of the present invention.

Claims

1. A method for injection-production blending during the high water-cut stage of water-injection development reservoirs, characterized in that, The process includes the following steps: Step 1, establishing a reservoir geological model and a reservoir dynamic model; Step 2, performing fine fitting of the reservoir numerical simulation model and outputting sub-layer data; Step 3, based on Step 1 and Step 2, identifying the effective oil wells and forming injection-production well groups; Step 4, quantifying the injection production and benefits of each well group; Step 5, dividing the well group into six types of allocation characteristic units through water cut comparison; Step 6, quantitatively calculating the layered injection allocation of the well group; Step 7, optimizing the scheme from five aspects: injection well conditions, formation energy, layer allocation amount, planar allocation scale, and allocation-increased oil production benefits.

2. The injection-production method for water-injection development reservoirs during the high water-cut stage according to claim 1, characterized in that, The reservoir geological model includes the following steps: acquiring drilling, seismic, logging, and geological data; establishing a structural model; establishing a reservoir skeleton model; performing reservoir attribute modeling; and establishing the reservoir geological model.

3. The injection-production method for water-injection development of oil reservoirs during the high water-cut stage, as described in claim 2, is characterized in that... The reservoir geological model requires at least 3 grids between 2 production wells and at least 5 grids between production wells and injection wells.

4. The injection-production blending method for water-injected oil reservoirs during the high water-cut stage according to claim 3, characterized in that, The reservoir property model includes a porosity model and a permeability model. The porosity model is established by: firstly, based on the reservoir development characteristics and provenance direction of the work area, performing variogram analysis on each sand body to determine the principal direction, principal range, secondary range, and vertical range; then, under the control of the variogram, selecting an appropriate algorithm to simulate porosity for each sand body to obtain the porosity model. The permeability model is established by: determining the correlation between permeability and porosity through core analysis; using porosity as a co-constraint condition for permeability during permeability simulation; and applying the co-kriging method to simulate reservoir permeability under the control of the variogram to obtain the reservoir permeability model.

5. The injection-production method for water-injection development of reservoirs during the high water-cut stage, as described in claim 1, is characterized in that... Step five specifically includes: comparing the water content at three levels: block, sub-layer, and well layer; and dividing the well group into adjustment characteristic units according to the rule of finding low water-bearing layers in high water-bearing wells and weak water-flooded areas in high water-bearing layers.

6. The injection-production method for water-injection development of oil reservoirs during the high water-cut stage, as described in claim 5, is characterized in that... Step seven includes the following allocation optimization rules: Rule 1: Subdivided into appropriate levels, ensuring no gaps or omissions, with priority given to adjustment, and optimization direction being optimal well conditions; Rule 2: Pressure coefficient > 0.95, injection-production ratio lowered; pressure coefficient < 0.80, injection-production ratio higher, with optimization direction being energy balance; Rule 3: Layers with allocation amounts exceeding 30 are prioritized for adjustment and sorting, with optimization direction being sequential screening; Rule 4: Emphasizing economies of scale, well areas with concentrated allocation are prioritized for adjustment, with optimization direction being scale concentration; Rule 5: Predicting allocation effects, prioritizing adjustments for high oil production increases, with optimization direction being benefit matching.

7. A method for injection-production blending in high water-cut reservoirs according to any one of claims 1 to 6, characterized in that, The establishment of the reservoir geological model also includes establishing a sand body model by inverting the top surface structure and inversion thickness of the sand body. The well attribute parameters are the porosity, permeability and net-to-gross ratio attributes of a single well interpreted using the well logging interpretation mode.

8. The injection-production method for water-injection development of oil reservoirs during the high water-cut stage, as described in claim 7, is characterized in that... The original well data is discretized and assigned to a grid.

9. A method for injection-production blending in the high water-cut stage of a water-injection oil reservoir according to claim 8, characterized in that, The well data includes porosity and permeability. The porosity is discretized using the arithmetic mean method, and the permeability is discretized using the RMS mean method.

10. A method for injection-production blending in the high water-cut stage of a water-injection development reservoir according to claim 8 or 9, characterized in that, The reservoir dynamic model was built using reservoir numerical simulation software Eclipse or RMsimple.

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