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I am doing a project in the university and I have been asked to do dry hole analysis for some wells in which all data given are seismic and logging data
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I would like to make presentation for my students to understand the dry hole analysis in petroleum Geology.
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I am asking if we could use the decline curve analysis (DCA) technique, especially the Arps method to calculate the remaining reserves in the mature phase of production (in case of the presence of multiphase) from petroleum reservoirs or we couldn't rely on it?
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The costs involved in building, calibrating and using other types of forecast models (3D reservoir dynamic simulation models, data driven machine learning models) are such that a large volume of reserves (most of the mature fields and a large fraction of remaining reserves) are derived from DCA. One can however surmise that streamlining of machine learning usage will enable such approaches to overcome simpler form of data driven approaches like DCA. In my opinion, these approaches will not overcome 3D reservoir models for green (or immature) fields any time soon.
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Hi guys! I am trying to design a simple two-phase reservoir model (gas-water) using eclipse, and I keep getting the same error message every time, like the picture I attached. Does anyone know what this problem is related? Any suggestions would be appreciated!
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Jungin Lee
Hi Jungin! This is the saturation profile I have applied.
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Reservoir modeling
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if you have any problem understanding Well placement optimization let me know@rami
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I'm trying to build a 3D velocity model (on a previously constructed 3D structural framework) in Petrel Software using only checkshots. Can anyone help me, please?
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You may try to remove the well tops and use constant numbers for the top and bottom of the velocity model.
Hope it works.
Regards,
Ahmed
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I would like to use Brugge field dataset for well placement optimization. it is developed by TNO
and I can not find the data in the website.
However, One paper has given the data file as a supplementary in this paper
( ). So my question is can I use this paper's data for my study with acknowledgment.
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Kartikay Sonrexa Can you please help with the link to access the Norne field data, as you mentioned? Thanks in advance.
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I have a watershed that has a reservoir (see the picture attached) . I want to model the reservoir as part of my set up. The reservoir takes in water from a stream. Water is withdrawn from the reservoir to feed a power plant.
How can I model the water intake into the reservoir from the stream?
How can I model the water withdrawal of water from the reservoir to the power plant?
Which reservoir modelling method in SWAT should I use?
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You can.
ND Liem
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I am working on optimizing well placement in the condensate reservoir model using an algorithm. Any kind of code example will be appreciated.
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The artificial learning hits its performance limits in case of using seismic with low signal to noise ratio to drive the petroleum reservoir modelling. The neural networks tends to learn either from the useful signal part as well as from the noise. What is the best practical way to avoid this problem which can result in a dramatic noise magnification?
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Dear Kiche Yacine.
Attenuating random noise and enhancing seismic signals, has been considered as a seirious and long-standing problem, especially for the pre-stack domain.
The best way is try to attenuate or minimize the effect of random noise before your present-day stage of reservoir modeling. That is: you should keep in mind that such cancellation or attenuation of random noise should be planned from the stages of seismic design, acquisition and processing.
But, even if a low SNR ratio already existed in your interpretation and reservoir modeling project, there are techniques that could be used, regardless of using or not using neural networks.
If you work in the poststack domain, 2D or 3D stacking seismic, there are filtering procedures for most seismic interpretation programs, for example: Ormsby bandpass, Butterworth bandpass, trace mix, fx deconvolution, coherency filter, dip-scan, fk weighting, fk fan filter.
Also, if you work in the prestack domain (gathers), you may use: bandpass, mute, super gather, parabolic random transform.
The skill to remove or cancelate the noise in both above scenarios, is a function of your length of the filtering window applied.
But remember that SNR (signal-to-noise-ratio) is a subjective judgment. Furthermost random noise attenuation needs a control of the trade-off-between preservation of useful signal and subtraction of random noise. For example, if we add several random noises together, there will be some cancellation because they will be out-of-phase with each other. If they are truly random in the statistical sense, the sum of n random signals will be proportional to the root mean square of n, whereas the sum of n coherent in-phase signals will be proportional to n so that the SNR will be improved by the factor of n root mean square.
Let me share the classical work of Mike Galbraith (“Seismic processing 5: Noise rejection / relative amplitude processing”). Also, I attached the Chen and Fomel´s paper, “Random noise attenuation using local similarity”. From these examples I am trying to point out with emphasis that random noise attenuation does not depend on the use of neural networks, but on what is done preventively to increase or improve SNR.
My best wishes, Mario E. Sigismondi
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I am working on optimizing well placement in the condensate reservoir model using an algorithm. Any kind of code example will be appreciated.
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If you are interested. I have a book for python which contains a chapter about GA.
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We observed a huge difference between simulated and observed outflows from a catchment during a hydrological modelling exercise in HEC-HMS. The catchment contains numerous ponds and smaller lakes (of varying areal extent), lacking operational data. How can we account for the effect of these storage structures in the hydrological modelling?
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I am not totally familiar with HEC-HMS. I believe that it runs by reaches, with a stage, storage, outflow for each reach, is that correct? If so, then you need to make each reservoir along the river to to have its own stage storage outflow information. This is challenging modeling, so it will take some time to fully describe each of the reservoirs.
If you are modeling the upland runoff to HEC-HMS using the Curve Number methodology, there is a way in the method to account for the effect of reservoir storage in the sub basins. Let me know if you need some suggestions on how to do that.
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What should the payzone thickness be incase of horizontal wells? Should we use MD or TVD?
in terms of Well test interpretation in Kappa Saphir?
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MD will give you the more representative flow length, however the assumption normally that the total well length is contributing to flow. unless there is a PLT survey combined with the pressure build-up, use the total measured depth.
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I'm just starting to know how to use petrel.
and I was just wondering if it's possible to build an anticline or whatever the complex shaped reservoir model just using "simple grid" in RE(reservoir engineering). (something looks like the attached picture)
All I can model is just a square.
If someone can tell me the brief workflow, it will be a great help
Thanks!
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I have attached a figure for the general workflow for building a 3D model which can be used for further dynamic simulations.
This figure is obtained from this reference:
Bartucz, D. (2009). Exploration of geothermal systems with Petrel modeling software. M.Sc.Thesis, (RES) The School for Renewable Energy Science in affiliation with University of Iceland & the University of Akureyri, 55 p.
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If I want to construct a fracture model in Petrel for a certain area, what are the input data? and what is the general procedure?
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Fracture modelling is a technical problem best left to qualified Petroleum Engineers. There is a depth dependent transition between vertical and horizontal fractures at about 300m - 500m that can be critical to safe completions. Geological input should be confined to identifying the lithology of the target horizon and the occurrence of unconformities above that level. The presence of a sealing lithology above any such unconformity and the presence of any potable aquifers above the target horizon will also be of critical interest to the engineer.
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Please, I have five (5) reservoir simulation results from five (5) different compositional gradient models. History matching using either of the model will give that model a comparative advantage. How do I know the model that produced the most realistic simulation result? Thank you.
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Ikechi,
What are the parameters that you are trying to match? Do you have observed data for history matching, such as rates and pressure?
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I am performing pore shape analysis and creating pore network models of segmented microCT scans of carbonate plugs.For this purpose I require a parameter to estimate the complexity of a single pore.
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It is all about the shape aberration from the circle, isn't it?
If you can discretize the image to triangular mesh, determine the distance range between the closest and the most distant vertices from the pore barycenter. Calculate weighted average distance between the barycenter and every vertex in that ring. Sum all distances between the neighbouring vertices in the ring and divide with the circumference of weighted mean distance from the barycenter. What you get is a dimensionless positive real number that tells you how many times is the rim of that pore longer than rim of the circle with the radius you calculated as weighted average distance.
If you can't triangulate the image you must work with the intensity values from the image. A circular pore has small area of the transitional intensity gradient in the edge region. A complex pore must have greater area in the same region. If you divide the first one with the second one and take the square root out of it, you should get the ratio analogue to the mesh based solution.
In both solution you should figure out how to compensate for inaccuracy due to discretization.
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In stochastic fracture modelling, is there a specific parameter that refers to how the fractures are well connected (able to percolate)?
If such parameter exist? could we use it through the commercial software fracture modelling package such as Petrel?
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Hi Faisal
In terms of modeling,
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Hi everyone!
I'm simulating a 2D oil reservoir in Abaqus, and it's gonna be a "coupled pore fluid diffusion and stress analysis".
I need to use infinite elements on the right boundary of the model, and the rest of the elements are pore fluid/stress.
How can I link between these elements without any warning and error?
Thanks.
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Gents
If your analysis is purely acoustic, Abaqus handles the job as is. If soils are involved, things complicate.
Here are some examples of how the above is implemented in Code Aster. MISS 3D is an analytic code for analysis of multilayered soils.
The procedure is very much the same as for FE-BE fully coupled vibroacoustic analysis, only more dofs are involved in the wave propagation for the soil.
/Claes
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Hi, I am trying to perform a transient simulation in CFX of saturated steam injection into an oil reservoir (5-spot injection scheme). Everything works fine when thermal phase change is deactivated. However, when it is turned on, I get error messages from the CFX solver. Below are the details of the simulation:
- Inlet: steam (80%) + water (20%), 500 K
- Reservoir: 100% oil at 310 K at t = 0
- Total time: 24,000h
- Time step: 1h
- Phase model: thermal phase change with sat. temperature as a function of pressure
- Fluid properties: the dynamic viscosity of the fluids is a function of temperature
I have read through the CFX tutorials, tried to decreased the time step, set the saturation temperature and the dynamic viscosity of the fluids as constants, even so, I've been getting those error messages in the 10th time step or so in the CFX solver.
Again, everything works fine when the thermal phase change is off. Am I missing something? Does anyone have any idea on how I should proceed? Thanks.
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Hi, 
It 's been long ago that  I was simulating multiphase flow.
I hope the following question are helpful for you. 
What is the detail information in the Out-File of the solver?
(A additional information could be a backup-file after the 5th and the 8th timestep. )
Is the transient timestep in a realistic scale of the massflow through the control volume?
One per cent of the pass-through time of the steam ought to be a reference value. The control volume oughts to be very big for a timestep of 1h. Typical timesteps are under 1 second.
Do you use the thermal energy equation or the total energy equation for solving the problem?
What happen if you only simulated the inlet condition with phase model without the reservoir? 
Is the absolute pressure near the inlet physical (wet steam)?
Have you define a reference absolute pressure in your control volume?
Good luck!
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A typical flow simulator handles around 105 to 106 cells, while a GM typically contains around 107 to 108 cells. As an essential component of a reservoir management, we have to evaluate the risk and uncertainty of the model responses, and thus we need to run thousands of such simulations [5,6]. Therefore, it is necessary to upscale the properties of the GM grid blocks to a coarsened grid that can be used in a reservoir simulation with an economical amount of computation time, while ensuring that the predictions resulting from the coarse model is close enough to the reference fine-scale model.
Upscaling is carried out for the simulation of a reservoir with a single-phase or multi-phase flow. Single-phase upscaling is concerned with upscaling absolute permeability, while multi-phase upscaling deals with upscaling absolute and relative permeabilities.
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You may also look at the attached SPE Distinguished Lecture about the upgridding and upscalling.
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Tar may feel comfortably fine in crude oil in the reservoir, but may drop out during surface. Tar observed in the lab may not be tar downhole. What is the bets way to characterize tar in the reservoir for reservoir modeling and development purposes?
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Re: What is the best way to characterize tar in the reservoir for reservoir modeling and development purposes?
For your consideration, the below may be of use:
  • One of the objectives of this paper was to describe and model distribution of tar in a reservoir
Characterisation, Origin and Repartition of Tar Mat in The Bul Hanine....https://www.onepetro.org/download/conference-paper/IPTC-11812-MS?id=conference-paper%2FIPTC-11812-MS
  • The results of these 2008 proceedings may be of use. The workshop covered: characterization, through modelling, reservoir management, drilling, to production of new reserves. 
EAGE/SPE Technical Workshop on Tar Mats
9 - 12 November 2008
Maximizing Recovery from Reservoirs with Tar Mats: from Characterization to Production Dubai, United Arab Emirates
  • This paper looked at modeling of tar-mats:
Investigating and modeling tar-mats in a Kuwaiti
carbonate reservoir and their role in understanding
  • This paper was delivered at a OnePetro Conference:
Tar Characterization for Optimum Reservoir Management Strategy
AuthorsMuhammad Al-Harthi (Saudi Aramco) | Mohammed Al-Ali (Saudi Aramco) | Ronny Gunarto (Saudi Aramco) DOIhttp://dx.doi.org/10.2118/160891-MS
  • This researcher is a specialist in Petrel and other software - you may wish to request a LinkedIn connection.
Linji An - Senior Staff Geologist at Pioneer Natural Resources Company
A petroleum geologist specializing in geologic modeling, reservoir characterization, structural geology, fault seal analysis, and software development.
Cheers,
Leo
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when Net to Gross ratio (NTG) decrease in the reservoir model, it means that the amount of clay increase?
does anyone has any idea about how NTG effect on the low salinity waterflooding?
Thanks
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You need to be specific, as net to gross is used in two specific ways in the industry. Firstly one has the most important; net pay to gross (generally shortened to net to gross), where the amount of effective reservoir (the rock that will contribute to flow etc) is calculated from either logs or core. Effective rock is normally defined by applying a permeability  (often related to porosity via a permeabilty/porosity relationship), volume of shale and water saturation cutoffs. The net pay to gross is of course calculated as the amount of effective reservoir relative to the total interval defined.  The lack of effective reservoir can be the result of many factors including clay/shale in the system, which may be caused by the original sedimentological facies or later clay cementation/diagenesis. It can also be caused by mineral diagenesis such as calcite dolomite and quartz.
The other main use of net gross is to define net reservoir thickness relative to the overall thickness of the interval. Here one is looking at the amount of potential reservoir in the system, such as sand without looking at the effects of diagenesis (for example). This later 'net-to'gross is of course the basis of geological/sedimentological modelling.
A reduction in permeability/effective reservoir and the net to gross does need to be recognised in the development of reservoir models to understand the various permeability pathways in a reservoir. Also if the decrease in net to gross could be related to an increase in interstitial diagenetic clays, whcih in some instances can adversely affect water injection and general flow in the reservoir if care is not taken with conpatibility of injection water
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Hi all,
Greetings. I am modelling a catchment using Arcswat 2012 with many floodplains which i consider as reservoirs in the model. I have calculated all characteristics of reservoirs (floodplains) and the simulated discharge seems fine as the reservoirs clearly have an influence on the peak discharges. However when i look at the output file i noticed the following:
TILE FROM IMPOUNDED WATER = 0.000 (MM)
EVAPORATION FROM IMPOUNDED WATER = 0.000 (MM)
SEEPAGE INTO SOIL FROM IMPOUNDED WATER = 0.000 (MM)
OVERFLOW FROM IMPOUNDED WATER = 0.000 (MM)
When I increase the hydraulic conductivity to 1mm/hr, it give the same output as above.
Could someone explain to me where i have gone wrong? I am using Arcswat2012 (version ArcSWAT 2012.10.2.17).
Elias
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your input was not a problem. All the outputs were related to impounded water. the water impounded on surface means after meeting the all loses such as evaporation, seepage and overland flow the water gets accumulated on the surface. hence nothing wrong in your output.  
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Good evening
I would to ask you these questions that will help me in my literature search. 1- does the push-sediment influences the crack propagation in the dam? Because I've noticed that many researchers do not take into account this setting. 2- does the water quality of dam reservoir influence the crack propagation ? 3 What is the best method to model the crack propagation in the body gravity dams taking into account the water pressure; XFEM (Extended Finite Element Method) or DEM (Disrecte Element Method)?
Thank you Best regards
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thank you for your help and interest that you carried me
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Is it possible for me to use 1D2D hydrodynamic model for generating  river reservoir or dam to study the flood impact on studied area before and after built reservoir or dam?
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Various investigators at TVA (Tennessee Valley Authority) have published many articles on this over the years. They have also analyzed networks of dams, as they control a large network. You should also check out the Iowa Institute for Hydraulic Research. Both organizations have been involved in the development of dams around the world, including massive projects in China.
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the regional empirical factor  will help me to estimate TOC in shale reservoir
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TOC is a problematic value.  It will be the sum of all losses in weight resulting from decomposition of organic matter, hydromicas and carbonates in the sample.  You may use it as a "quick and dirty method" but unless you know the mineral composition of the\actual deposit, your results will not necessarily be a true measure of the hydrocarbon content of the deposit.  Remember too, that sediments usually vary in composition laterally and this must be taken into account when interpreting the results.  This means that unless you have a substantial amount of data from the same stratum in a relatively small area, your results need to be interpreted with caution..
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What is the petroleum system of the Santos Basin, Brazil?
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Hi Eugene
Please see this publication
Regards
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Dear all,
I only have observed water stage of the reservoir on daily, no observed inflow to reservoir, no observed outflow from reservoir.
I would like to calibrate water stage for a reservoir in SWAT. So how can I do that?
I am looking forward to hearing from all of you soon!
Thank you so much!
Liem
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You can convert the stage data to volume (rating curve -area-volume-stage/depth) and compare with daily volume of reservoir simulated with SWAT model (in res.out) or you can do vice-versa. 
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Prior to fit the experimental design model by multiple linear regression, how to validate the model in terms of number of observations, orthogonality , and distance? How to evaluate the last two terms?
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According to Giunta et al., he presented empirical estimations to get the number of experiments in Latin Hypercube Sampling only:
 1.5*V runs for 5-10 variables (V), 3*V runs for 10-20 variables (V), and 4.5*V runs for a 20- 30 variables(V).
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i have problem in running regression of PVT analysis. Can anyone explain to me what is the meaning or mathematics theory of changing component-based regression variables (i see some numbers like 1,2 or 3 when we change the variables) and show me the way to do that. Sorry im new in this sector. Thanks a lot.
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This is one of the most debated and open ended questions simulation guys are faced with. These are a few heuristics that might help you in the process provided you have lab PVT data to calibrate your model with:
Volumetric data - Accentric factors, omega values, critical conditions (not recommended)
Viscosity data - Z (critical) and V (critical)
Kindly note these are just a few observations from literature and can serve as a good starting point should you need one.
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What is the rational behind refining the grids that has CO2 injection wells n compositional reservoir modeling? Does it affect or facilitate the history matching?
Overall, is it so necessary to implement grid refinery at this problem?
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Selecting the coarser grid blocks (lower number of cells) in the compositional modeling through CO2 EOR flooding cause the larger effect of numerical dispersion. The presence of numerical dispersion has the effect of smearing out the recovery curves and make the determination of a break point more difficult / inaccurate. Hence, the task of determining the MMP becomes a balance between acceptable accuracy and acceptable CPU time consumption.  Further, as explained by Zick and Stalkup, the MMP can always be found by compositional simulation, though fine grids and repeated simulations at multiple pressures and certainly a significant computation times will be required.
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I am trying to design a small reservoir model and looking for a (vacuum?) pump that keeps well bore pressure lower than reservoir pressure.
I prefer a pump that keeps pressure constant, but it doesn't have to be as long as it is not very strong.
I already tried electric vacuum pump but it was too strong.
I also tried hand pump but it was impossible to keep the pressure constant.
Any recommandation?
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For a moderate but constant vacuum, I would use a water-air jet pump, very common in the lab and very cheap. Provided that your system is not sensitive to moisture, however.
Alain
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I am aware that the process itself depends on the geology of the reservoirs to a certain extent in addition to of course development scheme (depletion followed by water injection or gas injection .. etc). I am in the process of trying to compile a benchmarking of recovery vs. reservoir geology vs. mobility ratio vs. heterogeneity (areal and vertical) for different waterflood patters. Then I might try to develop further to other development schemes (gas injection, EOR .. etc)
I am sure that I need to use average drainage radius/permeability, communication between layers and BHP. However this is making it very complicated. 
Any ideas? Any suggested references? Any one who is interested in trying this as a first method of field development appraisal/bidding process?
What I am thinking is once these factors are estimated, a reasonable estimate of recovery factor can be achieved even before simulation process starts.  Since static and dynamic models are using basically this data to generate forecasts in the first place. Appreciate you feedback and discussion. 
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These incorporating parameters have significant effect on the recovery factor. Specially, Permeability that influences on the cut-off calculation
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It is a routine approach that production logging tool (PLT) data are used to match and find the best correlations for well flowing model in oil&gas fields.
My question is to understand whether it's possible to use a reservoir simulator as data generator for well flow modeling. If this is feasible, the expensive, time-consuming PLT test can be simulated to select the best model for a given reservoir
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Reza,
Please try this keyword: WRFTPLT. It exports both RFT and PLT data. Search in the manual what it exports and what you need to specify. As far as I remember it is in the schedule section.
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Hello
i m doing a problem on dam reservoir foundation interaction to apply a unit harmonic ground excitation.. please any body can share how to apply unit harmonic ground excitation on the abaqus model.  
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u can see the koyna dam problem in abaqus problems manual. It is similar to your model. 
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It is around  two years that Iran's ministry of water and energy is looking for a remediation to salty Gotvand dam. The dam reservoir is  placed on geological formation known as "Gachsaran". This formation is completely repleted by structures out of salt, which has changed  the quality of water inside the reservoir. This dam is placed in Karoon basin beside Karkhe basin located in the center and south-western of the country. A schematic figure of reservoirs and the drainage system is attached to questions . Any help and notion is appreciated.
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It would be helpfull if you could be more specific on the problem that needs to be solved. The information you are providing is of general nature. Another thing that would be helpfull would be to provide some stratological description of the formation and its spatial relation to the reservoir.
If for example the problem at stake is the high salinity caused by disolution of this formation and the formation "touches" extensive areas of the reservoir at high water levels, one alternative could be to operate the reservoir (lower its level) so as to minimize contact area; that is of course if the economical losses from energy production are deemed to be acceptable.  But again, this is only a wild guess without much thought, since there is no precise information. If you are more clear about your request and provide more information, you are likely to get better answers.
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I am solving the IMPES equation for the reservoir simulation. I wanted to know the criteria for stability of the equation.
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IMPES method has two source of stability limitations: primary variables and transmissibility.
During IMPES method, capillary pressure term is treated explicitly which cause stability issue depending on the Pc-curve's magnitude. Fluid comprerssibility changes the stability limit. Nevertheless, it is common to consider the stability limit under the incompressible assumption for practical purposes.
Besides, explicit treatment of transmissibility term leads to strong non-linearity. The well known stability limit due to this is that flood front can only advance one grid block per iteration. Otherwise, the total throughput of any grid block per iteration must be less that its pore volume.
Ref: Aziz, K., and Settari, A. 1979, Petroleum Reservoir Simulation. London, UK: Applied Science Publisher
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Reservoir modeling for saline aquifers is well accomplished by Generalized Equation of state Modeling software (GEM). I wish to know which model are they choosing for the same viz., Peng Robinson state or Soave Redlich equation or any other model.
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Dear Ankita,
Try Soave Redlich Equation, but in my mind Preeqc program is more known for saline groundwater.
Best for you
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distance, discharge from upper reservoir, storage in both reservoir, effects on downstream of lower dam. 
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management of sedimentation scouring from the upstream dam, versus re-deposition in the downstream one.
Environmental effects of a widely varying flow regime between the two dams, compared to a (possibly) less wide range of flows downstream of the lowermost one.
The management of both, to optimise the hydropower generated to the national grid, at those times when the power is most valuable, while operating them within safe upper/lower water levels
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Reliability for reservoir operation is defined as number of periods that downstream demand is met to all periods. This definition is applicable for single reservoir system. As multireservoir system may work at series or parallel, I want to know : Is there any "reliability index" to evaluate the operation of multireservoir system ?
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Dear Mohammad, Have you seen this innovation and patent description, it presents some discussion on reliability for the systems you are looking at:
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In the classical reservoir engineering context, the well drainage radius is normally kept constant; while new findings indicate that it should not be kept constant; rather, the well drainage radius can be subject to change with time, depending on some operating and reservoir parameters.
I am looking for method(s) and techniques to detect and record changes in drainage radius as the well is put into production
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It is certainly true that the drainage radius would change with time. Methods to discern that are not exactly lucid though. However, well test analysis a way of establishing boundary effects and by extension, the drainage radius of the well. The imaging technique in superposition should also aid in this. Dynamic simulation also shows this.
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How do you determine equilibrium displacement in an injection and production well pattern? Please can anyone give me a clear way of approach or any method to go about it.
In a well pattern say 5 point or 7 point under different reservoir properties arrangement. How do you get equal oil displacement in all the production wells.
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Could you specify what you exactly need?
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With reservoir quality modeling, we can simulate many quality variables in the reservoir such as temperature, salt, alkalinity etc.
Well known 1D simulators, such as HEC5Q, needs MSDOS to run, I want to find a Windows based one for my modeling.
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I finally find DYRESM model useful for my study. this model can run on several OS including Win, Mac, Linux and ..
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Based on the 3D structure information of a building I want to perform a fluid flow simulation. In particular, I want to find out places with the highest fluid flow density. You can imagine it as filling a building uniformly with water and then finding out where water has the highest flow density. I am looking for a simple-to-use and easy tool to perform this simulation as I am not an expert in the field.
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Assuming your application is more metaphorical and less about precise computational fluid dynamics for engineering simulation, you might find useful models in the literature of computer graphics and animation (eg SIGGRAPH) where there has been a lot of work on fast approximate methods that produce visually good, if not highly accurate, results.
See for example Jos Stam's influential 1999 paper “Stable fluids” (http://dl.acm.org/citation.cfm?id=311548 -- http://www.dgp.toronto.edu/people/stam/reality/Research/pdf/ns.pdf)
See also his 2003 application oriented paper “Real-Time Fluid Dynamics for Games” http://www.intpowertechcorp.com/GDC03.pdf
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I am interested in this kind of work, and a major part of my master thesis deals with gestatistics and reservoir simulation
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thanks Adnan,
actually i am interested in stochastic modeling, more specifically in some kind of integration between sequential indicator simulation and object-based simulation (Boolean)
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Can someone point me to a key publication or review paper that discusses the van Genuchten and Brooks Corey models re: capillary pressure curves. I need to make sure I reference this properly and am having problems finding an appropriate paper aimed and oil and gas reservoirs. Thanks
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J. Chen, J.W. Hopmans*, M.E. Grismer, 1999. Parameter estimation of two-fluid capillary pressure–saturation and permeability functions. Advances in Water Resources Vol. 22, No. 5, pp. 479–493.