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Hello everyone. I'm working on reservoir rock mechanical properties. Do you know any conducted study on correlation between rock mechanichanal and thermal properties?
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Thank you Mehdi Razavifar jan.
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Dear Friends,
I am trying to simulate immiscible WAG injection using the black-oil model in IMEX and Eclipse 100.
I built a PVT file in Winprop, activated the Black oil output, and used it to feed both simulators.
Although every model condition is the same, I can not match the results.
Is there anyone who has had the same problem?
#Petroleum Engineering
#Reservoir Engineering
#simulation
#PVT
#CMG
#Eclipse
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Pierre Bergey Thank you so much for your kind reply. I did what you mentioned and it works. Thank you
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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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In our different studies for petroleum fluid analysis, we always assume that petroleum reservoirs are isothermal. Do you agree with this assumption? And if not, what is the impact of this assumption on the different calculations related to fluid analysis and consequently reserves calculations?
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Reservoir temperature in accumulations depends on their occurrence depth and geothermal specifics of the giver Earth crust area. Observed temperatures vary from near 0°С in gas-hydrate accumulations to hundreds °С in deep-lying formations
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This pore water pressure is being investigated on hydro-station reservoir construction material in a bid to avoid rupture of the structure after construction.
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I'm completely agree with Imoukhuede Idehai
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I'm interested in pursuing a PhD in Reservoir Engineering and Simulation.
I have First-Class BEng and MSc in Petroleum Engineering from the University of Manchester and Heriot-Watt University, respectively. I specialised in Reservoir Simulation and Enhanced Oil Recovery (EOR) completing my Master's thesis "Maximising Oil Recovery Through Thermally-Activated Polymer Placement" with 81% and will be presenting a paper on this topic at the 21st European Symposium on Improved Oil Recovery (IOR) in Vienna, Austria 2021.
I would appreciate it if anyone could put me in touch with interested parties.
Thank you
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Try King Fahd University (KFPUM) -KSA
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For anyone attempting to find a job as a petroleum engineer (whether it be a reservoir engineer, drilling engineer, etc.) in Ontario, Canada... is it recommended that they acquire a P.Eng designation?
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Not sure there is such title as P.Eng in Ontario but definitely a PE status is recommended regardless of your engineering discipline. Canada is highly regulated environment for engineering practise whether in a corporate employment or as an independent consultant. All provinces have their own licensing authorities with different requirements. Without a license, an engineer must work under the supervision of a PE who must certify or sign-off his work, reports or design. To be licensed, an engineer will have to go through series of engineering and professional certification exams (depending on level of experience some can be waived but not all) to be licensed to practise professionally in Ontario. Visit Professional Engineers Ontario (https://www.peo.on.ca/) for details.
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What techniques do reservoir engineers employ for averaging relative permeability curves? Any specific averaging equation?
I found only two equations for averaging relative permeability curves, as listed in the below paper (equations 2 and 7).
Do you know any other methods?
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Hassan Mahani I saw you mentioned one the works of Alan S. Emanuel from Chevron. Back in 1970s, Emaneul had published remarkable works in the area of commercial simual. In fact, in the first year of my Ph.D. I was totally stuck, and I only figured out the general idea of my PhD work after reading one of his papers ( )
It was interesting to me to see his name here. If I am not wrong Emanual has around 30 papers in SPE library.
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could anyone help me with this eror?
I'm dealing with a simple model in CMG STARS and as you see in the below picture, just after starting simulation (production and injection simultaneously, with 4 wells ,2 injection and 2 production) the pressure drop from 3000 psi to sth around 100 psi.
then 100 days after the start of simulation, I want to stop injection and prodction for about 20 days in 2 well of 4 total well, so this is the time that I've got the second fluctuation.
It should be noted that I'm working with dead oil and there is not any gas in the system.
if you had any similar experience,I'll be so glad to hear.
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The fact that there is no gas in your system (meaning low compressibility) and the small description you provide suggest that your are dealing with a small closed (no analytical or explicitly gridded aquifer) low compressibility reservoir. In such situation and unless you have setup a pressure control of your injection or production or both, seeing strong pressure variations is normal. You would need to make the injection or production or both controlled by a regional pressure.
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I just read a paper that one can view a fracture trace from the impression packer? Could anyone provide an example for understanding? Thank you.
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I am not sure what you mean by "provide an example". These are inflatable packers with relatively soft rubber sleeves. When you inflate the packer, the rubber will enter the fracture and you get an in-print of the fracture intersection with the wellbore. If in the same time you have a compass downhole, you can take a reading and orient the fracture in space. Once at the surface you unwrap the oriented fracture in-print. It is used in hydraulic fracturing applications ) mainly geotechnical and mining).
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The observational method is a framework wherein construction and design procedures and details of a geotechnical engineering project are adjusted based upon observations and measurements made as construction proceeds.
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Hi,
My name is Manoel Farias, reservoir engineer for PetroRio and Reservoir Eng Professor at Universidade Veiga de Almeida.
I would like to know if you have some results about the use of nanoparticles as a stimulation technique, I mean, to inject them through a bullhead in production wells.
Have you read or research something about it?
Thanks in advance,
Best Regards,
Manoel
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Hi Manuel - yes, we are currently injecting this into wells as a stimulation technique and have seen very good results. Due to confidentiality, I am unable to share specific well results but can send you sales literature on the nanoparticle fluids if you email me at j.williams@nitrolift.com.
Nitro-Lift Technologies is the master distributor for Nissan Chemical's nanoActiv® Enhanced Flowback Technology (EFT) and Hydrocarbon Recovery Technology (HRT) nanoparticle fluids in the Lower-48.
This revolutionary product is increasing production in wells through surface-modified nanoparticles that actually “lift” and fragment oil in the reservoir allowing it to move the wellbore. The best visual showing nanoActiv®’s ability to dislodge oil in pore space is shown in the following video:
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Recently, I'm interested in the topic of THMC (thermo-hydro-mechanical-chemical) simulation for CO2 injection and reservoir engineering. I'm looking forward for any recommended open-source THMC simulators for geoscience. This simulator can simulate e.g. fracturing in reservoir due to temperature and pressure during CO2 injection and how chemical activity controls the reservoir.
Thank you for your kind recommendations.
Regards,
Nuwara
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I'm involved in 'Study of Sustainable sediment management' in a river of Nepal on which a storage type hydro electric project is going to be built in near future. It seems that Sediment Sluicing is most feasible according to the site. I'm interested to get details on Serpent Sediment Sluicing System but I couldn't access to any such detailed knowledge. Is it I don't know much ways to find such study online or the papers(s) I'm asking for is patented or reserved that I from Nepal can't access online?
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Thank you Dr. John Machell !
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Required Inputs:
1. Mwt of the Dead oil (STO)
2. API
3. Viscosity vs Temperature Data
Hi Everyone, I am research scholar at university of Houston and I am currently QCing the performance of existing dead oil correlations for heavy oils. If anyone in this group can provide me the following data I can let him know about how easily the viscosity of that sample could be modeled and also how well or how bad is the performance all leading published correlations.
Thanks
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Hi, I already looked at it however the paper the doesn't contain the raw data use to build the correlation.
Thanks Appreciate
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I am interested in pursuing a funded PhD research project in any of the following areas
Reservoir engineering
Well bore integrity
Well P&A
Oil and gas Decommissioning
.I would really appreciate if anyone could link me up.
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You can also look at the Chinese Government Scholarship for China University of Petroleum (CUP) in Beijing or Qingdao.
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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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In the context of Reservoir Engineering,
we use "Intrinsic Permeability"
(as against Hydraulic Conductivity); and
we also use "mobility" or "hydraulic diffusivity".
But, no where, "fluid density" comes into picture.
Then, How do we account for the "Variations in Density"
resulting from
(a) Dissolved-mineral content of the reservoir fluid; &
(b) temperature changes
in a typical Petroleum Reservoir - under normal circumstances?
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Under typical circumstances, we factor in variations in disolved mineral in log interpretations and ignore variations in most (all?) other reservoir aspects (static modelling and dynamic flow simulation). Occasionnaly, we factor in variations of disolved minerals all over the modelling chain (usually when there is strong variations in inital water salinity). In such cases, it is typical (but not mandatory) to limit mineral presence to the water phase. Changes in mineral content linked to variations of temperature are ignored except in peculiar circunstances such as SAGD. Above comment relate to reservoir development space and time scales not migration or digital rock physics space and time scales. Motivations are obvious considering the physics involved and the limited impact such aspects have on what matters. When to make things more complex and how to improve representation is reasonnably well understood (in my opinion).
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WAG injection is an EOR process that was developed to mitigate the technical and economic disadvantages of gas injection. It is the most widely applied and most successful traditional EOR process.
It involves the injection of slugs of water alternately with gas although sometimes the two fluids are injected simultaneously (termed SWAG= zero slug size).
My question is: when optimising the slug size to achieve high oil recovery, the optimisation directs me towards small slug sizes that the period of injection will be one month to inject gas and one month to inject water, is that still considered as SWAG or is it considered as WAG injection at small slug sizes behaving similar to SWAG?
Keep in mind that I dont have a real field, and I didnt consider the economic part.
The only thing I can consider in my work is how much gas available to inject, which leads me to my second question.
I could not find a source to tell me approximately how much gas available to use for injection, I appreciate any suggestions or links I can find the answer?
Thanks in advance
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From a reservoir / recovery perspective one can consider that infinitely small sized slugs tangent the behavior of simulatenous injection. But this is not true from an operations and design of facilities perspective. Equipments and procedures for true simultanenous operations will differ from those of alternating with short slugs (CAPEX /OPEX will be different, HSE aspects too).
For the second question, there are many possible answers. I would structure things considering different configurations. First configuration would be reinjection of associated gas (minus whatever was used for compression and other utilities) eventually focusing WAG on part of reservoir(s), second configuration would be maximum efficiency level of gas injection (no limit on gas availability).
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Hi,
I'd like to share a question that has been puzzling me for a long time now:
It is common to use the assumption that a partially filled cryogenic tank is a volume in vapor-liquid equilibrium (VLE).
How does this assumption hold ?
Is there a kind of Biot number one could use to justify this key hypothesis ?
Based on observations, some zonal models consider the temperature isn't homogeneous between the vapor and liquid phase.
I guess the size of the tank matters.
I am looking for a formal way to justify the VLE assumption (more or less like when using the biot number to set a thermally simple model, due to uniform temperature fields inside the body).
Any clue on this would be of immense help to me.
Regards,
Jonas
Key words: LNG, cryogenics, tank, thermal model, lumped thermal model, process engineering.
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interested
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Dear O&G Researchers and Reservoir Engineering, it's for you that I am writing in the hope to get some answers of the Following question to be able to accomplish a part of my master thesis;
What gonna happen if the applied EOR Technique don't match with our reservoir?
As you know, it is difficult to get a such informations but I am posting this message here to know if you can share with me some of your experiences about the resulting damages, both technical and economical, of an inappropriate method that was aplied for any reservoir in the worldwide. You can keep anonymous all confidential informations. Or if there is some technical papers talking about that.
One of useful response that I got is that there are some surveys that estimate a 20% of wells can be damaged due to compatibility problem. and off course this can be translated on many millions of USD. here come the need for respecting many steps to ensure a good implementation of any EOR process. still need the source of that and some quantification.
I look forward to get some interactions. Thank you in advance.
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A few years ago, our company performed a pilot test of immiscible gas injection (in WAG mode) in a mature, waterflooded, light-oil, sandstone reservoir. The injection gas was of high CO2 content and was available as production gas with no sales value from a nearby field.
Conventional EOR method screening criteria anticipated that this was not a case for a very good “match” between EOR process and reservoir/fluid characteristics: immiscible CO2 injection has been successful in steeply dipping reservoirs or in medium-viscosity oils, at relatively high remaining oil saturations.
Our case, in contrast, is a light oil (thus with very small margin for viscosity reduction by the CO2), contained in a horizontal reservoir with a relatively high recovery factor by primary recovery and waterflooding. Besides, permeability is highest at the topo layers and lower towards deeper intervals, a configuration that favors good vertical efficiency by water but not by gas injection.
How was then decided to explore the feasibility of this process in this reservoir? The oilfield to which this reservoir belongs was one of the company’s largest assets at that time; even a small increase in recovery factor meant a very interesting volume of oil. The low remaining oil saturation was considered to have a potential for further reduction with this process, based on very conclusive laboratory tests and pilot – scale simulation studies. Injection gas was readily available for the pilot and another large source of almost pure CO2 was present in a nearby structure and would have been used for commercial expansion. On the other hand, chemical EOR and high-pressure air injection had been considered for this field and discarded for non-technical reasons such as complexity, logistics, costs, operational risk.
We proceeded to the pilot test, after stating very clearly to management that it was a risky process. After about 1,5 years of operation, with 40% pore volume of gas and water injected into two different (separate) pilot patterns, the project was abandoned because the incremental oil was much smaller than predicted and gas production was becoming an operational problem.
Strong gravity segregation of the injected gas was the most likely cause of the poor performance, aggravated by the unfavorable permeability distribution that caused water and gas to follow different flow paths in the reservoir and thus prevented the full recovery mechanism from being effective.
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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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Dear Researchers,
I am now working on the development of modeling EOR project. However, I am stuck with the method to simulate flow diversion mechanism created by polymer flood that reduce high permeability zone. The flow then will sweep into small permeability area.
One solution I found was using Dynamic Permeability Model. Which is not possible to be created in CMG or other reservoir simulation.
Please I need your advise :)
Thanks
Madhan
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Industrial grade reservoir simulators like IMEX/ECLIPSE/INTERSECT/... are probably unsuited for the type of work you want to perform. You likely need to access and tweak the physical engine of the simulator. R&D codes are what you are looking for. Some source code, which allows you to tweak physics at core, are open source. Google MRST, ADGPRS, OPENFOAM, etc. I would expect some tweaks to be already available in those codes. This will require some investment on your side into the selected code. It is probably advisable that you select one that is used by people around you.
A very crude alternative is to tweak an industrial grade simulator with restarts or use some of the options that exist in some of those "a little bit far". But this is very crude and messy, I would not recommend that.
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The gas flow through porous media is an example of a classic problem for reservoir engineers, with almost all details have already been studied. Solution techniques, as well as analysis of results for many cases have been well documented. However, this rather old problem may have novel features, especially in certain systems like gas condensate reservoirs and shale gas. This is what I am looking for. Appreciate for receiving your comments and any related documents.
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I guess a major part of R&D effort in gas flow is directed toward ultra low permeability reservoirs and source rocks. How desorption of gas from kerogen affects flow and EUR.
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We are working on finding solution of models of imbibition phenomenon which occurs during oil recovery process. In this phenomenon water is injected in oil saturated porous medium and it displaces oil from it.
In the literature which I have refered so far, there are some papers in which they conclude that saturation of water increases as distance increase and there are some other papers in which they show that as distance increases, saturation of water decreases.
In mathematics, we can conclude both of this by assigning appropriate boundary conditions.
My doubt is which one is physically consistent ?
As I understand, the saturation of water should increase as we go further but that depends on water injection rates also.
But most of the standard papers show that saturation of water decreases as distance increases.
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based on my studies, I realized that when your porous medium is considered to be triangle Unit it will decrease when your pore size decreases ,however when it is circular tube the water pour the biggest pores and move to the smallest one then saturation increases in imbibition. I hope t was related to ur topic :S and dipak can I ask you worked on which equation to describe them mathematically? 
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In a gas condensate reservoir, as the flowing bottom-hole pressure goes below the dew point pressure, liquid condensate would condense out of the dominant gaseous phase. This would cause a remarkable decrease in the gas relative permeability in the near wellbore region where most of the pressure drop would occur. A possible explanation of this decrease in gas relative permeability is that the heavy components in the liquid condensate get attracted to the pore surface and shift the wettability towards a more oil-wet state.
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I agree with Andreas.
Usually, carbonates tend to be more oil wet than sandstone. Usually, heavy oil wets more than light oil. Therefore, especially if the reservoir is not carbonate, it is difficult for a super-light liquid such as condensate to actually wet the pore walls.
To answer the question above, I do not consider realistic that the long term occupation of pore space by a condensate in the near wellbore region causes the rock matrix to become more oil/condensate-wet.
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I am currently working on matrix acidizing an emulsifed acid and need to work on core flooding, wish to seek any researcher who can take me under their wing.
Thank you,
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Dear Mohsin,
I am a field engineer and managed a number of acidizing operations including acid washing and matrix acidizing. What exactly do you want?
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As you know pore pressure prediction is performed in shale since one cannot measure pressure in shale. In pore pressure prediction, we develop compaction trend line for shale then predict pore pressure. What happens if there is no shale in the drilled field and measured pore pressure? How can we obtain pore pressure profile? Any suggestions or techniques?
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If you have seismic velocities it can be converted into pore pressure in absence of lithology also. the d-exponent curves generated will give us an idea about hydrostatic pressure and deviation from hydro static regime.
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I am trying to understand PKN and KGD models for hydraulic fracturing. I am wondering why equations for fracture width and length does not include 'breakdown pressure' (pressure at which fracture initiates? The formula for fracture length for KGD include shear modulus, injection rate, viscosity, fracture height and time only. Why there is not a threshold value, after which fracture initiates in this formula?
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You are welcome. You can find more details in 'Reservoir Stimulation' by Michael J.  Economides and Kenneth G. Nolte.
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Hello I´m looking for a software that generate synthetic stream flows with high size, for example 50, 100 years or more. I want to evaluated the performance reservoir index through reservoir simulation with the model HEC-ResSim but I need a synthetic stream flows. Please if someone knows a software that I could use for do it, I will appreciate so much.
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Use. SPIGOT software
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Currently I am trying to simulate heterogeneous seawater intrusion (2D/3D heterogeneous Henry problem). To achieve this goal it’s necessary to generate 2D/3D heterogeneous hydraulic conductivity distribution with a mean value.  Is there any free software/code used to generate 2D/3D random hydraulic conductivity fields (described by mean, variance, ……) by using the turning bands method.
Any code/User manual/ Example will be very helpful for me.
Thank you in advance
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Hi Ezzeddine,
The answer would heavily depend on your Fortran skills. The standard for these simulations is the geostatistical software library that comes with Deutch and  Journel, 1992 (reference below). I believe there is a newer edition that includes C code as well. The library is a collection of Fortran subroutines that need to be compiled and includes many different simulation methods (not just turning bands) that may prove useful. There is a matlab program (TBCOSIM) that can create fields using TB.
Finally a similar (fully compiled, thus no programming experience is required) utility is part of the groundwater tools that comes with PEST (www.pesthomepage.org) but it is based on the Sequential Gaussian method and only generates 2D fields.
Hope this helps.
Theo
Deutsch, C., and A. Journel, GSLIB Geostatistical Software Library and User's Guide: Oxford University Press, New York, 340 p, 1992.
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The oil flow through porous media is an example of a classic problem for reservoir engineers, with almost all details have already been studied. Solution techniques, as well as analysis of results for many cases have been well documented. However, this rather old problem may have novel features. This is what I am looking for. Appreciate for receiveing your comments and any related documents.
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Rea-search on Non_Darcy flows in porous media is worth looking into.
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I know in the Haynesville-Bossier Shale is around 13,500-14,000 ft. But is there another one more than 14,000 ft???
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Hi Soumitra is very interesting your answer, my question is focused to unconventional plays in petroleum Wells drilled in the MFS Tithonian (Upper Jurassic)
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Automated history matching of unsteady state core flooding data is a common method of relative permeability calculation. In a carbonated water injection process, many pore scale mechanisms exist while a commercial simulator cannot model all of them. when we write Darcy equation for an injection process (macroscopic scale) all mechanisms helping oil to produce are included in relative permeability term (almost except viscosity decrease). can one justify the application of a black oil simulator such as Eclipse E100 for modeling of CWI core flooding experiments? is there any publication in this regard?
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In general, if you intend to use a given simulator in further evaluation of the mechanisms, it is obviously legitimate to use such simulator in the match of the small scale experiment.
The real question I believe you are asking is whether or not a simulator like ECLIPSE 100/300, IX, etc is suitable for representing the large scale phenomenon considering that a wide range of microscopic phenomenon are represented (henceforth potentially oversimplified) by the Kr/Pc input in the model.
There is indeed a wide range of literature on the subject and many have questioned this point. The end result is typically that one need to tailor KrPc to the problem at hand at proposal for specific Kr models. I am not aware of a publication that has convincingly demonstrated one cannot deal with large scale phenomenon using blackoil or compositional simulator, provided the Kr/Pc input is tailored to the problem at hand (or in some case like some of my TOTAL publication relative to multiple oil phases tweaking some other aspect of the simulator). This led to the proposal of a wide range of different Kr models, particularly for 3 phase flow and hysteresis. The CWI injection context you are referring to is only one specific configuration of the KrPc problem, I personally do not see how it is of particular concern compared say to WAG, polymer injection, etc. (I am not a specialist of CWI).
You should concern yourselves about the whole range of flow conditions in field scale simulator when considering the issue.
Hoping this helps. 
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For oil wet carbonate rocks, capillary pressure is important or we can negligible as simulator input?
 I used black oil model in eclipse, I need your knowledge
thanks
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Of course it is important.  But the difference in carbonate rocks is that the pore geometry is very much more varied and so the model that you use must include a much wider range of capillary dispersion.  Think only of the effect of secondary porosity.  This range of capillary values throughout the rock will depend on a host of porosity-related factors, ranging from lithology through seminary process to diagenesis and fracturing. This is undoubtedly complex, and is the subject of numerous papers.  Whether you are able to capture this is another question.
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I'm working to manage optimization study to select the optimum well technique (i.e., vertical, horizontal, single fracture, multiple fractures, ........) that could lead to producing at an economic flow rate in a tight gas reservoir (reservoir permeability less than 0.01 md) .
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Omar
The straight answer for your kind of permeability(0.01 mD) is probably yes, regardless of the type of rock. In principle is a matter of area open to flow hence your horizontal section will have to be very long to achieve some sort of rate that makes economic sense. At this level of permeability there are very few options. I hope it helps
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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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The routine Gas Material Balance is often associated with analyzing the role of aquifer, its strength, and identifying the best model to find exact behavior of aquifer and GIIP. Doing so, the reservoir history matching and predicting its future performance is a function of proper estimation of aquifer model.
I am looking for a valid numerical example of a Gas Material Balance with Aquifer. Appreciate if any one provides with data and information.
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You may want to check out our recent paper on this topic. I can share one or two simulated cases as identified in Table 1 of the attached paper. In that case, I'll need your email address.
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Multi-Phase Fluid Flow: Reservoir Engineering / Unconventional Hydrocarbon Resources: 
Can anyone enlighten me on – whether – where could I get the field data on the following four parameters: (a) well-bore radius; (b) effective radius; {And it’s respective}   (c) well-bore pressure; & (d) effective pressure; [along with the details of fluid compressibility] associated with an OIL or GAS RESERVOIR or SHALE GAS RESERVOIR or TIGHT GAS RESERVOIR?
I am looking for reference materials or any other related reports. Your help in this regard is highly appreciated.
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Desr Sir, Thanks for the references which involve fluid flow through fractured reservoirs. However, I am specifically interested in securing the details of pressure distribution as a function of space and time in a fractured reservoir. Anyway, thanks for your time. 
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I have a three layered vertical reservoir, the givens are:
P1, P2, P3, K1, K2, K3, S1, S2, S3, H1, H2, H3, Pwf, Viscosity and Density.
The situation is a pseudo-steady state and it is only oil phase (single phase flow).
I am required to calculate PI for each layer and fine the Q and Qt.
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for each layer calculate PI from equation 1
then calculate the rate (Q) for each layer from equation 2
See the attached file.
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Dear colleagues, 
I measured centrifuge capillary pressure vs average water saturation. Now I want to plot capillary pressure vs corrected water saturation. I plotted corrected first drainage curve. The question is how to plot spontaneous imbibition (based on average saturation) and then plot corrected forced imbibition curve on the same plot? should I shift the sp. imb and forced imb. to the end of first drainage? That way I may end up with water saturation less than what I measured. Or I should just plot PC vs Sw_avg and then corrected curve on them? which again I have a hard time with it, because the face saturation at the end of drainage has changed. However, during the two weeks of spontaneous imbibition, I see a very strong fluid re-distribution in the cores (NMR profile measurement). In that case should I do the second option? Please kindly help me find a reference or explain for me how to do it. Thank you! 
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I would suggest you read the experimetal work on "Positive imbibition capillary pressure curves using the centrifuge technique" by M. FLEURY, G. RINGOT and P. POULAIN. I am certainly sure with that, all the issues raised above wil be solved. 
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Hi Everyone.
As you probably know that one item that is involving during injection of low salinity water flooding into Carbonate reservoirs, is the presence of Anhydrite. Austa et. al published a paper “Conditions for a Low-Salinity Enhanced Oil Recovery (EOR) Effect in Carbonate Oil Reservoirs”
On their paper, they mentioned that “The dissolution of anhydrite increases as the temperature decreases. Sulfate is a catalyst for the wettability alteration process, and it is important to have a maximum concentration of sulfate dissolved in the brine.”
On the other hand, further studies by Awolayoetal.(2014) suggested that smart water with four times sulfate concentrations might be the optimum sulfate concentration.
Based on all aforementioned papers, I like to ask following questions:
1-      Is there any other limitation or valuable range for anhydrate concentration during Low Salinity water injection for Carbanete reservoirs? Generally speaking, what is role of anhydrate for LSW of carbonate reservoirs?
2-      As I went over the literature, I noticed that there are two kinds of chromatography for evaluating ions concentrations. These instruments are “ICS 3000” and “LA ICP-MS”. Are there any other types of instruments for counting ion concentration? Does anybody know more information about that?
3-      Finally, I have seen that some authors illustrate profile of the ion concentration vs P.V injection. How can I generate such graphs? Are they analysis produced water after each pore volume injection? what is the procedure of generating those plots?
Thanks,
Alireza.
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well I'm not in your field. bit my one class in petroleum engineering involved modeling the reservoir as dimensionless. therefore pore volumes injected is really just flow rate used to measure time. for ion concentration we would use the error function to model diffusion effects. I am unable to type the math on my phone but check out multicomponent flow modeling, not sure it you're referencing multiphase flow as well but that is a little more complex. We used Buckley leverett method of modeling injection of water to displace oil. similar concepts in terms of dimensionless dimensions, ie pore volumes injected  (an arbitrary number) replaces time.
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I understand that reservoir properties wil have an effect in producer wells. But what about injector wells? Will thermal effects travel upstream against the flow of the injector fluid in the reservoir? At least in the early time of a fall off test or injectivity test?
Thanks
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Bhaskar
From a heat transfer point of view the three(3) mechanisms (convection......) are the ones driving the process therefore the change in temperature. The answer is yes they would and once you establish a stable system under injection then the "system" (well, near wellbore, casing, cement...) will have different conditions to those when the well is shut-in.  If you take the changes of stresses as a function of temperature as an example then you can see that Young modulus, Heat transfer coefficient and Poisson's ratio will change resulting in different fracture pressures. Most of these mechanical properties are closely linked to the parameters that you mentioned (skin, permeability...) as the way the heat is transferred from the reservoir to the fluid will changes. I attach a publication that I hope helps with your question
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Hi everyone, am Masters student, I am working on formation evaluation, i have calculated rest of the properties but i don't know the procedure for calculating pay reservoir net pay, i have searched a lot but there was no clear procedure. I also want to learn how to apply cut-off in different situations, like if i have low Vsh then what should i do? and if there are any formula please help me. if anyone want the calculated file i will send to guide me.
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Actually a very comprehensive site to answer your questions and much more is at:
Ross Crain put up the site and is the source I have gone to over the last 20 years or so for many issues in oil and gas.
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Hello,
Is there any way to calculate the remaining oil saturation in depleted area analytically beside the numerical simulation.
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Thanks
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which EOR methods are approprate?
and which reservoire has  similar characteristics?
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A good EOR recipe would take into account the driving forces as well as reservoir characteristics such as wettability. If the reservoir has a good vertical permeability and communication, gravity segregation plays a major role and injecting gas would be a good option. That being said, choice of gas depends on the in situ gas composition as recent studies in the Cantarall field of Mexico suggest the gas composition impacts the Gas-Oil contact movement that you might want to keep track of.
One can also choose a chemical EOR method based on the reservoir wettability and oil characteristics. Depending on the porosity/permeability, surfactants can be chosen as some reservoirs favor production by micro-emulsion formation while others by capillary imbibition (tighter ones).
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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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Reservoir simulation is done without using any optimization methods by trial and error process. please, share with me any information about of it.
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Thank you for yours answer
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I am working on a reservoir simulation project and I am wondering why do we need to provide the data for the capillary pressure to the simulator? 
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Actually, that is not really correct because you argue with a pore scale picture while the reservoir simulation uses Darcy scale concepts.
You need to include capillary pressure into the simulation in all cases where capillary forces are comparable or larger than the viscous forces. That is the case for instance in the a transition zone, because there the saturation is strongly influenced by capillary pressure. In other cases capillary pressure might not be important, i.e. In many waterfloods it may not be needed. If in doubt, include it (as a guess value, using reasonable parameters) in your simulation and see if it makes any difference. But you have to make sure to use the right imbibition or drainage pc.
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Something related with Production, Drilling and Reservoir Engineering.
Thanks
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Hi Rui,
These are the current hot topics
Hydraulic fracturing
Enhanced oil/gas recovery
Smart well engineering
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Can the concept of Equivalent Porous Medium be applied in a Fractured Reservoir in the absence of a reasonable REV?
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We know that - for a geological unit having a significant permeability - with a relatively larger pore throat - permeability is assumed to remain independent of effective pressure.
However, from the discussion; 
" This is because the drawdown is function of the minimum "pore throat" of the fractures " - Does it mean that the fracture permeability is a strong function of effective pressure - where the mean size of the pore throat is relatively smaller?
Then, what happens to the total compressibility; and in turn, hydraulic diffusivity?
Does the diffusivity equation still remain linear (that describes - liquid flow through porous medium)?
Our discussion excludes gas flow through a porous medium (where, the shale gas permeability might vary as a function of effective stress and time).
Thanks for your time and reply.
Suresh Kumar.
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Estimation of Uniaxial Compaction Coefficient of the Reservoir Rock - Is there any simple method to deduce this value - with the limited available data??; 
It can either be based on Hook's law and poro-elasticity; OR reservoir properties.
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This is a fascinating subject, what we know from using Bercovici et al is that considering a two-phase deformation model is; that off course the deformation from any depletion cycle is permanent so we move closer to the critical state line indicating the onset of dilatancy. For shallow and weak reservoirs this transition tends to be very rapid (a few 10th psi maybe) and the loss of metro-physical properties in sandstones might be significant depending on what the original porosity was (Wong T.F. et al 1997). Even if secondary recovery is implemented the deformation has already occurred. The most critical part in our view is whether we reach pore collapse or even grain crushing pressures P*.  I hope it helps, regards
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Estimation of over-burden / pore / effective stress
Estimation of settlement / consolidation
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The classical concept was published by Geertsma:
Geertsma, J., 1973. Land subsidence above compacting oil and gas reservoirs. JPT, Journal of Petroleum Technology 25, 734-744.
If you look for citing papers, there is plenty of models/methods that address subsidence above HC reservoirs.
I hope this is what you were looking for.
Regards, Andreas
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The PVT and phase behavior studies of reservoir fluids are normally conducted regardless of existing residual fluids. For example, a single-phase gas reservoir is considered to be single phase with no thermodynamic interaction between bulk gas and residual oil phases. However, from thermodynamic point of view, any phase that exist in a system must be considered in phase behavior studies.This question is targeting this approach and asks the experts to share their knowledge and experience on this subject.
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In case where pores become very small, like in some unconventionals, then the phase behavior depends explicitly on the size of pores. More generally speaking, when the size of pores becomes comparable to inter and intramolecular interactions and surface forces, then interaction between rock and fluids can have a large influence on the phase behavior. For instance freezing/melting point of fluids can be very different in nano-pores. A respective method to determine pore size distributions in this way is termed thermoporometry. But for that effect, we talk typically of pore sizes smaller than 1 micrometer or more 100 nm or so.
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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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I have come across studies attempting to predict future dam water levels (in Nigeria and Pakistan), using different approaches (artificial neural networks, SWAT model). I am interested in developing a tool that would use readily-available climatic data (mainly precipitation, evaporation and temperature) to conduct analysis of variance and ultimately predict water levels for a given reservoir/catchment.
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There are many regression algorithms that can be used in your case such as multiple linear regression, generalized linear modeling, generalized additive modeling, etc.
You can implement these methods easily in R. through stats, glm, gam packages.
The most accurate algorithm is generalized additive modeling that leads to more accurate prediction than other methods.
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dear searchers hello,
I am trying to predict flow zone indicator (FZI) using log data, but still no representative ANFIS model, can any one help me please to finish this exercise ....my questions are which ANFIS should I use (Anfis 1 or Anfis 2), even when I get results with good R2 in traindata calculation it will be very bad for checking and testing data ????!!!!! 
the selecting of MF ...how can I select the best MF and the optimum number of MF.
thanks in advance.
Regards
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Faycal,
first, clarify the following:
what do you mean by ANFIS1 and ANFIS2
Do you use any commercial code/toolbox for fuzzy modeling?
What have you implemented so far?
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SSSV is installed 100 FT deep in a production tubing 3-1/2" 13%CR NVAM
Pressure buildup at well head (WHP) is 50 PSI/MIN
Initial WHP=zero
Reservoir pressure is 6500 PSI
Reservoir depth 14,000 FT
Formation fluid is Gas & Condensate
Gas Liquid Ratio (GLR) = 10000 SCF/BBL
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See this standard : Design, Installation, Repair and Operation of Subsurface Safety Valve Systems. ANSI/API RECOMMENDED PRACTICE 14B
FIFTH EDITION, OCTOBER 2005
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and what is the difference with mercury capillary pressure?
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Dear Barham,
As stated by Ashkan, the air-brine Pc can be measured in the lab using either the centrifuge or the porous plate technique. In principle MICP and air-brine can be compared by converting the MICP to air-brine using the ration of the IFT between the different fluid pairs. For more details I am attaching two of my earlier publications. I hope that helps you. In both papers I only partly talk about the Pc measurements.
Best Regards
Shehadeh 
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When I calculate the average water residence time in reservoir according to this relationship Tr= reservoir volume/annual discharge, is what I consider the dam is full to 100%, in this case I consider the total capacity storage, or just 67% of this end  according to the study vorosmarty et al 2003. 
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I am not familiar with the study you mentioned.  You will never know exactly the residence time of a single molecule.  Some water is apt to circulate faster than others.  But in general the ideas above give you basic approaches that should work, but there are more complex that could come up for specific problem analyses.  If it was important to tie this down closer, or address more holistically, check to see if there were any topographic maps available before the dam was put in.  Of course if there have been major sediment influx or dredging, this might not work.  Get your GIS skills or a friend to develop a Digital Elevation Model from the original topographic data.  Then as suggested, there is variance in water inputs dependent on rain and waters flowing in, evaporation losses, leakage or deep seepage, irrigation or other withdrawals, etc.  But with the GIS and the reservoir data, you probably can identify the conservation pool elevation that they like to maintain (probably impossible in droughts) and the full pool that they do not want to exceed due to flooding of residents, flow over dam, etc.  Both the lake area and mean depth will change with weter level, so you must select at least one as your basic assumption.  But you can also consider flow inputs in a wet year, dry year, average year and then use the low,, high and mean pool depths over dry years, wet years and average years, respectively.  So you can make this really complex if you for some reason wanted to address varied circumstances.  Anyway, the GIS original surface will identify the bottom (or defined by the bathymetry studies) and then you select one or more elevations you want to use for lake surface.  GIS can probably give you mean depths fairly easily if you prefer that based on any water surface elevation of the lake.  The volume of the inflow (stream discharge) in acre feet per year is divided by the capacity assumption of the lake in acre feet, and the result will be years time.  You adjust to similar international units.  So if your reservoir has a mean management pool of 10,000 acre feet of water, and the mean inflow is 1000 acre feet over a normal year, with those assumptions the mean residence time must be 10 years.  But we all know that reservoirs are not uniformly mixed, and under certain conditions due to water temperatures  and where the water releases come from (top, bottom, in-between, some waters are going to circulate faster than others.  There could be wind, lake turnover and other mixing considerations. 
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Fast sonic travel time correlates with more brittle, slow travel time is less brittle.
This is a crude method, but I lack a better one. Any suggestions for a better method, and a good definition of brittleness?
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Actually approach on neutron-density curves works very well for a qualitative answer.
Depends what you need it for and if you have some actual core derived measurements over logged interval to calibrate with.
I'll see if I can send you some papers.
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Can you help me to get information about drilling techniques and reservoir engineering  for EGS?
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You could also try this report which may help you, particularly Appendix C Section C2 which focuses on those drilling technologies that have been shown to deliver better performances than standard conventional drilling methods.
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some one have an idea about the Fully coupled multiblock wells in oil simulation?
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Thanks for your answer 
can you send me your e-mail to this adresse for more details 
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Skin Factor is usually defined to account for additional pressure drop due to damage or stimulation around the wellbore in an oil / gas formation. The positive skin may be caused by such phenomena as mud and cement infiltration, wax/asphaltene deposition, connate water vaporization, etc. On the other side, such processes as acidizing, solvent injection, hydraulic fracturing may cause negative skin. In my question, I am looking for maximum allowable skin values for each of the above causes.
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This discussion might help.  
Does the case include turbulent flow? (non-Darcy skin factor?). Non-Darcy skin? what flow rates and D are you talking about? 
If he/she is including that, then the number can go high more than normal skin factors due to damage. Also, what are the other conditions: partial penetration, two phase flow ... etc
Here are other good links:
Good luck. 
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In oil well drilling, the quality of cement bonding (CBQ)
between well casing and formation rock, is very important because good CBQ ensures the success of oil and gas exploitation from a reservoir.
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Thank you Dear Mr. Sallam,
I have see this website it's interesting, but for this articles must be purchased, and I have not a credit card.
Best regards
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I would like to know the necessary parameter for SSARR watershed and channel routing model for flood forecasting, please help me, thank you for your time.
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Capillary Pressure, Pc, has a crucial role in flow of immiscible fluids through porous media. This term runs as a key factor in hydrocarbon production from reservoirs. My question is to see if Pc can change during oil/gas production from reservoir. That is, shall we consider a dynamic, i.e. time changing Pc in reservoirs due to pressure decline, PVT change, and other consequences of oil production?
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Reza,
As a common practice, for immiscible systems (say WO), the change in capillary pressure for a given rock type is only a function of saturation. This is already accounted for in all simulators by providing a table of Pc as a function of Sw. Another way is to provide an analytical correlation such as Brooks-Corey model.
For miscible systems (say OG), in addition to saturation, the change in Pc is also a function of PVT because sigma (Interfacial tension IFT) may vary. Most simulators can also account for this change using an EOS to calculate sigma from hydrocarbon-phase densities and components composition and Parachor.
Hope this helps
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Does performing perfect history matching in reservoir simulation model reflect the accuracy of the geostatistical model that was built the reservoir model?
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My opinion is No. I agree with Ann. And the same conclusion is true for every model.
If you are testing some feature of a model (let's say production), accuracy in the prediction of that feature does not guarantee accuracy in all it's other features.
Probably the best method for you to test your geostatistical reservoir model (seismic inversion, Acoustic Impedance, Elastic Impedance, Porosity, Lithologies and so on...) is to test it against blind data (because that data is real).
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The simulators I know are either not maintained, at a very early stage of development, or written in old programming languages, namely:
* BOAST, UTCHEM, etc. written in Fortran 77 -- http://www.netl.doe.gov/technologies/oil-gas/software/simulat.html
* DuMuX written on top of a C++ library -- http://www.dumux.org/
If you know any alternative, please share.
--------------------------------------------------------
UPDATE:
* MRST is a MATLAB® toolbox that is part of the OPM initiative -- http://www.sintef.no/MRST
* OPM is also a C++ library -- http://www.opm-project.org
* PFLOTRAN is a Fortran 2003 library -- http://www.pflotran.org
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PFLOTRAN (www.pflotran.org) is actively maintained and supported, written in modern Fortran 2003, has an extensive set of capabilities, and runs on machines ranging from laptops to the largest-scale supercomputers.
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It was found in a siliceous monomictic reservoir. Size of the algae: 3,38µm and it has some warts or protuberances...
some idea about de genus?????
stratify reservoir
secchi disk: 4.75m
Temperature: 26.50
pH: 8.69
alcalinity: 88.70
Thaks in advance for your help
Maria 
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Thanks to Ana Negro who find the solution:  spores of fungus!!!!
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A specific methodology or the apparatus requirement for that?
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For published work would suggest to search  SPE a nd other sources for papers from  K.E. Newsham or J.A. Rushing.
We are currently working in an atlas of TGS. for more info see our website:
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Anyone aware of the best way to incorporate thin beds in static and dynamic simulations.
Two methods are: fine scale modelling and pseudo relative permeability curves. However both of them result in increase in run time. Any ideas about the topic? 
Thanks in advance, 
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I would suggest Discrete Wave Number method, is quite fast with very low computational cost, the implementation is feasible as well.
Another method i might suggest is Cellular automata, it is a very interesting method however i have not worked with it.
Good luck  
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The gas condensate fluids are light products and thought to be free of components which may cause solid formation in reservoir, well bore and storage tanks. However, there is evidences of sludge formation in condensate storage tanks in refineries and transfer ports. I am looking for papers and other documents which address worldwide evidence of wax formation in gas condensate systems, compositions that lead to wax formation, consequences of wax and sludge formation, prevention techniques,  etc.
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Dear Reza I am sure a lot of stuff you can find on SPE image library  or with the help of Google.  I mentioned u in general, still if u have a specific paper just send me the title, I will try to send u back the complete paper.
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For every industry, there are some important Key Performance Indicators, called KPIs, which can be considered as criteria for process efficiency, perfiamcnce and efficacy.
My question refers to identification of most relevant KPIs in gas processing industry, mainly those that point to production, sweetening, energy consumption,  operation, etc. If any one has an experience on this subject to share with me, or has any document (paper, report, book, powerpoint, etc.), I'd appreciate to receive them.
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Fuel index, specific energy consumption(sec), availability, reliability, chemical consumption index, flare index, waste water disposal, so2 emission, ..... Are the most important index in the south pars gas company. I will send you all other index.
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What I have found so far and what I usually do is defining the optimum gridblock size in a reservoir model by running multiple cases with fine and then coarser gridblock sizes then find a compromise between simulation accuracy and run time. 
I am not sure if there is a method to pre-define the optimum gridblock size that does not result in large reduction of accuracy without the need of making multiple runs (maybe based on governing equations of reservoir simulation). I am more interested in areal since vertical is governed by heterogeneity mostly. The issue raises again when trying to use paeudo relative permeability to reduce  number of gridblocks. Here, I am not trying to eliminate a geological aspect and I am aware simulation is governed by geological aspects and data, but for the same homogenous model, the more gridblocks (the finer the model), the slower the fluid front is simulated. Example, injecting water in one gridblock that is two gridblocks away from producer will result in faster breakthrough than the model has 20 gridblocks between producer and injector. One method used is the pseudo modelling, however that is also time consuming (closed loop).
Please let me know if you are aware of such a method/fast guess. Many thanks in advance. 
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Khaldoon, you are overlooking the recovery mechanism in your overview of the cell size rules of thumb issue. A number of the rules of thumb  relate to mechanism (e.g. thermal reservoir simulation require cell size of around 1 meter along main flow path direction, gas can accomodate large cells except for condensate banking representation, etc). I unfortunately cannot post TOTAL proprietary documentation relative to the matter but be assured they exist. 
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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.