#  > Petroleum Industry Zone >  > Reservoir >  >  >  Question to simulation engineers!

## Alamen Gandela

I am working in field with huge lateral extent. there are no separation faults to make compartments nor geological bodies to separate and compartmentalize the field.



however,one thing I notices is the change in PVT properties mainly viscosity is drastic !

ranges from just 1 cp in the west to 20 cp on the east.and the other PVT are almost identical.

so,can I consider the field as one PVT region or should I make subdivisions based only on one PVT property?

waiting for your contributionsSee More: Question to simulation engineers!

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## vergatario

One way:
you may divide your model in 4 or 5 pvt regions, according to API variation. then you need to define a pvt table for each region. The only problem is when the fluid migates from one region to other it wil change its properties automatically.

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## 06pg22

Use more than 1 region  and accordingly pvt tables for each region. Now it depends on you how many regions you define for a reservoir

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## vinomarky

Suggest that you first try to understand the physical significance of your observations.... what's causing the properties to vary so much in an ostensibly homogeneous system? Perhaps it is not as homogeneous as you think? Could it be related to change of depth/temp over that areal extent?

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## Alamen Gandela

Thank you all for your valuable comments.

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## perezo

please how do i solve this problem?


 @           LINEAR EQUATIONS NOT FULLY CONVERGED - RUN MAY GO FASTER        
 @           IF YOU INCREASE LITMAX (= 25 - TUNING KEYWORD)                  

 @--PROBLEM  AT TIME     1657.8   DAYS    (15-JLY-2004):
 @           NON-LINEAR EQUATION CONVERGENCE FAILURE                         
 @           ITERATION LIMIT REACHED - TIME STEP CHOPPED FROM  23.41

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## totor

ahem... try to increase Newton iterations number or something like that in the numerical parameters of your simulator (have a look at the "numerics" section in the user's guide of your reservoir simulator); and/or decrease the time step (keep it constant and very very small); and/or relax the material balance criteria

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## Alamen Gandela

Mr perezo

I suggest you workout the problem of IMPES.vs.Fully implicit  in workshop data sets in Applied reservoir simulation seminar by Schlumberger

cheers

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## Alamen Gandela

> One way:
> you may divide your model in 4 or 5 pvt regions, according to API variation. then you need to define a pvt table for each region. The only problem is when the fluid migates from one region to other it wil change its properties automatically.



the API is identical for the whole reservoir the variation is just on viscosity !

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## Alamen Gandela

> Use more than 1 region  and accordingly pvt tables for each region. Now it depends on you how many regions you define for a reservoir



  the problem is that : the reservoir is shared by more than one company,and the objective of the simulation is to prove the communication and calculate the oil migrated.in history match phase the field was proved to have been in communication with two PVT regions .And now  i use single PVT region there is more oil migration and better history match,but the other companies still arguing of using more  PVT regions! what should I do?

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## Alamen Gandela

> Suggest that you first try to understand the physical significance of your observations.... what's causing the properties to vary so much in an ostensibly homogeneous system? Perhaps it is not as homogeneous as you think? Could it be related to change of depth/temp over that areal extent?



you are right to some extent!

in the measurements there are some sort of scatter variations, but as general observation (average values) there are one region with viscosity around 10 cp and another one with viscosity around 20 and the WOC difference between theses regions is about 90 ft.  
One interesting point I noticed is that the region of 20 cp is the only part of the model which doesn't have aquifer support!

waiting for your comments

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## vergatario

A good tool to prove comunication is to use geochemist analysis. You have take samples of fluids in several points (for instance one ell of your company and other sample in a well of ther company). They generate a kind of diagram for each of the samples and later it can be said if the oil is the same. you can propose that.

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## elamin

Dear Mr perezo
if U r using Petrel RE 
1\ remove all permeability and porosity from the define simulation and put eg 1000 for permx and permY and 100 for permz
2\try to change the function parameters and run the simulation 
at the end you can discover the problem from the grid or from the data entry



thanksSee More: Question to simulation engineers!

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## perezo

thanks elamin.. 

actually i am using eclipse and in the model Ky and Kx are 1000md and Kz 100md..but my problem with the model now is, i am trying to match it the actual reservoir data and i dont want to use Simopt (because i dont know how to ). this are the data i am trying to match

 reservoir data          built model
6.1mmmstbo            10mmstbo
33bcf                      420bcf

i dont know if i had to made some adjustment in the SCAL or PVT?

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## vinomarky

One zone has water support, other does not
One zone has double the oil viscosity of the other

To me it points to compartmentalized reservoirs. You may not be able to 'see' the faults (or strat traps) on seismic, but if pressure does not communicate (water support/no water support) and oil properties are different then you have to assume some compartmentalization is there. If you simply go ahead and initialize your model with different fluid regions, but leave them otherwise connected, then from the sounds of it your model will not describe the physical observations

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## acang_024

u can look at pressure data, make datum pressure each wells at certain same time record, if it has large differences, it has different compartment

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## acang_024

is there any rule of constrain i have to consider if i wanna forecast my model (for gas and oil)?

please need your favor

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## ahmedm

I think you have major fault divid your reservoir into two regions (compartments)
different pressure regions so you need to discuss that with your geologist

so then you sign the pressure for each area and sign the fault as sealed
so even you have same pvt but different pressure, you will have different viscosity for each area


hope this helps
good luck

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## gustavohd

Try to change your initial guess you must be at a saddle point...

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## temr

My advise,
Before making any considerable changing to you model 
Check input data to abbey main rule of reservoir engineer
Garbage in - garbage out 
As usual the most questionable data from the field is PVT data

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## vinomarky

There is the degree of confidence (level of uncertainty) you have in any aspect of your data, and there is also the impact of that uncertainty

In my experienced, the two top ticket issues in terms of their impact on your model outcomes are;
1. GRV -> Structure
2. Geology and property distribution

In terms of data from the field, if you are doing history matching, often production data (at least to a well level) introduces significant uncertainty  - In these cases I often use GCONPROD at the field level set to known field offtakes, and then set WCONPROD's for each well with +20% allowed (or whatever uncertainty is appropriate) instead of more usual WCONHIST. This way total withdrawals are honoured, while not driving you to point geological/well PI changes that may not make sense in the framework of uncertain well allocations.

For me, PVT data uncertainty is usually second order in terms of the impact on the results - there are exceptions

Agree totally on the GIGO principle

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## temr

Vinomarky, keep in mind that the models or are basically  made for recovery factor ,
In this particular case when the topic starter wanted to divide dynamically connected reservoir in two parts with different PVT he will face the problem during runs
My point was that PVT itself is the key data which will effect not only history matching but forecast section, like you can make history matching but in 10 years your run will stop due to negative Co or Cg encounter during the massive injection
So for me main rule is - if want to smooth runs of you sim models - make dip approach in choosing  pvt first
Reagrds

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## dipak_m

Dear Temr,
Please elaborate the correct  approach to choose correct PVT data.

Thanks

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## temr

Dipak all is here ............ in the forum 
Problem encounter when the well start produce / inject on the pressure values which are out of the one you describe in PVT table, in this case Eclipse starts to make extrapolation 
attached is compressibility check file for PVT 
But the extrapolation Eclipse uses are not linear which i am used but harmonic so i working now to fix it 
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## dquento

Hi all,


What important simulation aspects  are to be considered when modeling an oil-gas system with gas lift wells, especially as the model will be used for prediction. It is my first time to handle such a case and wish to solicit the help of those with some experience with such field cases. Thanks for helping.See More: Question to simulation engineers!

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## acang024

dear all

i have to forecast new field, and no well before, what should i do to make a reservoir model, what constraint i have to use. because the forecast could be so high or even low rate.

thanks 
acang

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## elamin

Dear all
For constrain or Predication economical limit put
1-Limit BHFP
2-Maximum Water Cut
3-Minimum Oil Production Rate
4-Prediction time

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## acang024

my field is new, i can't predict what the dominant drive mechanism on my reservoir. Could i make a aquifer in my model? because it can maintenance reservoir pressure, so i can get high cumulative production. but, of course that way could gets wrong forecast. So, my question is, what should i do if i want to make a forecast in a new field.

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## karakurt2

Hello,

I would like to know if there is facility to define multi-stage compressor in Eclipse extended network model.
For now we used to describe all compressor units in one VFPPROD table in conjunction with NETCOMPA keyword.
The following keywords used to define interaction with compressors in my model:

VFPPROD 
WCONPROD
NETCOMPA
NWATREM
WTEST
WEFAC
WORKTHP
WORKLIM
PRORDER
WELDRAW
WELOPEN
WECON
NETBALAN
GCONPROD

If you need more information, I will excerpt keyword data from Eclipse input file. I omit these info in sake of clarity.

I define dtwo delivery points in the network named UKPG and UPPG. First I put all wells in THP control mode
and then define monthly production rates for this points. Also we have two compressor units just before delivery points.
There compressors defined in two VFPPROD tables.

In real world there is two stage compression for flow before it get to gas-main pipeline. The delivery scheme schematically presented in the following drawing:


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Can I define these compression rig in network model? It would be interesting to see how cumulative power changes in 
different time steps, how compression units switched on or off, what mode of operation will be necessary to get
fixed pressure in final node. It will be wonderful if Eclipse could balance compression ration between stages so
that power spent on each stage will be equal.

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## boomtata

hi all,

i am a postgraduate student and I ll use eclipse from my thesis. I am trying to understand the basics. So I copied data file from petrofaq website **[link Point to another website Only the registered members can access]
*link*




<![CDATA[[Only Registered And Activated Users Can See Links] in a notepad and i saved the notepad as eg. example.data. However when I try to run eclipse with these data it gives me an error invalid file name. Also if i paste the code at 

Advanced -> Enable -> Edit Command Line 

it says no data selected. What am i doing wrong?

The way I am trying to import the data is

Simulation launcher -> Simulators -> Eclipse -> Summary -> Select -> Add dataset
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> RUNSPEC
> -- Title is used as header on output, to identify run
> TITLE
> Example Simulation
> -- Specify dimension of model, NX, NY, NZ
> DIMENS
> -- NX NY NZ
> 10 10 3 /
> -- Phases included (oil and water, i.e. 2-phase run)
> ...



EDIT -> Problem FiXED

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## jahsan99

HI , Can any one suggest development strategy for maximum recovery and wells model in petrel and simulator is eclispe100 - I dont know how and which parameters to fill in the prediction/depletion and water injection prediction rules. Here is the link to the model i am working, I have basic idea of how petrel works since I am very new to petrel and eclipse (gives me convergence problem), any help will be appreciated.
Here is the link to the model: **[link Point to another website Only the registered members can access]
*link*




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