production profile- reservoir model and well decline profile in excel.

Hi Guys,

I am an economist by profession and trying to come up with an integrated cash flow model to evaluate field opportunities at broad brush level.

Is there a basic excel model of well decline profile and reservoir based on user defined characteristics I can learn from? Something someone might have done in their student days? :rolleyes:

It is primarily for gas-condensate reservoirs. Otherwise, can anyone direct me towards any information that will help me model it. Bear in mind I am an economist, so a very very basic model will suffice.

Appreciate it.:o:)

Unfortunately this is more than meets the eye, particularly if the Gas Condensate reservoir is a retrograde reservoir and you are looking to model condensate production in the retrograde (liquid drop out) region. Well decline is a function of many parameters however is mainly influenced by: (1) reservoir drive mechanism, (2) relative permeability effects, (3) reservoir permeability, (4) well spacing and (5) well timing etc...

You get the drift here, it is unfortunately not straight forward particularly in the case of gas condensate reservoirs, however what you can do is look to a similar fields known as "analogues" that have similar reservoir and geological properties, see what the historical well declines are there and use those declines in your cashflow model. Importantly this gives you a "defensible" answer as to why you selected the well declines etc... you did.

Know this is probably not the answer you are looking for, but condensate reservoirs particularly retrograde condensate reservoirs are tricky.

[QUOTE=Chee Koh Peh;114387]Unfortunately this is more than meets the eye, particularly if the Gas Condensate reservoir is a retrograde reservoir and you are looking to model condensate production in the retrograde (liquid drop out) region. Well decline is a function of many parameters however is mainly influenced by: (1) reservoir drive mechanism, (2) relative permeability effects, (3) reservoir permeability, (4) well spacing and (5) well timing etc...

You get the drift here, it is unfortunately not straight forward particularly in the case of gas condensate reservoirs, however what you can do is look to a similar fields known as "analogues" that have similar reservoir and geological properties, see what the historical well declines are there and use those declines in your cashflow model. Importantly this gives you a "defensible" answer as to why you selected the well declines etc... you did.

Know this is probably not the answer you are looking for, but condensate reservoirs particularly retrograde condensate reservoirs are tricky.[/QUOTE]


Hi Thanks for the reply. Would it make it easier if it was just a gas reservoir.? It is primarily a gas reservoirs I am looking at with some associated condensate production. I have just downloaded the reservoir engineering handbook and using the volumetric method for gas reservoirs. There seems to be a lot of variables to calculate Gas in Place. I am wondering if some of these can be taken as constant based on analogues?

How do RE colleages do it if they have no prior information about a reservoir and only geological information.

Thanks again for your help.
Adi.

Hi. send me your email and I will send something that may help you :-)

[QUOTE=Shakespear;114420]Hi. send me your email and I will send something that may help you :-)[/QUOTE]

Hi

my email id. is
[email]adi.mukherjee@gmail.com[/email]

Many Thanks for your help .:)

Nothing shrink wrapped - I generally make them as needed. Often assume the following;

Rate [I]potential [/I]declines exponentially - that is, Rate Potential = Max Potential x (1-(Cum Produced/EUR))
You would cap this rate at maximum of plateau rate

For economic screening this is often a surprisingly good approximation, as any aquifer effects in gas reservoirs are usually late time, and with discounted cash flow are generally second order in terms of their effect on NPV

With gas condensate, you often drop some liquids out in reservoir during depletion, meaning you have leaner gas later in life. In absence of anything else, assume straight line from initial CGR to 0.25 x Initial CGR with similar equation

So, you enter 4 variables;
EUR
Max rate potential
Plateau rate
Initial CGR

Then simply calc 6 columns with each time step;
Rate potential, Truncated Rate, Gas vol produced, Cond Vol Produced, Cum Gas Produced, cum Cond produced
Repeat
Repeat

[QUOTE=dumdum01;114373]Hi Guys,

I am an economist by profession and trying to come up with an integrated cash flow model to evaluate field opportunities at broad brush level.

Is there a basic excel model of well decline profile and reservoir based on user defined characteristics I can learn from? Something someone might have done in their student days? :rolleyes:

It is primarily for gas-condensate reservoirs. Otherwise, can anyone direct me towards any information that will help me model it. Bear in mind I am an economist, so a very very basic model will suffice.

Appreciate it.:o:)[/QUOTE]

Ello.
I am an economist too by background so be proud of it )))
As for you task if you want to make simple prediction production profile to get revenue it depends on what stage you asset are
1. beginning
2. Plato
3. Decline

1. Exploration and wild cat drilling - production start - this one is most difficult to predict the only or i would say best way is to build material balance + well productivity
2. Plato - stable production again build material balance
3. Decline - time when you production decline due to several reasons like pressure down or water cut - the easy part the only thing you do - plot your production and make decline trend in excel
But i will advise you to build material balance model or tank model for your field as it is not difficult to do - but in this case your results will be firm and solid
in this case all you need to do is to make tank model
here is link for mbal [url]http://www.4shared.com/file/Bg-ErMcF/Material_Balance.html[/url] spreadsheet and docs
and calculate well productivities [url]http://www.4shared.com/document/NWTdhYRC/Shape_factor.html[/url]
If you know how to solve irr you can solve the pressure problem )))

All good answers.

From an econs perspective, your key factors are (1) Individual well deliverability (number of wells required to initially meet DCQ requirements), (2) Reservoir homogeneity and permeability thickness kh (number of wells required to drain the reservoir to abandonment pressure / or approximate recovery by well). (3) Well Cost (Drilling Capex) and (4) Timing of new wells (required to keep the total field rate at the DCQ).

I am assuming here of course you have DCQ contract which specifies a fixed plateau rate and duration to meet a specific gas sales contract, if not best to assume one before you start as that will be the base for the number and timing of wells required. For a volumetric gas reservoir you can initially assume field plateau rate is between 5-10% of the reservoir EUR / per year.

To answer your question, if you only know the geological properties, and do have not reservoir properties i.e. you have not drilled therefore you have not tested, you can only estimate well rate (deliverability) using an analogue field.

So you can do this two possible way as mentioned in the thread:

1. You can do this on a well by well basis if you can estimate the individual well rate and estimated ultimate recovery (EUR) per well, and assuming volumetric depletion your well decline is exponential, then the only thing you need to play around with is timing of additional wells to ensure the fields overall production continues to meets the DCQ, as existing wells are declining - Reasonably quick, but more assumptions required.

2. Or if you have well data i.e. well deliverability, you can construct a well inflow model (IPR), and when tie this into a gas material balance for the reservoir - More complicated but technically robust and defensible.

At the end of the day the number of wells you are required to drill and their timing will largely determine your NPV, IRR etc...

This is why determining well deliverability or estimating this with confidence, is essential if your Econs are going to tell the truth!

CKP

[QUOTE=Shakespear;114420]Hi. send me your email and I will send something that may help you :-)[/QUOTE]

I don't see any help that comes hidden, better share your knowledge with all people instead of sharing it through private emails, it's my point of view, anyone else can have its own, hence if you are afraid of disclosure and confidentialities issues, clear well names, company names and yours obviously!!

[QUOTE=kader_007;115636]I don't see any help that comes hidden, better share your knowledge with all people instead of sharing it through private emails, it's my point of view, anyone else can have its own, hence if you are afraid of disclosure and confidentialities issues, clear well names, company names and yours obviously!![/QUOTE]

Kader,don be impolite to people who already made big efforts to the sake of this forum.
And have some respect to the person who is in the age.

[url]http://www.4shared.com/account/dir/jYkqWjMB/sharing.html?rnd=40[/url]

Enjoy

Hi Guys,

Thanks for your help so far.

I have now worked out:-
1. GIIP based on Trapezoidal/Pyramidal method (given Net to Gross Ratio, Avg Rock Porosity, Avg Oil Saturation, Avg Gas Saturation, Oil Form Factor and Gas Expansion Factor)
2. Recovery Factor and hence EUR using the volumetric method (Based on Area of Reservoir, porosity, water saturation, temperature and pressure) - using the volumetric method (Pg 856 Reservoir Engineering Handbook.)

At this stage I have a couple of questions:-
1. How can I calculate the CGR. Is this to do with gas viscosity? If so, can someone guide me through the steps and additional data required to calculate this.
2. I have assumed a wellhead pressure to come up with the recovery factor using the volumetric method. If one doesn't have this information, what is best to assume? i.e. one that maximises recovery.
3. Well decline profiles. How do I calculate the production profiles for GAS given the EUR and initial and abandonment pressure (wellhead pressure). This would include calculating the number of wells required to drain the reservoir optimally, and so I am guessing the starting point would be well deliverability?
One method is mentioned earlier here:-
Rate Potential = Max Potential x (1-(Cum Produced/EUR))

However it doesn't take into account calculating the number of wells required to produce or the deliverability of individual wells?

Please advise.

Many Thanks.