#  > Petroleum Industry Zone >  > Reservoir >  >  >  production profile- reservoir model and well decline profile in excel.

## dumdum01

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?  :Roll Eyes (Sarcastic): 

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. :Embarrassment:  :Smile: See More: production profile- reservoir model and well decline profile in excel.

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## Chee Koh Peh

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.

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## dumdum01

> 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.




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.

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## Shakespear

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

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## dumdum01

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



Hi

my email id. is
adi.mukherjee@gmail.com

Many Thanks for your help . :Smile:

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## vinomarky

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

Rate _potential_ 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

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## temr

> 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? 
> 
> 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.



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 **[link Point to another website Only the registered members can access]
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and calculate well productivities **[link Point to another website Only the registered members can access]
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If you know how to solve irr you can solve the pressure problem )))

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## Chee Koh Peh

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

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## kader_007

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



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!!

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## temr

> 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!!



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.

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## Shakespear

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Enjoy

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## dumdum01

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.

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## vinomarky

1. This is related to the richness of the gas in heavy ends - its not something you can calculate from properties such as viscosity (although I'm sure there is some relationship). You really need to have some understanding on how rich or lean the gas is likely to be


2. Using wellhead abandonment pressure, and correcting back to the sandface pressure taking into account friction and head is an appropriate way of dealing with this
3. If you need to be able to incorporate number of wells required and timing etc, then you need to step up the complexity of your model. The number of wells required is related to not only individual well deliverabilities, but also structure size and continuity. The simple rate potential equation is suitable if you are modeling the field as a tank with one (set of) offtake(s).

General (simple) equation for well deliverability is rate = C(Pr^2 - Pwf^2)^n. You'll have to find your own values of C and n depending upon your reservoirSee More: production profile- reservoir model and well decline profile in excel.

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## Shakespear

dumdum

CGR can be obtained from production history (good luck on this one), analog field/reservoir in your area or a PVT study.

Can you tells us more about what your are doing and for what purpose? This may help us to perhaps give you better council :-)

"evaluate field opportunities" to do .......  ????

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## dumdum01

Hi Guys,

The idea is to be able to see a new acquisition or merger opportunity and be able to act quick. I am trying to base it on the general kind of information that will be available for such opportunities initially. 

like seismic (interpreted)?
maybe a GIIP value?
sometimes a EUR.? 

I want to be able to take this information and do a quick and dirty valuation. (This is just to understand potentially if an opportunity exists till the geo, PE and cost engineers can analyse data and come up with a development scenario.) 

It also helps me understand whats going on in project meetings and not look completely dumb)))

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Here is a quick cut of what I have done till now. ( I have marked questions in red.) ... maybe this will give a good idea??

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## dumdum01

Also, 

If there is an opportunity that has an exploration well already drilled in (or maybe even appraisal wells drilled in)... then... should I use the material balance method? 

It seems very complex to model.....?? or does the volumetric method suffice?...

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## Shakespear

> Hi Guys,
> 
> The idea is to be able to see a new acquisition or merger opportunity and be able to act quick. I am trying to base it on the general kind of information that will be available for such opportunities initially. 
> 
> like seismic (interpreted)?
> maybe a GIIP value?
> sometimes a EUR.? 
> 
> I want to be able to take this information and do a quick and dirty valuation. (This is just to understand potentially if an opportunity exists till the geo, PE and cost engineers can analyse data and come up with a development scenario.) 
> ...



OK dumdum, from the above I suspect that you are very new to this. Don't take this negatively but just an assessment of what you have said above.

If I was doing a "quick" evaluation than it might look like this in terms of the information I have.

1) I have little, then I need 
      - a map of estimated reservoir extent
      - estimate of Oil/Gas in place
      - estimated recovery coefficient (conservative estimate) for the field

From this I can get an idea of how much I will produce from this field. If you want cash flow then you will have a problem as you have no well production data to even get an idea of how a well will produce in this field. So now you will need to do "magic", guess based on near-by fields or doing simple math (drainage radius expected, number of wells that would fit in your map of the field, some decline rate ) of what you think wells will be producing like here.

2) I have info in 1) plus logs and three wells producing.

Now you can get a "type well" for the field. Perhaps do a kh map and tie that to the kh of the producing wells. Using drainage radius, estimate where you will drill additional wells, estimate there the kh, and scale production expected from these well to be drilled to those that are already producing.

3) I have 1) plus 20 wells.

Now you will do what you did in 2) but you will need to look closer at the producing wells to see "what they were doing", well histories. Why did they producing the way they did? Why the down times? What workovers were done? What problems did they have? What is in the well that they lost, because in the details you may find that the wells is down due to junk in the hole, casing collapse, tubing lost in the hole, or corrosion problems...... DETAILS that are important to understand what this field is all about !!!!!! This means READING and understanding intervention reports on wells which are written in "insider" language. Without this you may run into HUGE PROBLEMS !!!!!!

This is needed to see what remaining production you can expect of exiting producers in the future,if something is left to produce from shut-in wells, if workovers will bring production online for wells shut in, if unperfed zones exist that could bring in additional production ....


Material Balance - you need pressure data, but if it exists this is never plug and play. Questions that come up are, when were they taken, how were they taken, with what were they taken, where were they taken .....? 

Once you are clear on pressure, you move on to average reservoir properties and PVT properties. More thinking and probable sensitivity studies to see how things change with the input uncertainty. MB is looking at the reservoir as though it was a huge barrel, one porosity, thickness etc.

Doing MB will require more work and requires more data to be good. With two wells MB won't be any better than doing 1) or 2).

Perhaps others can chip in here to suggests other ideas.

But from my perspective "understand potentially if an opportunity exists" requires logs, map of reservoir extent, some wells producing

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## vinomarky

Agree - I think the Bard has outlined a good summary.

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## dumdum01

> OK dumdum, from the above I suspect that you are very new to this. Don't take this negatively but just an assessment of what you have said above.
> 
> If I was doing a "quick" evaluation than it might look like this in terms of the information I have.
> 
> 1) I have little, then I need 
>       - a map of estimated reservoir extent
>       - estimate of Oil/Gas in place
>       - estimated recovery coefficient (conservative estimate) for the field
> 
> ...



Hi Shakespeare,

I suspect this is very much based on the 1st scenario you have. From the above analysis you have kindly provided, it seems the second and the third scenario is both out of my reach and time limit for this project.

I would like to know how to create this "magic". If I do know ( the reservoir area, the estimated Oil/Gas in place and finally the recovery coefficient), how can I then figure out a production profile for the field. In a way, is there a way to "optimise" this to say 1. get the most recovery, 2. highest plateau rate etc. (Be able to play around with the number of wells required?) 

Many Thanks,

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## dumdum01

> 1. This is related to the richness of the gas in heavy ends - its not something you can calculate from properties such as viscosity (although I'm sure there is some relationship). You really need to have some understanding on how rich or lean the gas is likely to be
> 2. Using wellhead abandonment pressure, and correcting back to the sandface pressure taking into account friction and head is an appropriate way of dealing with this
> 3. If you need to be able to incorporate number of wells required and timing etc, then you need to step up the complexity of your model. The number of wells required is related to not only individual well deliverabilities, but also structure size and continuity. The simple rate potential equation is suitable if you are modeling the field as a tank with one (set of) offtake(s).
> 
> General (simple) equation for well deliverability is rate = C(Pr^2 - Pwf^2)^n. You'll have to find your own values of C and n depending upon your reservoir



Hi Vinomarky. Thank you for the above, could you please elaborate what each of the symbols (C, Pr, Pwf, n) mean in this instance. As you have already guessed, I am very new to this. Some elaboration will be kindly appreciated.

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## Shakespear

By "magic" I meant your experience. You have little data but you need to say more than the data allows. Hence you, with your 15-20 yr. experience act like the almighty magician. To do this you need GOOD arguments regarding why you  assumed what you assumed.   :Wink: 

In your case you will have to wait for this phase to kick in. Your just a novice magician. :Smile:

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## dumdum01

> By "magic" I meant your experience. You have little data but you need to say more than the data allows. Hence you, with your 15-20 yr. experience act like the almighty magician. To do this you need GOOD arguments regarding why you  assumed what you assumed.  
> 
> In your case you will have to wait for this phase to kick in. Your just a novice magician.



Haha... Can you help this novice with some behind the scenes magical notions. For example. (how do I assume a given number of wells? what factors do I need to look into for this?) 

I am an economist, intend to be an economist. But I would still like to be able to understand and appreciate the work of PE because it is integral to the value of a project. You guys rule!! lol.

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## vinomarky

How about this Mr Economist - can you tell me how to make a simple spreadsheet which I can use in all fiscal regimes to quickly get the jump on other economists and value opportunities?  ;-)

Your answer would of course be no, but you'd be able to on a case-by-case basis generate rapid valuations based upon your judgment - simplifications as needed and plain old experience, that'd get you a 90% solution

I draw this rather simple analogy to illustrate what you are asking of us.... like the various fiscal regimes, there really is no single set of assumptions that will keep you out of trouble when predicting how a reservoir will produce - how many wells you will need over the life etc.... I'm afraid you will have to be stuck with dealing with one of us as required when looking at your new field. 

Having said that, if you do sit down with a capable PE/RE to look at a new field, it really shouldn't take very long (hours) to come up with something that'd work as a first pass.

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## dumdum01

Haha, 

Maybe I have the wrong end of the stick here but I know Chevron already use a similar model to come up with a basic first cut.

As to can I give you a simple spreadsheet that takes into account all fiscal regimes... is a resounding yes. It wouldn't give you NPV correct to two decimal places, it would give you maybe a +- 30% accurate answer. Thats the kind of thing I am looking for. In RE terms that probably is +- 200% but I am willing to live with it. The first estimates on a field before anything is drilled will be wrong anyways. There is no way G&G and RE comes up with a correct view of a green field development in a frontier play without drilling even a well.

And this has been a great process for me to understand things, even basic things like what an aquifier effect means, or what is Gas formation volume factor. Words that are banded around in functional reviews all the time, and I suspect many people understand it outside the function.

Thank you guys for your help so far.)) It has been very very much appreciated. It has helped me a lot to scratch the surface. It is quite otherwise to know what to look at unless there are some nudges in the right direction sometimes. (And I found the formula in the RE handbook vinomarky. Lol.) Now just to understand it. hehe

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## vinomarky

If you are willing to assume/WAG values for variables such as;


- Appropriate BCF or drainage radius per Well required for field development, 
- mmscf/day capacity per well, 
- manually enter a drill schedule that takes into account logistical realities as well as production decline 
- EUR & Abandonment rate/THP
- CGR

then you can surely get something along the lines of what you outline

I think where our lines are getting crossed is the notion that a generic sheet would calculate all of these for you - this will not be the case.See More: production profile- reservoir model and well decline profile in excel.

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## Shakespear

> Maybe I have the wrong end of the stick here but I know Chevron already use a similar model to come up with a basic first cut.
> 
> As to can I give you a simple spreadsheet that takes into account all fiscal regimes... is a resounding yes. It wouldn't give you NPV correct to two decimal places, it would give you maybe a +- 30% accurate answer. Thats the kind of thing I am looking for. In RE terms that probably is +- 200% but I am willing to live with it. The first estimates on a field before anything is drilled will be wrong anyways. There is no way G&G and RE comes up with a correct view of a green field development in a frontier play without drilling even a well.



The assumptions that Chevron has in its spreadsheet are ones that CHEVRON CAN live with. If you took their spreadsheet and applied it to your company that may not be true. Why? Because the assumptions about resources to develop (drilling, facilities etc.) may be not be true for your company. I am thinking along the lines of what vinomarky says here

"- manually enter a drilling schedule that takes into account logistical realities as well as production decline "
This is serious money here. If your over optimistic and it takes longer to develop because you can not get the rigs there, can not build the pipeline fast enough, permits take longer than you assumed ...... And your job will be short with them. This is where pure experience comes in. People buying in MUST HAVE GOOD experience or else you will pay through the nose !!!! The other sides wants AS MUCH as possible, you want to pay as little as POSSIBLE. Experience can give you the edge with this.

Have a look at this paper to see how some reservoirs can look

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## petroengineer

You can find a quite good conceptual field development software (DevModel-EPCI) in www.eastexpetroleum.com web page.
Petroengineer.

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## Chee Koh Peh

Let me share a perspective on this, having worked as a reserves auditor for an international PE consulting firm. I often saw old fields/prospects return with eager new investors thinking $$$ signs on the potential upside after slick marketing by the owner. The firm I worked for, would invariable be engaged to perform the technical due diligence for the "eager new investor" in the potential acquisition.

I got to the point, where I would ask the potential investors this question upfront, "What are the five (5) greatest technical/commercial risks with the old fields/prospects? When the client would reply they did not know I would ask again, and then a 3rd time. By that time the client would usually work out where I was coming from. Until you can list and to some point quantify the top five (5) technical/commercial risks, it is virtually impossible to assign a range of realistic commercial value to the old fields/prospects.

As mentioned above prior experience is the greatest teacher. We reservoir engineers never deal with deterministic (i.e. singular) answers, simply because we cannot see what is happening downhole, we draw inferences as to what is happening through indirect methods. If I were to give one piece of advice in this area for you dumdum it is Occam's razor (courtesy Wikipedia), which states, that the simplest explanation is usually the correct one. Simplest is not defined by the time or degree of calculations it takes to express the theory; "[simplest] is really referring to the theory with the fewest new assumptions.

The more complicated your reservoir modeling becomes, the more assumptions you are usually forced to make. I think Vinomarky's post was excellent on the modeling, this is what I did 90% of the time. The value in the modeling is identify the range of potential outcomes, that is to encapsulate the range of commercial risk in the acquisition/development, then the value become clearer.

Apologies if this seems obvious!

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## Shakespear

> seems obvious



There is nothing obvious in our business as we never get close to seeing 99% of what it is we are studying.  :Smile: 

If there was one piece of advice I would give dumdum it would be to CLEARLY always state your assumptions and with what data you are working and what you are lacking. This way you "cover your ass" because no one will do this for you !!!! 

There will always be people who will want you to answer the question "So we can say that we will get this much production if we drill this well?". Your answer should be "No, we can not "say", we can "assume" based on ....". 

Then you drag in the geologist, production engineer etc. to clarify to the one wanting A NUMBER how shaky the numbers are. They probable know this already but they need someone to hang the responsibility for the decision to buy, drill, farm or what ever. They want to be able to say "Eng. Dumdum told us ..." 

You learn this with TIME.

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## coyee

Thanks for your advice, Shakespear.. I'll remember this: "No, we can not "say", we can "assume" based on ...."

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## dumdum01

> Let me share a perspective on this, having worked as a reserves auditor for an international PE consulting firm. I often saw old fields/prospects return with eager new investors thinking $$$ signs on the potential upside after slick marketing by the owner. The firm I worked for, would invariable be engaged to perform the technical due diligence for the "eager new investor" in the potential acquisition.
> 
> I got to the point, where I would ask the potential investors this question upfront, "What are the five (5) greatest technical/commercial risks with the old fields/prospects? When the client would reply they did not know I would ask again, and then a 3rd time. By that time the client would usually work out where I was coming from. Until you can list and to some point quantify the top five (5) technical/commercial risks, it is virtually impossible to assign a range of realistic commercial value to the old fields/prospects.
> 
> As mentioned above prior experience is the greatest teacher. We reservoir engineers never deal with deterministic (i.e. singular) answers, simply because we cannot see what is happening downhole, we draw inferences as to what is happening through indirect methods. If I were to give one piece of advice in this area for you dumdum it is Occam's razor (courtesy Wikipedia), which states, that the simplest explanation is usually the correct one. Simplest is not defined by the time or degree of calculations it takes to express the theory; "[simplest] is really referring to the theory with the fewest new assumptions.
> 
> The more complicated your reservoir modeling becomes, the more assumptions you are usually forced to make. I think Vinomarky's post was excellent on the modeling, this is what I did 90% of the time. The value in the modeling is identify the range of potential outcomes, that is to encapsulate the range of commercial risk in the acquisition/development, then the value become clearer.
> 
> Apologies if this seems obvious!



That is a great way to sum it. ( I will try and incorporate it as part of the thinking. Thank you.)

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## dumdum01

> There is nothing obvious in our business as we never get close to seeing 99% of what it is we are studying. 
> 
> If there was one piece of advice I would give dumdum it would be to CLEARLY always state your assumptions and with what data you are working and what you are lacking. This way you "cover your ass" because no one will do this for you !!!! 
> 
> There will always be people who will want you to answer the question "So we can say that we will get this much production if we drill this well?". Your answer should be "No, we can not "say", we can "assume" based on ....". 
> 
> Then you drag in the geologist, production engineer etc. to clarify to the one wanting A NUMBER how shaky the numbers are. They probable know this already but they need someone to hang the responsibility for the decision to buy, drill, farm or what ever. They want to be able to say "Eng. Dumdum told us ..." 
> 
> You learn this with TIME.



Haha... I know the feeling.

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## dumdum01

OK someone help me with the chain of thought here.

I know.
1. Reservoir Pressure
2. Wellhead Pressure I need to keep going, bottomhole pressure and so in effect abandonment pressure.
3. CGR
4.porosity/permeability data.
5.A production profile for the reservoir.

1. How do I get (Drainage radius per well) (ASSUME NO FAULT LINES!!!...Tank model) 
2. Well deliverability and decline rate (given this data.)

3.

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## Shakespear

dumdum

You need to get down to the basics. Look in a reservoir engineering book or the net  :Roll Eyes (Sarcastic): 

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## dumdum01

> dumdum
> 
> You need to get down to the basics. Look in a reservoir engineering book or the net 
> 
> **[link Point to another website Only the registered members can access]
> *link*
> 
> 
> 
> ...



FANTASTIC WEBPAGE!! Thanks for that. I have been reading the petroleum engineering handbook. But most of the calculations require a lot of data which I dont have(yes, you have impressed this point onto me... but now it is a personal thing, not a project anymore. I gotta DO THIS!!) 

Thats why i specified all the variables I have. But thanks a lot :Smile: )))))

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## dumdum01

Hi Again Guys,

With the help of our Moderator (Shakespeare) and all of you who have shared your expert knowledge, I have been able to come up with well profiles and a reservoir profile. 

Now, I need to be able to "optimise" the number of wells for a given production profile.

Anyone has any excel spreadsheets lying around which goes through this kind of an optimisation process. Is the solver tool in excel a good way to do this?

Thanks again as always,
dumdum.

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## Chee Koh Peh

DumDum,



Okay, I assume you have a gas sales agreement (GSA) in developing the field, is that correct? If so you should have a DCQ (Daily Contracted Quantity). Now all that needs to be done is drill sufficient wells initially to exceed the DCQ rate, and then drill additional wells to continue to meet the DCQ as existing wells decline (assuming you are on land). So, the number and timing of wells is simply a function of how many wells you need to meet the DCQ, and how often you need to drill / or bring an additional well(s) on line to compensate for the decline of existing wells. Offshore you will drill significant excess initial capacity above the DCQ given the costs and logistical issues involved in offshore drilling, you will most likely drill additional wells in batches assuming your platform has the slots etc. and this obviously impacts NPV etc.

Thus your individual well modeling i.e. rate and ultimate recovery will determine the number of wells required and associated drilling timing. At this level the uncertainty in the assumptions you have made in individual well modeling, far outweighs any accuracy that a solver in excel will give you on the optimal number of wells. 


Chee Koh PehSee More: production profile- reservoir model and well decline profile in excel.

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## dumdum01

Hi Guys, 

A quick question. I have calculated pseudo critical temperature and pseudo critical pressure for a reservoir with a given specific gravity of gas. Can anyone help me with an excel version of standing and katz compressibility factors chart. How do I go from pseudo - reduced pressure to z-value?

Thanks.

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## reservoirengineer

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