Production forecast

Could you please me how to calculate production forecast for the field has only one well that has just test data.
Thank you in advance.
Regards

Material Balance would provide a good estimation (check Tracy, Taner or Muskat methods). Some other colleagues I know build simple/conceptual 3D simulation models with the information at hand (if something is not available, such as PVT properties, analog reservoir fluids are considered).

Thank you so much for the help. Regarding 3D simulation model do you mean by using Eclipse?

Yes Bayan, I mean Eclipse or any other simulator. In CMG-Builder you can build a conceptual model in less than an hour, making this particular package suitable for quick evaluations.

Thank you for your advise and I would like if you can advise me if you have new field with only one production well..there is just DST test.I you need suggest long term test for that well.
what is the test methods that you suggest for the new well ?
How can to calculate STOIIP if we haven't any models?
How to know drive mechanism after the test?
and if you have any suggestion it would be good and appreciated.
Thank you in advance for any comments and you time

[QUOTE]Thank you for your advise and I would like if you can advise me if you have new field with only one production well..there is just DST test.I you need suggest long term test for that well.
what is the test methods that you suggest for the new well ?
How can to calculate STOIIP if we haven't any models?
How to know drive mechanism after the test?
and if you have any suggestion it would be good and appreciated.
Thank you in advance for any comments and you time[/QUOTE]

Unless you are talking many months test, the DST will only reliably yield (a) total kh over the interval tested and (b) P*. It will [U]not [/U]tell you anything about aquifer support, nor will it tell you much about vertical or areal permeability variations. If you are unfortunate enough to have a very small reservoir, you *may* see a level of depletion during production, but if that is the case you likely do not have a commercial accumulation. Assuming no measurable level of depletion seen, you can infer that the accumulation must be at least a certain size (given an understanding of insitu total compressibility, volume withdrawn and minimum measurable pressure differential).

You would have to calculate STOIIP volumetrically, using knowledge of one or more of oil leg gradient, water gradient, HKO, LKO, OWC and/or LCC plus understanding or porosity, saturation etc. At its simplest - if not a simple model - you would need at least a top depth map, and understanding of net thickness to do this

If you say you have nether a model, nor a map, and have seen no measurable depletion during your test, then all you can say is the volume must be at least a certain size.

In terms of predicting production profiles after the test, you would need to have some understanding of the structure, geology and possible water drive (if nothing else then from analogs).

Did you drill through the oil and contact water? If so, was there any competent shale between oil and water? if not, you could possibly expect a bottom water contribution, and likely rapid coning (depending on accumulation thickness and completion geometry)

Do you have a dipping bed and oil on rock? Do you have regional normal pressure gradient and evidence of water support in offset areas? If so, you likely would have an edge water drive system - how would this produce? Well you would also need to further understand the vertical perm variability and lateral connectivity/continuity in order to predict this.

Did you see a gas cap, or was your sampled oil (please tell me you did some good sampling...) at or very near to bubble point pressure, with further updip structure available? In which case you could quite likely have some gas cap drive contribution and possibly gas coning.

Are you overpressured? You quite possibly will have limited/no water support, and will probably have something like an exponential rate decline, governed by accumulation size and system compressibility.

I could go on and on, but the short answer to your question is that there are no short cuts. From DST alone you CAN make a production prediction, but its accuracy would be heavily dependent upon doing the work/investigation in order to characterize as much as possible the 'most likely' geometry, geology, architecture etc. You should ALWAYS state these assumptions, and normally describe end members (ie depletion only, edge water drive in gravity stabilized dipping bed) along with your 'most likely' along with some discussion on why you think some scenarios are more or less likely.

Simply creating a 30-minute simulation model is NOT the answer. The answer is in the [U]thinking [/U]you need to do. The model generation you then do - integrating those scenario assumptions - is the trivial part. If you simply create a model without the thinking, then you are performing at a level of an overpaid technical assistant rather than an engineer.

Thank you so much for your time for help me.what about if I suggest long drowdown test ?how long time do you suggest?it should be at constant rate for all time?
Thank you

Thank you so much for your time for help me.what about if I suggest long drowdown test ?how long time do you suggest?it should be at constant rate for all time?
Thank you

[QUOTE]Unless you are talking many months test, the DST will only reliably yield (a) total kh over the interval tested and (b) P*. It will not tell you anything about aquifer support, nor will it tell you much about vertical or areal permeability variations.[/QUOTE]




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I didn't see anything

No, sadly it appears that you didn't

Despite spending some time and writing over a page, outlining the need to think

Despite a not-so-subtle poke in the form of pasting a portion of the same answer already given detailing that you'd likely be talking many months (essentially what you are talking about is a pilot well production, not a DST), you are still saying "ok, thanks, but what's the answer"

*sigh*

How long would it take to 'see' the main drive mechanism in each of the scenarios I've already sketched above? Answer: it depends on the scenario.

Start thinking like a real engineer, and get to the REAL question. Why are you being asked to furnish a profile? Does management need a minimum volume for investment decision? Do they need certainty on time on plateau for contracts? Is water handling a critical design issue? The list goes on.... Generally, you would be far better off delineating your field with additional wells intelligently placed to tighten your understanding on key unknowns rather than an extended test. Once you understand your possible volumes and geometry a bit better, if (for example) your water cut behaviour with time for a prolific but relatively low relief oil reservoir overlying water remains a critical design parameter and the additional cost and delay to narrow the uncertainty is outweighed by the benefit, THEN you may want to consider a pilot well production test

THINK

Thank you for your advise.