Compute pressure from Depth of fluidn level 1

[goma1]

Hi there.

I have the following data: density of fluid, DFL (depth of fluid level) and FOP (Fluid over pump depth). How do I compute the pressure in the reservoir given these data.

Thanks for the help.

Goma1

 

[dcasto]

Draw it out. Start with the tubing surface pressure, add the pressure due the height of the fluid in the tubing.

 

[zdas04]

Sorry, but YOU DON'T. Those data will give you an estimate of the pressure on the wellbore side of the sand face. The shape of the pressure traverse from the sand face to the actual "average reservoir pressure" or "Pbar" is very much a specific well/specific reservoir issue.

Reservoir pressure is probably the most elusive single parameter in the industry. We pretend that the pressure recorded when the drill bit enters the formation is the reservoir pressure, but that is truly wishful thinking even when we take it to 9 decimal places.

Sometimes we do pressure-build-up tests to try to determine a surrogate for reservoir pressure only to find that the pressure is still increasing at the end of the test (and generally we pretend otherwise).

The data you've asked about simply will not be enough to even begin to calculate reservoir pressure or Pbar.

David

 

[jjwamp]

If you want a generic guesstimate of reservoir pressure (and as you have fluid above pump I am guessing it is rodded up)

Shut in the well until surface pressure stabilizes. If it is on rod pump my guess is the pressure will be low and although the gas on the backside has some weight it is pretty negligible but there are calculations to find out how much this is.

In US oilfield terms

BHP = Surf Pressure + (Fluid level above mid perf)*.052*Fluid density

where pressure is in psi, level is in feet, and density is in lbs/gal. Weigh your field saltwater/field oil to get estimate of weight of water/oil. Can use oil/water ratio to get estimate weighted effects of the fluid over the perfs.

You can then kick on the pumpjack and let it run for several days. Shoot another fluid level and repeat for find dynamic pressure at the perfs. From this and the BOFPD you should be able to guesstimate a PI.

Note: These are very round about numbers. Nothing is an exact science when shooting fluid levels, guessing fluids weights, or estimating downhole pressure caused by the gas gradient.

 

[zdas04]

jjwamp,
If that calc does anything at all (I don't know what the density of water is in lbm/gal so I can't verify it without more work than I want to do, I've most often seen the second term expressed as height * 0.43 psi/ft * SG), it will tell you the pressure on the well side of the perfs, how is that an estimate of reservoir pressure?

David

David Simpson, PE
MuleShoe Engineering

http://www.muleshoe-eng.com

Please see FAQ731-376 for tips on how to make the best use of Eng-Tips Fora.

The harder I work, the luckier I seem

 

[zither99]

That pressure will be a good estimate because it is equal to the reservoir pressure. If the pressure of the mud column would be lower than reservoir pressure then there would be a kick, and if it would be higher then there would be mud loss into the formation.

I'm not familiar with the term FOP (Fluid over pump depth).

 

[john1964]

my small piece.....
Normal formation pressure is equal to the hydrostatic pressure of the fluid extending from the surface to the subsurface formation. Add surface pressure if any.
Hydrostatic pressure psi= Density X0.052 X true vertical depth;
Hydrostatic pressure is defined as the pressure due to unit weight & the vertical height of a column of fluid. Since pressure is measured in psi & depth in feet, it is convenient to convert mud weights from pounds per gallon ( PPG) to pressure gradient psi/ft & the conversion factor is 0.052.
The conversion factor ( 0.052) is derived as follows-
A cubic feet contains 7.48 USG; A fluid weighing 1 ppg is equivalent to 7.48 lbs/cu.ft;
The pressure exerted by one foot of that fluid over the area of the base would be 7.48 lbs / 144 sq inches = 0.052 psi.
Again salinity , gas composition in water, tempearture will all affect density.

 

[jjwamp]

Thanks john1964 for the proof. .052 is just a conversion factor.

For David Simpson,

For drilling engineers hydrostatic pressure is often estimated by the equation:

.052 * MW (lbs/gal) * TVD (ft)

Weight of fresh water is 8.33 lbs/gal

8.33 * .052 = .433 psi/ft which is also the number you are quoting.

8.33 * SG = wieght in lb/gal of a fluid with specific gravity of SG

.433 * SG = pressure in lbs/ft of a fluid with specific gravity of SG.

Once the fluid level and surface pressure has stabilized the hydrostatic pressure in the wellbore should equal the reservoir pressure. If the pressure in the wellbore is higher fluid will move from the wellbore into the formation. If the pressure in the wellbore is lower than the reservoir pressure fluid will move from the reservoir into the wellbore. Thus fluid will continue to move from the reservoir into the wellbore until the fluid level rises to a point where the hydrostatic equals the reservoir pressure. Essentially the well "kills" itself. If we can measure the hight of the fluid column in the wellbore and know more or less the weight of the fluid in the wellbore and then we add the pressure at surface we should be able to more or less estimate the pressure downhole. It is not going to be exact but it is a pretty rough estimate.

This is basically the things centrilift/wood group or any other ESP manufacturer uses when calculating a PI and sizing an ESP pump.

 

[zdas04]

jjwamp,
I've heard that story from engineers in fields all over the world. Occasionally it is true during the drilling process and for 10-20 minutes after first production. From then on, you develop a hydraulic gradient across the near-wellbore area that is truly indeterminate. You simply don't know the cumulative resistance to flow, any anisotropic effects, or any natural fracture effects. There is always a relationship between reservoir pressure and flowing bottom-hole pressure, but it is never simple and rarely is it accurately determined.

Measuring the fluid level where the well stops flowing gives you a shut-off pressure a few inches from the wellbore, but the hydraulic gradient can easily extend hundreds of feet between the wellbore and average reservoir pressure--this is why it is common in every gas field I've ever visited to get a "flush production period" after a shut-in, the reservoir tries to equalize the depleted near-wellbore rock during the shut-in, and after the shut-in that gas is given up first.

A few years ago I did a statistical analysis on a large group of gas wells (1,200 wells). I looked at hourly surface pressure readings during periods of shut-in that ranged from 24 hours to 60 days. I did a curve fit on every well to try to determine when it would get to 95% of P(bar). The numbers ranged from 35 to 79 years.

I've since analyzed smaller data sets in a half dozen fields and found similar results.

I can't tell if the OP is talking about a gas field or an oil field. Everything I've said above has been quantified in gas fields, and I've had folks report similar behaviour in oil fields (but I've never measured it myself).

David

 

[DrillerNic]

What do you mean by "Reservoir Pressure"?

AS Zdas is saying, in a reservoir that on production, it varies with distance from each production well, depending upon how long and how hard that well has been on production, and if teh well is shut in, how long it has been shut in, and how long and how hard it was on production before it was shut in.

You can get estimates of the near well bore pressure looking a the SITHP (or the fluid level in a low pressure well), but to look further into the reservoir you need to start using welltesting techniques: Extended Well Tests, analysis of permanent down hole gauges, that sort of thing, with a few major assumptions hidden deep in the equations (or the sofware!). The more wells you have, the better the estimate of Average Reservoir Pressure, but it is still only an estimate.