Question about "Recovery factor of Associated gas"

[Demosthenes]

hello, my name is dimitri, i am self learner so i dont have any professional training,
i have been stuck with a question i couldnt find an answer to.

My question is the following:

"Say i have a reservoir with 1 billion barrels of oil OOIP, the initial GOR is 1000 Scf\bbl,
the recovery factor is 15% for the oil(so there is 150 million recoverable bbls)".

From this data i calculate the Quantity of the Associated gas in place as 1000 x 1 Billion bbls = 1 TCF of Associated gas in place.

Can i assume the recoverable Associated gas as 0.15 TCF(15% Recovery factor) or no? is the recovery factor of Associated gas>15% or <15%?

if the recovery factor is higher than 15%(recovery factor of oil in the reservoir) can i assume that the GOR become higher with time?

thanks in advance

Take a look here,

[link Point to another website Only the registered members can access]

[link Point to another website Only the registered members can access]

[link Point to another website Only the registered members can access]
Here someone did some regression work to answer the question of recovery

[link Point to another website Only the registered members can access]

[Chee Koh Peh]

Dimitri,

It is not as simple as a taking an oil recovery factor to estimate the amount of associated gas recovered.

The amount of associated gas recovered is a function of the reservoir drive mechanism, and this is because of the very important question, does the reservoir pressure drop below the bubble point in production?

For example if the reservoir is under moderate to strong waterdrive (or water injection/pressure maintenance) and the production rate does not allow reservoir pressure to fall below the bubble point then the recovery of associated gas will be equal to the Np x Solution GOR.

However if the reservoir pressure falls below the bubble point, and you have free gas saturation forming in the reservoir the producing GOR will rise, reflecting the production of the the free gas that is far more mobile than fluids and will thus be preferentially produced (this usually occurs when the free gas saturation is > 10% in the reservoir). In this case the amount of associated gas recovered is a function of the abandonment pressure in the reservoir. In this case you will recover more gas than would be estimated by using the oil RF x Solution GOR.

There is no single formula in this case.

Increasing GOR is solely a function of the free gas saturation in reservoir becoming mobile, that occurs only due to reservoir pressure falling below the bubble point.

Read Craft and Hawkins, particular the chapter on saturated oil reservoirs.

Rgrds

Chee Koh Peh...

[Demosthenes]

Thank you for the detailed answer, it was very helpful.

[Shakespear]

dimitri

There are excellent discussions on the subject of recovery on this web site. It is in Russian and I assume you speak it by the moniker you use.

[link Point to another website Only the registered members can access]
Chee Koh Peh observations are spot on.

ECLIPSE spits out the following which may be of interest to you but again think hard about what this number means.

In the ECLIPSE manual,

Table 2.135 Oil recovery mechanism (ECLIPSE 100)

[temr]

Dimitri it is simple if you will keep you wells above bubble point pressure you dissolved gas production will be = Oilproduction * GOR initial.
If you start to produce below bubble point the things become more difficult .
Having in mind tank model you can ruffly calculate your dissolved gas production as oilproduction * GORcurrent_step + Current OilinPlace*(GORcurrent_step-1-GORcurrent_step)
GORcurrent_step-1 means Gor for last period
GORcurrent_step means Gor for current period
GORcurrent depends on pressure and comes from PVT ( pressure versus GOR)
So the last equation is mine do not try to look for it anywhere else )) and it is takes assumes that all gas which evolved after pressure drops down below bubble point is going through wells
But it is true only in the tank model

[Shakespear]

OK, I have never did this but here are my suggestion what to perhaps look at and experiment with.

Lets start with he simplest option. ECLIPSE tracer tracking option that allows you to monitor fluid movement by "coloring" it. The term used is tagging but color is easier to relate to. This has its limits so you will need to read about this option.

The ECLIPSE 300 TRACK option allows a division of hydrocarbons in the original reservoir to be tracked through into recovered surface volumes. The tracer concentrations can be initialized on a region basis using a depth table method of data
input. This method of data input is especially suited to tracking fluid which initially exists within a particular region of the reservoir. In the case of gas condensate reservoirs, it is thus possible to track the oil which initially exists in the vapor phase in separate regions of the reservoir and to determine its subsequent movement through the reservoir grid. The Tracer option could also be used to predict the concentration of chemical impurity species (such as the sulphur content of the oil) in the hydrocarbon production streams.

Next best would be to have a "tracer" fluid which was every where with properties such that below bubble point its properties would be the same as that of the gas. Now the amount of this "tracer" at the well would be related to how much dissolved gas was produced.

Please remember that I am just brain storming and am not sure this can be done. I will try to check this out and will also ask someone I know if they have any ideas regarding this.