INITIAL OIL IN PLACE
To obtain initial oil in place similar procedure is done. Directly to obtain initial oil in place in STB divide initial gas in place by 5.615 as 1 bbl = 5.615 ft3.
In case of oil in place, it is under saturated reservoir i.e. gas is dissolved in oil and connate water is present.
In wild cat wells in which we don’t know the extent of reservoir such that area (For area of reservoir we drill appraisal wells after wild cat well) so we find gas or oil in place per unit acre.ft (such that per unit Vb). So,
Introduction to Reservoir Petrophysics (By Shoaib and Bilal) Page 96 PROBLEM
Calculate initial gas in place of reservoir, the average is 40ft and extend is 1500 acres, the average porosity 22% and average connate water is 23% Bgi = 0.00533 ft3/scf
Note:
103=M
106=MM
109=MMM
PROBLEM
Calculate oil in place per acre.ft when porosity=20%, Sw=0.2, Boi=1.24
Up to here we have studied how to find oil or gas in place present initially in a reservoir before taking any production, but as we take production, the reservoir pressure decreases depending on type of reservoir drive mechanism, so in order to study to calculate the gas or oil in place at any interval during taking production, first we have to study type of drive mechanisms.
Introduction to Reservoir Petrophysics (By Shoaib and Bilal) Page 97 FOR GAS RESERVOIR
Volumetric reservoir
It is one in which no encroachment of water influx in the reservoir and initial water saturation remains same at any interval during production, however reservoir pressure decreases (gas is produced through it), so gas in place at any point will be:
At any interval during production, in volumetric drive mechanism, 43560, A, h, Φ and Sw will remain same, the factor that only changes is Bg, that changes with change in reservoir pressure, so value of G only depending on Bg and we know from its graph that as reservoir pressure depletes, value of Bg increases so gas in place will decrease as production continues.
Water Drive
In this water occupies the empty pore spaces of the produced oil or gas. In any water drive (active, partial or weak), water coning takes place due to which water by passes the gas and is produced through perforation along with gas, and as production is continued, a time comes when it traps the gas present in reservoir and only water is produced, this is because well is produced based on Darcy forces, such that fluid whether gas or water will flow whenever pressure difference is created, so after sometime we have to stop taking production and abandon the well for some time so that gravity forces again become balanced such that gas come above the water and then we again continue to take production.
So, in water drive mechanism the initial water saturation does not remain constant as water
In this water encroachment is very small and pressure depletes very fast.
Q. Why volumetric or and weak water drive is good for gas reservoir?
A. We need volumetric or weak water drive because the main mechanism of gas production is gas expansion such that depletion and in active water drive as the reservoir pressure will not deplete, the gas will not be able to expand and its main mechanism of production will be failed. So for gas reservoir,
Introduction to Reservoir Petrophysics (By Shoaib and Bilal) Page 98 if we get active or partial water drive then we have to transform it to weak water drive and it can be done by drilling other wells from which water is produced only so that water aquifer in the subsurface loses its strength and transform into weak water drive.
PROBLEM
A volumetric gas reservoir has following properties:
A= 3000 acre
Calculate gas in place at 2600, 1000, 400 psi.
Since factor 43560Ahφ (1-Swi) remains constant so calculate it first and after that divide by BG value at particular pressure.
43560x3000x30x0.15x (1-0.2) = 470.448 x 106 At 2600 psi:
In volumetric gas reservoirs we have studied how to calculate reserves or in place at any pressure such that in these only the value of Bg changes such that as production is taken, the pressure of the reservoir reduces and Bg increases and as denominator increases but numerator remains same so the in places decreases so whenever we want to calculate the producible means those hydrocarbons that have been produced up to certain pressure or can be produced up to certain pressure, it can be determined by simply subtracting the in places at that pressure from the initial in places such that producible can be given as:
Introduction to Reservoir Petrophysics (By Shoaib and Bilal) Page 99 G=Gi-G
Where, for volumetric reservoir,
In order to calculate the maximum recovery, Recovery= Gi-Ga
Where Ga is the in place at abandonment pressure, which is described as under ABANDONMENT PRESSURE
As we know, as we produce from a reservoir, the in places decrease such the volume we get from reservoir at surface will decrease (in reservoir the volume remain the same), the reservoir pressure also decreases, we can produce our reservoir at atmospheric pressure because the stock tank at surface is at atmospheric pressure, and now if we want the reservoir fluid to flow from reservoir to the stock, the pressure difference should be created between them such that we have to create pressure difference between each of different components of our production phase such that the pressure in reservoir Pr should be greater than that at perforation (Pf), which should be greater than the pressure at well head (Pwh) and this should be greater than the pressure at separator and the separator pressure should also be greater than stock tank pressure which operates at atmospheric pressure. And from Darcy’s equation we also know that the greater the pressure difference between two points more is the flow rate, so as reservoir pressure decreases, the pressure difference between reservoir and surface equipment decreases due to which flow rate decreases, and we know that companies have to pay per day the charges of equipment so when their production per day will be reduced, their profit will be reduced and when the reservoir pressure decreases to so much extent that at that pressure, the flow rate is non-profitable for the company then the company has to shut the well or abandon the well, this pressure is called Abandonment pressure. For gas reservoirs, the abandonment pressure is usually 100 to 200 psi.