CHAPTER 4 RESERVOIR ENGINEERING

• Jurisdiction: United States

Basic Oil and Gas Technology for Lawyers and Landmen
(Apr 1979)
CHAPTER 4
RESERVOIR ENGINEERING
Dr. Daniel M. Bass, Jr.
Colorado School of Mines
Golden, Colorado

Petroleum reservoirs, as previously discussed, must have certain characteristics:

(1) ability to prevent fluids from migrating upward out of the formation (Trap);

(2) porosity;

(3) permeability; and

(4) sufficient hydrocarbons to produce economically.

Reservoir engineering normally deals with the last three items to determine the value of the petroleum deposit and the method to produce the hydrocarbon so as to maximize recovery and economic return.

In order to accomplish this objective, the engineer must assimilate the mass of data previously discussed and reduce it to a form suitable for use in some of the available evaluation techniques.

The most common technique, also the first used, for determining the quantity of hydrocarbons in the reservoir is referred to as the volumetric method. This method uses a simple equation

Surface volume of; Hydrocarbon in Place	=	Areal extent of the Hydro carbon accumula tion	x	net thick ness of the hydrocarbon formation
x porosity	x	fraction of pore volume containing hydrocarbons
underground volume per unit surface volume

The equation is normally written with symbols as follows

N = A h f (1–S_wi)
5.61 B_oi

or

G = A h f (1–S_wi)
1000×G_gi

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where N is stock tank barrels and

G is thousand of standard cubic feet

In order to obtain the values for the equation one must define certain terms:

Areal extend (A) — the square feet (sometimes acres) which are enclosed between the top of structure and the line marking the intercept of the hydrocarbon-water contact with the bottom and the top of the formation.

Gross thickness — the number of vertical feet between the top and bottom of the formation.

Net thickness (h) — the number of feet within the gross thickness which is thought to be capable of producing hydrocarbons.

Porosity () — an average value that applies to the net volume under consideration.

Water saturation (S_wi) — an average value of water content that applies to the net volume of the hydrocarbon accumulation.

Formation volume factor (B_oi, B_gi) — the conversion factor from the formation to the surface at original formation pressure and temperature.

As discussed by others, the information required by these definitions are obtained on a foot by foot basis in each well or on a well by well basis. A review of where the information for this equation is obtained might be in order:

1 — Top of formation

(a) S.P. log

(b) Gamma Ray Log

(c) Penetration Log

(d) Drilling depth correlated with drill cuttings

(e) Mud Log

2- Bottom of formation

(a) thru (d) above

3- Porosity ()

(a) Resistivity log with empirical equations

(b) Neutron log with empirical correlation

(c) porosity logs

(d) core analysis (conventional and side wall)

(e) Multi-well tests

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4- Water saturation (S_wi)

(a) Resistivity log with empirical equations

(b) Specially cut cores (oil base drilling fluid)

(c) Special laboratory analysis of cores (capillary pressure data)

5- Gross thickness — any combination which yield values for the top and bottom of the formation.

6- Net thickness

(a) porosity log,

(b) Resistivity log,

(c) Neutron log,

(d) Core analysis,

(e) S.P. log,

(f) Gamma Ray log, and

(g) a combination of the above

7- Hydrocarbon — water contact

(a) drill stem test (DST),

(b) Resistivity log

(c) Special core analysis

8- Formation volume factor

(a) Empirical correlations based on fluid property data from DST or initial production, and

(b) A fluid PVT analysis

9- Isopach map

(a) Gross feet

(b) Net feet

(c) Net porosity feet

(d) Net hydrocarbon feet

As can be seen from the fore-going it would be possible to obtain many different answers for the same reservoir if the values used in the calculation were obtained by a different combination of data sources.

A brief discussion of how one reduces the data to a usable form might be informative at this time.

A- On each well the logs or core analysis are used to determine what portion of the gross formation thickness is of another type rock or too dense to produce (shale, dense limestone, coal, bentonite, etc.).

B- For a relationship between water saturation and porosity and knowing the minimum saturation at which the hydrocarbon will flow, one can determine a "porosity cut-off". The "porosity cut-off" is the minimum value of porosity at which the hydrocarbon will flow in the formation, hence is capable of being produced. Knowing the "porosity cut-off", any part of the formation within the gross thickness that has a lower value is not treated as part of the net thickness.

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C- Using only the net thickness resulting from A and B determines a net/gross ratio for the well.

D- Using the data for the footage within the net thickness, determine the total porosity-feet in the well

ⁿ

fh = S f _jh_j
j=1

E- Using the data for the footage within the net thickness determine the hydrocarbon feet in the well

ⁿ

S

[fh(1–S_wi) ]_j

(fh(1–S_wi) = _j=1

F- Assign a drainage area to the well [spacing pattern is normal, 20, 40, 80, 160, 320 or 640 acres].

G- Determine the formation volume factor (usually from a correlation) (B_o)

H- Calculate surface volume of hydrocarbon in place

=
_n
A_{w S} [f h (1–S_wi) ]_j
N_{w = j=1}
5.61×B_oi

_n
A_{w S} [f h (1–S_wi) ]
G_{w = j=1}
1000×B_gi

I- The values determined in step G are summed...