5. 5
Reservoir:
A substance body of rock having sufficient porosity and permeability to store and
transmit fluids; (eg; Sandstone, Carbonate, Fracture Basement … etc...)
23. Oil Gas Water
• Estimating
properties of
reservoir
water is
important
for reservoir
calculations,
specifically
for those
with water
influx
Reservoir fluids
23
24. Bubble Point Pressure
The bubble point pressure is defined as the
pressure at which the first bubble of gas comes
out of solution.
At this point, we can say the oil is saturated - it
cannot hold anymore gas. Above this pressure the
oil is under saturated, and the oil acts as a single-
phase liquid.
At and below this pressure the oil is saturated,
and any lowering of the pressure causes gas to be
liberated resulting in two-phase flow.
24
25. Oil Gravity
Oil gravity relates the density of oil to that of the density of water.
API gravity is gradated in degrees on a hydrometer instrument and was
designed so that most values would fall between 10° and 70° API.
It ranges from 45 °API (light oil) through 20 °API (medium density) to 10
°API (heavy oil). The conversion from API gravity (oil field units) to relative
gravity (relative to water) is:
25
26. Formation Volume Factor
The ratio of the volume of oil and dissolved gas at reservoir (in-situ) conditions to
the volume of oil at stock tank (surface) conditions, volume factors are needed to
convert measured surface volumes to reservoir conditions. It is defined as:
As pressure increases, the amount of solution gas that the oil can dissolve
increases such that the oil swells, and so the formation volume factor exceeds 1.0
oil formation volume factor is dominated by swelling below the bubble point
pressure (due to dissolved gas), and by compressibility above the bubble point
pressure (since all available gas is now dissolved).
Solution gas
Compressibility of oil
26
27. Gas Oil Ratio
The solution gas-oil ratio is the amount of gas
dissolved in the oil at any pressure.
GOR increases approximately linearly with
pressure and is a function of the oil and gas
composition. A heavy oil contains less dissolved
gas than a light oil.
The solution gas-oil ratio increases with
pressure until the bubble point pressure is
reached, after which it is a constant, and the oil
is said to be under saturated.
27
29. y = 26
y = -0.0935x + 143.14
R² = 0.9457
0.0
10.0
20.0
30.0
1150 1200 1250 1300 1350 1400
API
Depth (m)
API Vs Depth of Fal-1&Fal-5
y = -0.1241x + 184.59
R² = 0.946
0.0
10.0
20.0
30.0
1280 1320 1360 1400
API
Depth (m)
API Vs Depth of Fal-3&Fenti
y = -0.036x + 85.636
R² = 0.5786
20.0
30.0
40.0
50.0
1150 1200 1250 1300 1350 1400
PourPoint(℃)
Depth (m)
Pour Point Vs Depth of Fal-1& Fal-5
As the depth is increasing, oil viscosity decreases, API decreases, and pour point decreases
Low bubble pressure: 300~650psi
Low GOR: 42.8~89.6scf/bbl
Medium to heavy oil: oil viscosity 30.4 ~ 360cp;
API 14.5~23.8
Medium to high pour point: 15.0~42.2℃
1
2
3
29
33. A core is a sample of rock in the shape of a cylinder. Taken from the side of a
drilled oil or gas well, a core is then dissected into multiple core plugs, or
small cylindrical samples measuring about 1 inch in diameter and 3 inches
long.
Core Definition
Types of Cores:
There are several types of cores that can be recovered from the well:
Full-diameter cores.
Oriented cores.
Native state cores and
Sidewall cores.
33
36. Special Core Analysis:
Detailed understanding of a reservoir requires additional measurements obtained in the special
core analysis laboratory (SCAL). Examples include
ƒ
Calibrating electrical logging measurements of porosity and saturation.
ƒ
Determining a formation-specific cutoff value for the relaxation time from a nuclear
magnetic resonance (NMR) log.
ƒ
Determining capillary pressure measurements to indicate distributions of pore throats and
evaluating saturation distribution as a function of height in a formation.
ƒ
Relative permeability determines the multiphase flow character of the formation.
Evaluating wettability.
36
49. Routine Core Analysis:
Measurement of basic properties helps you
determine if a rock contains a fluid-filled space
(porosity) and hydrocarbons in that space
(saturation), and the ability of those hydrocarbon
fluids to be produced (permeability). Core gamma
logging links core depth to logging depth.
Computed tomography (CT) scans indicate core
heterogeneity.
49
90. 90
The STOIIP of P1, P2, P3 (Proved, Probable, Possible) in each reservoir
is assessed using the volumetric calculation method. The formula is
shown as below.
STOIIP = Ao * H * Por. * So / Boi * 6.29
Where: STOIIP= Original Oil in Place, MMstb
Ao= Oil bearing area (km2)
H = Net pay (m)
Por= Porosity (fraction)
So =Oil saturation (fraction)
Boi= Oil formation factor (v/v)
Volumetric Assessment:
Example of Mirmir area – Melut Basin - DPOC
91. 91
PROVED/PROBABLE/POSSIBLE CATEGORIES
(HALF-WAY CONCEPT)
The categories and halfway concept may be overridden by some other geological,
geophysical and engineering data of which the basis and assumptions must be clearly stated.
Range of Uncertainty Categories for Hydrocarbon Accumulation
92. 92
Based on structure map of pay zones, the boundary line of oil or gas bearing area is
determined by fault boundary, lithology boundary and fluid contacts. Fluid contacts
often are determined by well testing, well logging evaluation and MDT data.
Oil Bearing Area
Net pay for each layer in wells is obtained from well log interpretation. Based on
the net pay contour map, net pay of the hydrocarbon reservoir is determined by
weighting of hydrocarbon bearing area.
Net Pay
Porosity of net pay in wells is obtained from well log interpretation. For a
hydrocarbon reservoir, porosity value is determined by weighting of net pay.
Porosity
Oil saturation of net pay in wells is obtained from well log interpretation. For a
hydrocarbon reservoir, oil saturation value is determined by weighting of net pay.
Oil Saturation
Volume factor is determined based on the PVT data, and obtained from reservoir
engineering analysis.
Formation Volume Factor (Boi)
103. This is the recovery of hydrocarbons from the reservoir using
the natural energy of the reservoir as a drive.
Primary Recovery
(i) Solution gas drive
(ii) Gas cap drive
(iii) Water drive
(iv) Gravity drainage
(v) Combination or mixed drive
103
104. This is recovery aided or driven by the injection of water or
gas from the surface.
Secondary Recovery (IOR)
(i) Waterflooding
(ii) Gasflooding
104
119. Water flooding Reduces Oil Viscosity Well sorting
Large grain Low API
SCAL Formation pressure
Saturation
Single liquid phase
Cubic packing High APIMiscible
1 2 3
4 5 6
7 8 9
10 11 12
119
A
120. Light oil N2
High permeabilityAbove the bubble pointpsi
T2 cut-off48% Porosity
Steam injectionOil gas, or water Oil
Good porosity
Heavy Oil
Secondary recovery
A 120
123. Briefly discus the following:
A. Reservoir pressure
B. Injection well
C. Viscosity
D. Pour point
E. Secondary porosity
F. Wettability
G. Capillary pressure
H. Absolute Open Flow Potential (AOF/AOFP)
I. Computed Tomography (CT)
Exercise 1
123
126. 126
Exercise 4
The STOIIP of P1, P2, P3 (Proved, Probable, Possible) in each reservoir
is assessed using the volumetric calculation method. The formula is
shown as below.
Calculate STOIIP for L_Aradeiba-4-1 Foramation?
STOIIP = Ao * H * Por. * So / Boi * 6.29
Where: STOIIP= Original Oil in Place, MMstb
Ao= Oil bearing area (km2)
H = Net pay (m)
Por= Porosity (fraction)
So =Oil saturation (fraction)
Boi= Oil formation factor (FVF)
129. 129
(A) (B) (C)
EOR Type EOR methods Main Mechanism
1 Thermal Miscible Improve swept efficiency
2 Chemical Hot Water Make oil volumetric swell
3 Gas Injection Gas Injection Viscosity reduction
Exercise 5
Match the following column A, B & C.