reservoir vera no pdf
TRANSCRIPT
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RESERVOIR
I
PP-324 A
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rocks
Rocks continental Rocks marine
sediments
Sediments water
sweet
transport and
sedimentation
of particles
transport in
solution and
precipitation
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Sedimentary
rocks • Are formed by sediments that have
settled into layers. The layers are squeezed together until they harden into rock.
• Formed by the cementation of sediment grains/particles on or near surface at ordinary temperature .
• Sandstone
• Limestone (CaCO3)
• Dolomite (CaMg(CO3)2
Igneous Rocks • An igneous rock is a rock that had
molted (derritió) but it later cooled
and hardened (endureció).
• Formed by solidification of molten
minerals/materials:
• Beneath surface
(magma):Granite
• At surface (lava): Basalt
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Metamorphic
Rocks
• Is an igneous or sedimentary rock that has been changed (alterada) by heat and pressure.
• Formed within earth’s crust by transformation of other rocks at high pressure and temperature (marble,slate)
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conversion factors are:
•1 acre-ft = 43560 ft3
•1 acre-ft = 7758 barrels
•1 barrel = 5.61458 ft3
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• Source Rock - A rock with abundant hydrocarbon-prone organic matter
• Reservoir Rock - A rock in which oil and gas accumulates:
• Porosity - space between rock grains in which oil accumulates
• Permeability - passage-ways between pores through which oil and gas moves
• Seal Rock - A rock through which oil and gas cannot move effectively (such as mudstone and claystone)
•Trap - The structural and stratigraphic configuration that focuses oil and gas into an accumulation
•Migration Route - Avenues in rock through which oil and gas moves from source rock to trap
Petroleum System Elements
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DK - 11 -
Seven Key Elements
of Petroleum
Reservoir
1. Source Rock
2. Reservoir Rock
3. Timing / Burial
History
4. Maturation
5. Migration
6. Cap Rock
7. Trap
HIGH
PRESSURE
10 km
1000
0
2000
3000
4000
5000
6000
7000
8000
9000
10000
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DK - 12 -
Reservoir Components
Reservoir Rock
Cap Rock Reservoir Trap Fluids
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DK - 13 -
Geology Structural
Products
Fold
Fault
Fracture
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DK - 14 -
Structural Reservoir
Trap
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DK - 15 -
Structural Reservoir
Trap
Normal Faults
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DK - 16 -
Structural Reservoir
Trap
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DK - 17 -
Structural Reservoir
Trap
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DK - 18 -
Structural Reservoir
Trap - Anticline
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DK - 19 -
Structural Reservoir
Trap - Fault
Ilustration of HC accumulation on Hanging
wall of Normal Fault
Fault Sealed
Fault Leaked
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DK - 20 -
Stratigraphyc Trap
Pinch out Channel
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DK - 21 -
Standard Scientific
Units
Parameter Symbol Dimensions cgs SI Darcy Field
Length L L cm metre cm ft
Mass m M gm kg gm lb
Time t T sec Sec sec hr
Velocity u L/T cm/sec metre/sec cm/sec ft/sec
stb/d
(liquid)
Rate q L3 /T cc/sec metre3 /sec cc/Sec
Mscf/d
(gas)
Pressure p (ML/T2 )/L2 dyne/cm2 Newton/metre2
(Pascal)
atm psia
Density M/L3 gm/cc kg/metre3 gm/cc lb/cu.ft
Viscosity M/LT gm/cm.sec
(Poise)
kg/metre.sec cp cp
Permeability k L2 cm2 metre2 Darcy mD
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DK - 22 -
Common Conversion
Factors
1 ft = 0.3048 m 1 acre = 4047 m2 = 43560 ft2
1 bbl = 0.159 m3 1 acre-ft = 1233 m3
1 dyne = 10-5 N 1 atm = 101.3 kPa
1 psi = 6.9 kPa 1 cal = 4.817 J
1 Btu = 1055 J 1 HP = 746 W
1 cp = 0.001 Pa s 1 md = 10-15 m2
1 lb = 0.454 kg 1 bar = 100 kPa
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Salt
Dome
Fault
Unconformi
ty
Pinchou
t
Anticlin
e
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Porosity
i. Define: Porosity = Total pore volume in the rock sample Total rock sample volume (solid+pore)
ii. Mathematically:
iii. Range of porosity: 0.1 to 0.3
iv. Use reservoir core to measure porosity
v. Limitations
a. Rock sample must be large enough to obtain many sand grains and many pores to be representative
b. Features sample has a different type of pore space from sandstone
lV
V
Fluid Saturation
i. Water saturation, Sw = Volume filled by water Total pore volume Oil saturation, So = Volume filled by oil Total pore volume
ii. If oil and water is the only fluid present, Sw + So = 1
iii. In most oil fields Sw tends to increase as porosity decrease
iv. Typical value of Sw – 0.1 to 0.5
v. Free gas also present in oil pools,
Free gas saturation, Sg = Volume filled by free gas Total pore volume
vi. 3 factors should always be remembered conceiving fluid saturation
a. It vary from place to place in reservoir rock; Sw higher in less porous sections due to gravity segregation of the gas, oil and water
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Example
One of the most important determinations for an oil accumulation is the volume of oil in place. Suppose that in geological evidence is known that the area extent of an oil reservoir is 2 million sqft and that the thickness of the bay zone is 30 ft. If the sand porosity and water saturation are 0.2 and 0.3, respectively, how much oil is present?
Solution:
Volume of bay = 2,000,000 ft3 x 30 ft = 6x107ft3
Total pore volume = 0.2 x 6x107 = 12x106 ft3
Then Sw+So=1; So = 1 - 0.3 = 0.7
Total oil volume = 0.7 x 12x106 = 8.4x106 ft3
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b. Vary with cumulative withdrawal; oil produced replace by water or gas
c. Oil and gas saturation frequently expressed in terms of HC-filled pore space.
Pore space = V
HC-filled pore space: SoV + SgV = (1-Sw)V
Therefore,Oil saturations, Gas saturations,
w
o
w
oS
S
VS
VSS
1)1(
0'
w
g
w
g
gS
S
VS
VSS
1)1(
'
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- MER (Most Efficient Recovery)
i. MER rate: based on most oil and gas that can extracted for a sustained period of time without harming the formation
ii. Generally, most well cannot work 24 hrs, 7 days a week – could damage formation
- Multiple Completions
i. Drilling single well at several different depth in formation
ii. Reason: increase production from a single well
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INJECTION GAS
PRODUCED FLUID
PRESSURE (PSI)
DE
PT
H (
FT
TV
D)
1000
2000
3000
4000
5000
6000
7000
0
1000 2000 0
OPERATING GAS LIFT VALVE
CASING PRESSURE WHEN
WELL IS BEING GAS LIFTED
FBHP
SIB
HP
CONSTANT FLOW GAS LIFT WELL
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DISSOLVED GAS DRIVEDISSOLVED GAS DRIVE
GAS CAP DRIVEGAS CAP DRIVE
WATER DRIVE
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Sistema cerrado (un pozo)
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Field Production
1.Primary Recovery (Natural Methods)
i. 1st method of producing oil from a well
ii. Solution gas drive
a. pressure inside reservoir relieved when well punctures and gas trapped in oil forms bubbles
b. Bubbles grow, exert pressure push oil to well and up to surface (20-30%)
iii. Gas cap drive
a. If contain gas cap, drill well directly into oil layer – gas cap expand
b. Expanding gas pushes oil into well (40%)
iv. Water drive scenario
a. Water layer press against oil layer
b. Water pushes oil towards surface and replace it within the pores of the reservoir rock
c. Highest recovery: up to 75%
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2.Secondary Recovery
i. Used to enhance or replace primary techniques
ii. Water flooding
a. Additional injection well is drilled into the reservoir
b. Pressure water injected
c. Water displaces the oil in reservoir
iii. Mechanical Lift
a. Reciprocating or plunger pumping called “horsehead”
b. Pump barrel lowered into well on 6 inch string steel rod (sucker rods)
c. Up and down movement force oil up to tubing
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3. Tertiary Recovery
i. When 2nd recovery no longer effective
ii. Thermal Process
a. Steam Flooding – steam injected, heats oil to flow readily
b. in-situ combustion (fire flooding) – air injected, a portion if oil ignited , combustion front moves away from air injection well toward production well
iii. CO2 injection
a. CO2 injected, mix with oil – reduces forces that hold oil to pores, allows easily displace by injected water
iv. Chemical recovery
i. Inject polymer into water phase of reservoir trap, large molecule add bulk to water, water thicken, wash oil from pores
ii. Sometimes surfactant added to reduce force water to solid
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4. Improvement of formation characteristic
i. To aid 3rd recovery because production drop
ii. Acidizing
a. Injecting acid into a soluble formation (exp: carbonate) to dissolve rocks
b. Enlarge the existing voids and increase permeability
iii. Hydraulic Fracturing
a. Inject a fluid into formation under significant pressure to enlarge existing fracture and create new fracture
b. This fracture extend outward from well bore into formation therefore increase permeability
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Petroleum Production System
1. Petroleum hydrocarbon production involve 2 districts
i. Reservoir – a porous medium with a unique storage and flow characteristic
ii. Artificial structures includes well, bottom hole, surface gathering, separation and storage facilities
2. Production Engineering - attempts to maximize production in a cost effective way
3. Appropriate production technology and method related directly with other major area of petroleum engineering such as formulation evaluation, drilling and reservoir engineering
4. Petroleum Hydrocarbon
i. Mixture of many compounds – petroleum and natural gas
ii. Mixture depending on its composition and conditions of P and T occur as liquid or gas or mixture of 2 phase
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4. Oil Gravity
i. Commonly expressed in degree API
ii. The terms heavy, medium and light crude cover approximately the ranges 10 to 20o, 20 to 30o and over 30o API, respectively
5. Instantaneous Water/Oil Ratio (WOR)
i. Homogeneous formation produce only oil and water (no free gas) then
ii. The pressure drop in oil may differ slightly from that in the water owing to effect of capillary forces, so dividing the equations above, results in
5.1315.141
60
F
o
oSGAPI
dl
dPkq
o
oo
dl
dPkq
w
ww
wo
ow
o
w
k
k
q
q
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iii. At the surface
iv. Or from above equation
(surface)
Where Bo is oil formation volume factor:
v. Bo is defined as ratio of the volume of oil (plus the gas in solution) at reservoir T and P to the volume of oil at standard conditions (so-called stock-tank oil)
o
wo
oo
w
q
qB
Bq
q
wo
owo
k
kBWOR
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6. Instantaneous Gas/Oil Ratio (GOR)
i. Homogeneous formation producing only oil and gas (no water production, although water may be present in the formation)
ii. Where the pressure drop across the distance dl is the same for both fluid, if capillary forces are neglected. Dividing
iii. Stock-tank oil rate will be qo/Bo, and surface free gas rate qg/Bg. In addition to free gas produced from the formation, each barrel of stock-tank oil will release a volume Rs of gas, then the total surface gas/oil ratio is
dl
dPkq
o
oo
dl
dPkq
g
g
g
go
og
o
g
k
k
q
q
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iv. At the surface
v. Therefore
(surface)
7. Productivity Index
i. Bottom hole flowing pressure - producing pressure (Pwf) at the bottom of the well
ii. The difference bettwen this and the well static pressure (Ps) is
og
os
oo
gg
sqB
qgBR
Bq
BqR
gog
ogo
skB
kBRGOR
wfs PPDrawdown
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iii. Ratio of producing rate of the well to its draw down is called Producing Index.
iv. If the rate q (bbl/day) of stock-tank liquid and draw down (psi), the productivity index (J) is defined as
(bbl/day/psi)
iii. Productivity index is based on the gross liquid rate (oil rate + water rate)
iv. Specific productivity index, Js is the number of barrel (gross) of stock-tank liquid produced/day/psi/ft net thickness
wfs PP
qJ
)( wfs
sPPh
q
h
JJ
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Rock Permeability
i. Measurement of the fluid ability to flow through the connected pores of the reservoir.
ii. A function of a degree of interconnection between pores in the rock
iii. The concept was introduced by Darcy in a classical experimental work from both petroleum engineering and ground water hydrology. Is expressed in milidarcies or Darcies.
iv. The flow rate can be measured against pressure (head) for different porous media
v. The flow rate of fluid thru specific porous medium is linearly proportional top head difference betwen the inlet and outlet and characteristic property of the medium, thus u = kDP
Where k = permeability and is a characteristic property of the porous medium
vi. The rock permeability is measured from core samples (plugs or whoke core) in the laboratory or it could also be calculated from well testing
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a. Suppose a cylindrical sample (core) of a porous rock is fully saturated with liquid of viscosity .
b. Experimentally for a particular rock sample the expression
Darcy
Equation
where k is constant
c. Q will increase a k increases, the higher the value of k the more readily will liquid flow through the core
l
A
Q
P
1 P
2
)( 21 PPA
lQk
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d. If in flow rate contain two fluid (oil and water), free gas is not present then,
d. If Q (cm3/s), (cp), l (cm) A (cm2), and P1 and P2 (atm), the value of k in Darcy is
1 Darcy = 10-8 cm2
)( 21 PPA
lQk oo
o
)( 21 PPA
lQk ww
w
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NUCLEOS PRESERVADOS
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PERFIL DE RADIACION
GAMMA
Objetivo: Puesta en
profundidad.
• Gamma Total
• Gamma espectral
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Equipo de Gamma
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Equipo
de
Gamma
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Equipo de Gamma
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Puesta en Profundidad
0
20
40
60
80
100
120
140
160
180
200
940 945 950 955 960 965 970 975 980
Profundidad (mbbp)
Gam
ma (A
PI)
GR Pozo Gamma Corona
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PLAN DE TRABAJO
Considerar:
• Objetivo del trabajo
• Recuperación y estado del
núcleo
• Urgencia de datos
• En núcleos preservados ver
estado de preservación y estado
de la muestra (necesidad de
freezar el núcleo)
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MANIPULEO DE NUCLEOS
EN LABORATORIO
• Marcar encastres
• Marcar techo y base general, y
techo y base de cada metro
• Marcar línea que una puntos de
mayor inclinación de las capas,
línea azul o verde. Marcar línea
roja a la derecha
• Numerar trozos
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MANIPULEO DE NUCLEOS
EN LABORATORIO
• Estimación y localización de
tramos de mala recuperación
• Marcar profundidad cada 50 cm
• Marcar ubicación de plugs y
numerar.
• Duplicación de números de
trozos y encastres.
• Planilla de pozo
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Marcado de líneas de
orientación
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Marcado de líneas de
orientación
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Numeración de trozos
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LABORATO
RIO
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PLANILLA DE CONTROL
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EXTRACCION DE PLUGS
De acuerdo al plan de trabajo:
• Seleccionar plenos diámetros
• Seleccionar intervalo de
muestreo
• Duplicación de plugs
• Preservación de plugs
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PLENO DIAMETRO
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PLENO DIAMETRO
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EXTRACCION DE PLUGS
DE PLENO DIAMETRO
• Con isopar
• Con agua de formación
• Con nitrógeno líquido
• Con aire
• Diámetro: 38 mm – 25 mm
• Longitud: 1.5 cm-6cm – Ideal:
6cm.
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EXTRACC
ION DE
PLUGS
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EXTRACCI
ON DE
PLUGS
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EXTRACCI
ON DE
PLUGS
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EXTRACCIO
N DE PLUGS
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FRENTEADO DEL PLUG
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FRENTEADO DE PLUG
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FRENTEADO DE PLUG
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FRENTEA
DO DE
PLUG
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CORTE Y PULIDO
• Remarcar líneas de orientación
y número de trozo si es
necesario.
• Cortar longitudinalmente un
tercio del diámetro total por
línea azul/verde.
• Corte: con agua, isopar,
nitrógeno líquido, aire.
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CORTE DE
NUCLEO
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CORTAD
ORA
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CARACTERISTICAS DE
ROCAS RESERVORIO
-Porosidad
-Permeabilidad
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POROSIDAD
-Es una medida que indica la relación entre el espacio poral de la roca reservorio y el volumen total de la roca reservorio.
-Se expresa en porcentaje.
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Arenas consolidadas
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PERMEABILIDAD
Es una medida que indica la facilidad de un fluido a fluir en una roca porosa.
La unidad que la representa es el “Darcy”.
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FLUIDOS DEL
RESERVORIO
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Fluidos
en el reservorio
Gas
Petróleo
Agua
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Petróleo
Densidad (API)
Gradiente (psi / ft)
Viscosidad (cp)
Factor de volúmen de formación (Bo)
Temperatura (°F)
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Agua de formación
Corte de agua (%)
Salinidad (ppm Cl)
Gradiente (psi / ft)
Viscosidad (cp)
Factor de volúmen de formación
(Bw)
Temperatura (°F)
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Gas Natural
Composición
Relación Gas – Petróleo (GOR)
Gradiente (psi / ft)
Factor de volúmen de formación (Bg)
Temperatura (°F)
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Formacion productiva
-Son aquellas rocas reservorio
que mantienen fluídos
hidrocarburos entrampados en
su interior.
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Trampa para petróleo y
gas
Condiciones.-
Roca fuente.
Porosidad y permeabilidad.
Tope y fondo con roca impermeable.
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Tipos de reservorio
-Reservorio de arenisca
-Reservorio de caliza
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Porosity Determination from Logs Porosity Determination from Logs
Most log interpretation techniques in use today
use a bulk volume rock approach
Quantitative rock data must be input into equations to
derive values of phi and Sw. For example:
Db = Φ x Df + (1 - Φ) Dm
Porosity is then derived:
Φ = (Dma - Db)/(Dma - Df)
Values of matrix density are normally assumed:
Dma = 2.65 for clean sand
= 2.68 for limy sands or sandy limes
= 2.71 for limestone
= 2.87 for dolomite
Fluid density is that of the mud filtrate:
Df = 1.0 (fresh)
= 1.0 = 0.73N (salt)
Where: N = NaCl concentration, ppm x 10-6
Accurate knowledge
of grain density is
essential
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Porosity at Net Overburden (NOB)
Increase in NOB can reduce porosity. Generally
the reduction is <10% of total porosity.
Less severe in consolidated rocks, more severe
in unconsolidated rocks
Grain Density
Measure the bulk volume of the sample. Weigh
the sample. GD = Dry weight/Grain volume
Most rocks are mixtures of minerals. The grain
density of any rock is variable and is dependent
on the mineralogy:
1.25gm/cc -- volcanic ash, some coals
2.65gm/cc -- clean, quartz sandstone
2.68gm/cc -- shaly sandstone with some carbonate
2.71gm/cc -- clean limestone
2.87 - >3.0gm/cc – dolomite
2.32gm/cc -- gypsum
2.96gm/cc -- anhydrite
3.89gm/cc -- siderite
Accurate values of grain density are important
because grain density is used to correct wireline
logs for potential sources of error
Fluid Saturations from Cores
Through knowledge of porosity, permeability
and residual fluid saturations (oil, water and
gas), it is possible to predict with a high
degree of accuracy the probable type of fluid
which will be produced from a given interval.
Review of the core fluorescence can also be
an indicator of oil gravity and should be
factored when type of production is predicted.
DATA USE
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Use of Routine Core Data of Routine Core Data
Laboratory measurements of routine core
properties (phi, k, saturation) are commonly used
for the following purposes:
to define pay,
to interpret gas/oil and oil/water contacts,
to estimate rate of production,
to determine storage capacity and evaluate vertical
sweep efficiency by secondary and tertiary recovery
methods
Wettability : Definitions :
Water Wet – the water phase is preferentially attracted to
the surfaces of the grains and water occupies most of the
small pores. Common in sandstones, especially those that
contain some shale
Oil Wet – the oil phase is preferentially attracted to the grain
surfaces and the oil occupies most of the small pores. Can
occur in carbonates (particularly those with abundant small
pores) and in some very clean (shale-free) sandstones
Neutral Wet – no preference for either water or oil
Fractional Wettability – certain areas of the rock are oil wet,
others are water wet due to mineralogical changes or to
changes in adsorption of the oil
Mixed Wettability – the larger pores contain oil (oil wet) and
the smaller pores contain water (water wet). Common in
carbonate reservoirs with heterogeneous pore geometry
Formations generally increase in their degree of water
wetness above 200°C
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Capillary Pressure (1)
Capillary pressure exists in a hydrocarbon reservoir
fundamentally because of differences in the density of
various fluids that affect the pressure gradients:
Pressure gradient of water = 0.44 psi/ft (density =
1gm/cc)
Pressure gradient of oil = 0.33 psi/ft (density =
0.8gm/cc)*
Pressure gradient of gas = 0.09 psi/ft (density =
0.2gm/cc)**
* 30°API
** 5000psi
As hydrocarbons accumulate in a trap, the difference in
density between the fluids results in a vertical segregation
of the fluids: gas on oil, oil on water
For example, at 10,000ft, oil pressure = 3300 psi and
water pressure = 4400 psi
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Capillary Pressure
Capillary pressure in reservoirs can be defined as
the difference between the force acting
downwards (hydrostatic head, related to density
contrasts) and the force acting upwards
(buoyancy, related to pore throat size, interfacial
tension and contact angle)
Capillary pressure is measured in the laboratory
generally using plug samples or rotary sidewall
cores. Occasionally cuttings samples are used
In the most common type of test, a non-wetting
phase fluid (e.g. mercury) is injected into the rock
at slowly increasing values of pressure. The
amount of fluid injected at each increment of
pressure is recorded and is presented as a
capillary curve
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Capillary Pressure and
Water Saturation (2)
Reservoir Sw decreases with increasing height
above the free water level (the level at which the
reservoir produces only water)
Zones that are at irreducible water saturation
(Swirr) produce only hydrocarbons. Swirr occurs
where sufficient closure and hydrocarbon column
exist
The transition zone occurs between the free water
level and the Swirr level. Formations in this zone
produce water and hydrocarbons
The magnitude of the Swirr and the thickness of
the transition zone are a function of the pore size
distribution
Small pore throats = low permeability = high Swirr
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Initial Reservoir Fluid Distribution
The amount of Sw at any height in the reservoir is
a function of:
Pore throat size, wettability, interfacial tension,
saturation history and differences in fluid densities
These variables control capillary pressure,
therefore there is a relationship between Sw, h,
Pc and pore throat size
Laboratory measurements of capillary pressure
are used to relate Sw to height above the free
water level as long as appropriate values of
laboratory and reservoir interfacial tension and
contact angle are used
Laboratory tests can be made with different fluids
oil, brine, mercury
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Capillary Pressure: :
Static Measurement
Static Method – Mercury injection
Widely used, rapid, economic and simple. Mercury is
the non-wetting phase and is injected into a cleaned and
evacuated core plug at successively increasing
pressures from 0 to 60,000psi
The core plug cannot be used for further testing
because of residual Hg saturation
Hg capillary pressure data must be scaled to reservoir
conditions using the following formula:
. Conversion factor = Mercury Pc = Sm Cos è m
Water-Air Pc Sw Cos è w
Where:
Sm = surface tension of mercury
Sw = surface tension of water
è m = contact angle of mercury against a solid (140 degrees)
è w = contact angle of water against a solid (0 degrees)
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Capillary Pressure:
Dynamic Measurement
Dynamic Method -- Centrifuge
Generally uses oil-brine fluid system but actual
reservoir fluids can also be used
Rapid, more complicated and more expensive than
mercury Pc measurements
Requires preserved or restored-state core plugs
Large (2 inch) plugs are required. These can be used for
further analysis
Brine saturated samples are centrifuged at ever
increasing speeds under oil to obtain a relationship
between capillary pressure and saturation
Capillary Pressure: Rock Controls
Pore geometry is a fundamental control on
capillary pressure, in particular the size of the
pore throats: the capillary pressure
characteristics change with changes in Rock
Type (pore geometry)
In heterogeneous reservoirs, it is essential to
collect capillary pressure data for each Rock
Type that is present in the reservoir
All other factors being equal, the lower the
permeability the smaller the pore throats the
higher the Pce and the higher the Swirr
Capillary pressure data is used to determine the
height above free water (column height) for each
Rock Type and to improve the prediction of the
type of fluid produced (hydrocarbon/water)
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Use of Pc in Reservoir Simulation
and Reservoir Characterization
For purposes of simulation and characterization, it is
necessary to know the Free Water Level (FWL)
When FWL is known it is possible to predict Sw at any
height in the reservoir even in areas that lack well
penetrations
This is particularly important in the following cases:
Areas with long transition zones and no obvious FWL
Areas with misidentified or unknown FWL
Areas with unknown or incorrect Rw
Areas where a, m and/or n are incorrect or unknown
Areas with multiple Rock Types (where a, m,n and Sw
vary as a function of Rock Type)
In these situations, it is possible to solve for Sw using
either the Pc curves or the Leverett J Function.
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Cálculo de Reservas de
Petróleo y Gas
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Definición de Reservas
• Petróleo crudo
• Gas: Gas Natural, Gas
condensado
• Líquidos del Gas Natural
• Sustancias asociadas
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Estimación de Reservas
Basados en:
• Interpretación de Datos de
Ingeniería y/o Geología
disponibles a la fecha.
• Condiciones económicas
existentes como precios , costos
y mercado.
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RESERVAS FACTIBLES DE
RECUPERAR
• ENERGIA NATURAL (RECUPERACION PRIMARIA)
• METODOS DE RECUPERACION MEJORADA
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Los Cálculos de Reservas se pueden
realizar:
• Métodos Volumétricos
• Balance de materiales
• Análisis de Curva de
Declinación
• Simulación de Reservorios
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Método Volumetrico
•Mapa de curvas de nivel de
la zona productiva (arena neta
productiva).
•Se emplean dos métodos para
determinar el volumen bruto:
•Trapezoidal V = h*( 0.5*A0 + A1+A2+A3+0.5*A4)
•Piramidal V = h (A0 + 4*A1+2*A2+4*A3+A4)
3
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Método Volumétrico - Reservorios
de Petróleo
Para el cálculo de petróleo insitu:
N = 7758*V**(1-Swi) / Boi
STB Para el petróleo remanente:
Nf = 7758*V**(1-Swg) /
Bo
Nf = 7758*V**(1-Sw -
Sg) / Bo El Factor de recobro F.R. :
F.R. = Np/N = 1 - Nf/N
V = Volumen bruto en Acres*ft
= Porosidad en fracción
Swi = Saturación inicial de agua Fracción
Boi = Factor de volumen de formación de petróleo inicial
Bo = factor de volumen de formación de petróleo final
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Método Volumétrico -
Reservorios de Gas
Para el cálculo de gas insitu: G = 43560*V**(1-Swi) / Bgi
SCF Para el gas remanente:
Ga = 43560*V**(Sgr) / Bga
El Factor de recobro F.R. :
F.R. = Gp/G =(Bga-Bgi)/Bgi
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Método Volumétrico - Reservorios de Gas
Condensado
Método 1.
o = 141.5 / (131.5 + API)
Mo= 6084/(API-5.9)
mw = R g 28.97 + 350 o
379
nw = R + 350 o
379 Mo
Mw = 0.07636 Rg + 350 o
0.002636 R + 350 o
Mo
w = Mw/28.97=Rg + 4584 o
R + 132800o
Mo
Encontramos la Tr y Pr y
luego el valor de Z luego
determinamos:
Gw = 379 PV/ ZRT
V = 43560 AH (1-Swi)
R = 10.73 Psia-ft3 / lb-mol °R
Fracción de gas:
fg = R /(R + 132800o/Mo
Cantidad de gas:
G = Gw* fg
Cantidad de líquidos
N = Gw fg/R
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Método Volumétrico - Reservorios de Gas
Condensado
Método 2.
avg gas prod. = gt ;
gt = qps ps + qst st
qps + qst Conociendo STB
cond./MMSCF y
utilizando una gráfica
desarrollada por Standing
podemos determinar una
relación (R)= u/ gt y
mediante la correlación
empírica desarrollada por
Standing podemos
encontrar Bo para
reservorio de
condensado.
Existe una gráfica de Bo es
función de:
R SCF/STB, gt , st ,
Temperatura reserv.
P reservorio ,
a altas relaciones gas/petróleo.
Cantidad de líquidos
N = 7758Ah (1-Swi)/ Bo
Cantidad de gas :
G = Rsi* N
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Exponencial Hiperbólica Armónica Lineal
CARACTERISTICAS Declinación es ConstanteDeclinación varía con
rate instantaneo
Declinación es directamente
proporcional a la rate instantáneo
EXPONENTE b = 0 b <> 0 , b <> 1 b = 1 b = 1
RELACION: Rate - Tiempo
RELACION: Rate - Cumulative
Tiempo de Abandono
Análisis de Curvas de declinación
q = q i e-a
t
i q = q i ( 1 + b ai t )-1/b q = q i ( 1 + ai t )
-1 q =qi(1 - ai t )
Np = qi - q
ai Np =
qib
(1-b)ai
(qi1-b - q1-b) ( )
ln qi
q Np = qi
ai Np =
(q1 - q2)
2 t
ta = ln r
a ta =
rb - 1
bai
ta = r - 1
ai
ta = 1 -1/r ai
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Análisis de Curvas de declinación
Aplicaciones Mecanismo PLOT
Hiperbólico • Gas Solución log (Np) vs log (q)
Exponencial • Gas Solución Np vs q
• Intrusion agua con
corte agua = 0Np vs q
2
Lineal
• Intrusion agua con
corte agua <> 0Np vs corte (petroleo/agua)
Exponencial• Intrusion agua, donde
produccion de fluido
total permanece cte.
Np vs q
Armónica • Intrusión de agua de flanco Np vs q
Lineal
• Impulsión capa gas
con bajo GOR,
gas solucion = 0
Np vs 1/p
Hiperbólico
• Impulsión capa gas
con bajo GOR bajo
gas en solución
log (Np) vs log (q) b = 2,0
• Impulsión capa gas
despues que GOC alcance
a los pozos productores
Np vs GOR
Np vs Profundidad del GOC
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Ecuación de Balance de Materiales -
Reservorios
de Gas
Para el cálculo tenemos: masa inicial- masa final final = masa
removida
ni - nf = n producido del reservorio
PiVi/ziRT - PfVf/zfRT = PscGp/RTsc
Vf = Vi - We + WpBw
GBgi -(G -Gp) Bgf = We + WpBw
Reservorio volumétrico, no hay
intrusión de agua entonces Vi=Vf
Pf/zf = Pi/zi - Psc TGp/Tsc = b - m Gp
P/z
Gp MMM SCF
Gi
Pi/zi
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Ecuación de Balance de Materiales -
Reservorios
de Petróleo
Reservorios No saturado, producción
cerca al punto de Burbuja no hay intrusión
de agua, Compresibilidad de la formación
y agua=0
Vi = Vf ; Vi = N Boi ;
Vf = Nf Bof = (N - Np) Bof
Luego: N Boi = (N - Np) Bof
N = Np Bof / (Bof - Boi )
F.R. = (Bof - Boi )/ Bof
PETROLEO PETROLEO
AGUA AGUA
Pi Pb
Reservorios No saturado, producción
cerca al punto de Burbuja no hay intrusión
agua , si efectos compresibilidades
Cf +w = Cf +CwSwi/ (1-Swi)
N = Np Bof / (Bof - Boi (1- Cw+f DP))
F.R. = Bof - Boi (1- Cw+f DP)/ Bof
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Ecuación de Balance de Materiales -
Reservorios
de Petróleo
Reservorios No saturado, producción
debajo al punto de Burbuja no hay
intrusión de agua
Vi = Vf = Vo + Vg;
N Boi = (N - Np) Bof + Gf Bgf
Gf = Nrsi - (N-Np)Rs - NpRp siendo Rp = Gp/Np
N = Np [Bof + Bg (Rp- Rs)]/ [Bof - Boi + Bg(Rsi-Rs)]
F.R.= [Bof - Boi + Bg(Rsi-Rs)]/ [ Bof + Bg (Rp- Rs)]
Si hay intrusión de agua:
Vi = Vf = Vo + Vg+ Vw
Vw = We-BwWp
N ={ Np [Bof + Bg (Rp- Rs)]- (We-BwWp)}
[Bof - Boi + Bg(Rsi-Rs)]
PETROLEO PETROLEO
AGUA AGUA
Pi Pf
GAS
Pb
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Ecuación de Balance de Materiales -
Reservorios
de Petróleo
Reservorios No saturado, producción
debajo al punto de Burbuja no hay
intrusión de agua, considerando la
expansión del volumen poroso
N = Np [Bof + Bg (Rp- Rs)]
[Bof - Boi + Bg(Rsi-Rs) + Cf+w Boi DP]
F.R.= [Bof - Boi + Bg(Rsi-Rs) + Cf+w Boi DP ]
[ Bof + Bg (Rp- Rs)]
PETROLEO PETROLEO
AGUA AGUA
Pi Pf
GAS
Pb
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Ecuación de Balance de Materiales -
Reservorios
de Petróleo
Reservorios saturado, producción
debajo al punto de Burbuja , intrusión
de agua, considerando la
expansión del volumen poroso
m= Vgli/Voi
Vi = Vf = Vo + Vgd + Vgl + Vw;
Vgl = m N Boi [Bg - Bgi] / Bgi
N = Np [Bof + Bg (Rp- Rs) - (We-BwWp) ]
[Bof - Boi + Bg(Rsi-Rs) + m Boi [Bg - Bgi] / Bgi]
PETROLEO PETROLEO
AGUA AGUA
Pi Pf
GAS
Pb
Intrusión de agua.
GAS
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Simulación de Reservorios
•Fundamentalmente se basa en los principios físicos de
conservación de masa, flujo de fluido y la conservación
de energía.
•Contiene un juego de ecuaciones que permiten describir
el comportamiento de los fluidos en un reservorio.
•Los tipos de simuladores existentes: Black Oil ,
Composicional, Recuperación Mejorada entre otros..
•Es un estudio planeado y organizado para obtener
buenos resultados, teniendo en consideración:
•Geometría del reservorio
•Propiedades de roca y fluido
•Pruebas de presión
•Datos de producción y completación
•Diseño del modelo del reservorio
•Inicialización del modelo del reservorio.
•Análisis de sensibilidad del modelo
•Ajuste de historia
•Performance del reservorio
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