Reservoir Vera No PDF

RESERVOIR

I

PP-324 A

rocks

Rocks continental Rocks marine

sediments

Sediments water

sweet

transport and

sedimentation

of particles

transport in

solution and

precipitation

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

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)

conversion factors are:

•1 acre-ft = 43560 ft3

•1 acre-ft = 7758 barrels

•1 barrel = 5.61458 ft3

• 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

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

DK - 12 -

Reservoir Components

Reservoir Rock

Cap Rock Reservoir Trap Fluids

DK - 13 -

Geology Structural

Products

Fold

Fault

Fracture

DK - 14 -

Structural Reservoir

Trap

DK - 15 -


Trap

Normal Faults

DK - 16 -


Trap

DK - 17 -


Trap

DK - 18 -


Trap - Anticline

DK - 19 -


Trap - Fault

Ilustration of HC accumulation on Hanging

wall of Normal Fault

Fault Sealed

Fault Leaked

DK - 20 -

Stratigraphyc Trap

Pinch out Channel

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

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

Salt

Dome

Fault

Unconformi

ty

Pinchou

t

Anticlin

e

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

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

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(

'

- 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

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

DISSOLVED GAS DRIVEDISSOLVED GAS DRIVE

GAS CAP DRIVEGAS CAP DRIVE

WATER DRIVE

Sistema cerrado (un pozo)

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%

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

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

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

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

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

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

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

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

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

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

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

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

NUCLEOS PRESERVADOS

PERFIL DE RADIACION

GAMMA

Objetivo: Puesta en

profundidad.

• Gamma Total

• Gamma espectral

Equipo de Gamma

Equipo

de

Gamma

Equipo de Gamma

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

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)

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

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

Marcado de líneas de

orientación

Marcado de líneas de

orientación

Numeración de trozos

LABORATO

RIO

PLANILLA DE CONTROL

EXTRACCION DE PLUGS

De acuerdo al plan de trabajo:

• Seleccionar plenos diámetros

• Seleccionar intervalo de

muestreo

• Duplicación de plugs

• Preservación de plugs

PLENO DIAMETRO

PLENO DIAMETRO

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.

EXTRACC

ION DE

PLUGS

EXTRACCI

ON DE

PLUGS

EXTRACCI

ON DE

PLUGS

EXTRACCIO

N DE PLUGS

FRENTEADO DEL PLUG

FRENTEADO DE PLUG

FRENTEADO DE PLUG

FRENTEA

DO DE

PLUG

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.

CORTE DE

NUCLEO

CORTAD

ORA

CARACTERISTICAS DE

ROCAS RESERVORIO

-Porosidad

-Permeabilidad

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.

Arenas consolidadas

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”.

FLUIDOS DEL

RESERVORIO

Fluidos

en el reservorio

Gas

Petróleo

Agua

Petróleo

Densidad (API)

Gradiente (psi / ft)

Viscosidad (cp)

Factor de volúmen de formación (Bo)

Temperatura (°F)

Agua de formación

Corte de agua (%)

Salinidad (ppm Cl)


Viscosidad (cp)

Factor de volúmen de formación

(Bw)

Temperatura (°F)

Gas Natural

Composición

Relación Gas – Petróleo (GOR)


Factor de volúmen de formación (Bg)

Temperatura (°F)

Formacion productiva

-Son aquellas rocas reservorio

que mantienen fluídos

hidrocarburos entrampados en

su interior.

Trampa para petróleo y

gas

Condiciones.-

Roca fuente.

Porosidad y permeabilidad.

Tope y fondo con roca impermeable.

Tipos de reservorio

-Reservorio de arenisca

-Reservorio de caliza

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

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

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

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

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

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

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

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)

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)

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.

Cálculo de Reservas de

Petróleo y Gas

Definición de Reservas

• Petróleo crudo

• Gas: Gas Natural, Gas

condensado

• Líquidos del Gas Natural

• Sustancias asociadas

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.

RESERVAS FACTIBLES DE

RECUPERAR

• ENERGIA NATURAL (RECUPERACION PRIMARIA)

• METODOS DE RECUPERACION MEJORADA

Los Cálculos de Reservas se pueden

realizar:

• Métodos Volumétricos

• Balance de materiales

• Análisis de Curva de

Declinación

• Simulación de Reservorios

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

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

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

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

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

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

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


con bajo GOR bajo

gas en solución

log (Np) vs log (q) b = 2,0


despues que GOC alcance

a los pozos productores

Np vs GOR

Np vs Profundidad del GOC

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


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


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


Reservorios

de Petróleo


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


Reservorios

de Petróleo


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


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

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

Documents

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