BASIC RESERVOIR ENGINEERING
A. Haribowo
Reservoir /Engineering
PERTAMINA EP REGION JAWA
2007
Dipersiapkan Untuk Materi „Pengenalan Teknik Reservoir‟ BPS-DS,
Cirebon 30 Januari 2007 di Hotel Patrajasa
RESERVOIR
ENGIEERING
HC-RESERVOIR COMPONEN RESERVOIR TYPE HC-RESERVE
Resevoir Rock Type
Reservoir Rock: Clastic Initial Oil in Place
Rock Type Non-Clastic ( IOIP ) Ni
Rock Properties Metamorphic
NR = Ni x RF
Trap
Rock Properties : Stratigraphic Volumetric Method
Structur
Porosity ( ) %
Combination
Saturation ( S ) %
Permeability ( K ) darcy Fluid Phase :
Material Balance
Gas Method
Condensat
Fluid Properties : Oil
Densitay ( ) Decline Curve Curve
Viscosity ( ) Drive Mechanism :
Formation Volume Factor (Bo) Solution / depletion Gas
Gas Solution ( Rs ) Drive Res.
Gas Cap Drive Res.
Water Drive Res.
Segregation Drive Res.
Reservoir Condtion Combination Drive Res. Recovery Factor ( RF )
Pressure
( @ drive mechanism
Temperatur
mechanisSetiap Drive )
Petroleum System
The Reservoir Rock
• Must have sufficient porosity (F) to store the oil
• Must have sufficient permeability (K) to allow fluid
flow
• F% = (volume of voids / total volume of rock) x 100
• Effective F = total volume of voids that are
interconnected
• K: measured in Darcy units (commonly miliDarcy) Kv
– Often measured as Kv and Kh due to grain orientation/
heterogeneity issues
Khz
• The perfect Reservoir rock:
– 10 – 30% F and 500 – 1000mD
– Well sorted, medium-coarse grain size Khx
– Laterally continuous with no poor RQ intervals/ facies
Diagram Komponen Penyusun Batuan Rersevoir
The Source Rock
• This shale typically contains >1% of organic carbon, by weight.
The Reservoir Rock:
Sandstone
• The layering in this sandstone may be the result of rhythmic climatic
changes in the shallow sea where this sandstone was deposited.
The Reservoir Rock:
Limestones
• An exposure of modern limestone.
This limestone is only a few
hundred years old. It shows the
structure of coral and other
organic remains. Note the
numerous pore spaces.
• Burial of this limestone would
probably lead to reduction in
porosity as a result of
cementation,. Good quality
reservoir rocks, such as the
dolomite shown in another picture,
are created by dissolution of some
of the rock. This usually occurs
many millions of years after the
initial formation and burial
The Reservoir Rock: Dolomite
• This is an example of an important reservoir rock type. Fossil
stromatoporoids have been hollowed out by the chemical
conversion of limestone to dolomite, creating pore spaces so
large that they are sometimes called “cavernous porosity”
The Seal
• Commonly
evaporites, chalks
and shales.
• Relatively
impermeable
Reservoir Rocks Properties
• Porosity
• Permeability
• Saturation
• Capillary pressure
• Rock wettability
• Tortuosity
• Compressibility, density and thermal
properties
Porosity
“Is A The Fraction Of The Total Formation Volume That Is Not
Occupied By Solid Rock (i.e. Filled By Formation Fluid)”
• Definition: = Vp / Vb
(bulk volu me) - (volume occupied by solids)
=
(bulk volu me)
f
• In fractured rocks:
t = f + (1 - f) m
• Measured in lab using core samples m
• Estimated from density, neutron and sonic logs
Measured in Lab. Using Core
Samples
• Porosity
• Permeability
• Saturation
Water
Rock Sample Oil
(Core)
Solids/
Grains
Pore Throad
LEMBAR : S.03
VITRIC TUFF SUMUR
KEDALAMAN
: JTB-48
1922.75 M
ANALISA :
A B C D E F G H J K L M N P • PETROGRAFI
1
2 • SEM
3
4
Sumur : JTB-48
Kedalaman : 1922.75 meter
5
Nama Batuan : Piroklastik teralterasi
6
7 Foto Mikroskop Elektron Atas
Foto SEM secara umum memperlihatkan perconto
8
batuan piroklastik teralterasi dengan komposisi
9 utama fragmen batuan, kuarsa, plagioklas, felspar,
klorit, ilit dan gelas (konfirmasi analisis sayatan tipis
dan XRD). Porositas visual rendah, terdiri dari
porositas sekunder hasil pelarutan mineral gelas
A B C D E F G H J K L M N P dan butiran tidak stabil dan setempat porositas
mikro yang terbentuk di antara mineral lempung
1 klorit dan ilit.
2
Proses diagenesa terdiri dari penggantian dan pelarutan
butiran tidak stabil klorit, ilit dan kuarsa dan
3 porositas sekunder, kompaksi dan sementasi oleh
klorit, ilit dan kuarsa.
4
Perbesaran: x 86
5 Foto Mikroskop Elektron Bawah
6 Foto SEM perbesaran tinggi memperlihatkan
porositas sekunder hasil pelarutan (D-M, 3-8) yang
7 tersemenkan sebagian oleh kuarsa (K-L, 5-6; H-J,
8
7-8; D-F, 6-8). Ilit autijenik (A-C, 4-5; H-K, 3-4)
tampak hadir sebagai semen di antara semen
9 kuarsa.
Perbesaran: x 1000
Combination Neutron-Density Logs
• Suitable for gas zones, shaly formations and in detecting
the gas-oil contact
• Opposite gas zones, density log reads too high and
neutron reads too low porosity
• In shale-free reservoirs:
-- The log curves separate opposite gas zones
-- Porosity = average of both readings
• In shaly reservoirs:
Effective porosity e = D - VshshD
e = N - VshshN
This provides a method for estimating Vsh
LOG ANALYSIS Estimated from density,
neutron and sonic logs
Matrix and fluid densities
m and b are based on
reservoir type or from log
calibration with core data
m
b
f
0 1
Core Porosity
Permeability
“Is a properti of the porous medium that measures
capacity & ability of the formation to transmit fluids.”
The rock Permeability k, is very important rock property because it control
directional movement and the flowrate of the reservoir fluids in the formation.
This rock characterization was first defined mathematically by Henry Darcy in
1856. In fact, the equation that defines permeability in terms of measurable
quantities is called Darcy’s Law.
Darcy developed a fluid flow equation that has since become one of the standard
mathematical tools of the petroleum engineer. If a horizontal linear flow of an
incompressible fluid is established through a core sample of length L and a cross-
section of area A, then the governing fluid flow equation is defined as :
Absolute Permeability
Lab measurements
Area A P1 P2
Flow rate q
L
• Using liquid: k = q L / [A(P1 – P2)]
• Using gas: k = 2q L Pa / [A(P12 – P22)]
• Usually air is used for lab measurements
Two-phase Oil-Water
Relative Permeability Curves
• In single-phase flow:
kf = k (abs. Permeability) 1
• In two-phase flow: kro0
water kw = krw k Oil
oil ko = krok kr
Water krw0
• krw and kro are
both functions
of water saturation Sw 0
0 Swc 1 – Sor
1 Sw
Estimating Permeability
from Well Logs
Vsh
• k is estimated from
cross-plots with Log k
porosity and
shale content
Various rock types
• Correlation with
Log k
porosity for
various rock types
Saturation
Defined as that fraction, or percent, of the pore volume occupied by a particular
fluid (oil, gas, or water). This property is expressed mathematically by the
following relationship:
Fluid saturation = total volume of the fluid
pore volume
Applying the above mathematical concept-
of saturation to each reservoir fluid gives ;
Rock Wettability
General concepts
The wettability of a liquid is defined as the contact angle
between a droplet of the liquid in thermal equilibrium on a
horizontal surface. Is is a measure of which fluid preferentially
adheres to the rock. Depending on the type of surface and liquid
the droplet may take a variety of shapes as illustrated below.
“Water wet” . “Oil wet”
Oil θ θ
The angle θ measured through the water, is called the contact
angle. If θ90°it is oil wet.
Wettability
• Information about wettability is
fundamental for the understanding of
multiphase flow in petroleum systems
such as:
– Oil migration from source rocks
– Primary production mechanisms
– Enhanced oil recovery processes (water and
alkaline flooding)
Rock Wettability
Contact angle Wettability
(measured in water) Type
90 Oil- wet
Wettability – ESEM after coreflooding
“Outlet (and original core)” “Inlet”
Water spreads evenly- Hydrophilic surface Water forms discrete globules
“Water wet” - Hydrophobic tendency “Oil wet”
Water films
Water globules
20 50m
m
Bennett et al., 2004 – Petroleum Geoscience
Capillary Pressure
Interfacial
tension
cos
Wetting phase Non-wetting phase
Pw Pnw r
Oil-water capillary pressure Pc = Pnw - Pw
Force balance: ( r2) Pc = (2 r) cos
Pc = 2 cos / r
Drainage Capillary Pressure Curves
Capillary
Pressure
0 SwcH Swcm SwcL 1.0
Water Saturation
Capillary Pressure Hysteresis
Capillary
Pressure
0 Swc 1-Sormax 1-Sor 1.0
Wetting-phase Saturation
Rock Tortuosity
• Definition: Tortuosity = (Lt / Lm)2
• Tortuosity is related to porosity and formation
resistivity factor: = F
Compressibility
• Definition: c = - (1/V)(dV/dP) in psi-1 or Pa-1
• Rock solid compressibility cr is very low but pore volume
compressibility cp is significant
• Eeffective compressibility ct = cp + co So + cw Sw + cg Sg
Pore Volume
Compressibility
Pa-1
Porosity, %
Drainage Capillary Pressure Curves
Capillary
Pressure
0 SwcH Swcm SwcL 1.0
Water Saturation
Capillary Pressure Hysteresis
Capillary
Pressure
0 Swc 1-Sormax 1-Sor 1.0
Wetting-phase Saturation
Other Rock Properties
Bulk Density:
• Definition: b = (1 - )r + (wSw + oSo + gSg)
• Bulk density from logs is used to estimate porosity
Thermal Properties:
• Specific heat and thermal conductivity of rocks and fluids can be
estimated from correlations
• Important in thermal recovery calculations
• Volumetric heat capacity:
Cvol = (1 - )r Cr + (wCwSw + oCoSo + gCgSg)
RESERVOIR PARAMETER/DATA
Geologic data Petrophysical Data Reservoir Fluid data
- SUBSURFACE MAP: - POROSITY () - FORMATION VOLUME (Bo,
CONTOURS, ISOPACHS, FULTS, -PERMEABILITY (K) Bg, Bw)
BOUNDARIES (OWC, GOC, ETC)
-SATURATION (So, Sw, Sg) - SOLUTION GAS OIL (Rs)
- RESERVES MAP
AREA (A) - REL. PERMEABILITY - VISCOSITY (o, g, w)
THICKNESS (H) (Kr vs Sw) - RESERVOIR TEMP.
BULK VOLUME (Vb)
Res. Environment Data Production data/
Injection data
- Botttom Hole Pessure (P) & Temp (T) - Qo, Qg, Qw, GOR, WC, Np,
Gp, Wp, vs T
- Flow rate (Qo, Qg, Qw vs Time)
- Iwi, Igi, Wi, Gi VS. t
- Well Mechanical & Surface data
Reservoir Fluids
Original 1. Water
2. Gas (dry, wet, condensate)
3. Oil (light, heavy)
From Injection
• Hydrocarbon gas
• Miscible solvents (CO2, N2, LNG, LPG, etc)
• Chemical solutions (polymer, surfactant, alkaline)
• Water and steam
• Air or oxygen
• Microbial cultures and nutrients
Gas Properties
Include:
Composition, molecular weight Mw, deviation
factor Z, density g, viscosity g , formation
volume factor Bg and compressibility cg.
Source:
• Composition is measured in lab
• Mw is calculated from composition
• Z and g can be measured or estimated from
correlations
• g , Bg , and cg are calculated from other
parameters
Gas Deviation Factor Z
• Read
Pc , Tc
• Calculate
Pr , Tr
• Read
Z
Gas Viscosity
1. Read gatm 2. Read g
Other Gas Properties
• Density g = MwP / ZRT
In common units: g = 1.494 MwP / ZT in kg/m3
• Compressibility
cg= (1/P) – (1/Z)(dZ/dP)
• Formation volume factor
Bg = PstZT / PTst
In common units: Bg = 5.04 ZT / P in RB/MCF
where :
P = pressure in psia, T = temperature inR
R = universal gas constant = 8314 Nm/kg-moleK
Oil Properties
Include:
• Composition ٠Molecular weight
• Gravity ٠Bubble point pressure
• Solution gas-oil ratio ٠Formation value factor
• Viscosity ٠Compressibility
Source:
• It is preferred that oil PVT properties are
measured in laboratory
• In some cases, they may be obtained from
correlations
Definitons of PVT Parameters
• Solution Gas-Oil Ratio (Rs)
Amount of gas dissolved in oil, SCF/STB
• Bubble Point Pressure (Pb)
Pressure value at which gas starts to come out of solution
• Reservoir Oil Density (o)
o = ( osc + gscRs)/Bo API gravity = (141.5 / o) – 131.5
• Formation Volume Factor (Bo)
Reservoir volume occupied by 1 STB oil + its solution gas
• Two-phase Formation Volume Factor (Bt)
Reservoir volume occupied by 1 STB oil + its solution gas + liberated-
gas
Formation Volume factor (Bo)
Definition: Volume of reservoir oil required to produce one barrel of oil
in the stock tank.
Can be calculated from the equation:
Bo = Vol. of oil @T& P (4)
Vol. of resultant tank oil @standard conditions
Assume for now that stock tank conditions are the same as standard
conditions. If they are not the same, some minor corrections can be made
to the Bo later.
Units: reservoir barrels/stock tank barrel
(res bbl/STB)
Magnitude: Always greater than 1.0
Solution Gas Oil Ratio (Rs)
Definition: Standard cubic feet of gas dissolved in 1 stock tank barrel of
oil.
Units: standard cubic feet/stock tank barrel (scf/STB)
Note: Gas oil ratio is usually referred to in the oil industry as GOR
Rsb = solution gas oil ratio at the bubble point pressure
Typical Solution GOR for Petroleum Reservoirs:
Black oil 0.43 psi/ft
Abnormal (underpressured) = <0.43 psi/ft
Temperature in the subsurface
• Increases towards the earth‟s core: geothermal
gradient
– Different lithologies will conduct heat differently:
thermal conductivity
– Additional heat added by decay of radioactive species
– Heat Flow = Geothermal gradient x thermal
conductivity Mineral Thermal
conductivity
Halite 5.5
Limestone 3 – 3.5
Sandstone 2.5 – 4
Coal 0.3
Temperature – Pressure Relationship
Boyle‟s Law: (P x V)/T = constant
• Fluid may exist in either the liquid or gaseous form depending on the PT
conditions.
• Above the critical point: only 1 phase may exist
c
evaporation
PRESSURE
gas
liquid
condensation
TEMPERATURE
Mixed fluids in the subsurface
• Subsurface fluid may be a mixture of water and
hydrocarbon.
• Petroleum is a mixture of many types of hydrocarbon in
liquid or gaseous forms
Bubble point curve
Gas begins to bubble out of c
liquid
PRESSURE
liquid &
liquid Dew point curve
vapour Gas condenses
vapour
TEMPERATURE
Tekanan Formasi & Gradient Rekah
TEKANAN FORMASI
Tekanan yang diakibatkan oleh
fluida yang berada di dalam pori
batuan yang terdesak keluar karena
adanya pembebanan diatasnya
(Overburden)
GRADIENT TEKANAN HIDROSTATIK
PEMBENTUKAN TEKANAN FORMASI
TEKANAN HIDROSTATIK
Tekanan Gradient :
u/ Air Murni :0.433 psi/ft
u/ Air Laut : 0.465 psi/ft
PEMBENTUKAN TEKANAN
FORMASI
Tekanan fluida dalam Pori batuan akibat
pembebanan dari proses sedimentasi
atau overburden
Overburden
Patahan
Kesetimbangan
MEKANISME TERJADI KICK
Terjadi Patahan
Patahan
Blowout
KEJADIAN AKIBAT TEKANAN ABNORMAL
(OVERPRESSURE)
Apabila Tekanan Abnormal
(Overpressure) bila didiamkan akan
terjadi :
1. Masuknya fluida formasi kedalam
lubang bor disebut “Kick”
2. Apabila Fluida formasi berupa
gas
maka lumpur yang kembali ke
permukaan mengandung gas
(berbuih), hal ini apabila
kejadian
ini tidak ditanggulangi maka
akan
terjadi “ Blow Out”
ESTIMASI TEKANAN FORMASI
Kondisi Tekanan Formasi Pada
Suatu Reservoir :
© Tekanan Formasi Normal
Gradient Tekanan 0.465 psi/ft
© Tekanan Zona Transisi
+ Perubahan dari Tek. Normal ke Tek.
Abnormal (Overpressured)
+ Terdapat Lap. Shale yang tebal
sehingga P. Form secara gradual
bertambah besar.
0 ft
Tekanan Formasi + Sebagai petunjuk bahwa akan
Tekanan Abnormal
Batuan Sand
menembus
Zona
Batuan Shale
Tek. abnormal
Depth Transisi
© Tekanan Subnornal
Batuan Sand
+ Dibawah zona Transisi biasanya
10.000 ft
mempunyai gradient Tek. yang kecil
Tekanan dan
sering terjadi Drilling Break kadang-
ANALOGI
TEKANAN FORMASI (Lab. Test)
S
S= T+P
S = Tekanan Overburden ( Sedimentasi )
T = Stress pada Pegas ( matrik batuan )
P
P = Tekanan Fluida ( Tekanan Formasi )
T
PERKIRAAN TEKANAN ABNORMAL
Parameter Pemboran :
A. Perubahan ROP terhadap WOB dijaga ROP dan WOB tetap konstan.
A
B
WOB
( Lb )
C
ROP
( Ft / Jam )
Keterangan :
A = Formasi Sand
B = Formasi Shale atau Clay
C = Formasi Sand
Catatan :
Apabila pada kondisi C maka sudah dipastikan adanya tekanan
Abnormal dan bisa TERJADI “ Drilling Break “
GRADIENT REKAH FORMASI
Untuk mencari Gradient Rekah Formasi
Dapat dilakukan dengan “ Leak of Test “
Tujuan :
Untuk mengetahui perencanaan program lumpur yaitu berat lumpur
maksimum yang di ijinkan pada setiap kedalaman
Berat maksimum lumpur yang di gunakan berada diantara :
“ gradient formasi dan gradient rekah “
Prosedur “Leak of Test” :
1. Bor 5 sampai 10 ft di bawah casing shoe
2. Tutup BOP
3. Naikkan tekanan permukaan secara bertahap denga slow ready
rate. Pada titik dimanan tekanan bleed off, matikan pompa.
PENENTUAN GRADIENT REKAH FORMASI
Hasil Leak of Test diperoleh tekanan bleed off sebesar 940 psi,
casing shoe di pasang pada kedalaman 5010 ft dan berat lumpur = 10.2
ppg.
Tentukan gradient rekah formasi pada kedalaman 5010 ft
Jawab :
Maksimum Tekanan Dasar Lubang Bor
= tekanan hidrostatis + Tekanan Leak of Test
= (0.052 x 10.2 x 5010) + 940
= 3597 psi
Berat lumpur maksimum
3597 . psi
= 5010 x 0.052 13.8 ppg
Dengan menggunakan safety factor 0.5 ppg, maka berat lumpur
maksimum yang diijinkan adalah :
= (13.8 – 0.5 )ppg = 13.3 ppg
Jadi gradient rekah formasi adalah :
= 0.052 x 13.3 = 0.692 psi/ft
TEKANAN HIDROSTATIS FLUIDA
Penurunan Rumus Tekanan Hidrostatis
F Berat .(W )
P= =
Berat (W) = x Volume
A A
= Berat .(W ) Volume = A x D
Volume
.x.Volume .x. A.x.D
P = A A .x.D
psi
P =
(lb/gal) x D (ft) x
lb
0.433 .
ft
x D x 0.052 ,psi
8.33 ..
gal
Keterangan :
P = Tekanan (psi) A = Luas (in2)
W = Berat (lb) D = Kedalaman (ft)
= Densitas (lb/gal) F = Force (Gaya)
(Air Murni = 8.33 lb/gal) P Hidrostatis air murni = 0.433 psi/ft