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Prof. Christoph Heubeck
Institut für Geologische Wissenschaften
Freie Universität Berlin
Malteserstr. 74-100
12249 Berlin
GERMANY
ph: ++49-(0)30-83870695
[email protected]
fax: ++49-(0)30-83870734
http://userpage.fu-berlin.de/~cheubeck/
Today‘s Lecture:
Reservoir Engineering
(light)
Reservoir engineering
• Drive Mechanisms
• Pressure-Transient Analysis
• Recovery Factor
• Subsurface Phases
• Links and Literature
1
Drive Mechanisms
9 High Porosity
9 Permeability
9 HC saturation
9Source of reservoir energy !
Drive Mechanisms
What causes hydrocarbons in the reservoir to move to the
wellbore ?
Which forces should be supported or pushed back ?
Driving force(s) to create a
pressure differential, causing
HC to flow to the wellbore
(natural or artifical)
Drive Mechanisms
Where and how should secondary recovery strategies be
implemented?
Gas Cap Drive
Gas cap drive
Solution gas drive
Water drive (Bottom-water, edge-water)
Gravity drainage drive
Combination Drive
Gas
Cap
Oil Zone
Only where a gas cap
exists (or where one
forms): RF ~20-45%;
possibly assisted by
gravity grive
Initial
Conditions
Danger of depressurizing
volatile phase (gas)
Gas
Cap
Oil Zone
During
Depletion
2
Solution Gas Drive
Gas comes out of solution as
production causes reservoir
pressure decline (cola-can
analogy): Least efficient of
the drive mechanisms, RF 520 %
Bottom Water Drive
Oil Zone
Aquifer
Initial
Conditions
Danger of producing
volatile phase (gas) first
During
Depletion
Need aquifer under
pressure. Need favorable
uniform water advance.
RF ~50% but may be as
high as 85% !
Danger of drawing the
less viscous phase
(water) to the wellbore
(water coning, water
tunneling)
Oil Zone
Edge Water Drive
Gravity Drainage /
Gravity Drive
Present in all reservoirs
but very low production
rates.
Important only
• near reservoir depletion,
• in reservoirs with high
structure, and
• low-viscosity oils
3
Producing GOR trends by drive mechanism
Combination Drive
Gas Cap
Producing GOR – mscf/stb
5
Dangers (and possibilities!)
from all sides !
Oil Zone
Aquifer
Gas-to-oil ratio
4
Solution
gas drive
Gravity
drive
3
2
Water drive
1
Gas Cap
0
Oil Zone
0
10
20
30
40
Oil Produced - % of OOIP
Reservoir Pressure Trends by drive mechanism
50
60
70
original oil in place
Reservoir Water Cut by drive mechanism
100
100
Water Cut (% of Produced Fluid)
Reservoir Pressure (% of Original)
Water drive
80
Water drive
60
Solution
gas drive
40
Gravity
drive
20
0
80
60
40
20
Gravity drive
Solution gas drive
Gas cap drive
0
0
10
20
30
Oil Produced - % of OOIP
40
50
60
70
0
10
20
30
40
50
60
70
Oil Produced - % of OOIP
4
5
5
Solution Gas Drive
Gas Cap Expansion Drive
4
4
Ultimate Recovery Ranges by Drive Mechanism
3
Drive Mechanism
Energy Source
Recovery (% OOIP)
Solution Gas
Drive
Evolved Solution Gas
Expansion
5-30
Gas Cap Drive
Gas Cap and evolved
solution gas expansion
20-40
Water Drive
Aquifer Expansion
35-75
Gravity Drainage
Gravity
5-30 ( incremental)
3
2
2
1
?
0
1
0
10
20
30
40
50
60
0
70
5
40
50
60
70
50
60
70
3
2
0
1
0
10
20
Black = GOR
30
40
50
Blue = water cut
60
70
0
0
10
20
30
40
Red = pressure
Solution Gas Drive
Gas Cap Expansion Drive
Recommendations for perforations
4
3
2
Gravity Drive
Gas Cap Drive
3
2
1
0
30
Gravity Drive
1
4
20
4
2
5
10
Water Drive
4
3
5
0
5
Gas
Cap
1
0
10
20
30
40
50
60
0
70
5
0
10
20
30
40
50
60
70
Gravity Drive
Water Drive
4
Oil Zone
Initial
Conditions
5
4
3
2
As close to the OWC in a
gravity drainage
2
1
0
As far away as posssible from
the gas cap in gas cap
reservoirs
3
1
0
10
Black = GOR
20
30
40
50
Blue = water cut
60
70
0
0
10
20
30
40
50
60
70
Red = pressure
5
Recommendations for perforations
Reservoir engineering
Water Drive
• Drive Mechanisms
• Pressure-Transient Analysis
• Recovery Factor
• Subsurface Phases
Oil Zone
• Links and Literature
Aquifer
As high up as possible in
water-drive reservoirs
Pressure-transient analysis of drill-stem tests
Pressure-transient analysis of drill-stem tests
110’
inner
radius
Undetermined
outer radius
5280’ = 1 mile
DST 1 was performed over
the perforated interval
12400’ - 12517’ MDRT
in the Fulmar Fm.
Fig. 62: Halley 30/12b-8 test overview.
Fig. 67: Interpretation of 30/11b-3 DST 1.
6
Pressure-transient analysis of drill-stem tests
28’
Open ?
Open ?
85’
5280’ = 1 mile
Parallel-boundary model for 30/12b-6 DST 1
Seismic and test data show fieldwide compartmentalization
30/12b-7
Dry hole.
Not te sted
ton
Apple ha
Alp
Outer radius
unknown due to
short test
durati on
• Drive Mechanisms
• Pressure-Transient Analysis
• Recovery Factor
• Subsurface Phases
110’
inner radi us
450’
30/11b-1
No reservoir.
Not te sted
30/11b-4
DST “saw”
only 8 -12 MMB OIP
580 0 psi
open
30/11b-3
Short tes t
gas condensate
490 0 psi
Mo
1550’
nik ie
Fau
Fault
Au k
a,
Gamm
Halley lta
De
108 0 psi
leton
App Beta
30/12b-6
Close II
faults.
30/11b-5
poo r shows.
Not teste d
28’
85’
open
lt
Halley
y
Halle Alpha
30/12b-4
Close Faults (3 0 deg)
In comm . with Fulm ar ?
open
V1
Zo
200’
ne
Fulmar
1000’
30/12b-2
U-shaped F bloc k
1100’
• Links and Literature
1100’
80’
960 psi
160’
open
1000’
1000’
Fa ult
h (V2) ~ 300’, Vol(V2) ~ 3.5 e8 ft3
A(V2) ~ 10,000 * 10000 ft2
Represented by 4 blocks of 2,500 side length each
Spatial Relation to V1 unconstrained
Reservoir engineering
open
833 psi
Be
ta
30/12b-8
In pressu re
comm. with 12b -4
2200’
970 psi
30/12b-3
Dry hole.
Not te sted
N
5280’ = 1 mile
Appleton / Halley
Fault Compartmentalization
from Seismic and Interpretation
of PTA and RFT Data
923 psi
F
Fulmar
ield
Clyde Field
882 psi
open
450 ’
1550 ’
Geometrical
Representation
Well
Major Pressure
7
Study of 100
fractured
reservoirs
(by C&C
Reservoirs)
Definition Recovery Factor
Recovery Factor:
Percentage of
economically
recoverable reservoir
fluid, compared to
Original Oil in Place
(OOIP)
FIELD NAME
COUNTRY
HASSI MESSAOUD
ALGERIA
ELMWORTH-WAPITI
TURNER VALLEY
WATERTON
Reservoir properties
•
•
•
•
•
•
Lithology
matrix heterogeneity
fracture distribution
fluid viscosity
drive mechanism
wettability
CANADA
FRACTURED TIGHT SANDSTONE
FRACTURED TIGHT SANDSTONE
CARBONIFEROUS
FRACTURED MUDDY DOLOMITE
DEVONIAN-CARBONIFEROUS
FRACTURED MUDDY DOLOMITE
PRECAMBRIAN
KARSTIC/FRACTURED MUDDY DOLOMITE
CHINA
AHWAZ
IRAN
CRETACEOUS
FRACTURED MICROPOROUS LIMESTONE
MANSURI
IRAN
CRETACEOUS
FRACTURED MICROPOROUS LIMESTONE
AIN ZALAH
IRAQ
CRETACEOUS
FRACTURED MUDDY CARBONATE
BAI HASSAN
IRAQ
TERTIARY
FRACTURED ORGANIC BUILDUP
KIRKUK
IRAQ
TERTIARY
FRACTURED/KARSTIC ORGANIC BUILDUP
KARACHAGANAK
KAZAKHSTAN
DEVONIAN-PERMIAN
FRACTURED ORGANIC BUILDUP
TENGIZ
KAZAKHSTAN
DEVONIAN-CARBONIFEROUS
KARSTIC/FRACTURED ORGANIC BUILDUP
CANTARELL
MEXICO
CRETACEOUS-TERTIARY
FRACTURED FORESLOPE CARBONATE
CRETACEOUS
FRACTURED FORESLOPE CARBONATE
CRETACEOUS-TERTIARY
FRACTURED FORESLOPE CHALK
CRETACEOUS
FRACTURED MICROPOROUS LIMESTONE
EKOFISK
Study of 100 fractured reservoirs ( by C&C Reservoirs)
CANADA
RSVR CLSS
CRETACEOUS
RENQIU
POZA RICA
www.pore-cor.com.
CANADA
RSVR AGE
CAMBRIAN
MEXICO
NORWAY
SAFAH
OMAN
IDD EL SHARGI NORTH DOME
QATAR
CRETACEOUS
FRACTURED MICROPOROUS LIMESTONE
VERKHNEVILYUY
RUSSIA
CAMBRIAN
FRACTURED MUDDY DOLOMITE
ABQAIQ
SAUDI ARABIA
JURASSIC
FRACTURED MUDDY CARBONATE
ANSCHUTZ RANCH EAST
USA
JURASSIC
TIGHT SANDSTONE
JONAH
USA
CRETACEOUS
TIGHT SANDSTONE
LOST HILLS
USA
TERTIARY
FRACTURED SILICEOUS SHALE
POINT ARGUELLO
USA
TERTIARY
FRACTURED MICROPOROUS CHERT
WATTENBERG
USA
CRETACEOUS
TIGHT SANDSTONE
YATES
USA
PERMIAN
KARSTIC/FRACTURED CARBONATE SAND
Type I
Type II
Type III
Type IV
Fractured
reservoirs
Fractured porous
reservoirs
Microporous
reservoirs
Macroporous
reservoirs
Little matrix
porosity and
permeability.
Fractures
provide both
storage capacity
and fluid-flow
pathways
Low matrix
porosity and
permeability.
Matrix provides
some storage
capacity;
fractures provide
the fluid-flow
pathways
High matrix
porosity and low
matrix
permeability
High matrix
porosity and
permeability.
Matrix provides
both storage
capacity and
fluid-flow
pathways, while
fractures merely
enhance
permeability
Reservoir management
strategy
• Optimization of production rate
• EOR technique:
Water flood, steam flood
Enhanced oil
recovery
8
Type I
Type II
Type III
Type IV
Which one are you going
to buy?
Type I
Type II
Type III
Type IV
Fractured
reservoirs
Fractured
porous
reservoirs
Microporous
reservoirs
Macroporous
reservoirs
ave. RF = 21 %
ave. RF = 26%
ave. RF = 24%
ave. RF = 34%
easily damaged by
excessive production rates.
Many perform well under
unassisted primary recovery
when managed properly
Ultimate recovery efficiency in 450 mature clastic fields
… dependent upon
lithology, wettability,
and fracture intensity.
The choice of proper
EOR technique is
essential for optimum
exploitation
… most sensitive to
drive mechanism
Reservoir engineering
Development strategies and reservoir management techniques play crucial roles in maximizing
expected ultimate recoveries for given reservoir/fluid parameters.
Five main fluid type/permeability clastic-reservoir classes, with characteristic ultimate recovery
distributions and controls, are:
(1)
heavy oil/tar reservoirs, in which RF is controlled by well spacing/reservoir depth, reservoir
connectivity and the application of tertiary recovery techniques;
(2)
low-permeability oil reservoirs, in which RF is controlled by permeability variations, well spacing
and application of waterflooding/miscible flooding, fraccing and horizontal drilling;
(3)
intermediate-permeability oil reservoirs, in which RF is controlled by fluid viscosity variations,
reservoir heterogeneity/architecture and application of waterflooding;
(4)
high-permeability oil reservoirs, in which RF is controlled by natural drive strength/type and
control of aquifer and gas-cap encroachment; and
(5)
gas/condensate reservoirs, in which RF is controlled by permeability variations, aquifer
encroachment and condensate drop-out.
• Drive Mechanisms
• Pressure-Transient Analysis
• Recovery Factor
• Subsurface Phases
• Links and Literature
9
Vaporization of a pure substance at constant Pressure
T1
P1
T2=Tv
P1
T2=Tv
P1
T3
P1
Gas
Liquid
Vaporization of a pure substance at constant Temperature
T1
P1
T1
P2=Pv
T1
P2=Pv
P3
Gas
Liquid
Gas
Liquid
T1
Gas
Liquid
Gas
Gas
Liquid
Liquid
Hg
Hg
Hg
Hg
Hg
Hg
Hg
Heating
Hg flows out so that
p stays constant
Hg
P above
Vapor
Pressure
Pressure-Volume Diagram of a Pure Substance
Pressure-Temperature Diagram of a Pure Substance
Critical Point
Liquid
tL
in e
Po
in
bl e
Bu
b
ine
tL
Liquid
+
Vapor
T7
T6
T5 = Tc
Vapor
T4
Solid
Precipitation,
Condensation
Freezing
Evaporation
Condensation ?
Vapor
T3
T2
T1
Vc
Pressure, p
Pc
Liquid
Melting
Critical
Point
o in
wP
De
Pressure, p
Pc
Specific Volume, v
Sublimation
Temperature, T
Tc
10
Chemical Composition of Hydrocarbons
Phase properties of the binary ethane – ethane system
Composition of Reservoir Fluids
1400
100%
8,21
CA
1200
22,57
C7+
nC5
nC4
CB
N2
CO2
34,62
500
co
400
Reservoir Temperature, deg F
Phase behavior of reservoir hydrocarbon mixtures
oi
l
Phase behavior of reservoir hydrocarbon mixtures
5000
5000
4000
4500
100%
Typical
reservoir
temperatures
80%
3500
3000
60%
92,46
2500
40%
2000
C7+
C6
nC5
iC5
nC4
iC4
C3
C2
C1
N2
CO2
0%
500
80%
3000
Gas
Condensate
60%
2500
40%
0%
Gas
Condensate
500
0
C7+
C6
nC5
iC5
nC4
iC4
C3
C2
C1
N2
CO2
20%
1000
Wet
gas
73,19
2000
1500
Liquid
Gas
8,21
3500
20%
1500
100%
Typical
reservoir
temperatures
4000
Pressure, psia
4500
Pressure, psia
Bl
ac
k
G
as
300
til
e
ry
D
200
O
il
0%
vo
la
D
200
C1
20%
sa
te
int
Po
Mixture
B
ne
Li
t
in
o
P
ew
C2
57,6
nd
en
b le
e
Lin
Critical
Point
Heptane,
CH
73,19
G
as
b
Bu
100
C3
40%
Mixture
A
0
iC4
92,46
86,12
W
et
600
iC5
60%
G
as
int
Bu
bb
le
Po
800
Lin
e
Critical
Point
Ethane,
CE
400
1000
C6
56,4
1000
Dew Point Line
Reservoir Pressure (psia)
80%
0
-300
-200
-100
0
Wet gas
100
200
300
400
500
600
700
Temperature, deg F
800
900
1000
1100
1200
-300
-200
-100
0
100
200
300
400
500
600
700
800
900
1000
1100
1200
Temperature, deg F
11
Phase behavior of reservoir hydrocarbon mixtures
Phase behavior of reservoir hydrocarbon mixtures
5000
5000
Typical
reservoir
temperatures
4000
4500
100%
22,57
Pressure, psia
4000
60%
3000
2500
40%
2000
57,6
C7+
C6
nC5
iC5
nC4
iC4
C3
C2
C1
N2
CO2
1000
56,4
60%
3000
2500
40%
2000
20%
1500
1000
0%
Volatile
oil
500
C7+
C6
nC5
iC5
nC4
iC4
C3
C2
C1
N2
CO2
34,62
0%
Black
oil
500
0
0
-300
-200
-100
0
100
200
300
400
500
600
700
800
900
1000
1100
-300
1200
-200
-100
0
100
200
300
Temperature, deg F
500
600
700
800
900
1000
1100
1200
800
900
1000
1100
1200
Behavior of fluids during depletion
5000
5000
4500
4000
Black
oil
2000
2000
1500
1500
1000
1000
500
500
0
0
-300
-200
-100
0
Wet gas
100
200
300
400
500
600
700
Temperature, deg F
Loci
3000
2500
800
900
1000
1100
1200
ci
Lo
2500
Poin
t
3500
i nt
Gas
Condensate
Po
Volatile
oil
3500
Bubb
le
4000
w
De
Typical
reservoir
temperatures
Pressure, psia
4500
3000
400
Temperature, deg F
Phase behavior of reservoir hydrocarbon mixtures
Pressure, psia
80%
3500
20%
1500
100%
Typical
reservoir
temperatures
80%
3500
Pressure, psia
4500
-300
-200
-100
0
100
200
300
400
500
600
700
Temperature, deg F
12
Pressure-Temperature Phase Diagram
4000
4000
Gas
condensate
reservoir
%
40
%
%
0
0
%
Li
e
m
lu
Vo
500
500
0
150
100
50
200
300
250
0
350
2
3
350
1
Reservoir
Fluid
Propane injection in oil
can cause dramatic
nonlinear viscosity
reduction (CO2 is
best)
Gas injection causes re-vaporization
of gas condensate
2
3
4
1
Reservoir
Fluid
Temperature
nt
P oi
ble
Bub Line
t Line
Dew Poin
s
Produced
Fluid
Pressure
C
t Line
Dew Poin
Pressure
300
250
Behavior of fluids during depletion
C
nt
P oi
ble
Bub Line
s
200
Reservoir Temperature, deg F
Behavior of fluids during depletion
4
150
100
50
Reservoir Temperature, deg F
s
Produced
Fluid
%
1000
id
qu
5
%
5
1500
10
%
10
1000
path of
produced
fluid
Loci
Loci
Liquid Volume
2000
%
%
40
20
1500
t
in
Po
e
bl ci 80 %
b
o
Bu L
2500
Reservoir
Fluid
Critical
Point
Dew
Poin
t
%
2000
3000
20
t
in
Po
e
bl ci 80 %
b
o
Bu L
2500
Critical
Point
Reservoir Pressure (psia)
3000
A
B
C
Reservoir
Fluid
Single-phase
gas reservoir
Gas
condensate
reservoir
3500
B
Dew
Poin
t
Reservoir Pressure (psia)
3500
Single-phase
oil reservoir
path of reservoir fluid
Pressure-Temperature Phase Diagram
Adding gas (a solvent)
to oil (about 40%) can
cause asphaltene
precipitation
s
Gas evolving from oil
due to pressure drop
during depletion can
cause wax
precipitation
s
s
Produced
Fluid
Hydrate may form from gas and
water upon gas expansion (need
antifreeze injection)
Temperature
13
Behavior of fluids during depletion
2
3
Pressure
4
1
5
Difficulty and relevance of early reservoir
fluid sampling !
C
4
s
s
pressure
3
s
Temperature
2
asphaltene precipitation
1
0
0
10
20
30
40
50
60
70
time
Last word
Geologist
Plant
Engineer
Reservoir
Engineer
Hydrocarbon
Basins
Geologist
Production
Engineer
14
Lectura
Practica
9:15-10:45
11:30-13:00
Lectura
15:15-16:45
Lu
Lectura 1 / 2 (Introduction;
The petroleum system)
Lab 2 (Internet
resources)
Lectura 3 (Geochemistry: Origin of
HC; organic matter, source rocks,
accumulation. The "petroleum
kitchen")
Ma
Lectura 4 (porosidad,
permeabilidad)
Lab 4 (Porosity
calculation)
Lectura 6 (The reservoir: Lithology,
geometry, and facies. Reservoir
characterization and management)
Mi
Lectura 5 (Reservoir
petrophysics: capillary
pressure, pore-size
distribution, bound water
etc.)
Lab 5 (Bound
water, capillarity
exercise)
Lectura 7 (Reservoir engineering:
Drive mechanisms, phase behavior,
production problems, scale
formation etc.)
Ju
Lectura 9 (Logging
concepts and tools;
quantitative evaluation of
lithology, fluids, and
porosity)
Lab 9 (Logging
exercise)
Lectura 8 (Geophysics in
exploration and reservoir
management)
Vi
Lectura 10 (Exploration:
Hydrocarbon classification
of basins; play types)
Lab 10 (Petro
Mod)
Lectura 11 (Summary: Reserves
and Resources, unconventional HC)
15