Transcript Mangala Field

SPE Distinguished Lecturer Program
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and a contribution from Offshore Europe
The Society is grateful to those companies that allow their
professionals to serve as lecturers
Additional support provided by AIME
Society of Petroleum Engineers
Distinguished Lecturer Program
www.spe.org/dl
Maximizing the Value of an Asset through the
Integration of Log and Core data
Tim OSullivan
Cairn India Ltd
Colleagues:
Society of Petroleum Engineers
Distinguished Lecturer Program
www.spe.org/dl
Hal Warner
Dick Woodhouse
Dennis Beliveau
Ron Zittel
Stuart Wheaton
Where is the data area ?
2004 Discovery Well
Mangala, Aishwariya &
Bhagyam Fields
( about 2 Billion Barrels STOOIP)
150m - 350m oil columns
The Reservoir
Porosity: 17%
Permeability: 200md
- Excellent Quality Sandstone
26%
33%
5D
20 Darcies
Clastic Fluvial
Reservoirs
Upper Fatehgarh
Lower Fatehgarh
What’s Interesting? (to Reservoir Teams)
Fatehgarh Sand Reservoirs
Excellent Reservoir Quality Sands
* Porosity 17-33% (average ~26%)
* Permeability up to 20 Darcies (average ~5D)
* Weakly-to-Moderately Oil-Wet
* VERY LOW Water Saturations – Field Avg. 5%
Quite a LOT of Interesting Oil
* Mangala Field – Over 1 Billion Barrels Oil In Place
* An Economic Incentive for Petrophysical ACCURACY
* Very Waxy, Sweet Crude – 27
o
API Avg.
An EXCELLENT Dataset
* All Wells with Full “Basic” Logging Suites
* Many Wells with “Specialty” Logs – CMR+, etc.
* 1.7 km of Core in MBA
Fatehgarh Sand Reservoirs
Routine Core Analysis – Mangala Field
100,000
10,000
100
LPSA Mean Grain Size
1000000
10
Coarse
Sand
100000
10000
Permeability
Permeability (OBC), md
1,000
1
0%
10%
20%
30%
40%
1000
100
Silt
10
1
0.1
0.01
Porosity (OBC), %
0
0.1
0.2
Porosity
0.3
Fatehgarh Sand Reservoirs
Combined Amott/USBM
Wettability Experiment
Wettability Index Data – Mangala Field
10
100,000
Intermediate
Water Wet
Capillary Pressure (psi)
Oil Wet
Permeability (md)
10,000
1,000
1
5
4
0
2
3
1 Initial Oil Drive
2 Free Imbibition of Brine
3 Brine Drive
4 Free Imbibition of Oil
5 Oil Drive
-10
0
100
Average Sw
IAH = WWI - OWI
10
-1
-0.75
-0.5
-0.25
0
0.25
~ -0.35 Weakly oil wet
0.5
Amott-Harvey Wettability Index
0.75
1
WWI = water wetting index
WWI = proportion of the total oil
production produced spontaneously
OWI = oil wetting index
OWI = proportion of the total brine
production produced spontaneously
100
Wettability vs. Various Parameters
30
60000
50000
40000
30000
Vol Clay (%)
K/Phi
80000
70000
20000
10000
0
-1.0
25
20
15
10
5
0
-0.5
0.0
0.5
1.0
-1
-0.5
0.5
1
Wettability
Wettability
We ttability
0.6
-1
0.5
-0.5
0
0.5
1
750
0.4
0.3
0.2
TVD ss
Mean Grain Size (mm)
0
0.1
0
-1
-0.5
0
0.5
1
850
950
Wettability
Probably Wettability predominantly a function of oil
composition, with some natural variation/heterogeneity
Wettability, Transition Zones and Saturation
Ht Functions
Wettability impacts the contact angle in conversions from
laboratory to reservoir conditions
PcR = PcL * (TCos0)R/(TCos0)L
Hydrophilic
(Water Wet)
Neutral Wetting
0
0
Cos0 > 0
OWC above FWL
OWC ~ FWL
OWC
OWC
FWL
Hydrophobic
(Oil Wet)
0
Cos0 = 0
FWL
T = Interfacial Tension
0 = Contact Angle
Cos0 < 0
OWC
Below FWL
FWL (FOL !)
OWC
At Mangala, OWC
& small Transition
Zone below FWL
due to Weakly Oil
Wet Rock !!
Fatehgarh Sand Reservoirs
Variation in
oil
composition
PVT Data – Mangala Field
Mangala Field
Sample Type
R. Pr
B Point
API
Viscosity @ RP
MDT/BHS
psig
psig
Degrees
cP
BHS
1515
1496
28.3
9.7
MDT
1474
1360.5
27.3
13.2
MDT
1620.6
1045.5
21.7
50.2
Mangala-1ST
MDT
1463
1463
29
10.5
Mangala-2
MDT
1598
1345
21.8
64.2
MDT
1521
1397
28.3
18.6
MDT
1598
1197
23
11.5
MDT
1404
1363
28.8
17.1
MDT
1582
950
24.9
Not Measured
MDT
1356
1078
28.8
21.1
MDT
1469
649
29.2
26.5
BHS-1
1561
1525
27.3
18.4
BHS-4
1523
1529
28.6
13.1
1479
29.3
12.1
Well Name
Mangala-1
Mangala-3
Mangala-4
Mangala-5
Mangala-5 oil
oil
Looks
VERY
EXTREMELY
looks interesting
interesting
Mangala-5
Mangala-5
High pour point - solid at
ambient temperatures
BHS-9
1496
600km heated pipeline – world’s longest
SEHMS = Skin Effect Heat Management System
(also known as STS/SECT)
SEHMS ensures temperature maintenance above 65 deg
What’s Interesting? (to Management)
Fatehgarh Sand Reservoirs
Quite a LOT of Oil…. But…. EXACTLY How Much?
Oil = V * Porosity * (1 – Sw)
Sw )
An Exercise in Classical Petrophysics
Or… “How to Get to Sw”
Conventional
“Archie” Log Analysis
Swn = Rw/Rt *a/phitm
NMR
Logging
Calculation
And
Assumptions
Sw ?
Direct
Measurement
With only log
Dean-Stark
data, and
Core Analysis
using a value
of n of 2.3
(oil wet
w reservoir) –
Sw of 15%
S !!
Swn = Rw/Rt *a/phitm
Capillary Pressure
Saturation-Height
Functions
Are low Sw’s 5% and less possible ?
Mangala, Aishwariya and Bhagyam Fields
An EXCELLENT Dataset
Summary - Available Core Analysis Data
SIXTEEN Cored Wells
•Routine Core Analysis
•Mostly Drilled with WBM
Mangala
Field
•First Core – Early 2004
•Water-Based Mud
•Initial SCAL Data
Aishwariya
Mangala 1ST
Dean-Stark Cores
•Mangala 7ST
Bhagyam
•Bhagyam 5
Well
Mud Type
Mangala 1
Water-Based
Mangala 1ST
Water-Based
x
Mangala 2
Mangala 3
Mangala 4
Mangala 5
Mangala 6
Mangala 7
Water-Based
Water-Based
Water-Based
Water-Based
Oil-Based
Oil-Based
x
x
x
x
x
Mangala 7ST
Oil-Based
x
Aishwariya 1
Aishwariya 1Z
Aishwariya 2
Aishwariya 2Z
Aishwariya 3
Aishwariya 4
Aishwariya 5
Aishwariya 6
Aishwariya 6Z
Bhagyam 1
Bhagyam 1Z
Bhagyam 1ST
Bhagyam 2
Bhagyam 2ST1
Bhagyam 3
Bhagyam 3Z
Bhagyam 4
Water-Based
Water-Based
Water-Based
Water-Based
Water-Based
Water-Based
Water-Based
Water-Based
Water-Based
Water-Based
Water-Based
Water-Based
Oil-Based
Oil-Based
Oil-Based
Oil-Based
Oil-Based
x
Bhagyam 5
Oil-Based
x
Bhagyam 6
Bhagyam 7
Oil-Based
Oil-Based
Fatehgarh Core SCAL Dean-Stark
x
x
x
x
x
x
x
x
x
x
Mercury Injection Capillary Pressure Data
Mangala Field
Low Sw !
Height above FWL (m)
Oil Column
500
450
400
350
Sw < 10%
300
250
200
150
100
50
0
0
5
10
15
20
25
Sw (%)
30
35
40
45
50
Validity of MICP data?
Probably reasonable in high quality clean reservoirs
(Honarpour - 2004 )
Main issues : Hg may not replicate reservoir fluid displacement
: destructive – normally conducted on small chips
: remove the effects of quartz compression
Quartz compression can account for 3 to 4 Sw units,
as modern MICP machines can reach up to 60,000 psi.
500
Straight line Tails
Quartz
compression
300
200
500
60000
400
50000
40000
30000
20000
100
10000
0
0
5
10
15
20 25 30
Sw (%)
35
40
45
0
50
1
0.8
0.6
0.4
0.2
0
Height above FWL (m)
Height above FWL (m)
400
70000
300
200
100
0
0
5
10
15
20 25 30
Sw (%)
35
40
45
50
Dean-Stark Fluid Saturations
Plugs cut at wellsite
SCAL Plug
Dean
Stark
Extraction
Horizontal
Plug
1 inch
Uninvaded core centre
Vertical
Plug
Oil based mud cores
Plugs cut at wellsite
Minimize fluid loss
Minimize surfactants
Minimize core exposure to air
and to sun
Minimize invasion of mud
Maximize retaining of fluids in plugs
Dean-Stark Fluid Saturations
Contamination Plot – Bhagyam 5 Horizontal
Plug
30%
OBM Filtrate Contamination
in Oil%
X80m
25%
X15m
X78m
20%
X32m
15%
10%
5%
0%
A
B
C
D
E
F
Plug Location
G
H
I
A B C D E F G H I
Dean-Stark Water Saturations
Mangala Field
Laboratory
Apparatus
Dean Stark
Extraction
Avoid any
water
loss in
laboratory
Collect all
water
even
droplets
Toluene
110°C
Dean-Stark Water Saturations
Mangala Field
xx50
Plugs sent to 2
independent
laboratories
xx00
<-- Depth
Lab A
Lab B
xx50
One lab had
consistently
lower Sw’s by
about 1 unit
(Lab A)
xx00
xx50
0%
2%
4%
6%
8%
Dean-Stark Water Saturation, %
10%
Oil-Brine Capillary Pressure Data
(porous plate)
Mangala 1ST
Laboratory
Apparatus
Oil-Brine Capillary
Pressure and
Resistivity Index
N2 Pressure
Crude oil
Core
Plug
Ultra fine
Fritted glass
disk
Brine
Oil-Brine Capillary Pressure Data
Mangala 1ST
300
Height Above FWL, m

Oil Column

250
Sw < 10%
200
2A
28A
45A
65A
89A
110A
124A
143A
150
100
18A
38A
60A
74A
96A
114A
131A
148A
50
0
0
10
20
30
Water Saturation, pct.
40
50
Cementation Exponent “m”
100
Mangala 1ST
Formation Factor
Formation Factor
100
a=1.00
-m=1.75
10
1
1
10
100
1000
Permeability (md)
10000
100000
0.1
1
Porosity (fraction)
“m” ~ 1.75
Archie’s original
paper 1942
Sw n = Rw/Rt *a/phit
m
Saturation Exponent “n”
Mangala 1ST
Resistivity index, RI
1000
Conducted on
aged, restored
samples
100
10
1
0.01
Even though rocks are
intermediate-wet to oilwet, “n” is less than 2 !!
“n” ~ 1.8
High perms and low
salinity water
0.10
Water Saturation, v/v
1.00
Sw n = Rw/Rt *a/phit
m
Water Saturation Calculations
Mangala 7ST
Note scale from
0 to 0.2
Good agreement
with Archie, Dean
Stark core data &
Saturation Ht Sw’s
Saturation Ht Function
Divide the capillary pressure data into permeability bins
Model the capillary pressure curves according to the Skelt equation
(Harrison 2002)
SWcap_press = 1-A*exp(-((B/(HAFWL+D)) ^C))
Establish relationships as to how A,B,C,D vary with permeability
Actual Data
Modeled
vs Saturation
PressurePressure
vs Saturation
Pressure
Saturation
Pressure
vsvsSaturation
10000
8000
6000
Pressure (psia)
Mercury
Mercury Pressure (psia)
Mercury
Pressure (psia)(psia)
Pressure
Mercury
10000
8000
5,000 - 10,000 m d
5,000 - 10,000 m d
1,000 - 5,000 m d6000
1,000 - 5,000 m d
500 - 1,000 m d
500 - 1,000 m d
100 - 500 m d
50 - 100 m d
4000
<50 m d
2000
0
1
0.9
0.8
0.7
0.6
0.5
0.4
0.3
Saturation
Mercury
Saturation (Fraction)
0.2
0.1
0
100 - 500 m d
50 - 100 m d
4000
<50 m d
2000
0
1
0.9
0.8
0.7
0.6
0.5
0.4
0.3
Mercury
Saturation (Fraction)
Saturation
0.2
0.1
0
Nuclear Magnetic Resonance
Native State Plug - Mangala 1ST
Normalised Amplitude
0.12
0.10
0.08
Note T2
distributions of
native state plug
and oil almost
identical
Crude, DST 2, 70 Degrees C
Crude, DST 2, Ambient
Plug, Ambient
Plug, 70 Degrees C
Conclusion:
0.06
T2 dist almost
entirely due to bulk
oil response
0.04
0.02
0.00
0.1
1
10
T2 (ms)
Relaxation Time
100
1000
10000
Applying cut-off
for bound fluid as
defined in lab, will
give Sw
Defining the T2 cut-off for Bound Water
Cumulative T2 distribution for Saturated Sample
1.0
Normalised Amplitude
0.8
0.6
0.4
0.2
Swi (5%) from
Capillary
Pressure
0.0
0.1
1 fluid cut-off
10
Bound
1.9
100
T2 (m s)
1000
Relaxation Time
10000
Wireline NMR Sw and Dean-Stark Sw
Mangala Field
All Data support low Sw’s
Data from very different sources
Sw’s 5% or less !!!!
Such low Sw’s are possible …..
Bound water cut-off
of 1.9ms
Further
confirmation
of low Sw
NMR
Archie
Dean Stark
Saturation Ht
Economic Implications
Mangala, Aishwariya, and Bhagyam
Initial
STOIIP
Estimate
+
~350 million
barrels
=
Current
STOIIP
Estimate
120 wells drilled to date
Multi well pad concept
Rapid rig design
Purpose built wheel mounted rigs capable of moving easily between
slots on a pad without rigging down
ST-80 Iron Roughneck
Large Savings $$
EOR
Pilot Stage
MANGALA COREFLOOD RESULT
(Post waterflood result displayed)
PHASE BEHAVIOR EVALUATION
% Sodium Carbonate
0.0 0.5 0.75 1.0 1.25 1.5 1.75 2.0 2.25 2.5 2.75 3.0 3.5 4.0
100%
100%
Start of Chemical Injection
90%
95%
80%
90%
Type-III
Type-II
60%
Coreflood recovery
nearly 95% of STOIIP
80%
Additional
oil from ASP
50%
40%
85%
75%
Oil Cut
Cumulative Oil
70%
30%
65%
20%
60%
10%
55%
0%
50%
0.2% Surfactant; 0.6% NaCl; 30% Oil
Cumulative Oil, %
Type-I
Oil Cut, %
70%
Conclusions
•Very Low Water Saturations
•As evidenced here, very low water saturations
(avg. 5%) exist in Mangala, Aishwariya and
Bhagyam Fields
•Model “Case Study” of the VALUE Of
PETROPHYSICS
•This is a case-study illustrating the economic
worth of “Doing it Right” in initial petrophysics
studies of high-value fields.
•Archie “n” in OilWet Reservoir
•Contrary to “conventional
wisdom”, moderately oilwet reservoirs can exhibit
Archie “n” values NOT
significantly above 2.0.
•VALUE Of Taking
Cores & Technology
Culture
CONTACT DETAILS
Petrophysics – Tim OSullivan - [email protected]
http://in.linkedin.com/pub/timothy-osullivan/12/a39/193
Provide a “free” 5 day petrophysics course to NOC’s
Drilling
– Abhishek Upadhyay- [email protected]
Pipeline
– Marty Hamill - [email protected]
EOR
– Amitabh Pandey- [email protected]
Wettability Index
Principle - the wetting phase will tend to
spontaneously imbibe into a pore system,
while an applied pressure is necessary to
push the non-wetting phase into the
pores.
Combined Amott/USBM
Wettability Experiment
Capillary Pressure” (Pc) is defined as the
pressure of the non-wetting phase minus the
pressure of the wetting phase, and thus is
always a positive number.
Capillary Pressure (psi)
10
1
In petroleum engineering typically define Pc as
the pressure in the oil phase minus the pressure
in the water phase (Pc = Po – Pw); so Pc would
be positive for a water-wet system and negative
for an oil-wet system.
5
4
0
2
3
1 Initial Oil Drive
2 Free Imbibition of Brine
3 Brine Drive
4 Free Imbibition of Oil
5 Oil Drive
-10
0
Average Sw
IAH = WWI - OWI
WWI = proportion of the total oil
production produced spontaneously
OWI = proportion of the total brine
production produced spontaneously
100
The experiment starts with a core at initial oil saturation and looks at how
much water will spontaneously imbibe (“spontaneous production”), as shown
on step 2 of Figure 2. This is followed by a measurement of how much
water enters the core under an applied pressure gradient as the core is
flooded to the residual oil saturation (Sorw). This is the “forced production”
shown in step 3 of Figure 2.
Note that the production measured is actually oil, since for each unit of water
that enters the core an equivalent amount of oil is produced into a collection
device. Obviously if the core was strongly water-wet, most of the oil
production would happen spontaneously, with little need to apply an external
pressure. The water-wetting index (WWI) is defined as the proportion of the
total oil production that is produced spontaneously, and would be 1.0 for a
strongly water-wet system and 0.0 for an oil-wet system.