1. SPE Distinguished Lecturer Program
Primary funding is provided by
The SPE Foundation through member donations
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

2. Maximizing the Value of an Asset through the Integration of Log and Core data
Tim OSullivan
Cairn India Ltd
Colleagues: Hal Warner
Dick Woodhouse
Dennis Beliveau
Ron Zittel
Stuart Wheaton
Society of Petroleum Engineers Distinguished Lecturer Program

3. Mangala, Aishwariya & Bhagyam Fields ( about 2 Billion Barrels STOOIP)
Where is the data area ?
2004
Discovery Well
Mangala, Aishwariya & Bhagyam Fields
( about 2 Billion Barrels STOOIP)
150m - 350m oil columns

4. The Reservoir - Excellent Quality Sandstone Clastic Fluvial Reservoirs
Porosity:
17%
26%
33%
Permeability:
200md
5 D
20 Darcies
Clastic Fluvial Reservoirs
Upper Fatehgarh
Lower Fatehgarh

5. 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

6. Fatehgarh Sand Reservoirs Routine Core Analysis – Mangala Field1 10
100
1,000
10,000
100,000 0%
10%
20%
30%
40%
Porosity (OBC), %
Permeability (OBC), md
Coarse
Sand
Silt

7. Fatehgarh Sand Reservoirs Wettability Index Data – Mangala Field
Combined Amott/USBM Wettability Experiment
Average Sw
100 10
-10 1 5 4 2 3
Initial Oil Drive
Free Imbibition of Brine
Brine Drive
Free Imbibition of Oil
Oil Drive
IAH = WWI - OWI
Capillary Pressure (psi)
Oil Wet
Water Wet
Intermediate
~ Weakly oil wet
No Relationship with Permeability!
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

8. Wettability vs. Various Parameters
No Relationship with K/Phi!
No Relationship with Vol Clay
No Relationship with Grain Size
No Relationship with Depth
Probably Wettability predominantly a function of oil composition, with some natural variation/heterogeneity

9. 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
T = Interfacial Tension
0 = Contact Angle
Hydrophilic
(Water Wet)
Neutral Wetting
Hydrophobic
(Oil Wet)
At Mangala, OWC & small Transition Zone below FWL due to Weakly Oil Wet Rock !!
Cos0 > 0
Cos0 = 0
Cos0 < 0
OWC
Below FWL
OWC above FWL
OWC ~ FWL
OWC
FWL (FOL !)
FWL
OWC
OWC
FWL

10. Fatehgarh Sand Reservoirs
PVT Data – Mangala Field
Variation in oil composition
Mangala Field
Well Name
Sample Type
R. Pr
B Point
API RP
MDT/BHS
psig
Degrees cP
Mangala-1
BHS
1515
1496
28.3
9.7
MDT
1474
1360.5
27.3
13.2
1620.6
1045.5
21.7
50.2
Mangala-1ST
1463 29
10.5
Mangala-2
1598
1345
21.8
64.2
Mangala-3
1521
1397
18.6
1197 23
11.5
Mangala-4
1404
1363
28.8
17.1
1582
950
24.9
Not Measured
Mangala-5
1356
1078
21.1
1469
649
29.2
26.5
BHS-1
1561
1525
18.4
BHS-4
1523
1529
28.6
13.1
BHS-9
1479
29.3
12.1
Mangala-5 oil
Looks VERY interesting
Mangala-5 oil
Looks EXTREMELY interesting
Mangala-5 oil
looks interesting
High pour point - solid at ambient temperatures

11. 600km heated pipeline – world’s longest
SEHMS = Skin Effect Heat Management System
(also known as STS/SECT)
SEHMS ensures temperature maintenance above 65 deg

12. What’s Interesting? (to Management) Oil = V * Porosity * (1 – Sw)
Fatehgarh Sand Reservoirs
Quite a LOT of Oil…. But…. EXACTLY How Much?
Oil = V * Porosity * (1 – Sw) Sw )

13. An Exercise in Classical Petrophysics
Or… “How to Get to Sw”
Conventional
“Archie” Log Analysis
Direct
Measurement
Calculation
And
Assumptions
Swn = Rw/Rt *a/phitm
With only log data, and using a value of n of 2.3 (oil wet reservoir) – Sw of 15%
Dean-Stark
Core Analysis
NMR
Logging
Sw!! Sw ?
Capillary Pressure Saturation-Height Functions
Swn = Rw/Rt *a/phitm
Are low Sw’s 5% and less possible ?

14. Mangala, Aishwariya and Bhagyam Fields An EXCELLENT Dataset
Summary - Available Core Analysis Data
SIXTEEN Cored Wells
Routine Core Analysis
Mostly Drilled with WBM
Mangala 1ST
First Core – Early 2004
Water-Based Mud
Initial SCAL Data
Dean-Stark Cores
Bhagyam 5
Mangala 7ST
Company Culture of taking CORES!

15. Mercury Injection Capillary Pressure Data Mangala Field
Low Sw !
Sw < 10%
Oil Column

16. Validity of MICP data?
Probably reasonable in high quality clean reservoirs
(Honarpour )
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.
Straight line Tails
Quartz compression

17. Dean-Stark Fluid Saturations
Plugs cut at wellsite
SCAL Plug
Dean Stark Extraction
Horizontal
Plug
Vertical
Plug
Oil based mud cores
Plugs cut at wellsite
Minimize fluid loss
Minimize surfactants
Minimize core exposure to air
and to sun
1 inch
Minimize invasion of mud
Maximize retaining of fluids in plugs
Uninvaded core centre

18. Dean-Stark Fluid Saturations Contamination Plot – Bhagyam 5
Horizontal
Plug
30%
X80m
25%
X15m
X78m
20%
X32m
15%
OBM Filtrate Contamination
in Oil%
10% 5% 0% A B C D E F G H I
Plug Location
A B C D E F G H I

19. Dean-Stark Water Saturations Mangala Field
Toluene
110°C
Laboratory Apparatus
Dean Stark Extraction
Avoid any water
loss in laboratory
Collect all water
even droplets

20. Dean-Stark Water Saturations Mangala Field
xx50
xx00 0% 2% 4% 6% 8%
10%
Dean-Stark Water Saturation, %
<-- Depth
Lab A
Lab B
Plugs sent to 2 independent laboratories
One lab had consistently lower Sw’s by about 1 unit (Lab A)

21. 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

22. Oil-Brine Capillary Pressure Data Mangala 1ST50
100
150
200
250
300 10 20
Sw < 10% 2A
18A
28A
38A
45A
60A
65A
74A
 Oil Column 
Height Above FWL, m
89A
96A
110A
114A
124A
131A
143A
148A 30 40 50
Water Saturation, pct.

23. Cementation Exponent “m” Mangala 1ST
Archie’s original paper 1942
Sw n = Rw/Rt *a/phit m

24. Saturation Exponent “n” Mangala 1ST
1000
Conducted on aged, restored samples
100
Even though rocks are intermediate-wet to oil-wet, “n” is less than 2 !!
High perms and low salinity water
Resistivity index, RI
“n” ~ 1.8 10 1
Sw n = Rw/Rt *a/phit m
0.01
0.10
1.00
Water Saturation, v/v

25. Water Saturation Calculations Mangala 7ST
Note scale from 0 to 0.2
Good agreement with Archie, Dean Stark core data & Saturation Ht Sw’s

26. 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
Pressure vs Saturation
Pressure vs Saturation
Mercury Pressure (psia)
Mercury Pressure (psia)
Saturation
Saturation

27. Nuclear Magnetic Resonance Native State Plug - Mangala 1ST
Note T2 distributions of native state plug and oil almost identical
0.12
Crude, DST 2, 70 Degrees C
0.10
Crude, DST 2, Ambient
Plug, Ambient
0.08
Plug, 70 Degrees C
Conclusion:
0.06
T2 dist almost entirely due to bulk oil response
Normalised Amplitude
0.04
0.02
0.00
Applying cut-off for bound fluid as defined in lab, will give Sw
0.1 1 10
100
1000
10000
T2 (ms)
Relaxation Time

28. Defining the T2 cut-off for Bound Water
Cumulative T2 distribution for Saturated Sample
Swi (5%) from Capillary
Pressure
Bound fluid cut-off
1.9
Relaxation Time

29. 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 …..
Further confirmation of low Sw
NMR
Archie
Dean Stark Saturation Ht
Bound water cut-off of 1.9ms

30. Economic Implications Mangala, Aishwariya, and Bhagyam
Initial STOIIP Estimate
Current STOIIP Estimate +
~350 million barrels =

31. 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

32. Large Savings $$

33. MANGALA COREFLOOD RESULT (Post waterflood result displayed)
EOR
Pilot Stage
PHASE BEHAVIOR EVALUATION
MANGALA COREFLOOD RESULT
(Post waterflood result displayed)
% Sodium Carbonate
0.2% Surfactant; 0.6% NaCl; 30% Oil
Type-I
Type-III
Type-II
Additional oil from ASP
Coreflood recovery nearly 95% of STOIIP
Start of Chemical Injection

34. Conclusions Archie “n” in Oil-Wet Reservoir Very Low Water Saturations
Contrary to “conventional wisdom”, moderately oil-wet reservoirs can exhibit Archie “n” values NOT significantly above 2.0.
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.
VALUE Of Taking Cores & Technology Culture

35. CONTACT DETAILS
Petrophysics – Tim OSullivan -
Provide a “free” 5 day petrophysics course to NOC’s
Drilling – Abhishek Upadhyay-
Pipeline – Marty Hamill -
EOR – Amitabh Pandey-

36. 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.
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.
Average Sw
100 10
-10 1 5 4 2 3
Initial Oil Drive
Free Imbibition of Brine
Brine Drive
Free Imbibition of Oil
Oil Drive
IAH = WWI - OWI
Capillary Pressure (psi)
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.
WWI = proportion of the total oil production produced spontaneously
OWI = proportion of the total brine production produced spontaneously