Upload
venus
View
77
Download
0
Tags:
Embed Size (px)
DESCRIPTION
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. - PowerPoint PPT Presentation
Citation preview
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 Programwww.spe.org/dl
Maximizing the Value of an Asset through the Integration of Log and Core data
Tim OSullivanCairn India Ltd
Society of Petroleum Engineers Distinguished Lecturer Programwww.spe.org/dl
Colleagues: Hal Warner Dick WoodhouseDennis BeliveauRon ZittelStuart Wheaton
Where is the data area ?
Discovery Well
Mangala, Aishwariya &
Bhagyam Fields
150m - 350m oil columns
2004
( about 2 Billion Barrels STOOIP)
Porosity:Permeability:
17% 33%200md 20 Darcies
The Reservoir - Excellent Quality Sandstone
26%5 D
Clastic Fluvial
ReservoirsUpper Fatehgarh
Lower Fatehgarh
What’s Interesting? (to Reservoir Teams)
Fatehgarh Sand Reservoirs
Quite a LOT of Interesting Oil
An EXCELLENT Dataset
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%
* Mangala Field – Over 1 Billion Barrels Oil In Place* An Economic Incentive for Petrophysical ACCURACY
* Very Waxy, Sweet Crude – 27 o API Avg.
* All Wells with Full “Basic” Logging Suites * Many Wells with “Specialty” Logs – CMR+, etc.
* 1.7 km of Core in MBA
LPSA Mean Grain Size
0.01
0.1
1
10
100
1000
10000
100000
1000000
0 0.1 0.2 0.3
Porosity
Perm
eabi
lity
Fatehgarh Sand Reservoirs
Routine Core Analysis – Mangala Field
1
10
100
1,000
10,000
100,000
0% 10% 20% 30% 40%
Porosity (OBC), % P
erm
eabi
lity
(OBC
), m
d
Coarse Sand
Silt
10
100
1,000
10,000
100,000
-1 -0.75 -0.5 -0.25 0 0.25 0.5 0.75 1
Amott- Harvey Wettability I ndex
Perm
eabi
lity
(md)
Oil Wet Water Wet
Intermediate
Fatehgarh Sand ReservoirsWettability Index Data – Mangala Field
Average Sw 0 100
0
10
-10
15
42
3Initial Oil DriveFree Imbibition of BrineBrine DriveFree Imbibition of OilOil Drive
1 2 3 4 5
IAH = WWI - OWI
Cap
illar
y Pr
essu
re (p
si)
Combined Amott/USBM Wettability Experiment
WWI = proportion of the total oil production produced spontaneously
OWI = proportion of the total brine production produced spontaneously
~ -0.35 Weakly oil wetNo Relatio
nship w
ith Perm
eabilit
y!
WWI = water wetting index
OWI = oil wetting index
Wettability vs. Various Parameters
01000020000300004000050000600007000080000
-1.0 -0.5 0.0 0.5 1.0
Wettability
K/P
hi
0
0.1
0.2
0.3
0.4
0.5
0.6
-1 -0.5 0 0.5 1
Wettability
Mea
n G
rain
Siz
e (m
m)
0
5
10
15
20
25
30
-1 -0.5 0 0.5 1
Wettability
Vol C
lay
(%)
750
850
950
-1 -0.5 0 0.5 1
Wettability
TVD
ss
Probably Wettability predominantly a function of oil composition, with some natural variation/heterogeneity
No Relationship with K/Phi!
No Relationship with Vol Clay
No Relationship with Grain Size
No Relationship with Depth
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
Hydrophobic(Oil Wet)
0
Hydrophilic(Water Wet)
0
Neutral Wetting
0
Cos0 > 0 Cos0 = 0 Cos0 < 0
FWL (FOL !)FWL
FWL
OWC above FWL OWCBelow FWLOWC ~ FWL
OWC
At Mangala, OWC & small Transition Zone below FWL due to Weakly Oil Wet Rock !!
OWC
T = Interfacial Tension0 = Contact Angle
OWC
Mangala-5 oil looks interesting
Mangala-5 oil Looks VERY interesting
Mangala-5 oil Looks EXTREMELY interesting
Mangala Field
Well Name
Sample Type R. Pr B
Point API Viscosity @ RP
MDT/BHS psig psig Degrees cP
Mangala-1
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
Mangala-3MDT 1521 1397 28.3 18.6
MDT 1598 1197 23 11.5
Mangala-4MDT 1404 1363 28.8 17.1
MDT 1582 950 24.9 Not Measured
Mangala-5
MDT 1356 1078 28.8 21.1
MDT 1469 649 29.2 26.5
Mangala-5
BHS-1 1561 1525 27.3 18.4
BHS-4 1523 1529 28.6 13.1
BHS-9 1496 1479 29.3 12.1
Fatehgarh Sand ReservoirsPVT Data – Mangala Field
Variation in oil
composition
High pour point - solid at ambient temperatures
600km heated pipeline – world’s longestSEHMS = Skin Effect Heat Management System
(also known as STS/SECT)
SEHMS ensures temperature maintenance above 65 deg
Quite a LOT of Oil…. But…. EXACTLY How Much?
What’s Interesting? (to Management)Fatehgarh Sand Reservoirs
Oil = V * Porosity * (1 – Sw)
Sw
)
Conventional“Archie” Log
AnalysisCalculation
AndAssumptions
Sw
An Exercise in Classical PetrophysicsOr… “How to Get to Sw”Direct
Measurement
Sw!!
Dean-StarkCore Analysis
Capillary Pressure
Saturation-HeightFunctions
NMRLogging ?
With only log data,
and using a value of n of 2.3 (oil
wet reservoir) – Sw of 15%
Swn = Rw/Rt *a/phitm
Swn = Rw/Rt *a/phitm
Are low Sw’s 5% and less possible ?
Mangala, Aishwariya and Bhagyam FieldsAn EXCELLENT Dataset
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
Summary - Available Core Analysis Data Field Well Mud Type Fatehgarh Core SCAL Dean- Stark
Mangala 1 Water-BasedMangala 1ST Water- Based x x
Mangala 2 Water-Based xMangala 3 Water-Based xMangala 4 Water-Based xMangala 5 Water-Based xMangala 6 Oil-Based xMangala 7 Oil-Based
Mangala 7ST Oil- Based x xAishwariya 1 Water-Based x
Aishwariya 1Z Water-BasedAishwariya 2 Water-Based x
Aishwariya 2Z Water-BasedAishwariya 3 Water-BasedAishwariya 4 Water-BasedAishwariya 5 Water-Based xAishwariya 6 Water-Based
Aishwariya 6Z Water-BasedBhagyam 1 Water-Based
Bhagyam 1Z Water-Based xBhagyam 1ST Water-Based xBhagyam 2 Oil-Based
Bhagyam 2ST1 Oil-Based xBhagyam 3 Oil-Based
Bhagyam 3Z Oil-Based xBhagyam 4 Oil-Based x
Bhagyam 5 Oil- Based x xBhagyam 6 Oil-BasedBhagyam 7 Oil-Based
Man
gala
Aish
wariy
aBh
agya
m
Company C
ulture
of tak
ing CORES!
050
100150200250300350400450500
0 5 10 15 20 25 30 35 40 45 50
Sw (%)
Hei
ght a
bove
FW
L (m
)
Mercury Injection Capillary Pressure Data
Mangala Field
Sw < 10%
Oil
Col
umn
Low Sw !
0
100
200
300
400
500
0 5 10 15 20 25 30 35 40 45 50Sw (%)
Hei
ght a
bove
FW
L (m
)
0
10000
20000
30000
40000
50000
60000
70000
00.20.40.60.81
Straight line TailsQuartz compression
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.
0
100
200
300
400
500
0 5 10 15 20 25 30 35 40 45 50Sw (%)
Hei
ght a
bove
FW
L (m
)
Dean-Stark Fluid Saturations
SCAL PlugDean Stark
Extraction Oil based mud cores
Plugs cut at wellsiteMinimize fluid lossMinimize surfactantsMinimize core exposure to airand to sun
Uninvaded core centre
Horizontal Plug Vertical
Plug
Minimize invasion of mudMaximize retaining of fluids in plugs
Plugs cut at wellsite
1 inch
Dean-Stark Fluid Saturations Contamination Plot – Bhagyam 5
0%
5%
10%
15%
20%
25%
30%
A B C D E F G H I
Plug Location
OBM
Filt
rate
Con
tam
inat
ion
in O
il%
X80m
X15m
X78m
X32m
A B C D E F G H I
Horizontal Plug
Laboratory ApparatusDean Stark Extraction
Dean-Stark Water SaturationsMangala Field
Toluene 110°C
Avoid any waterloss in laboratory
Collect all watereven droplets
Dean-Stark Water SaturationsMangala Field
xx50
xx00
xx50
xx00
xx500% 2% 4% 6% 8% 10%
Dean-Stark Water Saturation, %
<--
Dep
th
Lab ALab B
Plugs sent to 2 independent laboratories
One lab had consistently lower Sw’s by about 1 unit (Lab A)
Laboratory Apparatus
Oil-Brine Capillary Pressure and
Resistivity Index
Oil-Brine Capillary Pressure Data (porous plate)Mangala 1ST
Brine
Crude oil
N2 Pressure
Ultra fineFritted glassdisk
Core Plug
Oil-Brine Capillary Pressure DataMangala 1ST
Water Saturation, pct.
Hei
ght
Abov
e FW
L, m
0
50
100
150
200
250
300
0 10 20 30 40 50
2A 18A28A 38A45A 60A65A 74A89A 96A110A 114A124A 131A143A 148A
Sw < 10%
Oil
Col
umn
Cementation Exponent “m” Mangala 1ST
“m” ~ 1.75
Archie’s original paper 1942
1
100
10 100 1000 10000 100000
Permeability (md)
Form
atio
n Fa
ctor
1
10
100
0.1 1
Porosity (fraction)
Form
atio
n Fa
ctor
a=1.00-m=1.75
Sw n = Rw/Rt *a/phit m
Saturation Exponent “n”Mangala 1ST
1
10
100
1000
0.01 0.10 1.00Water Saturation, v/v
Resi
stiv
ity
inde
x, R
I
“n” ~ 1.8
Conducted on aged, restored
samples
Even though rocks are intermediate-wet to oil-wet, “n” is less
than 2 !!
High perms and low salinity water
Sw n = Rw/Rt *a/phit m
Water Saturation CalculationsMangala 7ST
Note scale from 0 to 0.2
Good agreement with Archie, Dean Stark core data & Saturation Ht Sw’s
Pressure vs Saturation
0
2000
4000
6000
8000
10000
00.10.20.30.40.50.60.70.80.91
Mercury Saturation (Fraction)
Mer
cury
Pre
ssur
e (p
sia)
5,000 - 10,000 md1,000 - 5,000 md500 - 1,000 md100 - 500 md50 - 100 md<50 md
Pressure vs Saturation
0
2000
4000
6000
8000
10000
00.10.20.30.40.50.60.70.80.91
Mercury Saturation (Fraction)
Mer
cury
Pre
ssur
e (p
sia)
5,000 - 10,000 md1,000 - 5,000 md500 - 1,000 md100 - 500 md50 - 100 md<50 md
Saturation Ht FunctionDivide 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
Pressure vs Saturation Pressure vs Saturation
Saturation Saturation
Mer
cury
Pr
essu
re (
psia
)
Mer
cury
Pr
essu
re (
psia
)
Actual Data Modeled
Nuclear Magnetic ResonanceNative State Plug - Mangala 1ST
0.00
0.02
0.04
0.06
0.08
0.10
0.12
0.1 1 10 100 1000 10000
T2 (ms)
Nor
mal
ised
Am
plit
ude
Crude, DST 2, 70 Degrees CCrude, DST 2, AmbientPlug, AmbientPlug, 70 Degrees C
Note T2 distributions of native state plug and oil almost identical
T2 dist almost entirely due to bulk oil response
Applying cut-off for bound fluid as defined in lab, will give SwRelaxation Time
Conclusion:
0.0
0.2
0.4
0.6
0.8
1.0
0.1 1 10 100 1000 10000
T2 (ms)
Nor
mal
ised
Am
plitu
de
Defining the T2 cut-off for Bound Water
Bound fluid cut-off 1.9
Cumulative T2 distribution for Saturated Sample
Relaxation Time
Swi (5%) from Capillary Pressure
Wireline NMR Sw and Dean-Stark Sw
Mangala Field
Bound water cut-off of 1.9ms
Further confirmation of low Sw
ArchieDean Stark Saturation Ht
NMR
All Data support low Sw’s
Data from very different sources
Sw’s 5% or less !!!!
Such low Sw’s are possible …..
Initial STOIIP
Estimate
Current STOIIP
Estimate+
~350 million
barrels
=
Economic ImplicationsMangala, Aishwariya, and Bhagyam
120 wells drilled to dateMulti well pad conceptRapid rig design Purpose built wheel mounted rigs capable of moving
easily between slots on a pad without rigging downST-80 Iron Roughneck
Large Savings $$
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
Oil
Cut
, %
50%
55%
60%
65%
70%
75%
80%
85%
90%
95%
100%
Cum
ulat
ive
Oil,
%
Oil CutCumulative Oil
Additional oil from
ASP
Coreflood recovery nearly 95% of
STOIIP
Start of Chemical Injection
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
0.2% Surfactant; 0.6% NaCl; 30% Oil
Type-I Type-III Type-II
EOR Pilot Stage
MANGALA COREFLOOD RESULT(Post waterflood result displayed)
• Very Low Water Saturations• As evidenced here, very low water saturations (avg. 5%) exist in Mangala,
Aishwariya and Bhagyam Fields
• Archie “n” in Oil-Wet Reservoir
• Contrary to “conventional
wisdom”, moderately oil-wet reservoirs can
exhibit Archie “n” values NOT
significantly above 2.0.
• 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.
Conclusions
• VALUE Of Taking Cores &
Technology Culture
http://in.linkedin.com/pub/timothy-osullivan/12/a39/193
CONTACT DETAILS
Petrophysics – Tim OSullivan - [email protected]
Drilling – Abhishek Upadhyay- [email protected]
Provide a “free” 5 day petrophysics course to NOC’s
Pipeline – Marty Hamill - [email protected]
EOR – Amitabh Pandey- [email protected]
Wettability Index
Average Sw 0 100
0
10
-10
15
42
3Initial Oil DriveFree Imbibition of BrineBrine DriveFree Imbibition of OilOil Drive
1 2 3 4 5
IAH = WWI - OWI
Cap
illar
y Pr
essu
re (p
si)
Combined Amott/USBM Wettability Experiment
WWI = proportion of the total oil production produced spontaneously
OWI = proportion of the total brine production produced spontaneously
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. 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.
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.