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 - tim.osullivan@cairnindia.com

Drilling – Abhishek Upadhyay- abhishek.upadhyay@cairnindia.com

Provide a “free” 5 day petrophysics course to NOC’s

Pipeline – Marty Hamill - marty.hamill@cairnindia.com

EOR – Amitabh Pandey- amitabh.pandey@cairnindia.com

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.